EnerCom s The Oil & Services Conference. February 20, 2013

Transcription

1 EnerCom s The Oil & Services Conference February 20, 2013

2 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 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

3 Key Growth Points Exploration & Production 212% average production replacement since % 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 drilling rig fleet Mid-Stream 1,134% increase in natural gas processing volumes since % increase in daily liquids sold volumes since ,304 miles of pipeline Strong Balance Sheet Remains conservatively financed as the company has grown 3 (1) As of 12/31/2012.

4 Capital Allocation Criteria Unit Petroleum Company Minimum 15% risk-adjusted ROR for new well proposals Unit Drilling Company 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 Superior Pipeline Company Minimum 25% ROR for POP/POI projects Minimum 15% ROR for Fee Based projects 4

5 2012 Highlights Total revenue for 2012: $1.3 billion, a 9% increase over 2011 Adjusted earnings per share for 2012: $4.15 (1), a 2% increase over 2011 Unit Petroleum Company During 2012, oil and natural gas liquids (NGLs) reserves increased by 9% and 59%, respectively; total oil, NGLs, and natural gas reserves increased 29 % Replaced 337% of 2012 production with new reserves Total production for 2012 was 14.2 MMBoe, an increase of 18% over 2011 Completed acquisition of Noble Energy properties in western Oklahoma and Texas Panhandle Completed divestiture of two non-core properties Unit Drilling Company Placed two new build rigs into service Sold a 600 HP mechanical drilling rig Superior Pipeline Company Expanded Hemphill processing plant (Granite Wash) by 45 MMcf/d Completed construction of Bellmon processing system in Mississippian play Expanded Cashion processing facility (central Oklahoma) by 25 MMcf/d 5 (1) See Adjusted EPS reconciliation to EPS.

6 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 46% 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 2012 Daily Production NGL 23% NGL 20% Oil 15% Gas 62% Oil 23% Gas 57% 6 Proved Reserves: 150 MMBoe Daily Production: 38.9 MBoe/d

7 Significant 2012 A&D Activity Unit Corporation acquired certain oil and natural gas properties and related gathering and processing infrastructure located in Western Oklahoma and the Texas Panhandle from Noble Energy Immediately accretive to cash flow per share, and accretive to earnings per share beginning in 2013 Transaction value ~$600 million Timing: Effective April 1, 2012; Completed September 17, 2012 Unit Corporation divested certain non-operated oil and natural gas interests in the McKenzie County, North Dakota Bakken play to QEP Energy Transaction value ~$226 million Timing: Effective July 1, 2012; Completed September 27, 2012 Unit Corporation divested certain non-core oil and natural gas interests in Brazos and Madison Counties in Texas Transaction value ~$44 million Timing: Effective July 1, 2012; Completed September 14,

8 Sale of Bakken Shale Properties 6,040 net acres Net Bakken Acreage Sold: McKenzie Co., ND (4,756) Remaining: Williams Co., ND 2,654 Montana 6,040 Remaining acreage 8,694 2,654 net acres Q4 Ave: 734 Boe/day Bakken Notes McKenzie County, North Dakota position sold during 2012 First well drilled in Sheridan County, Montana Sold 4,756 net acres 2Q Ave: 1,044 Boe/day Unit Acreage Current Drilling Properties Sold Remaining tracts in North Dakota and Montana are non-operated Anticipate sale of remaining Bakken interest within months 8

9 Track Record of Reserve Growth Proved Reserves (MMBoe) CAGR: 15% 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% (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. 9

10 Increasing Production while Improving Commodity Mix Annual Production (MBoe/d) % 55% E Net Wells Drilled: Oil / NGLs Natural Gas Production Range

11 Granite Wash Play Noble acquisition strategic fit with existing UPC leasehold Total 46,000 net acres in the Texas Panhandle Core Area (80% HBP) Approximately 800 potential drilling locations HIGHLIGHTS Production up 41% in 2012 over 2011 Q4 = average net 87 MMcfe per day (46% oil & liquids) Current AFE CWC: $5.3 MM Estimated reserve range: Bcfe Calculated ROR = 49% - 70% (Flat $90 oil, $30 NGL, $3.25 gas) GW Type Log - Buffalo Wallow Field 11,000 +/-200 First sales on 29 GW horizontal wells PLANS 13,400 +/ Unit rigs: First sales on 37 gross wells Estimate capital expenditures $150 million net First Noble well in Q2 11

12 Marmaton Oil Play Total 112,000 net acres in focus area (44% HBP) HIGHLIGHTS Completed 85 operated horizontal wells since 2010 Production up 61% in 2012 over 2011 Q4 = average net 4,248 Boe per day (93% oil & liquids) 150 potential locations on 640 acre spacing Focus Area Estimated reserve range: MBoe per well Current AFE CWC: $2.7 million per well Calculated ROR 80% - 100% (Flat $90 oil, $30 NGL, $3.25 gas) First sales on 32 horizontal wells (includes two extended laterals) in day IP 407 Boe per day for 2012 wells 2013 PLANS 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 12

13 Wilcox Liquids Play WILCOX HIGHLIGHTS Gilly Field Discovery Completed 120 wells since 2003 with 73% success rate Q4 = average net 32 MMcfe per day (42% liquids) 86,000 net acres (51K leasehold 30% HBP, 35K options) Gilly Field Discovery announced July 2012 Total reserve potential = 168 Bcfe net (242 Bcfe gross) Unit Prospect Area Current proved reserves = 30 Bcfe net (18% total) 8% oil, 35% NGL, 57% natural gas Eight Wilcox potential pay zones (3 zones currently producing) Gilly Field Discovery 1,000 Acres Five Gilly Field producing wells Average 255 net potential pay/well Estimated AFE CWC: $5.4 million Run one Unit rig in Wilcox 2013 PLANS Completed wells 2013 wells Future wells 12 gross wells (includes 5 Gilly field development wells / 2 Gilly field step out wells / 5 other prospects) Estimate capital expenditures $60 million net 13

14 Mississippian Play Total 105,000 net acres in focus area Central Kansas Uplift HIGHLIGHTS Mississippian Trend 2013 PLANS Focus Area Initial Well 105,000 Net Acres Mississippian Wells Approximately 300 potential locations (320 acre spacing) Average well depth +/- 8,000 (includes 4,000 lateral) Mississippian pay zone +/- 50 thick Estimated reserve range = 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 Three wells producing, one waiting on pipeline Initial well completed May 2012 Drill 3 wells in Q1 wait on pipeline infrastructure to be built estimate June 2013 completion Resume drilling in July 2013 with one Unit rig and anticipate adding second rig in September 2013 Total depth 8,115 (includes 3,850 lateral) Frac d 11 stages 30 day IP 352 Boe per day (92% oil and liquids) First sales on 13 gross wells 14 Estimate capital expenditures $40 million net

15 Significant Drilling Presence in Attractive Producing Regions 127 rig fleet Casper Office 77 Oklahoma City Office Tulsa Headquarters Fleet average ~1,200 HP rating; ~16,724 ft depth capacity 97% of contracted rigs drilling horizontal wells 58% utilization rate for % of 45 1,200-1,700 HP rigs under contract Refurbished / upgraded 19 rigs in 2011 and 15 rigs in 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% 15 Note: Based on 69 contracted rigs. All charts represent total 127 rig fleet.

16 Average Dayrates and Margins (1) $20, Margins / DayRates ($) $15,000 $10,000 $5, Average Number of Rigs Utilized $ Margins Day Rates Rigs Utilized 16 (1) Margins are before elimination of intercompany rig profit.

17 Diverse and Versatile Rig Fleet h.p ,000 h.p. 1,200-1,700 h.p. 2,000 h.p. >2,500 h.p. 20% Utilization Percentage (53% as of 2/15/13) 40% 60% 34 of 45 working 80% 100% Number of Rigs: % 6 82 rigs equipped with integrated top drives Average Depth Capacity: 16,724 feet 17

18 Superior Pipeline s Core Operations Plants Pipeline systems 18

19 Historical Performance Historical Daily Gathering Volumes (MMBtu / d) NGLs Volumes (Bbl / d) 300,000 15, ,000 10, ,000 5, Contract Mix (Based on Volume) (1) Contract Mix (Based on Operating Margin) (1) POP 52% POI 6% Fee Based 42% POP 59% POI 2% Fee Based 39% POI 29% Fee Based 14% POP 57% POI 6% Fee Based 25% POP 69% 19 (1) POP represents percent of proceeds. POI represents percent of index.

20 Superior 2012 Major Projects Bellmon gathering and processing system in Mississippian play Constructing Pittsburgh Mills gathering system in Pennsylvania Installed a 5 th processing plant at Hemphill facility taking plant capacity to 160 MMBtu/d in Granite Wash Connecting various new wells to new and existing gathering systems 20

21 Balance Sheet Summary 12/31/12 12/31/11 (In Millions) Total Assets 3, ,256.7 Long-Term Debt Senior Subordinated Notes Bank Facility Total Long-Term Debt Shareholders Equity 1, ,947.0 Credit Line Undrawn Long-Term Debt to Total Capitalization 27% 13% 21

22 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- B2 BB- Unsecured Bank Facility Borrowing Base $800 million Elected Commitment $500 million Outstanding $71.1 million Maturity September (1) As of December 31, 2012

23 Hedges Target 50 70% of current year projected oil and natural gas production Anticipate opportunistically adding hedges associated with production from acquired properties Natural Gas Crude Oil MMBtu/d 100,000 $3.63 Bbls/d 10,000 80,000 8,000 $ ,000 6,000 40,000 4,000 $ ,000 2,

24 Segment Contribution Revenues ($ millions) EBITDA ($ millions) (1) $1,400 $1,357 $1,315 $800 $754 $1,200 $1,208 $604 $656 $1,000 $800 $707 $871 $600 $400 $371 $442 $600 $400 $200 $200 $ $ Unit Petroleum Unit Drilling Superior Pipeline 24 (1) See EBITDA reconciliation.

25 Adjusted Earnings per Share (1) $7.00 $6.00 $6.80 $5.00 $4.00 $4.08 $4.15 $3.00 $3.09 $2.00 $2.52 $1.00 $ (1) 2009 (1) (1) 25 (1) See Adjusted EPS reconciliation to EPS.

26 Capital Expenditures (In Millions) $1,500 $1,000 $500 $ Budget Unit Petroleum Unit Drilling Superior Pipeline Acquisitions 26

27 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 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. 27

28