EnerCom s London Oil & Gas Conference June 11, 2013
Overview of Operations 16 Bakken 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 Casper Office 127 Unit Rigs E&P Plays 18 77 Anadarko Basin Oklahoma Permian Basin City Office Mid-Stream Operations Houston Office Tulsa Headquarters 16 Arkoma Basin Gulf Coast Basin Marcellus North La/ East Texas Basin Integrated Business Approach 2
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 69% since 2003 Sold 15 rigs since 2003 127 drilling rig fleet Mid-Stream 1,134% increase in natural gas processing volumes since 2004 902% increase in daily liquids sold volumes since 2004 1,373 miles of pipeline Strong Balance Sheet Remains conservatively financed as the company has grown 3 (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 4
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 Q1 2013 Daily Production NGL 23% NGL 20% Oil 15% Gas 62% Oil 20% Gas 60% 5 Proved Reserves: 150 MMBoe Daily Production: 44.1 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. 6
Increasing Production while Improving Commodity Mix Annual Production (MBoe/d) 50 40 39 45 44 33 30 29 28 27 20 10 28% 55% 0 2008 2009 2010 2011 2012 2013E Net Wells Drilled: 134 43 88 82 80 7 Oil / NGLs Natural Gas Production Range
Granite Wash Play Noble acquisition strategic fit with existing UPC leasehold Total 47,000 net acres in the Texas Panhandle Core Area (81% HBP) Approximately 800 potential drilling locations HIGHLIGHTS Current AFE CWC: $5.3 MM Estimated reserve range: 3.5 4.0 Bcfe Calculated ROR = 49% - 70% (Flat $90 oil, $30 NGL, $3.25 gas) First sales on 29 GW horizontal wells 2012 GW Type Log - Buffalo Wallow Field 11,000 +/-200 2012 30-day average IP = 4.1 MMcfe per day Production up 41% in 2012 over 2011 2013 ACTIVITY Q1 2013 = average net 88 MMcfe per day (46% oil & NGLs) Q1 4 wells completed 30 day IP = 4.7 MMcfe per day 13,400 +/-200 4-6 Unit rigs: First sales on 30 gross wells Estimate capital expenditures $140 million net First Noble well spud in Q2 8
Marmaton Oil Play Total 113,000 net acres in focus area (47% HBP) HIGHLIGHTS Completed 95 operated horizontal wells since 2010 150 potential locations on 640 acre spacing Estimated reserve range: 120-130 MBoe per well Current AFE CWC: $2.7 million per well Calculated ROR 80% - 100% (Flat $90 oil, $30 NGL, $3.25 gas) Focus Area First sales on 32 horizontal wells (includes two extended laterals) in 2012 30 day IP 391 Boe per day for 2012 wells Production up 61% in 2012 over 2011 2013 ACTIVITY Q1 2013 average net 4,148 Boe per day (92% oil & NGLs) Q1 10 wells completed 30 day IP = 393 Boe per day Two Unit rigs (3 rd rig for 4 wells) Estimate first sales on 40 gross wells (includes 3 extended laterals) Estimate capital expenditures $90 million net 9
Wilcox Liquids Play WILCOX HIGHLIGHTS Gilly Field Discovery Completed 122 wells since 2003 with 73% success rate 72,000 net acres Gilly Field Discovery announced July 2012 Total reserve potential = 168 Bcfe net (262 Bcfe gross) Unit Prospect Area Eight Wilcox potential pay zones (4 zones currently producing) Six Gilly Field producing wells Average 255 net potential pay/well Estimated AFE CWC: $5.4 million Gilly Field Discovery 1,000 Acres 2013 ACTIVITY Q1 2013 = average net 35 Mmcfe per day (42% NGLs) Completed wells 2013 wells Future wells One - two Unit rigs in Wilcox 12 gross wells (includes 4 Gilly field vertical wells / 7 other prospects / one horizontal well) Estimate capital expenditures $60 million net 10
Mississippian Play Central Kansas Uplift Total 110,000 net acres in focus area (5% HBP) HIGHLIGHTS Approximately 300 potential locations (320 acre spacing) Average well depth +/- 8,000 (includes 4,000 lateral) Mississippian pay zone +/- 50 thick Mississippian Trend 2013 ACTIVITY Focus Area Initial Well 105,000 Net Acres Mississippian Wells Drill 3 wells in Q1 wait on pipeline infrastructure to be built estimate Q3 completion Resume drilling in Q3 with one Unit rig and anticipate adding second rig in Q4 First sales on 13 gross wells Estimated reserve range = 125-180 MBoe (92% oil & liquids) Calculated ROR 40% - 66% (Flat $90 oil, $30 NGL, $3.25 gas) Estimated AFE CWC: $3.0 million 2012 Drilled 4 horizontal Miss wells in Kansas focus area Initial well completed May 2012; second well December 2012 30 day average IP 240 Boe per day (89% oil and liquids) 11 Estimate capital expenditures $40 million net
Significant Drilling Presence in Attractive Producing Regions 18 16 Casper Office 77 Oklahoma City Office Tulsa Headquarters 127 rig fleet Fleet average ~1,200 HP rating; ~16,724 ft depth capacity 97% of contracted rigs drilling horizontal wells 52% utilization rate for Q1 2013 69% of 45 1,200-1,700 HP rigs under contract Refurbished / upgraded 19 rigs in 2011 and 15 rigs in 2012 2012 placed 2 new build rigs into service (1,500 HP) Contracted Rig Commodity Mix Geographical Location 127 Unit Rigs 16 Houston Office Dry Gas 1% Liquids Rich 99% Rockies/ Bakken 27% E. TX, LA GC, S. TX 13% Anadarko Basin 60% 12 Note: Based on 65 contracted rigs. All charts represent total 127 rig fleet.
Margins / DayRates ($) Average Dayrates and Margins (1) $20,000 90 $15,000 $10,000 $5,000 60 30 Average Number of Rigs Utilized $0 2009 2010 2011 2012 Q1 2013 0 Margins Day Rates Rigs Utilized 13 (1) Margins are before elimination of intercompany rig profit.
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% Utilization Percentage (51% as of 6/4/13) 40% 60% 31 of 45 working 80% 100% Number of Rigs: 31 38 45 7 71% 6 82 rigs equipped with integrated top drives Average Depth Capacity: 16,724 feet 14
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 Conscience Dual-fuel capable engines Compact location footprint 15
Mid-Stream Core Operations Granite Wash 29,000 dedicated acres 1 processing facility 135 MMcf/d processing capacity 308 miles of gathering pipeline $12MM capital budget for 2013 Mississippi Lime 875,000+ dedicated acres 7 processing facilities 168 MMcf/d processing capacity* 477 miles of gathering pipeline $34.5MM capital budget for 2013 Pittsburgh Mills Hemphill Reno Bellmon Central & Eastern OK 197,000+ dedicated acres 497 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 23 miles of gathering pipeline Segno East Texas 41 Miles of gathering pipeline Processing facilities Gathering systems Indicates Company Headquarters in Tulsa, Oklahoma Indicates Regional office in Pittsburgh, Pennsylvania *Includes 28 MMcf/d from Reno, which will be operational in Q3 16
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 Q1 2012 Q1 2013 0 2009 2010 2011 2012 Q1 2012 Q1 2013 Contract Mix (Based on Volume) (1) 2012 Q1 2013 Contract Mix (Based on Operating Margin) (1) 2012 Q1 2013 POI 2% POP 59% Fee Based 39% POP 52% POI 2% Fee Based 46% POI 6% POP 69% Fee Based 25% POI 6% Fee Based 25% POP 69% 17 (1) POP represents percent of proceeds. POI represents percent of index.
Midstream Segment 2013 Outlook Mississippian Reno County, KS: 28 MMcf/d Cryogenic Plant (Q3 2013) Mississippian Bellmon: 60 MMcf/d Cryogenic Plant (Q4 2013) Marcellus pipeline expansions 164 expected well connects in 2013 Consistent growth through greenfield construction of pipelines and processing plants in unconventional resource basins 18
Balance Sheet Summary Total Assets 3,814.8 3,761.1 Long-Term Debt 3/31/13 12/31/12 (In Millions) Senior Subordinated Notes 645.4 645.3 Bank Facility 70.0 71.1 Total Long-Term Debt 715.4 716.4 Shareholders Equity 2,010.0 1,974.3 Credit Line Undrawn 430.0 428.9 Long-Term Debt to Total Capitalization 26% 27% 19
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 $70.0 million Maturity September 2016 20 (1) As of March 31, 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 60,000 40,000 $4.24 6,000 4,000 $91.16 20,000 2,000 0 2013 2014 0 2013 2014 21
Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,400 $1,315 $800 $1,200 $1,208 $602 $657 $1,000 $800 $707 $871 $600 $400 $373 $441 $600 $400 $319 $200 $148 $200 $0 2009 2010 2011 2012 Q1 2013 $0 2009 2010 2011 2012 Q1 2013 Oil and Natural Gas Contract Drilling Midstream 22 (1) See appendix for adjusted EBITDA reconciliation.
Adjusted Earnings per Share (1) $7.00 $6.00 $5.00 $4.00 $4.05 $4.16 $3.00 $2.00 $2.55 $3.08 $1.00 $1.12 $0.92 $0.00 2009(1) 2010 2011 2012(1) Q1 2012 Q1 2013 23 (1) See appendix for adjusted EPS 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
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. 25
Non-GAAP Financial Measures Adjusted EBITDA Three months ended March 31, ($ in Millions) 2012 2013 2009 2010 Years ended December 31, Net Income $52 $40 ($56) $146 $196 $23 Income Taxes 33 25 (32) 91 123 16 Depreciation, Depletion and Amortization 79 77 177 205 281 319 Impairment of Oil and Natural Gas Properties - - 281 - - 284 Interest Expense 2 4 1-4 14 (Gain) loss on unrealized value of commodity derivatives (7) (2) (2) 1 2 (1) Adjusted EBITDA $173 $148 $373 $441 $602 $657 2011 2012 Unit Petroleum Income Before Income Taxes (1) $48 $59 ($121) $176 Depreciation, Depletion and Amortization 52 52 115 119 Impairment of Oil and Natural Gas Properties - - 281 - Adjusted EBITDA $100 $111 $275 $295 Unit Drilling Income Before Income Taxes (1) $43 $24 $51 $60 Depreciation and Amortization 21 17 45 70 Adjusted EBITDA $64 $41 $96 $130 Superior Pipeline Income Before Income Taxes (1) $5 $1 $5 $17 Depreciation and Amortization 5 7 16 15 Adjusted EBITDA $10 $8 $21 $32 $200 183 - $383 $135 80 $215 $17 16 $33 ($77) 211 284 $418 $159 81 $240 $6 24 $30 (1) Does not include allocation of G&A expense.
Reconciliation of Adjusted Net Income and Diluted Earnings Per Share Three months ended March 31, Years ended December 31, ($ in Millions) 2012 2013 2009 2010 2011 2012 Adjusted Net Income: Net income $ 52.4 $ 40.2 $ (55.5) $ 146.4 $ 195.9 $ 23.2 Eliminate: Unrealized value of commodity derivatives gain (loss) (1.2) (4.3) (1.2) 0.6 1.5 (0.7) Impairment of oil and natural gas properties - - (175.1) - - (176.6) Adjusted net income $ 53.6 $ 44.5 $ 120.8 $ 145.8 $ 194.4 $ 200.5 Adjusted Diluted Earnings Per Share: Diluted earnings per share $ 1.09 $ 0.83 $ (1.18) $ 3.09 $ 4.08 $ 0.48 Eliminate: Unrealized value of commodity derivatives gain (loss) (0.03) (0.09) (0.03) 0.01 0.03 (0.01) Impairment of oil and natural gas properties - - (3.70) - - (3.67) Adjusted diluted earnings per share $ 1.12 $ 0.92 $ 2.55 $ 3.08 $ 4.05 $ 4.16