US Capital Advisors E&P Corporate Access DayMarchand Horizontal Producer Marchand Vertical Producer...
Transcript of US Capital Advisors E&P Corporate Access DayMarchand Horizontal Producer Marchand Vertical Producer...
NYSE: UNT
US Capital AdvisorsE&P Corporate Access Day
January 12, 2017
NYSE: UNT
Forward Looking Statement
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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 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.
NYSE: UNT
Unit Corporation: A Diversified Energy Company
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Casper Casper
Houston Houston
Oklahoma City
Oklahoma City
PittsburghPittsburgh
Tulsa HeadquartersTulsa HeadquartersArkoma Basin
Marcellus
North La/ East Texas Basin
Gulf Coast Basin
Anadarko Basin
Permian Basin94 Unit Rigs
E&P Operations
Mid‐Stream Operations
Office Location
• Tulsa based, incorporated in 1963
• Integrated approach to business allows Unit to capture margin from each business segment
NYSE: UNT
Setting the Stage for 2017
We have weathered many cycles during our 50+ year history
Maintain spending within cash flow Resume E&P drilling program Use cash flow to drill new wells Continue to manage costs
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NYSE: UNT
2016 Highlights
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$165 million anticipated 2016 capital expenditures – well within budget range of $161 millionto $187 million.
Exploration & Production 2015 year end total proves reserves: 811 Bcfe or 135 MMBoe
Wilcox Q3 production averaged 90 MMcfe per day – for 2016, completed 4 horizontal wells, 10 behind pipe recompletions, and 7 workovers
Granite Wash (Buffalo Wallow) Dixon 5554 XL #1H well during the first 250 days has cumulative production of approximately 50% greater than the projected type curve.
Beginning to put rigs back into service in Q4 – one currently in SOHOT and one in Granite Wash before year end
Drilling All nine BOSS rigs operating under contract
Increased number of rigs in service from a low of 13 to 22, a 69% increase
Continue to upgrade SCR rigs with new technology
Midstream Connected two wells pads to Pittsburgh Mills gathering system in Butler County, Pennsylvania (151 MMcf per day
average daily Q3 throughput volume)
Completed Snow Shoe gathering system in Centre County, Pennsylvania (11 MMcf per day average Q3 throughput volume)
Q3 year over year gathering volumes increased 20%
NYSE: UNT
Senior Subordinated Notes
$650 million, 6.625%
10‐year, NC5; maturity 2021
Key Covenants Interest coverage ratio ≥ 2.25x(1)
Secured Bank Facility (Amended October 2016) * Elected Commitment
and Current Borrowing Base $475 million
Outstanding(2) $215.0 million
Maturity April 2020
Key Covenants Current ratio ≥ 1.0 to 1.0(1)
Senior Indebtedness ratio ≤ 2.75(1)
Debt Structure – No Near‐Term Maturities
6(1) As defined in Indenture/Credit Agreement.(2) As of September 30, 2016. * Drilling rigs are not included in borrowing base.
Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes B+ B3 BB‐
9/30/20164.60x(1,2)
9/30/2016 Actual2.70x(1,2)
0.85x(1,2)
NYSE: UNT
Core Upstream Producing Areas
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Gas54%
29%NGLs
9 Mos. ‘16 Daily Production: 48 MBoe/d
Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)
Mid‐Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle)
Mid Continent Region
Upper Gulf Coast Region
Wilcox
SOHOTGranite Wash
0102030405060
2011 2012 2013 2014 2015 9 mos.2016
Natural Gas Oil / NGLs
82 80 91 121 8
Average Production (MBoe/d)
3339 46 4850 55
35Net Wells Drilled:
17%Oil
NYSE: UNT
“D”
“F‐1”
“E”
“A"
“A‐1”
“A‐2”
“B”
“C”
“C‐1”
“F”
“G”
Buffalo Wallow Field – Granite Wash Stacked Pay
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Dixon 5554 XL #1H
Gross Thickness = 2,273 Feet
* Shaded intervals have been tested horizontally
Vertical well
NYSE: UNT
Granite Wash Extended Length Laterals (~7,500’)
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500
1,000
1,500
2,000
2,500
0 50 100 150 200 250 300
Cumulative Prod
uctio
n (M
MCFE)
Days
1 1/3/2017 Strip Price Deck with 1st Production Starting 1/1/2017;See Q1 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html).
2 ROR calculation includes midstream margin.
Projected Type Curve (C1)7.9 Bcfe EUR
Dixon 5554 XL #1H (C1)9 – 12 Bcfe EUR
Buffalo Wallow Prospect 7,000 contiguous net acres Operated and ~90% HBP Average working interest ~ 95% 190 ‐ 240 potential XL locations (11 Granite Wash lenses) Resumed drilling activity in December 2016
Projected Type Curve (C1 Lense) 18‐22 locations Gross EUR 7.9 Bcfe Well cost $6.0 MM ROR1: ≈64% ROR1,2: ≈94% Dixon 5554 XL #1H (C1) is 1st7,500’ lateral in Buffalo Wallow
NYSE: UNT
Hoxbar (Marchand Sand)
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H O X B A R 3 , 0 0 0 ’
Harper 1‐19HIP30: 2,467 Boe/d
1/15
Rosey 1H IP30: 1,483 Boe/d
9/14
Powers 1‐15HIP30: 1,233 Boe/d
12/14
Norris 1‐28HIP30: 950 Boe/d
3/16
Earl 2‐30HIP30: 1,817 Boe/d
8/14
GB 1‐30H IP30: 1,367 Boe/d
3/14
Brown 1‐11HIP30: 867 Boe/d
1/15
Schenk 17‐2HIP30: 450 Boe/d
2/16
McGuffin 1‐19HIP30: 930 Boe/d
1/16
Marchand Horizontal ProducerMarchand Vertical Producer
Riley 1‐34HIP30: 720 Boe/d
4/16
Hoxbar Marchand Core Area EUR ~ 550 MBoe Well cost ~ $5.0 MM 83% liquids (68% oil) 55‐65 locations with average
working interest of 40‐45% Working interest will increase
through poolings ROR1 > 100% Resumed drilling in Q4 2016 Seven wells planned for 2017
Future Growth Seeking approval from OCC
to drill Hoxbar extended laterals
Kicked off waterfloodfeasibility study in Q4 2016
Waterflood offers a significant upside potential
1 1/3/2017 Strip Price Deck with 1st Production Starting 1/1/2017;See Q1 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html).
NYSE: UNT
Wilcox (Southeast Texas)
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Overall Wilcox Highlights Drilled 157 operated wells since 2003
(150 vertical, 7 horizontal) Program ROR > 100% Operated with working interest ~ 92% Production: ~ 90 MMcfe/d (42% liquids) Resuming drilling activity in Jan. 2017JASPER
POLK
3D AREA494 mi.²
HARDIN
Prior Years DrillingHorizontal Wells
TYLER
Gilly Field
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2012 2013 2014 2015 2016 est.
Gas Oil NGLs
Wilcox Annual ProductionBcfe
Gilly Field – World Class Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 94 Bcfe Average EUR of 10‐20 Bcfe per well Typical well cost ~ $6 MM ROR > 100%
Future Growth Over 100 stacked pay recompletions and
workovers to do in existing wells Two exploration areas to test in 2017 Generating new exploration ideas using
165 square miles of 3‐D data
NYSE: UNT
Gilly Field Wilcox Cross Section
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Temporarily Abandoned Perforations Current Production
Future Behind Pipe Recompletions 2016 YTD Q3 Behind Pipe Recompletions 2017 1st Half Behind Pipe Recompletions
ParkerGU #1
Parker#4
Parker#2
Gilly Field Gilly DT
BS R #4BS O #3
NYSE: UNT
YTD 2016 Wilcox BPR & Workover Results
Composite Gross Production from BPRs and Workovers10 BPRs & 7 Workovers Total Cost: $7.1 MM
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Start of Year3,360 mcfd80 bopd
End of Q330,920 mcfd1,280 bopd
* BPR: Behind Pipe Recompletion
NYSE: UNT
Rig Fleet Presence in Key Regions
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10
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Area # of RigsAnadarko Basin 10
Bakken 3Niobrara 1Permian 5Pinedale 2Wilcox 1Total 22
Current Rigs Operating(1)
94 rig fleet
69% electric 56% 1,500 HP or greater 94 equipped with top drives 59 equipped with skidding or walking systems
17% total fleet utilization rate for Q3 2016 Nine BOSS rigs operating under contract
20 ≤800 HP: 21%70 1,000‐1,700 HP: 75%4 ≥2,000 HP: 4%
(1) As of January 10, 2017.
NYSE: UNT
Average Dayrates and Margins (1)
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Average Rig Utilization
Margins and
Dayrates
$0
$5,000
$10,000
$15,000
$20,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 9 mos.'16
Margins Dayrates Average Rig Utilization
100%
75%
50%
25%
0%
(1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix(also available at www.unitcorp.com/investor/reports.html).
NYSE: UNT
The BOSS Drilling Rig
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Optimized for Pad Drilling Multi‐direction walking system
Faster Between Locations Quick assembly substructure 32‐34 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
NYSE: UNT
Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Connected 24 new wells in2016
Midstream Core Operations
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TulsaHeadquarters
PittsburghRegional office
Hemphill
Reno
Bellmon
Segno
Pittsburgh Mills
Processing facilities
Gathering systems
Panola
Key Metrics
• 26 active systems
• Three natural gas treatment plants
• 343 MMcf/d processing capacity
• Q3’16 processing volume 153 MMcf/d
• Approx. 1,460 miles of pipeline
East Texas 62 Miles of gathering pipeline 120 MMcf/d gathering capacity
Texas Panhandle 52,000 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 572 miles of gathering pipeline
Central & Eastern OK 57,000+ dedicated acres 15 MMcf/d processing capacity 428 miles of gathering pipeline
Brook Field
Snow Shoe
Bruceton Mills
NYSE: UNT
Midstream Segment Contract Mix
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Contract Mix Based on Margin
Fee BasedCommodity Based
85%30%
70%
15%
Contract Mix Based on Volume
Fee BasedCommodity Based
49%23%
77%51%
2010 Q3 2016
Unit vs. 3rd Party Margin Contribution
3rd PartyUnit
41% 37%63%59%
NYSE: UNT
Appalachian Growth Projects
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Snow Shoe Gathering System in Centre County, PA
– First flow in January 2016– Six wells currently connected to
this system– Average gathering volumes were
11 MMcf/d in Q3 2016
Pittsburgh Mills gathering system in Butler County, PA
– Connected 6 new wells in Q3 2016– Total of 18 wells connected to this
system in 2016– Received notice to connect a new
well pad mid‐2017– Average gathered volumes were
151 MMcf/d in Q3 2016
A P P A L A C H I A N P R O J E C T S
NYSE: UNT
Segment Contribution
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Oil and Natural Gas Contract Drilling Midstream
Revenues ($ millions) Adjusted EBITDA ($ millions)(1)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2012 2013 2014 2015 9 mos. 2016
$0
$200
$400
$600
$800
2012 2013 2014 2015 9 mos. 2016
$1,352
$1,573
$854
$428
$1,315
$787
$410
$170
$679 $667
(1) See Non‐GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html).
NYSE: UNT
Operating Segment Capital Expenditures
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$0
$500
$1,000
$1,500
2011 2012 2013 2014 2015 2016 Low EndBudget
2016 High EndBudget
Oil and Natural Gas Contract Drilling Midstream Acquisitions
(In Millions)
NYSE: UNT 22
APPENDIX
NYSE: UNT
Non‐GAAP Financial Measures ‐ Corporate
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Adjusted EBITDA
Years ended December 31,($ In Millions) 2016 2012 2013 2014 20152015
Nine months ended September 30,Q3 LTM
Net Income (Loss) ($728) ($137) $23 $185 $136 ($1,037) ($446)Income Taxes (439) (73) 16 117 87 (627) (261)Depreciation, Depletion and Amortization 280 160 319 334 405 355 235
Impairments 1,149 161 284 0 158 1,635 647 Interest Expense 23 30 14 15 17 32 39 (Gain) loss on derivatives (13) 5 1 8 (30) (26) (8)Settlements during the period of matured derivative contracts 32 12 0 (2) (6) 47 27
Stock compensation plans 13 11 17 22 24 21 19 Other non‐cash items 3 2 5 5 5 3 2 (Gain) loss on disposition of assets 6 (1) 0 (17) (9) 7 0 Adjusted EBITDA $326 $170 $679 $667 $787 $410 $254
NYSE: UNT
Unit PetroleumIncome (Loss) Before Income Taxes (1) $ (1,163) $ (137) $ (77) $ 239 $ 199 $ (1,631)
Depreciation, Depletion and Amortization 202 89 211 226 276 252Impairment of Oil and Natural Gas Properties 1,141 162 284 ‐ 77 1,599
Adjusted EBITDA $ 180 $ 114 $ 418 $ 465 $ 552 $ 220
Unit DrillingIncome (Loss) Before Income Taxes (1) $ 41 $ (12) $ 159 $ 96 $ 42 $ 45
Depreciation and Impairment 51 34 81 71 160 64Adjusted EBITDA $ 92 $ 22 $ 240 $ 167 $ 202 $ 109
Superior PipelineIncome (Loss) Before Income Taxes (1) $ (1) $ (1) $ 6 $ 11 $ 2 $ (30)
Depreciation, Amortization and Impairment 33 34 24 33 48 71Adjusted EBITDA $ 32 $ 33 $ 30 $ 44 $ 50 $ 41
(1) Does not include allocation of G&A expense.
Non‐GAAP Financial Measures ‐ Segments
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Adjusted EBITDAYears ended December 31,
($ In Millions) 2016 2012 2013 2014 20152015Nine months ended September 30,
NYSE: UNT
Non‐GAAP Financial Measures
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Reconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense
Years ended December 31,(In thousands except for operating daysand operating margins) 2016 2012 2013 2014 20152015
Nine months ended September 30,
Contract drilling revenue $215,114 $88,786 $529,719 $414,778 $476,517 $265,668
Contract drilling operating cost 123,717 66,489 289,524 247,280 274,933 156,408
Operating profit from contract drilling $91,397 $22,297 $240,195 $167,498 $201,584 $109,260
Add:
Elimination of intercompany rig profit and bad debt expense 3,666 235 15,583 17,416 29,343 3,991
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
95,063 22,532 255,778 184,914 230,927 113,251
Contract drilling operating days 10,175 4,578 26,704 23,720 27,516 12,681
Average daily operating margin before elimination of intercompany rig profit and bad debt expense
$9,343 $4,922 $9,578 $7,796 $8,392 $8,931
NYSE: UNT 26
Non‐GAAP Financial MeasuresReconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense
Years ended December 31,2007 2008 2009 2011
(In thousands except for operating daysand operating margins)
Contract drilling revenue $699,396 $627,642 $622,727 $236,315 $316,384 $484,651
Contract drilling operating cost 313,882 304,780 312,907 140,080 186,813 269,899
Operating profit from contractdrilling $385,514 $322,862 $309,820 $96,235 $129,571 $214,752
Add:
Elimination of intercompany rig profit and bad debt expense 22,239 24,449 29,381 1,549 9,158 19,900
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
407,753 347,311 339,201 97,784 138,729 234,652
Contract drilling operating days 39,798 36,299 37,745 14,183 22,367 27,619
Average daily operating margin before elimination of intercopmany rig profit and bad debt expense
$10,246 $9,568 $8,987 $6,894 $6,202 $8,496
2006 2010
NYSE: UNT
Derivative Summary
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Crude 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
CollarsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling ‐‐ ‐‐ ‐‐ ‐‐
3‐Way CollarsVolume (Bbl) 337,500 341,250 345,000 345,000Weighted Avg Floor $49.79 $49.79 $49.79 $49.79 Weighted Avg Subfloor $39.58 $39.58 $39.58 $39.58 Weighted Avg Ceiling $60.98 $60.98 $60.98 $60.98
SwapsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Swap ‐‐ ‐‐ ‐‐ ‐‐
Natural Gas 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
CollarsVolume (MMBtu) 1,800,000 1,820,000 1,840,000 620,000 Weighted Avg Floor $2.88 $2.88 $2.88 $2.88 Weighted Avg Ceiling $3.10 $3.10 $3.10 $3.10
3‐Way CollarsVolume (MMBtu) 1,350,000 1,365,000 1,380,000 1,380,000 900,000Weighted Avg Floor $2.50 $2.50 $2.50 $2.50 $3.25Weighted Avg Subfloor $2.00 $2.00 $2.00 $2.00 $2.50Weighted Avg Ceiling $3.32 $3.32 $3.32 $3.32 $4.43
SwapsVolume (MMBtu) 6,300,000 5,460,000 5,520,000 5,520,000 900,000 910,000 920,000 920,000 Weighted Avg Swap $3.04 $2.96 $2.96 $2.96 $3.03 $3.03 $3.03 $3.03
NYSE: UNT 28
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+
2017 $57.086 $3.434 $0.242 $0.741 $31.130 $1.239 $1.098 $1.257 $0.226 $0.743 $1.116 $1.200 $1.286
2018 $56.896 $3.082 $0.217 $0.739 $31.027 $1.235 $1.095 $1.252 $0.203 $0.740 $1.112 $1.196 $1.282
2019 $56.170 $2.862 $0.202 $0.729 $30.631 $1.219 $1.081 $1.236 $0.188 $0.731 $1.098 $1.180 $1.265
2020 $56.103 $2.877 $0.203 $0.728 $30.595 $1.218 $1.080 $1.235 $0.189 $0.730 $1.097 $1.179 $1.264
2021 $56.250 $2.905 $0.205 $0.730 $30.675 $1.221 $1.082 $1.238 $0.191 $0.732 $1.099 $1.182 $1.267
Thereafter $56.250 $2.905 $0.205 $0.730 $30.675 $1.221 $1.082 $1.238 $0.191 $0.732 $1.099 $1.182 $1.267
Q1 2017 Economic Prices
NYSE: UNT
US Capital AdvisorsE&P Corporate Access Day
January 12, 2017