Global Market Outlook
2
Agenda
Setting the Stage
Near-Term Fundamentals
U.S. Land – Why It Will Recover First and the Recovery We Envision Global Recovery
Conclusions
3
Setting the Stage
4
Longer-Term E&P Spending Outlook
Global E&P spending fell by ~30% in 2015 to approximately $560 billion For 2016 we expect spending to decline ~50% in NAM and ~20% Internationally We believe oil services investors should increase exposure to the space ahead of
the bottom in the capex cycle
Source: Company reports, EVR ISI Research
$0
$100
$200
$300
$400
$500
$600
$700
$800
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Rest of the World
Canada
United States
Actual Estimates
5
Global Production Is Declining Our analysis of ~200 companies is mostly derived from company guidance figures Our 2015 y/y production increase of 6.8% for the US is ~150 bps below the official EIA 8.3%
y/y increase which may provide downside (greater declines) to our expected 2-4% North American production decline.
Our overall prediction for ~560 kbpd of production declines is in line with the IEA's projection for non-OPEC supply to decline to 57.0 mmbpd this year from 57.7 mmbpd last year.
As demand improves by ~100,000 boepd per month on average this year, the rebalancing of physical supply and demand is coming into balance. The longer under-investment continues, the more physical damage is done to oilfields and the longer the eventual upcycle will be as reinvestment is needed to yield constant output.
Source: Company reports, EVR ISI Research
Region2014
Production (Mboepd)
2015 Production (Mboepd)
Y/Y +/- (Mboepd)
2014 vs 2015 % Change in Production
2016E Production (Mboepd)
Y/Y +/- ($MM)
2015 vs 2016E %
Change in Production
2014 vs 2016E %
Change in Production
U.S. 15,263 16,295 1,032 6.8% 15,920 (375) -2.3% 4.3%Canada 4,113 4,228 115 2.8% 4,077 (151) -3.6% -0.9%International 5,459 5,702 243 4.4% 5,666 (36) -0.6% 3.8%Total 24,835 26,225 1,390 5.6% 25,662 (563) -2.1% 3.3%
2014-2016E Production (Mboepd) - Regional Breakdown
6
Sentiment Remains Poor, But Is Improving
Source: EVR ISI Research
Institutional Equity Energy Allocations are the 2nd lowest of all groups compared to historical averages and long only funds remain underweight. We consider poor sentiment a leading positive stock market indicator. Buy when there’s blood in the streets.
Sector rotation has begun with hedge funds increasing net position to +30%
versus -11% in late’ 14 .
Sector Over Under Net Position Historical Avg Difference +/- Std. DevTechnology 74% 13% +61% +40% +21% 20%Cons. Staples 26% 35% -9% -21% +12% 15%Financials 36% 55% -19% -27% +8% 16%Telecom 26% 61% -35% -42% +7% 8%Industrials 43% 30% +13% +11% 2% 17%Materials 23% 41% -18% -19% 1% 13%Cons. Discretionary 43% 35% +8% +9% -1% 15%Util ities 5% 77% -72% -68% -4% 8%Energy 22% 43% -21% +3% -24% 14%Healthcare 23% 43% -+20% +11% -31% 10%
Institutional Equity Sector Allocation
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350
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-40
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0
10
20
30
40
Jan-04 Jan-06 Jan-08 Jan-10 Jan-12 Jan-14 Jan-16
Energy Net Position OSX
Energy Net Position OSX
Sector Over Under Net Position Historical Avg Difference +/- Std. DevCons. Discretionary 27% 36% -9% -33% +24% 27%Technology 50% 10% +40% +22% +18% 21%Telecom 40% 10% 30% 15% +15% 17%Materials 40% 30% 10% +7% 3% 18%Util ities 25% 25% 0% -1% +1% 15%Energy 50% 20% +30% +31% -1% 24%Healthcare 33% 11% +22% +36% -14% 19%Cons. Staples 30% 20% +10% +32% -22% 21%Financials 18% 55% -37% -6% -31% 24%Industrials 18% 36% -18% +13% -31% 21%
Hedge Fund Sector Allocation
7
E&P Bankruptcies
Source: EVR ISI Research; Haynes and Boone, LLP
69 North American O&G Producers, representing $34.4 billion in debt, have filed for bankruptcy since the beginning of 2015.
27 occurred this year and the month of April represented both the highest number of filings (11 total) and total debt ($14.9 billion).
8
E&P Redeterminations
Source: Haynes and Boone, LLP
Tracking 29 companies, we calculate the aggregate borrowing base fell by 19%, in line to slightly better than market expectations.
Market Expectations: Survey of 150 lenders and operators conducted in January; Lenders expected 70% of borrowing bases to decrease by average of 25%; Borrowers expected 67% of their borrowing bases to decrease by average of 28%. JP Morgan (late February): Expects revolvers to contract by 15%-25% Wells Fargo (early February): Expects borrowing base availability to fall by 10%-20% Wells Fargo (1Q Conference Call): 25% of borrowing base redeterminations have been completed;
50%-60% of borrowers have seen a reduction while 25% of clients have seen no change. WFC is using a price deck 20% lower than when borrowing bases were last redetermined in the fall.
Regulators and investors are pressuring lenders to reduce risk and exposure to
O&G
9
E&P Redeterminations
Source: EVR ISI Research
Rating
Ticker Date Fall 2015 Spring 2016 ∆ % ∆ Moody's/S&P
DNR 19-Apr $1,500 $1,050 ($450) -30% Caa2/SDLTS.CN 2-May $550 $250 ($300) -55% Ca/CCC-AXAS 21-Apr $165 $130 ($35) -21%COG 21-Apr $1,800 $1,600 ($200) -11%RSPP 2-May $600 $600 $0 0% B2/B+EPE 2-May $2,750 $1,650 ($1,100) -40%SM 14-Apr $2,000 $1,250 ($750) -38% B2/BB-AR 14-Apr $4,500 $4,500 $0 0% Ba2/BBSGY 14-Apr $500 $300 ($200) -40% Caa2/CCC-EPM 13-Apr $5 $10 $5 100%MRD 11-Apr $1,000 $1,000 $0 0% B2/BCHK 11-Apr $4,000 $4,000 $0 0% Caa2/CCCCPE 11-Apr $300 $300 $0 0%BBG 11-Apr $375 $335 ($40) -11% Caa2/B-UNT 8-Apr $550 $475 ($75) -14% B2/B+EVEP 4-Apr $625 $450 ($175) -28% Caa2/CCC+HAWK.LN 1-Apr $23 $13 ($10) -43%MPOY 1-Apr $252 $170 ($82) -33% Ca/DXCO 30-Mar $375 $325 ($50) -13% Caa2REN 29-Mar $145 $105 ($40) -28% Caa3/CCC-WLL 28-Mar $4,000 $2,750 ($1,250) -31% Caa1/B+WTI 24-Mar $350 $150 ($200) -57% Caa3/CCC-SN 21-Mar $500 $350 ($150) -30% Caa1/BWPX 18-Mar $1,750 $1,025 ($725) -41% B2/BB-HK 17-Mar $827 $700 ($127) -15% Caa2RRC 17-Mar $3,000 $3,000 $0 0% Ba3/BB+REXX 14-Mar $200 $190 ($10) -5% CaEGY 2-Mar $65 $20 ($45) -69%OAS 23-Feb $1,525 $1,150 ($375) -25% B3/B+Total 29 $34,232 $27,848 ($6,384) -19%
Borrowing Base Size
10
OFS Bankruptcies
Source: EVR ISI Research
61 oilfield service restructurings since the beginning of 2015, representing more than $9 billion.
11
Near-Term Fundamentals
12
1,345
872 829
722
522
391
0
200
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1Q15 2Q15 3Q15 4Q15 1Q16 2Q16E
Near-Term Fundamentals
There Will Be/Has Been Blood: U.S. Land Rig Count currently 388, down 79% from the 2014 peak. 2Q average is down 23% QoQ. We believe the rig count is very close to bottoming, but have little hope for material improvement in 2H.
E&Ps stayed ‘on script’ in 1Q, stating the need for sustained prices above $50/bbl before re-activating drilling programs, but the market will closely watch actions vs. words in 2H.
We expect excess cash flows will be first directed to repairing balance sheets, followed by workovers, DUCs, and finally adding incremental rigs.
U.S. Land Rig Count (1Q15-2Q16E)
Source: Baker Hughes, EVR ISI Research
13
Near-Term Fundamentals: Land Drillers Land Rig margins should continue to be pressured, though the companies
currently high grading their fleets should witness robust margin expansion when the recovery unfolds.
We expect U.S. land rig gross income for the big four drillers to trough by 3Q16, with a prolonged recovery thereafter as rigs rolling off term contracts into the spot market offset increases in utilization
U.S. Land Rig Gross Income ($ in millions)
Source: Company reports, EVR ISI Research Source: Company reports, EVR ISI Research
U.S. Land Rig Gross Margins per Day ($ in thousands)
14
$4
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$14
$16
HP NBR PDcn PTEN
-100
0
100
200
300
400
500
HP NBR PDcn PTEN
Near-Term Fundamentals: Pressure Pumpers Pressure Pumping gross margins should remain under pressure through
midyear ’16.
Margins should improve first with utilization and then pricing.
Pricing remains a knife fight with gross margins at or below breakeven in many cases as larger companies take down pricing to gain market share
U.S. P.P. Gross Income ($ in millions)
Source: Company reports, EVR ISI Research Source: Company reports, EVR ISI Research
U.S. Pressure Pumping Gross Margin %
15
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CFWcn PTEN RES TCWcn
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E
CFWcn PTEN RES TCWcn
Near-Term Fundamentals: Offshore Drillers The offshore rig market remains cyclically oversupplied
Worldwide floater utilization declined to 64.2% in March (down ~1,871 bps
y/y) while supply has declined by 12 rigs y/y as retirements have outpaced newbuild deliveries
Worldwide jackup utilization declined to 65.2% in March (down ~1,279 bps y/y) while supply is down by 9 units y/y
Worldwide Jackup Utilization
Source: IHS, EVR ISI Research Source: IHS, EVR ISI Research
Worldwide Floater Utilization
60%
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Total Supply Total Util %
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420
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Utilization Supply
Total Supply Total Util %
16
Near-Term Fundamentals: Offshore Drillers The worldwide working offshore rig count fell 8 units in March to 458 rigs (down
140 y/y), with about 146 working floaters and 313 working jackups
Worldwide Working Jackups
Source: IHS, EVR ISI Research Source: IHS, EVR ISI Research
Worldwide Working Floaters
Global jackup utilization is ~65% while semisub utilization is ~59% and drillship utilization is ~69%. Total offshore rig contracted utilization is about 64%
140150160170180190200210220230240250
Jan-
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Figure 1. Offshore Rig Count Weekly Utilization and Changes
Source: IHS-Petrodata, Evercore ISI Research
Total Contracted Total Contracted Total Contracted Total Contracted Total ContractedChange Contracted Util ization Change Contracted Util ization Change Contracted Util ization Change Contracted Util ization Change Contracted Util ization
Jackups (4) 346 64.6% 0 6 10.5% 0 53 76.8% (2) 12 44.4% 1 64 60.4%Semisubmersibles (1) 109 59.2% 0 8 36.4% 0 35 57.4% 0 6 37.5% 0 21 58.3%Dril lships 1 83 68.6% 0 31 91.2% 0 2 25.0% 0 19 79.2% 1 4 33.0%Total Fleet (4) 538 63.7% 0 45 39.5% 0 90 65.2% (2) 37 52.9% 2 89 57.4%
Asia/AustraliaWorldwide Gulf of Mexico Europe/Mediterranean West Africa
17
Near-Term Fundamentals: Offshore Drillers 2015 Fixtures: Average Dayrates Declining:
UDW: $359 kpd – down 24% from $471 kpd in 2014 DW: $295 kpd – down 19% from $364 kpd in 2014 MW: $200 kpd – down 34% from $304 kpd in 2014 JU: $114 kpd – down 18% from $140 kpd in 2014
No DW fixtures have achieved rates above $300 kpd in the past 11 months
Global Jackup Fixtures
Source: IHS, EVR ISI Research Source: IHS, EVR ISI Research
Global Deepwater Fixtures
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$300 kpd or below
18
U.S. Land
19
Why U.S. Land Will Lead the Recovery More flexible capital budgets allow U.S. operators to react faster to changes
in commodity prices.
International budgets assumed $30-$35/bbl. Given their stickiness, we see little room for upside in 2016.
International projects also tend to be longer-term, require longer payback periods, giving NAM a first-mover advantage.
When oil recovers, oil-currencies will likely move in tandem, causing higher costs on a USD-basis.
Accommodating equity market in the U.S., particularly for operators who can reassert themselves as growth stocks, give NAM independents access to capital alluding other, non-growth E&Ps.
Offshore isn’t dead, but has its challenges.
20
The Recovery We Envision
21
The U.S. Cyclical Recovery We Envision
We expect the U.S. land rig count to decline another ~50%-55% y/y in 2016 to average ~440 rigs before rising ~25% next year and 30% in 2018, exiting 2018 at ~780 rigs
Pressure pumping utilization should reach +65% by 3Q17 and rise above 80% by 2Q18 as attrition remains underestimated (assumes 3MM HP will removed from the market over the coming ~2 quarters from BHI, HAL, CJES, FTSI, others)
U.S. Land Rig Count (1Q14-4Q18E) U.S. P.P. Effective Utilization (%)
Source: Baker Hughes, EVR ISI Research Source: PacWest, EVR ISI Research
22
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Why? U.S. Production In Decline
Oil supply growth will sharply moderate in 2015 and will begin to fall in 2016 as spending remains curtailed.
The EIA expects U.S. crude production to decline through 3Q17.
Source: EIA, EVR ISI Research
U.S. Crude Oil Output (2013-2017E, kbpd) U.S. Crude Oil Y/Y Output Growth (kbpd)
Source: EIA, EVR ISI Research
23
(1,000)
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2013 2014 2015E 2016E 2017E
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8,000
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Jan-13 Jan-14 Jan-15 Jan-16 Jan-17U.S. Crude Oil Production Expected Production
U.S. Rig Productivity Peaking
Source: EIA, EVR ISI Research
U.S. Shale Oil Rigs Needed To Maintain Production and Production Per Rig (2015-Current)
While oil productivity gains have indeed been impressive (doubling from 4/13 to 3/16; 5-year CAGR of 31%), productivity gains should flatten out in the near future, exhibiting a much slower growth rate – and likely on the verge of peaking
Legacy production declines are accelerating in all basins, though declines have slowed the past ~2-3 months
The next rig replacement cycle could be the kryptonite to our forecast
Legacy Shale Oil Production Changes by Basin (bpd)
Source: EIA, EVR ISI Research
24
350 400 450 500 550 600 650 700 750 800
400 420 440 460 480 500 520 540 560 580 600
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15
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-15
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Production per rig Rigs Needed to Maintain Production
0
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Bakken Eagle Ford Permian Niobrara
Rig/Well Productivity
Source: Company reports, EVR ISI Research Source: Company reports, EVR ISI Research
Potential Thesis: Resiliency of U.S. production is due in part to longer laterals, higher stage counts, and greater proppant per stage which has increased production on a gross, but not normalized basis. Core of the core production is the focus.
Benefits of higher quality rigs, more experienced crews, lower service costs and a retrenching to the core of the core will revert
Hess’ 30-Day IP per Stage 3 Major Basins Production/Completed Well
25
22.122.8
24.5
29.0
27.3
29.5
24.8
28.8
26.7
29.6
23.6
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1Q16
30-D
ay IP
per
Sta
ge (b
oepd
)
30-day IP per Stage Average 30-day IPs
Why The NAM Shale Production Recovery Will Take Longer Than You Think
Labor – 20% reduction in O&G Extraction/Drilling Jobs according to BLS, but unemployment rates in major crude producing states have remained flat
Between the big four and five pressure pumpers (BAS, CJES, CFW, RES, and SSE), over 130,000 people have been laid off this cycle, with vast majority occurring in the U.S.
Frustration with cyclicality, alternative industries (Construction, PetChems, Manufacturing/Machinery) and a migration out of the oil patch to seek opportunities elsewhere. Unemployment Rates
Source: BLS, EVR ISI Research
O&G Extraction and Operations Support Employment
26
0.0%1.0%2.0%3.0%4.0%5.0%6.0%7.0%8.0%9.0%
Jan-
08
Jun-
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Nov
-08
Apr-
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0
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-12
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TX OK LA ND
380
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11Ap
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1O
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-14
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Apr-
16
Why The NAM Shale Production Recovery Will Take Longer Than You Think
“We're joining the rest of everybody else saying the pressure pumping fleet is going to attrite, but not ours” ~RPC’s VP of Corporate Finance, Jim Landers
PacWest estimates that 53% of the industry’s 17.6MM HHP is stacked with slightly over 50% of stacked capacity designated as cold stacked. HAL expects ~4-6MM HHP will permanently exit the market
Constraints won’t expose themselves until the call on incremental crews extends beyond the first handful. First group of incremental spreads will be relatively easy to deploy and crew, though they will likely require an increase in pricing.
27
Ticker Stacked/ Parked HHP
% of Fleet Stacked/Parked
Total Fleet
Notes: As of:
RES 372K 40% 930K 60% of HHP capacity is crewed with util ization for that 60% below 40% 1Q CallBAS 134K 30% 443K Stacked C&R HHP 3/31/2016TCW 218K 34% 645K Announced sale of U.S. Pressure Pumping Business to Keane Group on 1/26 January Presentation
CFW 404K 60% 674K ~60% of horsepower is parked and CFW temporarily suspended its fracturing operations in the Fayettevil le
5/12/2016
BHI 768K 50% 1536K*Over 50% of BHI's fleet was idled or impaired in 1Q15, since then segment util ization has underperformed broader activity declines, market intel suggests BHI has just two fleets operating
4Q Followup
HAL 1036K 40% 2589K*
HAL considers its older equipment better than what its competition has now, but it is not better than their Q10 pumps. Company believes there is simply no need for it in this market. It has impaired a large portion of its older, non-Q10 pumping equipment. We believe non-Q10 pumps comprised 40% of total fleet
1Q
FTSI 904K 55% 1646K*As of call: 14 fleets active, 4 fleets warm stacked , 5 fleets cold stacked and requiring consumables/minimal repairs ($1MM per spread in repairs); 9 hard down ($2-2.5MM per spread in repairs, but not permanently impaired)
1Q Call (5/13/16)
CJES 661K 66% 1000K 10/11 horizontal fleets working, down from 16 last quarter and 31 following NBR acquisition, could ramp back to 15/16 fleets pretty easily
1Q Call (5/11/16)
PTEN 540K 54% 1000K In total PTEN has stacked slightly more than half of its fleet of more than 1MM HHP with 140K HHP being stacked since the beginning of 2016
1Q Call (4/28/16)
*According to PacWest
(3.0)
(2.5)
(2.0)
(1.5)
(1.0)
(0.5)
0.0
0.5
1.0
MM
HHP
U.S. Pressure Pumping Capacity: Attrition Rate to Surprise to Upside
With utilization for most product lines at 50% or lower, the attrition rate for many commoditized lines such as fracking is accelerating
We believe some 4 million HHP currently sidelined will never return to the market and about 2 million HHP has gone to auction largely to be bought by spare parts providers (if at all)
Natural attrition rates for fracking are 10-15% per year, although likely much higher this year
Source: PacWest, EVR ISI Research
Total U.S. P.P. S/D (MM HHP) and Utilization (%) Quarterly Change in U.S. P.P. Capacity (HHP)
Source: PacWest, EVR ISI Research
28
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456789
10111213141516171819
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4Q18
E
MM
HHP
U.S. HHP Supply U.S. HHP Demand Effective Utilization
Why The NAM Shale Production Recovery Will Take Longer Than You Think
Higher Activity Higher Revenues Higher Capex and Working Capital Lower FCF
Companies with lower quality balance sheets will be more discreet in ramping up activity as they only accept only jobs which generate superior profitability.
Will allow companies with stronger balance sheets to benefit from opportunity to gain market share from weaker peers and from broader industry-wide pricing discipline.
Aggregated Free Cash Flow for (WFT, CJES, BAS, KEG, PTEN, CFW, TCW, RES)
Source: Company Data, EVR ISI Research
2016 2017 2018EBITDA $876 $1,827 $3,287Interest Expense ($826) ($807) ($753)∆ WC $70 ($373) ($602)Capex ($728) ($1,318) ($1,659)FCF ($608) ($671) $273
29
But Isn’t There Too Much Capacity? The Big 4 Land Drillers own 64% of all active AC rigs
Source: RigData, EVR ISI Research
Attrition is underestimated in Pressure Pumping
U.S. P.P. Marketable Supply (MM HHP)
Source: PacWest, EVR ISI Research
30
10.010.511.011.512.012.513.013.514.014.515.015.516.016.517.0
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
3Q15
4Q15
1Q16
2Q16
E3Q
16E
4Q16
E1Q
17E
2Q17
E3Q
17E
4Q17
E1Q
18E
2Q18
E3Q
18E
4Q18
E
MM
HHP
5/6Company Current Prior ∆ ∆% ∆ ∆% ∆ ∆% Q4'14 Q1'15 Q2'15 Q3'15 Q4'15 Q1'16 Q2'16
Helmerich & Payne (HP) 61 55 6 11% 63 -2 -3% 68 -7 -10% 272 266 138 126 117 113 64Nabors Industries (NBR) 31 33 -2 -6% 33 -2 -6% 34 -3 -9% 135 133 76 73 61 51 32Patterson-UTI (PTEN) 32 31 1 3% 37 -5 -14% 34 -2 -6% 88 87 76 57 51 43 33Precision Drilling (PDS) 15 16 -1 -6% 15 0 0% 12 3 25% 47 45 28 26 24 21 13Ensign Energy Services (ESI-CA) 16 17 -1 -6% 14 2 14% 17 -1 -6% 44 35 29 24 23 18 15Independence Contract Drilling (ICD) 4 4 0 0% 5 -1 -20% 6 -2 -33% 9 11 7 7 10 11 6Seventy Seven Energy (SSE) 6 6 0 0% 7 -1 -14% 5 1 20% 19 23 15 10 11 11 6Pioneer Energy Services (PES) 7 10 -3 -30% 10 -3 -30% 8 -1 -13% 11 3 6 7 7 10 10Xtreme Drilling & Coil (XDC) 3 4 -1 -25% 2 1 50% 3 0 0% 15 11 9 7 6 4 3Unit Corporation (UNT) 6 5 1 20% 5 1 20% 4 2 50% 1 2 1 3 1 2 6Other 35 34 1 3% 32 3 9% 37 -2 -5% 90 91 70 67 60 51 33
Total 216 215 1 0% 223 -7 -3% 228 -12 -5% 731 707 455 407 371 335 221% of Rig Count 62% 61% 81 bps 59% 318 bps 60% 218 bps 39% 43% 50% 49% 51% 58% 59%% of Rig Count held by Big Four 40% 38% 147 bps 39% 87 bps 39% 107 bps 29% 32% 35% 34% 35% 40% 38%% of AC Rig Count held by Big Four 64% 63% 156 bps 66% -202 bps 65% -56 bps 74% 75% 70% 69% 68% 68% 64%
4 Weeks Ago
End of Q1'16
Beginning Of
What Will Change in North America? An M&A cycle across the oilfield service, equipment and drilling space is
starting.
The strong will get stronger: niche technology providers are likely targets and weak hands will be swallowed up by larger companies.
Scale will become more important as it provides superior supply chain and logistics management. The larger companies also tend to develop the leading edge technologies.
North America is moving from a brute force approach (drill then frac) to a more technologic/scientific drilling approach (drill, evaluation, better placement of fractures, better production management).
The large cap diversifieds are best positioned as well as those mid-caps that are positioning to be the main alternatives.
31
Onshore Drilling Rig of the Future Pad Optimal Rigs will become the rig of choice among operators and typically
have the following technical attributes: 1,500 HP Bi-fuel capabilities 7,500 psi mud systems AC VFD Drive Omni-directional walking system – 3 hours release to spud Four day conventional move capability
Bending the industry’s cost curve downward Best Suited for wellbore manufacturing model Ability to participate in Big Data/Digital Oilfield
collection network Capable of more wells per rig thereby optimizing
operator production profiles/cash flows
Source: NBR, EVR ISI Research
32
Global Recovery- A Spending Problem
33
Spending Example: Non-NAM, Non-OPEC Can’t Grow
Non-OPEC, non-NAM nations have struggled to meaningfully increase energy output beyond ~40-41 MMboepd despite large increases in capital expenditures prior to 2013
Lack of spending has a two-fold effect on supply: 1. Exploration: Increasingly difficult to replace reserves 2. Production: Deferred maintenance accelerates production decline rates
Source: IEA, EVR ISI Research
Non-NAM, non-OPEC Capex ($MM) and Energy Output (MMboepd)
35
36
37
38
39
40
41
42
43
44
45
$200,000
$250,000
$300,000
$350,000
$400,000
$450,000
2008 2009 2010 2011 2012 2013 2014 2015 2016E
ProductionCapex
Capex Production
“The magnitude of E&P [exploration and production] investment cuts are now so severe that it can only accelerate production decline and the subsequent upward movement in [the] oil price.” – Paal Kibsgaard, CEO of Schlumberger
34
Global Spending: Exploration Disappoints Offshore exploration spending stood near record levels in recent years, but did not lead to
the same level of successful discoveries Increased demand + cost inflation = doubling of exploration costs per well from 2005-2014
($34MM to $74MM) Further cost restructuring is needed to bring the economics into parity with lower cost
plays
Source: IEA, EVR ISI Research
Global Supply: Exploration Disappoints
35
Decrease in well maintenance spending will lead to production declines Operators in U.S. Shales have reportedly let wells “water out” without using
vacuum trucks to empty surface tanks Corrosive scale build-up, sour gas sequestration, and extended periods at
high temperature/pressure will degrade tubing and casing Result: higher workover costs when maintenance resumes
Global Supply: Deferred Maintenance To Take A Toll
U.S. Shale Production Decline (M/M %)
(10%)
(9%)
(8%)
(7%)
(6%)
(5%)
(4%)
(3%)
(2%)
(1%)
0%
Decl
ine
Rate
Bakken Eagle FordPermian Niobrara
Effects of scale buildup and sour gas migration
36
Higher incentives are needed to sustain drilling and exploration Rystad estimates NAM shale average breakeven have fallen to $65/bbl Could see shale/offshore activity increase in the $50-$55/bbl band
Global Liquids Cost Curve
Source: Rystad Energy, EVR ISI Research
2016 Global Liquids Cost Curve
37
Global Supply: LatAm Declines
Pemex Quarterly Crude Oil Production (mmbpd)
Source: Pemex, EVR ISI Research
Pemex Q/Q Crude Oil Production Change (mmbpd)
Source: Pemex, EVR ISI Research
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16
-0.1
-0.08
-0.06
-0.04
-0.02
0
0.02
0.04
MEXICO PEMEX Cash Issues- $1.5B Government Emergency Relief In April New Fibra-E tax regulations will not materialize in investment inflow until
crude prices improve
38
Petrobras Production Forecast (MMboepd)
BRAZIL Per-barrel levy on production introduced in April (est. total of $522M) Petrobras: unplanned outages (platform fires, corrective maintenance) Political Instability: May 10th, President Dilma Rousseff suspended pending
impeachment hearing
Global Supply: LatAm Declines
“It’s a coup” – Dilma Rousseff
39
2.45
2.50
2.55
2.60
2.65
2.70
2.75
Dec-14 Feb-15 Apr-15 Jun-15 Aug-15 Oct-15 Dec-15 Feb-16
Venezuela Production (MMboepd)
“Since the Supreme Court of Justice closed the legal path (to change), we will take our call for urgent political changes to the streets.”- Maria Corina Machado, leader of Vente Venezuela
Global Supply: LatAm Declines
VENEZUELA Cash Crunch for PDVSA: SLB, HAL, BHI, WFT all pared back operations due to
PDVSA payment problems. Public outrage: Vente Venezuela calling for Pres. Maduro’s impeachment
despite Supreme Court ruling to keep Maduro in office. Power Outages: low hydroelectric water levels force government to ration
power in cities across the country. Crude output diverted to domestic power generation.
40
Global Supply: Russia Oil output could decline by as much as 8% (~0.8 mmbpd) due to cuts in Siberian drilling
U.S. sanctions continue to specifically target Rosneft, Novatek, Gazprom Neft, and Transneft, and prohibit the export of goods, services, or technology in support of deepwater, Arctic offshore, or shale projects
Virtually all Western involvement in Artic offshore and shale projects has ceased following the sanctions – which will severely restrict future production growth.
Limited access to international capital markets Oil and natural gas revenues account for more than 50% of federal budget revenues
Russian Crude Oil and Condensate Exports by Destination (2014)
Russian Crude Oil and Condensate Output by Company (2013)
Source: EIA, Evercore ISI Energy Research Source: EIA, Evercore ISI Energy Research
41
Other Countries to Watch Algeria
Canada
China
India
Nigeria
Norway
Petroleum products = 95% export revenues. Perhaps the country with most on the line with respect to crude prices
Steady Economic Growth: Oil consumption turning over positively with improved 1Q16 manufacturing
Forest Fires in Alberta knocked 1.6M bpd offline, production ramping up, but how quickly?
2016 investment to decline at least ~13%; delays to startup of Goliat – Eni Norge. North Sea maintenance to cut output
Rapid Increase in Petroleum Demand (30% of total 1Q16 consumption)
Consistent pipeline destruction at the hands of the Niger Delta Avengers militant group
42
Iran: Consequences from Implementation Day Failed talks in Doha, Iran/Saudi Arabia standoff over capping Iranian
production with larger OPEC freeze
Production back up to pre-sanction levels (~4.0M bpd) as of late April
Now that output is maximized, Iran ready to discuss longer-term OPEC production management
New IPC replaces the outdated buyback model first introduced in the 1990s
Under the new IPC, developers and investors would receive a more sustained production payment stream (as much as 25-30 years)
Increased risk-sharing likely works only for companies with the strongest balance sheets
Publicly stated need for $100-165 billion of upstream investment, or ~$20-30B/year over the next 5-6 years, plus $28 billion of investment in electricity projects and renewable energy through 2021
Iran introduced over 50 projects including 14 exploration and development blocks as well as major onshore and offshore fields (South Azadegan, North Pars)
Western technologies and products should benefit vs. Chinese and
other Asian suppliers
Is Schlumberger truly a potential winner in easing Iranian sanctions?
2.00
2.25
2.50
2.75
3.00
3.25
3.50
3.75
4.00
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016E 2017E
Iran Historical Output WoodMac Forecast ''Consensus'' Forecast
Historical Iranian Output and Forecasts (mmbpd)
Source: IEA, EVR ISI Research
43
Lost Production Offshore To Grow In 2016
Source: Rystad, Platts, Bloomberg, Evercore ISI Energy Research
Lost Production Lags Lower Drilling Activity
The decline in offshore drilling activity is a prelude to lost production which will likely be increasingly more pronounced in the out years due to the lag effects of decision making and contract rollovers
Faced with a depleting reserve base and with the vast majority of known reserves controlled by NOCs, majors will be forced into higher cost basins (i.e. deepwater) or risk permanently ceding market share
One risk to this thesis is consolidation among the Supermajors, which could result in their replacing reserves via M&A rather than searching offshore
44
Stabilizing Global Oil Demand Growth The EIA revised its global demand growth estimate upward to 1.4mmbpd in 2015 and
1.5mmbpd in ’17, up 0.3mmbpd and 0.2mmbpd, respectively. Negative revisions to global GDP forecasts by the IMF and World Bank have moderated. Strong gasoline demand in the U.S. (affordable fuel prices and robust auto sales), strength
from South Korea (transportation and petrochemicals) and stabilization in China (rising auto sales, lower gasoline prices, changes to industrial base and SPR) remain supportive for oil demand in 2016.
Revisions to Oil Demand Projections
Source: IEA, EIA, OPEC, EVR ISI Research
45
Conclusions
46
Conclusions
Oil supply/demand capacity coming into balance
Oil price spike imminent North America will recover first and the strongest
International will be second, offshore third
A large, strong, sustainable upcycle looms
AC-Pad Optimal rig pricing to recover rapidly
SCR/Mechanical likely very little pricing recovery
47
Sources Advanced Resources International Baker Hughes Bloomberg BP Company Reports DOE EIA Evercore ISI Energy Research FERC IEA IMF FactSet National Energy Board of Canada
NBR OPEC PacWest Pemex Petrobras Petroleum Intelligence Weekly Platts Quest Offshore RDC RIG Rystad Energy USGS
48