IPAA Oil & Gas Investment Symposium Presentation April 13, 2011 1:35 p.m.
Overview of Operations Tulsa based company founded in 1963 with long history of operations in the Mid-Continent Ticker: UNT / NYSE Market Cap: $2.9 billion (1) Enterprise Value: $3.1 billion (1) Proven track record of an integrated approach allows Unit to balance its capital deployment across E&P, drilling and midstream, gathering and processing through various stages of the energy cycle Focus on emerging high quality liquids-rich plays Granite Wash, Wilcox (Segno), Bakken shale, and Marmaton oil play Casper Office Bakken 3% Permian Basin 4% Oklahoma City Office Andarko Basin 55% Houston Office Tulsa Headquarters Arkoma Basin 19% Gulf Coast Basin 16% North LA/ East Texas Basin 3% 121 5 E&P plays Unit Rigs New Rigs 2011 Superior Pipeline's Core Operations Proved Reserves: 104 MMBoe Percent Natural Gas: 68% Percent Proved Developed: 80% Drilling Rigs: 122 (2) Miles of Midstream Pipeline: 860 (1) Market data as of 3/7/2011. (2) Includes one new build operational in late first quarter 2011. Integrated Business Approach
Summary of Business Strengths Integrated Approach Enhances Stability and Flexibility Quality upstream asset base with significant growth potential 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 Large development drilling inventory with attractive economics in current price environment, with significant horizontal drilling upside potential 191% average production replacement since 2001 90% success rate for wells drilled during 2010 Leading drilling services provider with highly capable fleet Average 1,200 HP for 122 rig fleet (1)(2) 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 4 of the 5 new build rigs for 2011. (2) Includes one new build operational in late first quarter 2011.
Core Upstream Producing Areas Permian Basin 4% West Division (1) : Rockies, Permian, and Gulf Coast East Division: Arkoma, E. Texas, N. LA, and Appalachia Central Division: Granite Wash Texas/OK Panhandle, and Kansas 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 10 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) Segno (Gulf Coast) 2010 Proved Reserves (MMBoe) Q4 2010 Daily Production (MBoe/d) East Division, 22% West Division, 23% Central Division, 55% NGL, 15% Oil, 17% Gas, 68% East Division, 23% West Division, 32% Central Division, 45% NGL, 15% Gas, 66% Oil, 19% Proved Reserves: 104 MMBoe Daily Production: 29 MBoe/d (1) Note: Map does not include 3% of proved reserves located in the Bakken shale play.
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% 0% 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 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 Drilled 19 Marmaton wells in 2010 (oil) 30-day average IP of 230 Boe/d Drilled seven Granite Wash horizontal wells in Q4 2010 (liquids-rich gas) 30-day average IP of 1,133 Boe/d (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.
Maintaining Production while Improving Commodity Mix Annual Production (MBoe/d) Production (MBoe/d) 35 28 25 24 29 28 2005-2011E CAGR: 9% 27 31 30 35 28 25 29 28 26 25 27 29 31 30 21 19 21 14 14 7 7 0 Net Wells Drilled: 2005 2006 2007 2008 2009 2010 2011E 73 85 97 134 42 88 0 Net Wells Drilled: 2007 2008 2009 Q1 Q2 Q3 Q4 2010 2010 2010 2010 97 134 42 12 23 22 31 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 Annual Production Mix (MBoe/d) Gas, 75% 2008 2009 2010 Liquids, 25% Gas, 73% Liquids, 27% Gas, 69% Liquids, 31% 2011E Gas, 63% Liquids, 37% With attractive economics and evolving technology, Unit continues to shift to more horizontal drilling Gross Wells Drilled Drilled three operated 2008 2009 2010 2011E horizontal wells in 2009 Drilled 50 operated horizontal wells in 2010 Plan to drill 70 operated horizontal wells in 2011 Horizontal 18% Horizontal Vertical, 29% 37% Vertical, 82% Vertical, 71% Horizontal 63% Horizontal 72% Vertical, 28% Unit Continues to Execute on Its Strategy to Increase Its Liquids Portfolio and Drilling Economics
Low Risk Growth Opportunities Unit has a multi-year backlog of highly economic drilling locations providing it with plenty of running room with good visibility Proved Q4 2010 2010 Net Reserves (1) Daily Production R/P Capex Region Acreage (MMBoe) (Mboe/d) (Years) ($MM) West Division Gulf Coast Basin 126,031 16.5 7.1 6.3 $95.6 Rockies / Bakken 72,726 3.5 0.9 10.7 27.3 Permian 56,543 4.0 1.4 7.8 15.6 East Division E. Texas / N. Louisiana 25,167 3.4 1.5 6.2 $31.3 Arkoma Basin 66,525 19.2 5.0 10.6 19.4 Appalachia 42,049 0.1 - N/A 2.1 Central Division OK / Texas Panhandle 180,894 39.5 8.8 12.3 $205.9 Anadarko Basin 125,307 17.5 4.2 11.4 66.7 Total 695,242 103.7 28.9 9.8 $463.9 (1) As audited by Ryder Scott for year end 2010.
Granite Wash Play Q4 2010 Results Average 30-day IP for 7 operated horizontal wells = 1,133 Boe/day Average reserves: 585 MBoe (48% oil & liquids) Average CWC: $5.1 MM (4,000 lateral, 11 stage frac) Average working interest: 73% Type Log 7,200 Lower Douglas 9,700 10,500 Granite Wash Texas Oklahoma Unit 2011 Horizontal Wells Unit 2011 Non-op Horizontal Wells Unit Acreage 2011 Projected 3-4 rigs drilling = 22 operated horizontal wells Additional 16 non-operated GW horizontal wells Cap Ex: $96 MM 38,000 net acres 11,100 Upper Morrow
Marmaton Oil Play Q4 2010 Results Average 30-day IP for operated horizontal wells = 230 Boe/day Average reserves: 131 MBoe (90% oil & liquids) Average CWC: $2.5 MM (4,000 lateral, 16 stage frac) Average working interest: 93% 2011 Projected 2 rigs drilling = 30-36 operated horizontal wells +/- 6200 Horizontal Lateral Target Marmaton Type Log Upper Cap Ex: $52 MM 60,000 net acres located primarily in Beaver County, OK 400 Middle Lower Unit Focus Area Unit Acreage Completed and Producing Wells 2011 Wells (first half) +/- 6600
Segno Wilcox Extension 3-D Area West Segno Expansion (2008) 2003 to Current Completed 87 wells at 77% success rate 2010 Results Average initial production rate = 326 Boe/day Average reserves: 252 MBoe (50% oil & liquids) Average CWC: $3.5 MM Average working interest: 94% Wilcox Type Log 2011 Projected Upper 7,800 9,400 2009 Expansion 1 2 rigs drilling = 20 operated vertical wells (80% WI) Middle 10,500 11,400 Segno South Approx. 151 sq. mi. Cap Ex: $54 MM 48,000 net acres Lower 12,000 Completed and Producing Wells 12,900 2011 Rig Schedule 16
2011 Upstream Capital Program $357 million drilling capital budget allocated principally to the liquids-rich Granite Wash, Marmaton, and Segno plays 8% increase in the drilling budget for 2011 Approximately $202 million allocated to Granite Wash, Oklahoma Marmaton oil play, and Texas Segno field operations (~57% of overall drilling budget) Current plan will provide Unit with 11%+ annual growth in production Total CapEx by Category Drilling CapEx by Region Other 14% Drilling 86% Segno 15% Granite Wash 27% Marmaton Oil 15% Bakken 8% Dry Gas 6% Other 29% 2011E CapEx Budget: $415 Million 2011E Capital Budget: $357 Million Focused Capital Program Emphasizes Higher Return Liquids-Rich Drilling Plays
Significant Drilling Presence in Attractive Producing Regions 7 122 rig fleet (excluding 4 of 5 new builds)(1) 5 Fleet average ~1,200 HP rating; ~16,400 ft depth capacity 20 70% of rigs capable of drilling horizontal Casper Office 59% utilization rate for Q4 2010 100% of 38 1,200-1,700 HP rigs at year end Tulsa Recently spent $55 million to refurbish / Headquarters upgrade 30 rigs 67 6 Oklahoma City Office 21 121 Unit Rigs 5 (1) New Rigs - 2011 Houston Office Identified ~20 additional rigs with upgrade potential 2010 added a new 1,500 HP, dieselelectric rig into Rockies and acquired a 1,200 HP electric drilling rig 2011 5 new build rig program (1,500 HP rigs) 2-year contracts for all 5 rigs in the Bakken shale One new build operational late first quarter, one new build to be in operation early second quarter and three new builds in early fourth quarter.
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 (59% as of 12/31/10) 60% Growing demand from increased shallow horizontal drilling activity 80% 100% Number of Rigs: New Rigs - 2011: 67 rigs equipped with integrated top drives 30 40 38 7 71% 6 5 14 Average Depth Capacity: 16,426 feet
Conditions Support Improving Utilization, Dayrates and Margins (1) $20,000 100% Margins / DayRates ($) $15,000 $10,000 $5,000 75% 50% 25% Utilization (%) $0 2007 2008 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Margins Day Rates % Utilized 0% Four Consecutive Quarters of Improving Day Rates and Margins as Utilization Increases (1) Margins are before elimination of intercompany rig profit.
Superior Pipeline s Core Operations Average Processing Pipeline Volume Average Capacity Processing (miles) Pipeline (MMbtu/d) Volume (MMcf/d) Capacity (miles) (MMbtu/d) (MMcf/d) Hemphill/Mendota 130 43,700 100 Perkins Hemphill/Mendota 55 130 5,600 43,700 10 100 Cashion Perkins 140 55 22,500 5,600 25 10 Minco Cashion 130 140 7,700 22,500 12 25 Minco 130 7,700 12 Panola (1) Panola (1) 45 52,000 - Segno 30 45 19,900 52,000 - - Segno 30 19,900 - (1) Includes two treatment plants. Three natural gas treatment plants Ten natural gas processing plants 34 active gathering systems 860 miles of pipeline
Historical Performance Historical Daily Gathering Volumes (MMBtu / d) 250,000 NGLs / Condensate Volumes (Bbl / d) 8,000 200,000 150,000 100,000 50,000 6,000 4,000 2,000 0 2006 2007 2008 2009 2010 0 2006 2007 2008 2009 2010 2010 Contract Mix (Based on Volume) (1) 2010 Contract Mix (Based on Operating Margin) (1) POP 33% POI 16% Fee-Based 51% POI 47% POP 38% Fee-Based 15% (1) POP represents percent of proceeds. POI represents percent of index.
Segment Contribution Revenues ($ millions) EBITDA ($ millions) (1) $1,400 $1,358 $800 $754 $1,200 $1,000 $882 $600 $800 $600 $710 $400 $371 $442 $400 $200 $200 $0 2008 2009 2010 $0 2008 2009 2010 Unit Petroleum Unit Drilling Superior Pipeline Other (1) See EBITDA reconciliation.
Strong Capital Structure Strong capital structure In the process of extending maturity of Credit Facility to 2016 Capitalization ($ millions) 12/31/2010 12/31/2009 Cash & Cash Equivalents $1 $1 Debt - Revolver (May 2012) 163 30 Book Value of Equity 1,711 1,566 Total Book Capitalization $1,874 $1,596 Total Liquidity Revolver Elected Commitments (1)(2) $325 $325 Less: Amount Outstanding (163) (30) Plus: Cash 1 1 Total Liquidity $163 $296 Operational Statistics Proved Reserves (MMBoe) 104 96 Proved Developed Reserves (MMBoe) 83 77 LTM EBITDA (3) $442 $371 Selected Credit Statistics: Total Debt / LTM EBITDA 0.4x 0.1x Total Debt / Proved Reserves ($ / Boe) $1.57 $0.32 Total Debt / PD Reserves ($ / Boe) $1.97 $0.40 Total Debt / Book Capitalization 8.7% 1.9% (1) Total borrowing base is $600 million. See appendix for more details. (2) Based on current revolver elected commitments of $325 million. (3) See EBITDA reconciliation.
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 Hedged over 600,000 gallons/mo of NGLs at an average price of $0.97 for 2011 MMBtu/d 100,000 Natural Gas Bbls/d 4,000 Crude Oil $84.28 $95.01 80,000 $4.85 3,000 60,000 2,000 40,000 $5.48 $102.18 1,000 20,000 0 2011 2012 0 2011 2012 2013
Prudent Capital Spending Unit maintains a conservative and disciplined approach towards asset development with a focus on maintaining balance sheet strength Target capex spending to remain in-line with projected cash flows Ability to proactively manage capital budget with overall market conditions Integrated model further provides enhanced market intelligence to support capital allocation with regards to drilling programs, infrastructure build-out and rig construction CapEx ($ millions) (1) Operating Cash Flow ($ millions) $900 $750 $807 $900 $750 $779 $600 $612 $605 $600 $450 $300 $308 $450 $300 $387 $457 $150 $150 $0 2008 2009 2010 2011E Unit Petroleum $0 Unit Drilling 2008 2009 2010 Superior Pipeline Track Record of Aligning Capital Spending with Cash Flows (1) Includes expenditures for acquisitions.
Why Unit? Three consistent growing energy segments: Unit Petroleum Company 191% average production replacement since 2001 90% success rate for wells drilled during 2010 Unit Drilling Company Average 1,200 HP for 122 rig fleet (1)(2) 70% of fleet capable of drilling horizontal wells 120% increase in rig count since 2001 Superior Pipeline Company Focus in emerging plays of Granite Wash and Marcellus shale 513% increase in per day natural gas processed volumes since 2004 1,099% increase in per day liquids sold volumes since 2004 Debt to capitalization percentage at the end of 2010 was 9%. (1) Excludes 4 of the 5 new build rigs for 2011. (2) Includes one new build operational in late first quarter 2011.
Forward-Looking Statement This presentation contains forward-looking statements within the meaning of the Securities Litigation Reform Act that involve risks and uncertainties, including the closing of pending acquisitions, productive capabilities of the wells, future demand for oil and natural gas, future rig utilization and dayrates, timing of the completion of drilling rigs currently under construction, projected growth of the company s oil and natural gas production, oil and natural gas reserve information (including valuation), anticipated production rates from company wells, the prospective capabilities of offset acreage, anticipated oil and natural gas prices, anticipated gas gathering and processing rates, number of wells to be drilled by the company, development, operational, implementation and opportunity risks, and other factors described from time to time in the company s publicly available SEC reports, which could cause actual results to differ materially from those expected.
Appendix
Non-GAAP Financial Measures EBITDA Year ended December 31, ($ in Millions) 2008 2009 2010 Net Income $144 ($56) $146 Income Taxes 82 (32) 91 Depreciation, Depletion and Amortization 245 177 205 Impairment of Oil and Natural Gas Properties 282 281 - Interest Expense 1 1 - EBITDA $754 $371 $442 Unit Petroleum Income Before Income Taxes (1) ($4) ($126) $177 Depreciation, Depletion and Amortization 160 115 119 Impairment of Oil and Natural Gas Properties 282 281 - EBITDA $438 $270 $296 Unit Drilling Income Before Income Taxes (1) $240 $51 $60 Depreciation and Amortization 70 45 70 EBITDA $310 $96 $130 Superior Pipeline Income Before Income Taxes (1) $16 $5 $17 Depreciation and Amortization 15 16 15 EBITDA $31 $21 $32 (1) Does not include allocation of G&A expense.