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2014-11-13_Floater Attrition Forecast - D. Gacicia
1. People. Ideas. Success.
Guggenheim Securities, LLC
Oilfield Services, Offshore Contract Drillers & Capital Equipment
November 13, 2014
Floater Attrition Forecast: A Potential Inflection Point
Darren Gacicia
(212) 293-3054
darren.gacicia@guggenheimpartners.com
GUGGENHEIM SECURITIES, LLC See pages 43 - 44 for analyst certification and important disclosures.
Thisreportisintendedforeric.w.loyet@guggenheimpartners.comatGuggenheim.Unauthorizeddistributionofthisreportisprohibited.
2. Floater Attrition May Be a Potential Positive Catalyst for the Group
Floater Market Forecast: Introduces Rig Attrition, Flat Demand, Market Utilization Bottoming in Low 90s %, & Scenarios for Upside. We are recalibrating our
floater market assumptions, forecasting that 58 total floaters leave the market by the end of 2016 (70 by 2018, pgs. 3-6), versus no retirements previously, and assume a
flat demand forecast amid limited visibility, versus demand growth previously. Limited slackening of the floater market to 90+% marketed utilization under a flat demand
outlook, although not a clear bullish signal, suggests a better outcome than the current market forecasts and more stable dayrates. In our view, announcements of rig
stacking and retirement will mark a bullish shift in the sentiment around floater market balances and likely a bottom in offshore driller shares. Under a flat forecast for
contracted rigs (currently 280, pg. 12) and our rig attrition forecast, utilization of marketed rigs falls from a current ~94% to ~92% at the end of 2016 (pg. 3), as attrition
largely offsets the arrival of newbuilds. Given plausible scenarios for low single digit (2.5%) demand growth and potential for delays or cancellations of Brazilian-built
newbuilds, the market may tighten and investor sentiment could shift quickly. We believe the stocks are likely near bottom and range-bound into year-end, as negative
investor sentiment reigns, but patient investors should build positions at current levels (see favored stocks below). If rig attrition trims supply, upstream budgets surprise
(better rig demand growth), and the oil outlook becomes more balanced (political/fundamental reasons), offshore driller shares may outperform in 2015.
Flat Floater Demand Forecast Conservative vs. Recent History. Firm contracted demand through 2015 for development work (pg. 21), a fall in exploration activity back
to historical averages (pg. 20), and limited near-term visibility around capital budgets supports a flat 2015 demand assumption. No growth beyond 2015 may prove
conservative versus historical trends. Historically, development drilling growth has been resilient through commodity volatility, as offshore basins remain important for new
source production. Our most recent demand forecast (pg. 14-16) must be revisited, as high growth, project-by-project data from consultant sources must better factor the
outcomes of a cautious capital budgeting cycle in addition to our probability weighting (“Second Derivative” Leads Drivers, Despite Near-Term Dayrate Headwinds,
6/2/14). Although 3Q14 industry comments temper offshore spending expectations and suggest project delays, favorable marginal cost economics for a large number of
projects (pg. 18) and the push for standardization indicate oil companies look to press forward with projects.
Two Plausible Bullish Scenarios May Turn the Market in 2H15/1H16 (pg. 3):
Growth Can Change Dynamics Quickly. A low single digit demand growth forecast (2.5%/year) remains plausible (pg. 3). Even small growth, in addition to rig attrition,
may tighten the market via an inflection in utilization, and turn market sentiment. For the last ten years, the number of contracted floaters grew at a 6-7% CAGR (pg.
19), largely driven by the search for larger scale reserve replacement and production growth. The advent of unconventional plays has not derailed the trend, but the
quest to lower breakeven costs has slowed activity and started the industry up the learning curve within the deepwater frontier, toward an establishment of best
practices and standardization. A flat growth forecast works contrary to historical trends and the need for oil companies to generate cash from offshore assets, if a
better ROIC, production growth, and dividend sustainability remain IOC goals.
Brazilian Floater Delays May Significantly Change Supply Dynamics. If the 28 newbuilds scheduled for construction in Brazil (9 by 4Q16) are delayed or do not come
to market, marketed utilization may improve dramatically (pg. 10). Only 13 of these rigs are under construction at shipyards with participation from established players
(Keppel FELS & Jurong). The remaining shipyards are under construction themselves. Probability favors Brazil rig delays/cancellations as a tailwind.
Drawing the Line in the Fleet: Multi-Factor Rating Methodology. We have constructed a proprietary multi-factor model to assess the floater fleet by capability, age, and
free date in order to create a ranking for each rig, retirement list and schedule (pg. 7). From the analysis we have derived a list of 71 rigs set to leave the market (pg. 9),
most in addition to those already idle/not contracted (47, pg. 12). We see 4Q14 as a significant attrition period, with 13 rigs leaving the market, of which 6 are currently
uncontracted. In our view, our retired rigs will leave the marketed fleet and drive marketed utilization higher, but may be counted in the fleet until scrapped, lowering the
optics of total fleet utilization despite no longer competing. Several offshore drillers have begun to announce rigs as stacked, retiring, or held for sale, while others have
suggested retirements are to follow. We see strategic reasons for offshore drillers to be coy in identifying rigs until they formally leave the market, but maintain the view
that rig retirements are on the horizon and will serve as positive catalysts for sentiment. We believe RIG (BUY, $27.08), DO (BUY, $35.84), and ESV (Neutral, $39.27) will
see the most retirements (pg. 8), but these are largely factored into our models and appear to be discounted in their share prices.
Favored Offshore Drillers. In our coverage, we believe SDRL (BUY, $21.27) and RIG (BUY, $27.08) have the most leverage to the more bullish offshore driller outlook,
especially if capital markets remain open to financing newbuild deliveries and fleet renewal, respectively. Post PGN spin and recent announcements, NE (BUY, $21.54)
continues to screen better with a solid cash flow story with catalysts around the MLP and share repurchase prospects. In the small/mid-cap names, we continue to like
PACD (BUY, $6.87) and ATW (BUY, $35.52) for quality of fleets, longer-term growth stories, and emerging payout strategies.
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 2
4. Forecast of 60+ Incremental Rigs to Retire Through 2018
13
7
7
3
4
7
3
4 4
2 2
1
3
0
2 2
0
13
20
27
30
34
41
44
48
52
54
56 57
60 60
62
64 64
0
10
20
30
40
50
60
70
0
2
4
6
8
10
12
14
4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18
CumulativeFloaterAttrition
QuarterlyFloaterAttrition
Attrition Cumulative
Forecasted Floater Attrition
6 of the 13 rigs we see
exiting the market in 4Q14
are not contracted.
The majority of rigs will exit the market
in the near term, as market conditions
remain slack. In our view, retirements
will drive a change in the perceived
direction of market balances.
Source: Guggenheim Securities, LLC, IHS-Petrodata
Note: All estimates are by Guggenheim Securities, LLC
Note: We do not include rigs stacked or idle prior to 4Q14 in our incremental rig
retirement assumptions.
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 4
5. Drawing a Retirement Line on the Older, Lower Spec Fleet.
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
0.55
0.60
0.65
0.70
0.75
0.80
0.85
0.90
0.95
1.00
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015
PercentileRank
Year in Service
3G
4G
5G
6G
Floater Fleet Percent Rank by Generation
We see the bottom quartile of
the floater fleet as ripe for
retirement as new rigs arrive,
the market remains
oversupplied, and higher spec.
5G/4G rigs compete for work.
Source: Guggenheim Securities, LLC, IHS-Petrodata
Note: All estimates are by Guggenheim Securities, LLC
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 5
6. Lower Deciles of the Fleet Screen Show Risk to 3G & 4G Rigs
43
40
29
11
3
- - - - -
-
2
10
12
2
- - - - -
- -
3
15
13
12
2 1 - -
-
4
26
29
40 41 42 43
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 2 3 4 5 6 7 8 9 10
%ofRigsbyGeneration
Decile
3G 4G 5G 6G
Floater Fleet Percent Rank by Deciles
Need to stretch retirements into
the bottom 3rd and 4th deciles to
begin retiring a meaningful
number of 4th and 5th
generation rigs.
Source: Guggenheim Securities, LLC, IHS-Petrodata
Note: All estimates are by Guggenheim Securities, LLC
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 6
7. Multi-Factor Rig Ranking Methodology
Our floater factor-weighting methodology ranks each rig against every rig in the floater universe. Each rig is percent
ranked against the universe on the below factors, with the overall ranking as an average of the category ranks.
Double counted
due to being
significantly
differentiating
factors that are
difficult/expensive
to change.
Rig Ranking Methodology
Source: Guggenheim Securities, LLC
Factor Description Weighting
Water Depth The rig's maximum operating water depth. A deeper depth ranks higher. Standard
Drilling Depth The rig's maximum drilling depth. A deeper depth ranks higher. Standard
VDL (Variable Deck Load) The variable deck load represents the carrying capacity of the rig. A greater
capacity ranks higher.
Double
Derrick/Hook Load Maximum weight the derrick/mast and substructure can handle. A greater
maximum load ranks higher.
Double
BOP Rams (Blowout Preventers) Total count of BOP rams onboard. BOP rams are designed to help prevent
blowouts and are important for the safety of the crew, environment, and rig.
More rams rank higher.
Double
DP (Dynamically Positioned) A dynamically positioned rig employs computerized thrusters to keep a rig
positioned correctly at all times. Dynamically positioned is a binary measure
with a DP system ranking positively.
Standard
Dual Activity A rig with two drilling packages to allow for greater efficiency. A binary measure
with dual activity ranking positively.
Standard
Rebuild Credit is given to rigs that have been rebuilt. Standard
Generation Rig generation is based on the rig's initial delivery year. Newer generation rigs
rank higher.
Standard
YIS (Year in Service) Year in service represents when a rig first began working. Newer rigs rank
higher.
Standard
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 7
10. PBR Sponsored & Brazil Built Newbuilds
Manager Rig Name Rig Type
Water
Depth
Drilling
Depth
North Sea
Capable Shipyard Country Build Cost
Drilling
Package BOP Cementing Order Date
Delivery
Date Operator
Contract
Duration
1 Etesco / OAS Cassino Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Jul-16 Petrobras 15.2
2 Etesco / OAS Curumim Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Mar-17 Petrobras 15.9
3 Etesco / OAS Salinas Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Nov-17 Petrobras 15.9
4 Etesco / OAS Itapema Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 May-19 Petrobras 15.8
5 Etesco / OAS Comandatuba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 Jan-20 Petrobras 15.6
6 Not known Grumari Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Jul-16 Petrobras 15.3
7 Not known Ipanema Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Mar-17 Petrobras 15.3
8 Not known Leblon Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Nov-17 Petrobras 15.3
9 Not known Leme Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Jul-18 Petrobras 15.3
10 Not known Marambaia Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Feb-11 Dec-18 Petrobras 15.6
11 Odebrecht Ondina Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Japan 799 HAL Dec-12 Jul-16 Petrobras 15.1
12 Odebrecht Pituba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 May-17 Petrobras 15.1
13 Odebrecht Boipeba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 NOV HAL Apr-12 Jan-18 Petrobras 15.6
14 Odebrecht Interlagos Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 Sep-18 Petrobras 15.7
15 Odebrecht Botinas Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Aug-19 Petrobras 15.4
16 Odfjell Galvao Deepsea Guarapari Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 792 CAM BHI Feb-12 Jul-16 Petrobras 15.0
17 Odfjell Galvao Deepsea Itaoca Drillship 10,000 40,000 N Estaleiro Jurong Aracruz Brazil 792 CAM BHI Mar-12 Aug-17 Petrobras 15.4
18 Odfjell Galvao Deepsea Siri Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 CAM BHI Mar-12 Dec-18 Petrobras 16.1
19 Petrobras Arpoador Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 792 NOV BHI Feb-11 Jun-15 Petrobras 15.6
20 Petrobras Copacabana Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Feb-16 Petrobras 15.1
21 Petroserv Frade Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Dec-16 Petrobras 15.4
22 Petroserv Portogalo Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Apr-18 Petrobras 15.4
23 Queiroz Galvao Urca Semisubmersible 10,000 32,808 N BRASFELS Brazil HAL Dec-11 Dec-15 Petrobras 15.6
24 Queiroz Galvao Bracuhy Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Aug-17 Petrobras 15.4
25 Queiroz Galvao Mangaratiba Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Dec-18 Petrobras 15.4
26 Seadrill Camburi Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Dec-16 Petrobras 15.4
27 Seadrill Itaunas Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Apr-18 Petrobras 16.1
28 Seadrill Sahy Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Aug-19 Petrobras 16.1
We assume that rigs built by
established offshore drillers do
come to market on time, which
may prove an aggressive
assumption if final construction
takes place at Brazilian yards.
The yards building rigs in Brazil are
largely still under construction. Aside
from Jurong and Keppel FELS, the
yards are also inexperienced in
building rigs.
Source: Guggenheim Securities, LLC, IHS-Petrodata; Note: All estimates are by Guggenheim Securities, LLC
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 10
37. OFS Valuations & Risks
Source: Thomson Reuters, Company Reports, Guggenheim Securities, LLC
` Ticker Valuation Risks
BHI BHI currently trades at approximately 13x our 2014 EPS and 6x our 2014 EBITDA estimates. Our 12-month
price target of $72 is based on 15x our 2015 EPS and 6.5x our 2015 EBITDA estimates.
While w e believe that current consensus capex is still achievable even if WTI averages $85/bbl next year, and w hile w e note that BHI has several
buffers w hich should protect its 2015 earnings grow th, w e submit that another prolonged leg dow n in oil prices due to domestic or international
factors w ould likely put E&Pspending at risk, and therefore our estimates may prove too high.
HAL HAL currently trades at approximately 14x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month
price target of $75 is based on 10.5x our 2015 EPS and 8.0x our 2015 EBITDA estimates.
In our view , the risks to the stock are all macro related right now . As our “Picking Up the Pieces” report of October 20 pointed out, should the price
of WTI collapse and average $75/bbl or less next year, the organic contraction in E&Pspending w ould be an estimated 18%—a gap vs. current
consensus that w ould be too w ide to close w ith incremental debt. Under this scenario, w e believe N American earnings w ould fall by roughly one-
third (to the 1H13 level), removing roughly $1.00 from our current 2015 EPS estimate. Additionally, HAL maintains a relatively high level of exposure
to Iraq; consequently, should the conflict w ith ISIS interfere w ith operations (as it did during 3Q14), EPS could be adversely impacted.
SLB SLB currently trades at approximately 18x our 2014 EPS and 10x our 2014 EBITDA estimates. Our 12-month
price target of $125 is based on 19.5x our 2015 EPS and 11.5x our 2015 EBITDA estimates.
Much of the investment thesis for SLB rests w ith its ability to grow market share by delivering superior services quality and tool reliability, and
reduce the cost of services delivery. To the extent that execution of this strategy takes longer than w e currently expect, our estimates—especially
margins—could prove too aggressive. Similarly, SLB’s human resources program has long been a competitive advantage, and to the extent that the
company loses key people (particularly to IOCs), its competitive positioning in the industry could w eaken.
WFT WFT currently trades at approximately 14x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month
price target of $25 is based on 15.0x our 2015 EPS and 7.5x our 2015 EBITDA estimates.
Over the course of this year, WFT’s progress on its transformation initiatives has led it to begin to improve margins and cash flow w hile shedding
underperforming businesses, allow ing it to begin to trade more in line w ith peers; how ever, should commodity prices encounter any w eakness due
to crude saturation in North America, or should WFT be unable to execute on its remaining divestitures in a timely manner, multiples may begin to
compress again and our estimates may prove too high.
CAM CAM currently trades at approximately 15x our 2014 EPS estimate and 8x our 2014 EBITDA estimate. Our 12-
month price target of $75 reflects a multiple of 12.4x our 2015 EPS and 8x our 2015 EBITDA estimates.
In addition to the obvious macro risks, w e believe CAM has several company-specific risks. For instance, Drilling Products still make up about one-
third of the company’s revenue, and new orders for offshore rig equipment have been w eak as a result of the decline in offshore rig rates. Next
year, w e believe the Drilling group’s contribution to revenue and earnings grow th w ill be determined by the aftermarket segment in w hich the
company has very little forw ard visibility. Moreover, CAM has onshore U.S. exposure through its surface and distributor valves segments. Should
oil prices w eaken enough to push U.S. onshore E&Pspending materially low er next year, our current 2015 earnings estimate w ould likely prove to
be too high.
FTI FTI currently trades at approximately 20x our 2014 EPS and 11x our 2014 EBITDA estimates. Our 12-month
price target of $70 reflects a multiple of 16.4x our 2015 EPS and 9.5x our 2015 EBITDA estimates.
In addition to oil-price related macro risks, w e believe FTI has a couple of company specific risks, including: 1) the timing of the delivery of its
intervention stacks next year (w hich w ould impact the timing of incremental subsea services revenues and earnings); and 2) the risk that frac
company’s scale back meaningfully on capex next year, adversely impacting FTI’s fluid-end orders, revenues, and earnings.
NOV NOV currently trades at approximately 12x our 2014 EPS estimate and 7x our 2014 EBITDA estimate. Our 12-
month price target of $90 reflects a multiple of 11.6x our 2015 EPS and 6.3x our 2015 EBITDA estimates.
Maintaining EPS of $6+ over the next tw o years requires onshore equipment orders to remain strong through 1H15, visibility of w hich w eakens as
oil prices retrench to the $70/bbl level.
TS TS currently trades at approximately 15x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month
price target of $50 is based on 11.3x our 2015 EPS and 6.6x our 2015 EBITDA estimates.
In addition to the risk to the U.S. rig count brought on by the recent correction in oil prices, w e believe the biggest risk to TS is margin associated
w ith shifting product mix. For instance, the absence of premium shipments to Saudi Arabia in 3Q14 are expected to contribute to a 100bp
contraction in EBITDA margin. Should premium volumes not recover in 4Q and 2015 in other regions, providing better balance to TS's mix, margins
could remain under pressure as volumes and revenues from commodity products (e.g., U.S. w elded OCTG) drive grow th.
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 37
38. OFS Valuations & Risks
Source: Thomson Reuters, Company Reports, Guggenheim Securities, LLC
Ticker Valuation Risks
CJES CJES currently trades at approximately 6x our 2014 EBITDA and 6x our 2014 OCFPS estimates. Our 12-
month price target of $32 is based on 6.5x our 2015 EBITDA and 6.5x our 2015 OCFPS estimates.
In our view , risk to our estimates stems from C&J’s ability to execute on the cost synergies it expects to realize from the merger; should integration
issues cause the transition to take longer than w e expect, there could be dow nside risk to our estimates. Conversely, should sustained higher oil
prices result in higher E&P spending levels than w e now expect, our estimates could prove too low .
CLB We arrive at our price target of $170/sh by calibrating against our P/E valuation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 28.4x multiple on 2014 EPS and a 26.0x multiple on our 2015 EPS
estimate. Our DCF valuation implies a value of $170/sh, given strong grow th over the explicit forecast,
reinvestment of capital, and a normalization of returns w ithout economic rents. Also, yield-based metrics
support our $170 target.
Since CLB’s largest customers conduct roughly 75% of their reservoir testing in-house, there is a risk that they w ill look to fully integrate their
reservoir diagnostics internally. If the major integrated oil companies w ere to bring their testing in-house, roughly 30% of CLB’s revenues may prove
at risk. Secondly, increased perforation product competition from the larger pressure pumping players, like HAL, BHI, and SLB, w ould challenge
economics for CLB. In addition, if discovery of reserves in less challenging basins shifts the sources of production, the need for more data,
diagnostic tests, and equipment may decline w hich w ould adversely impact CLB’s earnings. Finally, if macro factors reduce commodity demand,
resulting in a collapse of oil and natural gas prices, numerous fields may prove uneconomic, leading to reduced upstream spending to the detriment
of CLB economics. If macro factors turn out stronger than our expectations, thus increasing commodity demand, operator spending may provide
upside to CLB earnings.
CRR We arrive at our price target of $55 per share by triangulating betw een our P/E valuation framew ork, yield-
based metrics, and our discounted cash flow valuation methodology. In our view , yield metrics may offer
support but investor focus on grow th and operating leverage w ill continue to drive shares through traditional
earnings and cash flow metrics. Future estimated earnings grow th discounted by our cost of capital implies
a valuation range betw een an 16.3x multiple on our 2014 EPS and a 17.6x multiple on our 2015 EPS estimate.
Our DCF valuation implies a value of $55 per share, given grow th expectations over the explicit forecast,
reinvestment of capital, and a normalization of returns. Given management’s desire to maintain grow th of a
sustainable dividend, potential upside may lie in yield-based metrics, w hich may magnify the benefit of
outsized returns, free cash flow grow th, and the emergence and communication of a fuller payout strategy.
Market Oversupply from Low er or Higher Quality Entrants. In our view , the threat of higher marginal cost Chinese supply likely caps the excess
returns that may be seen in the North American proppant business. The threat of heightened pricing volatility from poorly managed inventories,
given the presence of distributors, likely increases the amplitude of economics across the business cycle. Superior Product Takes Market Share.
CRR appears to be the innovator in the industry, especially w ith the upcoming introduction of proppant for deepw ater use. If a new or existing
player w ere to create a better product alternative, CRR’s economics may prove at risk. Service Intensity Declines Across Basins. Grow th in
reservoir complexity, unconventional plays, and deepw ater activity continue to drive service intensity. If discovery of reserves in less challenging
basins shifts the sources of production, the need for more and higher quality proppant may w ane, adversely affecting CRR’s economics. Capital
Budgeting. CRR may overbuild capacity or add lines w ithin plants too quickly, expanding fixed overhead to the detriment of returns. Since it costs
$70-75M to add a production line w ithin a nine-month timeline, CRR might find it easy to create a hiccup if it does not have clarity on the means of
how to sell out the new line upon start of additional operations. Macroeconomic Risks and Commodity Price Decline. Oil prices have recently
declined. If oil prices declined too far, numerous fields may prove uneconomic, leading to reduced upstream spending to the detriment of CRR
economics.
Macroeconomic and Commodity Price Strength. If macro factors turn out stronger than our expectations, thus increasing commodity demand,
operator spending may provide upside to CRR earnings. Positive Investor Sentiment and Short Covering. If investors become more optimistic on
North American oil & gas activity in 2015, CRR’s stock could rise. In the near term, short covering may keep upw ard pressure on shares.
FI FI currently trades at approximately 16x our 2014 EPS and 5x our 2014 EBITDA estimates. Our price target of
$27 is based on 20x our 2015 EPS and 11x our 2015 EBITDA estimates.
Given that FI generates an estimated 72% of its revenue offshore—the majority of w hich comes from DW and UDW projects that have a higher
degree of complexity and are subject to delays related to engineering and project management constraints at the operator level, grow th beyond
2015 may not accelerate as w e currently expect. In addition, should the changes mgmt has made over the last several quarters require a longer
transition period to produce results than w e now expect, there may be dow nside risk to our estimates.
OIS OIS currently trades at approximately 14x our 2014 EPS and 6x our 2014 EBITDA estimates. Our price target
of $60 is based on 13.3x our 2015 EPS and 6.6x our 2015 EBITDA estimates.
Should oil prices drop below $80/bbl for a quarter or more, w e believe OIS's Wellsite Services—both completion and drilling segments—w ould
experience a decline in revenues and earnings. Conversely, the stock could move higher on M&A speculation, as OIS is often talked about as a
takeover candidate due to the strength of its franchises and management team.
SPN We arrive at our price target of $26 per share by calibrating betw een our P/E valuation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 14.5x multiple on our 2014 EPS estimate and a 11x multiple on our
2015 EPS estimate. Our DCF valuation implies a value of $25/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns.
Undisciplined Grow th in International Markets. Given SPN’s international grow th ambitions, if it w ere to take an undisciplined approach, adding large
fixed costs ahead of potentially risky revenue streams, SPN profitability may suffer. Failure to properly leverage capital expenditure may adversely
impact returns and economics. Lack of Execution Removes Competitive Advantage from Completions Business. Many of SPN’s larger competitors in
the pressure pumping business either bundle services, gain share w ith scale, or offer more value added services (IP) in order to maintain their
market share lead. While raw horsepow er continues to commoditize in the face of over-supply, SPN w ill need to maintain crew s and service
reliability in order to differentiate its offering. Macroeconomic Risks and Commodity Price Decline. Oil prices have recently declined. If oil prices
declined too far, numerous fields may prove uneconomic, leading to reduced upstream spending to the detriment of SPN economics.
North American Market Strength. If the North American services market reaches a positive inflection point in the near/medium term, SPN w ould likely
benefit given its high leverage to the region.
SLCA We arrive at our price target of $70 per share by triangulating betw een our P/E valuation framew ork, yield-
based metrics, and our discounted cash flow valuation methodology. In our view , yield metrics may offer
support, but investor focus on grow th and operating leverage w ill continue to drive shares through
traditional earnings and cash flow metrics. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 24.3x multiple on our 2014 EPS estimate and a 21.1x multiple on
our 2015 EPS estimate. Our DCF valuation implies a value of $70 per share, given grow th expectations over
the explicit forecast, reinvestment of capital, and a normalization of returns. Given the firm’s ability to convert
to an MLP structure, potential upside may lie in yieldbased metrics, w hich may magnify the benefit of
outsized returns, free cash flow grow th, and a fuller payout strategy.
Risks to our investment thesis include a shift in the market tow ards frac sand alternatives such as ceramic proppants; increased regulation
surrounding either sand mining activities or hydraulic fracturing; SLCA's customer concentration, as SLCA's top ten customers represented 52% of
its sales revenue during 2013; a logistical disruption or cost increases pertaining to transportation and handling as transportation costs represent a
significant portion of the delivered cost of sand; plant dow ntime, namely at one of the firm's major plants; and, an economic/cyclical dow nturn that
reduces commodity demand and prices. Economic cycles impact commodity prices, w hich in turn impact fracking activity and sand demand.
TESO TESO currently trades at approximately 18x our 2014 EPS and 6x our 2014 EBITDA estimates. Our price
target of $23 is based on 11.3x our 2015 EPS and 4.4x our 2015 EBITDA estimates.
Last year, TESO generated roughly $100mm in revenue from equipment sales and services in Russia; how ever, this year, Russia as an end market
should be closer to $60mm. Although the market has proven to be very lumpy in the $60-100mm range over the last several years, w e believe the
U.S. and E.U. sanctions have started to have an impact on the outlook—both in terms of TESO’s w illingness to take the credit risk associated w ith
Russian sales, as w ell as the actual capex budgets of TESO’s Russian customers. Consequently, w e w ould expect Russian revenue next year to
drop to +/-$25mm, w hich TESO has indicated to be its recurrent services revenue. We also believe that the risk to this revenue—along w ith the
sentiment surrounding TESO’s historical exposure to Russia—could w eigh on multiples as w ell.
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 38
39. OFS Valuations & Risks
Source: Thomson Reuters, Company Reports, Guggenheim Securities, LLC
Ticker Valuation Risks
AKSO We arrive at our price target of kr75/sh by calibrating against our P/Evaluation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 17.8x multiple on our 2014 EPS estimate and a 14x multiple on our
2015 EPS estimate. Our DCF valuation implies a value of kr125/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.
Business Model Risk - The transition to a matrix business model that crosses regional management and product management in order to create a
single point of contact w ith customers poses a risk to existing client relationships that may threaten future orders. At the same time, the change in
management structure may also lead to supply chain and other execution issues. There is a risk that AKSO may choose to grow revenues by
underbidding the competition on price. Resultant low er margin business may challenge the company’s margin expansion goals.
DRC DRC currently trades at approximately 31x our 2014 EPS estimates, and 16x our 2014 EBITDA estimates;
after the announcement of the acquisition by SIE, w e expect the deal to be completed and therefore have
based our target price on the agreed upon value of $83/sh, w hich implies target multiples of 25.5x our 2015
EPS and 14.0x our 2015 EBITDA estimates.
As w ith any acquisition, there is alw ays risk that the deal does not go through, in w hich case there may be dow nside risk to our estimates. In
addition, there is risk that a third-party intervenes w ith a higher offer, in w hich case our expectations may prove too low . How ever, as w e have
stated previously, w e believe SIEpresents the best industrial fit for DRC, and consequently believe that the stock w ill trade in a relatively tight range
around $83 until the deal is completed in 2Q15.
DRQ We arrive at our price target of $100/sh by calibrating against our P/Evaluation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 19.9x multiple on our 2014 EPS estimate and a 18.2x multiple on
our 2015 EPS estimate. Our DCF valuation implies a value of $100/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.
Not Hedge Its Raw Material Inputs. Given that Dril-Quip does not hedge its steel or other inputs, the risk remains that rising input costs may erode
margins on its fixed price equipment. Historically, management has successfully aligned costs and revenues through thoughtful coordination of
tender pricing and supply chain management. Product Adoption. Management is focused on its core competency in w ellheads and specialty
connectors, but they have allocated capital and budgeted manufacturing capacity for grow th in liner hangers, manifolds, subsea trees and control
systems. Despite our view that the company w ill utilize its current relationships to increase its presence in these products in the improving market,
there is a risk that a failure to gain traction w ith customers may hamper capacity utilization and performance. Macroeconomic Risks and Commodity
Price Decline. Oil prices have recently declined. If oil prices declined too far, numerous fields may prove uneconomic, leading to reduced upstream
spending to the detriment of DRQ economics. Macroeconomic and Commodity Price Strength. If macro factors turn out stronger than our
expectations, thus increasing commodity demand, operator spending may provide upside to DRQ earnings.
FET We arrive at our price target of $40 per share by calibrating betw een our P/Evaluation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een an 21.9x multiple on 2014 EPS and a 17.3x multiple on our 2015
EPS estimate. Our DCF valuation implies a value of $40/share, given strong grow th over the explicit forecast,
reinvestment of capital, and a normalization of returns.
We see the ability to finance an acquisition strategy through debt or to maintain a valuation multiple that provides an accretive equity currency as
potential risks. The company may face competition from larger competitors if they enter FET's specific markets. If macro factors reduce commodity
demand, resulting in a collapse of oil and natural gas prices, reduced upstream spending w ould negatively impact the company's operations. In
terms of positive risks, if the North American services market reaches a positive inflectiion point, FET w ould likely benefit gtiven its high leverage to
the region.
OII We arrive at our price target of $80/sh by calibrating against our P/Evaluation framew ork and our discounted
cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of capital implies
a valuation range betw een a 20.1x multiple on our 2014 EPS estimate and a 17.7x multiple on our 2015 EPS
estimate. Our DCF valuation implies a value of $80/sh, given strong grow th over the explicit forecast,
reinvestment of capital, and a normalization of returns w ithout economic rents.
Macroeconomic Risks and Commodity Price Decline. We assume that the ROV business grow s w ith the expansion of the offshore rigs fleet and the
acceleration of offshore drilling activity. That said, oil prices have recently declined w hich may cause operators to reevaluate or delay certain
projects in the nearerterm. If oil prices declined too far, numerous fields may prove uneconomic, leading to reduced upstream spending to the
detriment of OII economics. Contract Rolls. A significant portion of OII’s ROVs rolling off contract in 2015 do not yet have new contracts negotiated.
If low er-spec drilling rig attrition occurs during 2015 w e could see a decrease in demand for OII’s yet-to-be contracted ROVs. Strong Offshore Rig
Fundamentals. Persistently high dayrates and favorable supply/demand dynamics in the offshore rig market may benefit earnings.
Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 39
