Raymond James Institutional Investors Conference March 8, 2016

Transcription

1 Raymond James Institutional Investors Conference March 8, 2016

2 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 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

3 Unit Corporation: A Diversified Energy Company 12 Tulsa based, incorporated in Integrated approach to business allows Unit to capture margin from each business segment Casper Anadarko Basin 54 Tulsa Headquarters Arkoma Basin Marcellus Pittsburgh 94 Unit Rigs Permian Basin 12 Oklahoma City 6 North La/ East Texas Basin E&P Operations Mid Stream Operations Office Location Houston Gulf Coast Basin 3

4 We Are Focused on 2016 and Beyond We have weathered many cycles during our 50+ year history Balance sheet preservation is key Spending within cash flow Reduce debt with excess cash flow Manage costs 4

5 2015 Statistics (1) As of 12/31/2015. Exploration & Production Attained record annual production of 20 MMBoe, a 9% increase year over year Liquids production grew 7% year over year Proved reserves: 135 MMBoe (1) Drilling Eight BOSS rigs placed into service; seven under contract 94 drilling rig fleet Mid Stream 13% increase in daily natural gas processing volumes in % increase in daily gathered volumes in 2015 Approximately 1,464 miles of pipeline 5

6 Segment EBITDA Margins (1) in Line with Pure Play Peers 90% 80% 70% EBITDA Margins 60% 50% 40% 30% 20% 10% 0% Oil and Gas Contract Drilling Midstream E&P Company Peer Average Land Drilling Peer Average Midstream Peer Average (1) See Segment EBITDA Margins in Appendix (also available at Source: E&P: CRK, EGN, NBL, NFX, QEP, SGY, SM, XEC; Contract Drilling: HP, ICD, NBR, PES, PKD, PTEN; Midstream: BPL, DPM, ENLK, EPD, ETE, ETP, MMLP, PAA, PAGP, RRMS, SXL 6

7 Debt Structure No Near Term Maturities Senior Subordinated Notes $650 million, 6.625% 10 year, NC5; maturity 2021 Ratings S&P Moody s Fitch Corporate B+ B2 BB Senior Subordinated Notes B+ B3 BB Key Covenants Coverage ratio 2.25x (1) Actual ratio 7.17x (1,2) Unsecured Bank Facility Current Borrowing Base Elected Commitment Outstanding (2) $550 million $500 million $281.0 million Maturity April 2020 Key Covenants Current ratio 1.0 to 1.0 (1) Actual ratio 2.30x (1,2) (1) As defined in Indenture/Credit Agreement (2) As of December 31, 2015 Leverage ratio 4.0 (1) Actual ratio 2.58x (1,2) 7

8 Core Upstream Producing Areas Mid Continent Region Granite Wash SOHOT Upper Gulf Coast Region Wilcox Key focus areas include: Gulf Coast: Wilcox (Southeast Texas) Mid Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle) $109 Million 2016 Capital Budget D & C Spending: $42 Million 2015 Daily Production: 54.7 MBoe/d G & G $17 MM Capitalized/Other $16 MM Land & Seismic $10 MM Workover $24 MM D & C $42 MM 33% Hoxbar Other 6% Granite Wash 18% 43% Wilcox Oil 19% NGL 26% Gas 55% 8

9 Historical and Projected Production Average Production (MBoe/d) est. Natural Gas Oil / NGLs Prod. Range Net Wells Drilled: est. 9

10 Wilcox (Southeast Texas) POLK TYLER Overall Highlights Year End 2015: Drilled 153 operated wells since 2003 (150 vertical, 3 horizontal) 92% average working interest Q4 15 net avg. production: 88 MMcfe/d 42% liquids (12% oil) Historical ROR: 108% Gilly Field 3D AREA 494 mi.² JASPER Average 2015 LOE down 19% to $0.91/Mcfe 2016 Activity: HARDIN Complete 4 horizontal Wilcox wells Prior Years Drilling Horizontal Wells Complete 8 10 behind pipe recompletions Identified 2 new Wilcox project areas Acquired 165 square mile 3 D data Currently leasing

11 Gilly Field Cross Section Allar GU #1 A 3.8 miles A Lower Wilcox 91 Mcfed *Feb. 16 Exit Rate Temporarily Abandoned Perforations Current Production Future Behind Pipe Recompletions

12 Allar GU #1 Summary Recomplete to Lower Gilchrease B sd. Tubing & Packer Installation Recompletion to Lower Gilchrease B Sand Production increased from 15 Bopd and 445 Mcfd to 300 Bopd and 5,700 Mcfd AOF Potential: MMcfd 1,200 1,300 Bopd Economics AFE: $500,000 Est. Actual: $690,000 Net PW10: $8.5 million WI: % RI: 75.27% 12

13 Hoxbar (Marchand Sand) Marchand Core Case: EUR: 530 MBoe* Extensional Area Brown 1 11H IP30: 867 Boe/d 1/15 Harper 1 19H IP30: 2,467 Boe/d 1/15 IP30: 802 Boe/d* Well cost: $4.9 million ROR: 30% Rosey 1H IP30: 1,483 Boe/d 9/14 Schenk 18H IP30: 700 Boe/d 6/15 Earl 2 30H IP30: 1,817 Boe/d 8/14 H O X B A R 3, % liquids (72% oil) core operated locations 50% average working interest core non operated locations 35% average working interest 2016 Marchand Activity: Marchand Horizontal Producer Marchand Vertical Producer Powers 1 15H IP30: 1,233 Boe/d 12/14 GB 1 30H IP30: 1,367 Boe/d 3/ rig 4 horizontal wells *Q Strip Price Deck with 1 st Production Starting 1/1/2016; see Q Economic Prices in Appendix (also available at * 24 total operated and nonoperated wells. 13

14 Expertise in Areas of Operations $16 Unit has experienced management and operating teams and is a leader in minimizing operating expenses Operating Expense / Boe (1) $12 $8 $4 Average: $9.64 $0 Peer 1 Peer 2 Unit Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 (1) Data in table is as of Q Source: CRK, EGN, NFX, NBL, QEP, SGY, SM, XEC 14

15 Significant Drilling Presence in Attractive Producing Regions 94 rig fleet HP: 21% 70 1,000 1,700 HP: 75% 4 2,000 HP: 4% 69% electric 56% 1,500 HP or greater 94 equipped with top drives 58 equipped with skidding or walking systems Niobrara Bakken 29% total fleet utilization rate for Q Eight BOSS placed into service; seven under contract Area # of Rigs Anadarko Basin 7 Bakken 3 Granite Wash 3 Permian 3 Niobrara 3 Wilcox 1 Total 20 Granite Wash Permian Anadarko Wilcox 15

16 Average Dayrates and Margins (1) $20, % $15,000 75% Margins and Dayrates $10,000 50% Average Rig Utilization $5,000 25% $ % Margins Dayrates Average Rig Utilization (1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix (also available at 16

17 The BOSS Drilling Rig Optimized for Pad Drilling Multi direction walking system Faster Between Locations Quick assembly substructure 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 17

18 Midstream Core Operations Brook Field Texas Panhandle 50,100 dedicated acres 135 MMcf/d processing capacity 343 miles of gathering pipeline Northern Oklahoma and Kansas 1,972,000+ dedicated acres 193 MMcf/d processing capacity 567 miles of gathering pipeline Pittsburgh Mills Pittsburgh Regional office Bruceton Mills Snow Shoe Hemphill Reno Bellmon Tulsa Headquarters Central & Eastern OK 54,400+ dedicated acres 12 MMcf/d processing capacity 443 miles of gathering pipeline Appalachia 66,000+ dedicated acres 49 miles of gathering pipeline Snow Shoe completed Jan Panola East Texas 62 Miles of gathering pipeline Segno Key Metrics 25 Active Systems Three Natural Gas Treatment Plants 340 MMcf/d Processing Capacity Approx. 1,464 miles of Pipeline Processing facilities Gathering systems 18

19 Midstream Segment Contract Mix Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 32% 68% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 35% 65% Unit vs. 3 rd Party Margin Contribution 41% 59% 3 rd Party Unit 42% 58% 19

20 Appalachian Growth Projects A P PA L A C H I A N P R O J E C T S Completed construction of Snow Shoe Gathering System in Centre County, PA in Q First flow in January 2016 Signed contract with new producer to connect wells in Q Expansion of Pittsburgh Mills gathering system into Butler County, PA Completed construction of compression station in Q Connected new well pad in Feb Three additional well pads scheduled for connection in 2016 (one in March; two in July) 20

21 Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,600 $1,573 $800 $758 $1,400 $1,200 $1,208 $1,315 $1,352 $600 $603 $657 $640 $1,000 $800 $854 $400 $385 $600 $400 $200 $200 $ $ Oil and Natural Gas Contract Drilling Midstream (1) See Non GAAP Financial Measures in Appendix (also available at 21

22 Operating Segment Capital Expenditures (In Millions) $1,500 $1,000 $500 $ Low End Budget Oil and Natural Gas Contract Drilling Midstream Acquisitions 2016 High End Budget 22

23 APPENDIX 23

24 Segment EBITDA Margin December 31, Revenues Oil and Gas (Including Cash Flow Derivatives Settled) $318,208 $357,599 $391,480 $552,696 $362,245 $399,771 $514,614 $567,944 $649,718 $740,079 $385,774 Drilling $462,141 $699,396 $627,642 $622,727 $236,315 $316,384 $484,651 $529,719 $414,778 $476,517 $265,668 Gas Gathering $100,464 $101,863 $138,595 $181,730 $108,628 $154,516 $208,238 $217,460 $287,354 $356,348 $202,789 Derivatives Settled (Non designated) $0 $0 $0 $0 ($2,422) $0 ($711) $0 ($1,764) ($6,038) $46,615 Expenses Oil and Gas Operating cost $60,779 $81,120 $97,109 $116,239 $87,734 $105,365 $131,271 $150,212 $184,001 $187,916 $166,046 DDA $67,282 $108,124 $127,417 $159,550 $114,681 $118,793 $183,350 $211,347 $226,498 $276,088 $251,944 Impairment $0 $0 $0 $281,966 $281,241 $0 $0 $283,606 $0 $76,683 $1,599,348 Drilling Operating cost $266,472 $313,882 $304,780 $312,907 $140,080 $186,813 $269,899 $289,524 $247,280 $274,933 $156,408 Depreciation and impairment $42,876 $51,959 $56,804 $69,841 $45,326 $69,970 $79,667 $81,007 $71,194 $159,688 $64,449 Gas Gathering and Processing Operating Cost $92,467 $88,834 $119,776 $150,466 $87,908 $122,146 $174,859 $187,292 $243,406 $306,831 $161,556 Depreciation, amortization, and impairment $3,279 $6,247 $11,059 $14,822 $16,104 $15,385 $16,101 $24,388 $31,191 $47,502 $70,642 G&A $14,343 $18,690 $22,036 $25,419 $24,011 $26,152 $30,055 $33,086 $38,323 $42,023 $35,415 G&A Allocation Oil and Gas $5,182 $5,767 $7,451 $10,366 $12,226 $12,025 $12,833 $14,288 $18,419 $19,772 $15,962 Drilling $7,525 $11,280 $11,947 $11,652 $8,073 $9,492 $12,046 $13,327 $11,758 $12,731 $10,992 Gas Gathering $1,636 $1,643 $2,638 $3,400 $3,711 $4,636 $5,176 $5,471 $8,146 $9,520 $8,391 EBITDA Margin Oil and Gas 79% 76% 73% 77% 72% 71% 72% 71% 69% 72% 53% Drilling 41% 54% 50% 48% 37% 38% 42% 43% 38% 40% 37% Gas Gathering 6% 11% 12% 15% 16% 18% 14% 11% 12% 11% 16% 24

25 Non GAAP Financial Measures Adjusted EBITDA ($ in Millions) Net Income (Loss) Income Taxes Depreciation, Depletion and Amortization Impairments Interest Expense (Gain) loss on derivatives not designated as hedges and hedge ineffectiveness Settlements during the period of matured derivative contracts (Gain) loss on disposition of assets 2011 $ $ (2) 1 Years ended December 31, 2013 $ (2) (6) 1 (17) (9) Adjusted EBITDA $603 $657 $640 $ $ (30) 2015 $(1,037) (627) 355 1, (26) 46 7 $385 Unit Petroleum Income (Loss) Before Income Taxes (1) Depreciation, Depletion and Amortization Impairment of Oil and Natural Gas Properties EBITDA $ $383 ($77) $418 $ $465 $ $552 $(1,631) 252 1,599 $220 Unit Drilling Income Before Income Taxes (1) Depreciation and Impairment EBITDA $ $215 $ $240 $96 71 $167 $ $202 $45 64 $109 Superior Pipeline Income Before Income Taxes (1) Depreciation, Amortization and Impairment EBITDA $17 16 $33 $6 24 $30 $11 33 $44 $2 48 $50 $(30) 71 $41 (1) Does not include allocation of G&A expense. 25

26 Non GAAP Financial Measures Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense (In thousands except for operating days Years ended December 31, and operating margins) Contract drilling revenue $ 484,651 $ 529,719 $ 414,778 $ 476,517 $ 265,668 Contract drilling operating cost 269, , , , ,408 Operating profit from contract drilling 214, , , , ,260 Add: Elimination of intercompany rig profit and bad debt expense 19,900 15,583 17,416 29,343 3,991 Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 234, , , , ,251 Contract drilling operating days 27,619 26,704 23,720 27,516 12,681 Average daily operating margin before elimination of intercompany rig profit and bad debt expense $ 8,496 $ 9,578 $ 7,796 $ 8,392 $ 8,931 26

27 Derivative Summary Crude Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Subfloor Price Weighted Average Ceiling Price Period Structure Volume Bbl/Day Jan'16 Jun'16 3 Way Collar 700 $46.50 $35.00 $57.00 Jan'16 Jun'16 Collar 2,150 $46.36 $55.62 Jul'16 Dec'16 3 Way Collar 1,400 $47.00 $35.00 $60.25 Jul'16 Dec'16 Collar 1,450 $47.50 $56.40 Jan'17 Dec'17 3 Way Collar 750 $50.00 $37.50 $63.90 Natural Gas Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Subfloor Price Weighted Average Ceiling Price Period Structure Volume MMBtu/Day Jan'16 Swap 35,000 $2.63 Feb'16 Dec'16 Swap 45,000 $2.60 Jan'16 Dec'16 3 Way Collar 13,500 $2.70 $2.20 $3.26 Jan'16 Dec'16 Collar 42,000 $2.40 $2.88 Jan'17 Dec'17 Swap 10,000 $2.795 Jan'17 Dec'17 3 Way Collar 15,000 $2.50 $2.00 $

28 Q Economic Prices February 2, 2016 Strip Case Crude Natural Gas MB C2 MB C3 MB NC4 MB ic4 MB C5+ CW C2 CW C3 CW NC4 CW ic4 CW C5+ 2/16 1/17 Avg. $ $2.316 $0.169 $0.401 $0.602 $0.602 $0.789 $0.160 $0.365 $0.550 $0.674 $ /17 1/18 Avg. $ $2.714 $0.200 $0.424 $0.625 $0.632 $0.983 $0.172 $0.380 $0.595 $0.676 $ /18 1/19 Avg. $ $2.800 $0.206 $0.450 $0.665 $0.672 $1.045 $0.178 $0.404 $0.632 $0.719 $ /19 1/20 Avg. $ $2.890 $0.213 $0.469 $0.692 $0.699 $1.087 $0.183 $0.420 $0.658 $0.748 $ /20 12/20 Avg. $ $3.059 $0.225 $0.475 $0.701 $0.709 $1.102 $0.194 $0.426 $0.667 $0.758 $

29 Raymond James Institutional Investors Conference March 8, 2016