FMC TECHNOLOGIES INC FTI
November 12, 2013 - 2:11pm EST by
tumnus960
2013 2014
Price: 48.80 EPS $2.16 $2.94
Shares Out. (in M): 239 P/E 22.6x 16.6x
Market Cap (in $M): 11,658 P/FCF 28.3x 18.8x
Net Debt (in $M): 1,216 EBIT 734 997
TEV ($): 12,874 TEV/EBIT 17.5x 12.9x

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  • Offshore Oil and Gas
  • Natural gas

Description

Introduction

FTI is an exceptional energy franchise with strong exposure to two of the industry’s most compelling long term trends: offshore oil production and hydraulic fracturing.  The company’s stock has sold off in recent weeks after FTI once again reported disappointing margins for its largest segment (Subsea Technologies).  This has created an attractive buying opportunity, especially given the early stage of the industry’s upcycle and the steps that management has taken in recent years to capitalize on these robust growth opportunities. 

The company reports results in three segments:

  • Subsea Technologies (SST): 66% of segment revenues and 59% of segment profits
  • Surface Technologies (SFT): 25% of segment revenues and 31% of segment profits
  • Energy Infrastructure (EI): 9% of segment revenues and 10% of segment profits

 

Subsea Technologies (SST)

SST is the leading provider of subsea wells and associated equipment used in offshore oil production.  Unlike capital equipment on a drilling rig which can be used over and over to drill many wells, SST’s type of equipment is permanently installed on each well.  Because wells’ production naturally declines, there is a constant need to drill new wells and install SST’s type of equipment.  This creates a quasi-recurring revenue opportunity since SST’s market is tied to the wells themselves as opposed to rigs drilling the wells.  FTI’s equipment is essential for the safe and reliable operation of subsea wells, and it often acts an enabling technology that expands the boundaries of which reservoirs can be produced from and how long their production can be sustained.  Key products include:

  • Subsea Wellheads and Trees—these are the portions of the well that sit on the seabed.  The wellhead is the “foundation” from which the casing string and production tubing hangs from.  The trees (a.k.a. “Christmas Trees”) sit on top of the wellhead and are a complex collection of valves used to control production from the well. 
  • Subsea Templates—these are large steel plates that the wellhead, trees, and other equipment sits on top of.
  • Subsea Manifolds—these are gathering points that consolidate production from multiple wells and channel that production into a single flowline that runs to the production platform.  Subsea wells are often spread out over large areas, so consolidating their production into a few flowlines is more economic than running direct connections between every well and the production platform. 
  • Multiplex Controllers—these are the electronic and hydraulic systems used to control the trees, manifolds, and other subsea equipment.
  • Subsea Meters—these are used to gather production information from the wells and in some cases can measure the raw production stream even if it is “multi-phase,” meaning a mixture of oil, gas, and water.
  • Subsea Processing Equipment—this is a relatively new family of equipment that can be used to perform a variety of processing tasks that have traditionally been performed on the topside (i.e. above water on the production facility).  Key tasks include separation of the raw production stream into its constituent fluids (i.e. oil, gas, water), reinjection of gas and water back into the reservoir, and boosting of oil towards the production platform. 

Bear in mind that all of this equipment has to operate reliably in very harsh environments for decades.  The saltwater on the outside of the equipment is corrosive, very cold, and under extremely high pressures.  The hydrocarbons on the inside of the equipment can be very hot, corrosive, and also at very high pressures.)  Lastly, this equipment has to be serviceable underwater through the use of underwater robots (Remotely Operated Vehicles; ROV’s).  Given these technological demands and the enormous costs that will be incurred if this equipment fails, this market is limited to five vendors who already have decades of experience producing this type of equipment.  FTI is the leading vendor, and I believe that they enjoy a sustainable competitive advantage.  The five subsea suppliers and their respective marketshares are listed below:

  • FMC Tech: 41%
  • Cameron: 19%
  • Aker Solutions: 19%
  • GE Oil and Gas: 15%
  • Dril-Quip: 6%

FTI is the technology leader which is the starting point of their competitive advantage.  As oil companies are continually forced into more challenging fields, they need new technology to help them overcome these new challenges.  As the technology leader, FTI is the natural candidate to develop solutions for these problems, and the insights that FTI gains during this process position FTI to solve the next round of challenges, perpetuating their technological leadership. 

FTI has also become advantaged by taking a more holistic approach to solving their customers problems (as opposed to simply taking a spec sheet and building the tree).  FTI was the first vendor to begin offering integrated solutions as opposed to individual components, and their competitors were surprisingly slow to adopt this approach.  This holistic approach and technological leadership has enabled FTI to  secure numerous Alliance Partnerships and Frame Agreements with oil companies.  Through these agreements, FTI collaborates with its customers in order to develop solutions and standardize tree designs.  (Such standardization helps to lower costs and improve order turnaround times.)  These customers also involve FTI in Front End Engineering and Design (FEED) studies which gives FTI a competitive advantage in understanding their customers’ needs and developing the best solutions for a given field’s development.  A few years ago, I congratulated Jack Moore, the CEO of Cameron, on a competitive win over FTI in Brazil.  He remarked, “Thanks. . . though it would be nice to have [FTI’s] Alliance Partnerships.”  Subsea developments usually span many years, and a collaborative vendor can thus add considerable value in helping oil companies to maximize the production and reduce the costs of these extensive projects. 

This holistic approach sometimes leads to “outside of the box” thinking that eventually expands FTI’s market opportunity.  For example, several years ago, FTI introduced a Riserless Light Well Intervention stack that was able to conduct well maintenance at a much lower cost than a drilling rig which was the conventional approach at that time.  FTI reasoned that as the population of subsea wells expanded and aged, this population would naturally require an increasing amount of maintenance work, and customers would benefit from a more economic means by which to do this.  FTI acquired Shilling Robotics for similar reasons.  Shilling produces heavy duty ROV’s, and FTI believed that as the ecosystem of subsea equipment continued to expand, it would require a larger and more capable fleet of ROV’s.  While these markets are both highly complementary to SST’s core market, neither of these moves were obvious extensions for a business that had produced well components. 

Cameron has historically been the industry’s second largest vendor.  They too offer systems integration for large subsea projects, though not as extensively or with as holistic a vision as FTI.  About a year ago, Cameron merged its subsea equipment business into a JV with Slumberger, and this new JV is named “OneSubea.”  GE acquired its way into this market through the acquisition of Vetco Gray in 2007.  (Vetco Grey had changed hands over the years and lost important talent by the time that GE acquired it.)  Dril-Quip is a very small player, and they are somewhat unusual in that they are very focused on manufacturing the equipment itself (as opposed to manufacturing the equipment, the control systems, and providing the systems integration work to tie everything together).  For example, Dril-Quip operates its own forge, and I remember sitting through one of their investor presentations where they focused on the number of milling machines they had recently acquired and also showed a chart of their machinist headcount.  This narrower focus on manufacturing, and the lack of systems integration work has given Dril-Quip industry leading margins, but it has also prevented them from winning major subsea awards which usually require a broader solution set and a willingness to do systems integration work.  Another example of this narrow focus is the fact that Dril-Quip is the only subsea vendor that does not make control systems. 

SST is benefitting from a host of trends including:

  • The long-running trend for more of the world’s oil to be produced offshore as land based opportunities are gradually depleted.
  • Improved seismic techniques such as Wide Azimuth that are providing a better picture of geological structures.  These techniques are thus uncovering new drilling targets and reducing the risk that those targets might actually be dry holes.
  • Advancing drilling technologies that enable rigs to drill in increasingly deep waters and harsh environments.  These more capable rigs, along with the improved seismic techniques mentioned above have given rise to a large and growing backlog of offshore discoveries that are waiting to be developed.
  • A shrinking opportunity set for major oil companies.  In the past, national oil companies (NOC’s) enlisted the help of the majors in order to secure the technology and financing needed to develop their countries’ reserves.  High oil prices have allowed the NOC’s to self-fund their developments, and much of the technology now resides in the hands of the service companies, both of which are allowing the NOC’s to bypass the Majors or negotiate better terms.  Deepwater developments are thus one of the few remaining large prospect areas where the Majors’ scale and technical talent provide them with an advantage.
  • High oil prices which make deepwater developments economically viable.
  • Enabling technologies being developed by the subsea vendors such as subsea processing equipment.  These advances both lower the cost and increase the ultimate estimated recoveries (EUR) of offshore fields.  Critically, these additional technologies are increasing the Order Value per Tree and thus allowing subsea revenues to outpace the growth of tree awards.    

I should also mention that subsea projects are large and complex which often leads to delayed awards, especially when a NOC is involved.  Projects can also sometimes become troubled, resulting in delays and cost over runs.  This makes execution a competitive advantage.  Another dimension of the competitive landscape is how each vendor’s capacity is positioned geographically.  National Oil Companies often require that a certain amount of equipment for their countries’ developments be manufactured within their own countries.  (They are under political pressure to ensure that their countries derive the maximum economic value from their natural resources, including sourcing the equipment.)  FTI is well positioned in this regard and has extremely high capabilities in Brazil which is an especially large subsea market. 

 

Surface Technologies (SFT)

SFT’s primarily product lines are surface wellheads, surface trees and fluid control products that are used during hydraulic fracturing.  The company has also been assembling a suite of services for niche frac operations such as frac flowback services.  The majority of SFT’s surface wellhead revenues come from international markets which happen to also be higher margin geographies since fewer vendors operate in those markets than in North America.  This portion of SFT has historically outgrown the international rig count, due in part to a trend towards higher-spec wellheads. 

FTI’s fluid control products include the pumps that cram frac fluid into tight reservoirs as well as the high pressure pipes that convey this fluid from the pumps to the wellhead.  Due to the abrasive nature of the frac fluids, these parts wear out over time, and they carry higher margins due to the mission critical nature of the equipment.  This sub-segment has been a major beneficiary of:

1)    The growing number of wells that are being hydraulically fractured, and

2)    The increasing number of stages being fractured in each of those wells (i.e. greater frac intensity per well).

This division entered a cyclical downturn in mid-2012, but appears to have troughed.

 

Energy Infrastructure (EI)

EI produces a number of infrastructure related products including:

  • Meters used to measure hydrocarbons as they move through transfer stations.
  • Loading Systems such as the booms used to connect LNG tankers to liquefaction and regasification facilities. 
  • Material Handling Solutions such as conveyors used to move bulk materials at mines or processing plants (i.e. coal, ores, etc.).

 

Recent Developments

FTI has entered an exciting period for their business.  FTI rebounded from their industry’s downturn much faster than their competitors, and they had returned to prior-peak backlog by early 2011.  At that time, management believed that the industry would enter a major upcycle around 2013-2014, so they began a very aggressive hiring campaign in order to attract and train the technical talent that would be required during the upcycle.  This was absolutely critical because technical talent is the primary bottleneck for executing subsea projects, and subsea technologists are not readily available in the marketplace like other oil field talent such as geologists.  Subsea technologists have to be developed internally, and they take 1-3 years to become productive.  FTI’s rapidly replenished backlog made it the only subsea vendor with enough financial visibility to make this investment as well as the only vendor with enough projects on which to train new engineers.  Now that the industry has entered its upcycle and competitors’ backlogs have been replenished, FTI is uniquely positioned with enough engineering capacity to operate at this high and rising level of activity. 

Subsea tree awards are currently in an upcycle that is expected to continue until at least 2017, and over half of these awards are expected to come from operators with whom FTI has strong relationships.  In addition, the suite of equipment and services that FTI supplies should continue to expand during this time.  For example, FTI’s initial subsea processing units have been establishing time in the field and proving the viability of this technology.  Petrobras, in particular, is currently evaluating their Subsea Separation pilot at the Marlim field in order to determine whether to extend this technology to the other 80 wells in that field.  FTI also expects significant growth in its subsea services business over this time.  These services include expanded well intervention services, refurbishing older subsea wells, and eventually asset management whereby FTI will gather data from subsea equipment in order to detect problems early and recommend corrective action to the oil companies. 

Fluid Control appears to have troughed and should eventually benefit from a cyclical recovery in North America as well as a continuing trend towards greater frac intensity.  In addition, the techniques used to fracture horizontal wells that were pioneered in North America are just starting to be applied to international basins, and I expect this to generate growth for Fluid Control in the future. 

Despite this very positive outlook, which has been documented by robust backlog growth in SST and a backlog recovery in SFT, SST’s margins have not recovered as sharply or as quickly as expected.  I believe this is the primary reason that FTI’s stock sold off after the 3Q13 conference call, and also the reason that its stock had been generally flat in recent quarters even as it entered a significant upcycle. 

3Q13 SST OM’s had been expected to step up sequentially from 11% during 2Q13 to  roughly 13% in 3Q13 and roughly 16% during 4Q13.  This expectation was underpinned by:

  • A reduction in R&D spending due to the completion of certain projects during 1H13. 
  • Less low margin revenue from two troubled projects (CLOV and Laggan Tormore) as those projects flushed out of backlog. 
  • Cost reductions that were scheduled for the beginning of 3Q13 that would reduce overhead. 

All three of those improvements occurred as expected except for overhead reductions in SST’s Eastern Region.  Unfortunately, four new developments materialized during 3Q13 which depressed SST margins:

Project-Specific Problems due to Execution Issues in SST’s Eastern Region

1)    Liquidated damages charges (i.e. financial penalties) that were incurred when several schedule dates slipped.

2)    Abnormally high rework costs on equipment that had already shipped for legacy projects including the troubled CLOV and Laggan Tormore projects.

Delays Reducing Structural Costs in SST’s Eastern Region

3)    As noted previously, when FTI entered 2011, management believed that the industry was approaching a major upcycle, and they thus began an aggressive 2.5 year investment period to  increase SST’s engineering and manufacturing capacity.  What management was less confident about was how this growth would be distributed geographically, and they recognized that they might have to make adjustments as the regional order books materialized.  By mid-2013, SST’s Eastern Region’s BL was about $600MM lower than FTI had expected, and management began taking actions to right-size the region’s cost structure.  Those actions were originally scheduled for the beginning of 3Q13, but reducing headcount in Norway is difficult, and those actions were not completed until the end of 3Q13.  Since then, management has planned additional cost reductions for this region, and those will go into effect in 4Q13 and early 2014.

Accounting Change

4)    Direct Drive Systems (DDS) was reclassified from the Energy Infrastructure (EI) segment to the SST segment which added a roughly 50bp margin headwind since DDS has been incurring significant losses as they commercialize FTI’s helioaxial pump. 

While these four factors have placed SST’s margin recovery about a quarter behind schedule, the segment’s profitability is likely to improve during the next 3-6 months.  Factors #1 and #2 occurred due to serious execution problems in the Eastern Region.  Costs like these could recur in the future, but much of those costs during 3Q13 were related to troubled legacy projects that are now complete.  In addition, management is aggressively working to ensure that such problems are not repeated by strengthening the region’s management team in order to improve the execution of large projects.  They are also redirecting more experienced global resources such as technical and supply chain talent to this region.  Factor #3 should go away now that Eastern Region’s cost reductions have occurred and additional measures are being undertaken.  Factor #4 should go away now that DDS’ commercialization efforts are winding down.  Lastly, the margin profile of backlog continues to improve as low margin projects are completed and the pricing of inbound orders continue to increase.  It’s also important to note that while the Eastern Region has struggled with execution issues and a lower than anticipated backlog, SST’s other three regions’ collective BL has developed better than expected, and those regions have profitably ramped up to much higher activity levels.   

 

Valuation & Outlook

Using 2014 estimates, FTI’s P/E is 16.6x, and its EV / EBITDA is 9.8x.  (My estimates are a bit higher than consensus.)  These compare favorably to FTI’s historic multiples, especially when considering the fact that FTI owned two slower growing segments prior to mid-2008.  These segments, Food Technology and Airport Systems were spun out as JBT Corp in mid-2008, and they should have theoretically weighed on FTI’s multiple prior to their spin-out.  FTI’s historic multiple ranges are shown below:

    2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                         
P/E                        
High   24.8 21.2 27.2 23.1 22.6 29.5 30.6 20.7 30.9 34.0 28.3
Average   19.9 18.1 22.7 18.6 18.1 19.1 19.7 14.6 22.4 27.8 23.5
Low   14.9 15.5 17.3 15.0 13.7 12.0 7.4 7.6 15.7 21.4 18.9
Current                        
                         
EV / EBITDA                        
High   11.2 9.6 12.3 14.3 10.8 15.1 17.3 11.0 15.9 18.2 14.6
Average   9.2 8.3 10.4 11.6 8.7 9.9 11.3 7.8 11.6 15.0 12.2
Low   7.3 7.3 8.2 9.6 6.7 6.3 4.5 4.3 8.3 11.6 9.9
Current                        

 

I am forecasting that SST revenue will grow 12.7% to 14.2% from 2013 to 2017 due to the trends mentioned above.  This is considerably slower than the 24.1% CAGR this segment realized during its prior upcycle from 2002 to 2009, but the segment is now growing off of a much larger base, and I have attempted to calibrate my projections to anticipated industry tree awards as well as some of the projected opportunity in subsea services.  I am also forecasting that SST OM’s will recover into the mid-teen range.  This, however, could prove conservative because when FTI was recognizing revenue from projects bid at prior-peak pricing, this segment’s OM’s were in the high teens.  I also believe that Subsea Processing could eventually become an enormous market, though significant revenue from these types of projects might be beyond my forecast window.

I believe that SFT revenues will grow in the mid-single digits from 2013 through 2014 due to the above mentioned trends, and I’m forecasting mid-teen OM’s for this segment which are lower than their historic high-teens levels.

I’m forecasting EI to grow very slightly over time with stable 9-10% OM’s, consistent with recent years’ margins.

These assumptions yield 2017 EPS estimates of $3.93 to $4.51.  Combining these with exit multiples of 19.5x to 21.0x implies exit prices of $76.69 to $94.66.  Annualized over three years, this implies returns of 16.3% to 24.7%.  I believe the greatest risk to my thesis is that industry delays or slower technology adoption cause FTI to reach these EPS levels a year or two later than I am projecting.  Even in that scenario, however, the stock’s return should still be respectable.

 

Historical Financial Results

Note that FTI was a spin-off, and over the years, it discontinued certain operations and spun out others.  This has created some rifts in the historical results shown below, as well as some segment reclassifications.  My spreadsheet is peppered with explanatory notes about these rifts, but it is not practical to include all of those details in the figures I've pasted in below.  

FMC   Technologies                          
Fiscal Year End: December 31                          
In   Millions, Except for Percentages & per Share Amounts                  
Annual   & Quarterly Results Have Been Restated as of 2006 and 4Q05 Respectively              
                           
    2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                           
Sales   1,927.9 2,071.5 2,307.1 2,767.7 3,226.7 3,790.7 4,615.4 4,550.9 4,405.4 4,125.6 5,099.0 6,151.4
% Change (Yr./Yr.)     7.4% 11.4% 20.0% 16.6% 20.7% 22.9% 24.7% -3.2% -6.4% 23.6% 20.6%
                           
COGS   1,489.2 1,654.2 1,843.6 2,244.3 2,618.6 3,026.4 3,653.0 3,623.1 3,434.5 3,074.0 3,966.2 4,832.9
                           
Gross Profit   438.7 417.3 463.5 523.4 608.1 764.3 962.4 927.8 970.9 1,051.6 1,132.8 1,318.5
% of Sales   22.8% 20.1% 20.1% 18.9% 18.8% 20.2% 20.9% 20.4% 22.0% 25.5% 22.2% 21.4%
                           
SG&A   292.5 264.5 301.6 340.4 369.7 410.4 452.2 351.7 389.5 432.0 479.9 596.9
% of Sales   15.2% 12.8% 13.1% 12.3% 11.5% 10.8% 9.8% 7.7% 8.8% 10.5% 9.4% 9.7%
                           
R&D   54.9 47.8 45.3 50.4 51.5 49.9 59.5 45.3 51.3 68.0 90.5 116.8
% of Sales   2.8% 2.3% 2.0% 1.8% 1.6% 1.3% 1.3% 1.0% 1.2% 1.6% 1.8% 1.9%
                           
Operating Income   91.3 105.0 116.6 132.6 186.9 304.0 450.7 530.8 530.1 551.6 562.4 604.8
% of Sales   4.7% 5.1% 5.1% 4.8% 5.8% 8.0% 9.8% 11.7% 12.0% 13.4% 11.0% 9.8%
                           
Restructuring & Other   15.5     (31.9) 16.6 (1.2) (23.7) 23.0 2.7 4.9 1.4 (23.0)
Minority interests   1.2 2.2 1.1 (1.4) 2.5 2.5 1.1 1.4        
Interest Expense, Net   11.1 12.5 8.9 6.9 5.5 6.7 9.3 1.5 9.5 8.8 8.2 26.6
                           
EBT   63.5 90.3 106.6 159.0 162.3 296.0 464.0 504.9 517.9 537.9 552.8 601.2
% of Sales   3.3% 4.4% 4.6% 5.7% 5.0% 7.8% 10.1% 11.1% 11.8% 13.0% 10.8% 9.8%
                           
Income Tax Expense   24.1 26.2 31.0 42.3 56.2 84.5 156.5 152.0 155.1 159.6 149.3 166.4
Rate   38.0% 29.0% 29.1% 26.6% 34.6% 28.5% 33.7% 30.1% 29.9% 29.7% 27.0% 27.7%
                           
Net   Income Attributable to Non-Controlling Interests             1.5 2.4 3.7 4.8
                           
Income from Cont. Ops.   39.4 64.1 75.6 116.7 106.1 211.5 307.5 352.9 361.3 375.9 399.8 430.0
Ex. Non-Rec.   58.7   77.7 87.9 135.2 202.2       360.1 392.5 469.0
                           
Income from Discont. Ops.             64.8 (4.7) 8.4 0.5 (0.4)    
Cumulative Effect   (4.7) (193.8)                    
                           
Net Income   34.7 (129.7) 75.6 116.7 106.1 276.3 302.8 361.3 361.8 375.5 399.8 430.0
Ex. Non-Rec.   58.7 64.1 77.7 87.9 135.2 223.0       359.7 392.5 469.0
                           
EPS, Cont. Ops.   $0.15 $0.24 $0.28 $0.42 $0.37 $0.75 $1.15 $1.36 $1.44 $1.53 $1.64 $1.78
Ex. Non-Rec.   $0.22   $0.29 $0.32 $0.48 $0.72       $1.47 $1.61 $1.95
                           
Diluted EPS   $0.13 ($0.49) $0.28 $0.42 $0.37 $0.98 $1.13 $1.39 $1.44 $1.53 $1.64 $1.78
Ex. Non-Rec.   $0.22 $0.24 $0.29 $0.32 $0.48 $0.79       $1.47 $1.61 $1.95
                           
Diluted Shares Out.   263.6 267.2 267.6 277.2 283.2 280.8 267.6 259.4 251.4 245.4 243.2 240.9

 

    2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                           
                           
Financial Ratios                          
ROS   3.0% 3.1% 3.4% 3.2% 4.2% 5.3% 6.7% 7.8% 8.2% 8.7% 7.7% 7.6%
Asset T/O     1.47 1.55 1.59 1.62 1.65 1.62 1.34 1.24 1.15 1.29 1.21
                           
ROA     4.6% 5.2% 5.0% 6.8% 8.8% 10.8% 10.4% 10.2% 10.1% 9.9% 9.2%
ROE     17.8% 20.8% 15.9% 19.9% 25.5% 32.2% 41.1% 40.2% 29.8% 28.7% 28.8%
ROTC     11.1% 12.6% 11.6% 13.6% 19.2% 26.1% 29.6% 25.4% 22.4% 19.6% 14.2%
                           
TD / TC   39.5% 43.6% 33.3% 19.8% 26.8% 19.8% 10.5% 41.5% 27.6% 21.7% 30.4% 47.2%
Net TD / Net TC   36.9% 40.0% 30.3% 5.6% 12.8% 13.6% -1.0% 18.2% -3.8% 3.5% 16.4% 41.4%
                           
Net TD / EBITDA   1.6 1.2 1.0 0.2 0.4 0.3 (0.0) 0.2 (0.1) 0.1 0.4 1.4
                           
Days Receivables     70 76 80 80 79 74 78 78 88 88 92
Days Inventory     61 56 49 53 63 63 62 61 69 59 63
                           
Book Value   $1.59 $1.14 $1.66 $2.39 $2.47 $3.16 $3.82 $2.69 $4.39 $5.35 $5.86 $7.63
Tangible Book Value   $0.27 $0.69 $0.95 $1.71 $1.84 $2.49 $2.80 $1.92 $2.69 $3.65 $4.24 $3.70
                           
Book to Bill                          
Subsea Technologies               1.81 0.89 0.58 1.53 1.20 1.14
Surface Technologies               1.02 1.06 0.90 1.11 1.14 0.95
Energy Infrastructure               1.03 1.05 0.83 0.94 1.10 1.12
Total               1.51 0.95 0.67 1.38 1.17 1.09

 

    2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                           
                           
Segment Figures                          
Inbound Orders                          
Subsea Technologies               4,092.0 2,656.0 1,793.0 4,183.0 3,933.3 4,571.4
Surface Technologies               916.0 1,049.0 736.0 1,057.8 1,488.2 1,519.5
Energy Infrastructure               520.0 627.0 437.0 428.4 555.5 644.7
Intercompany Eliminations   & Other               n.a. n.a. n.a. 5.6 (16.3) (13.7)
Total Inbound Orders               5,528.0 4,332.0 2,966.0 5,674.8 5,960.7 6,721.9
                           
% Change (Yr./Yr.)                          
Subsea Technologies                 -35.1% -32.5% 133.3% -6.0% 16.2%
Surface Technologies                 14.5% -29.8% 43.7% 40.7% 2.1%
Energy Infrastructure                 20.6% -30.3% -2.0% 29.7% 16.1%
Total Inbound Orders                 -21.6% -31.5% 91.3% 5.0% 12.8%
                           
Backlog                          
Subsea Technologies           1,300.0 1,800.0 3,878.0 2,980.0 2,035.0 3,593.5 4,090.0 4,580.1
Surface Technologies               337.0 390.0 314.0 404.4 577.7 500.8
Energy Infrastructure               279.0 291.0 211.0 178.7 226.9 298.0
Intercompany Eliminations   & Other               (3.3) (9.8) (14.6) (5.1) (18.2) (1.1)
Total Backlog   675.9 932.5 1,012.4 1,326.5 1,711.0 2,333.5 4,490.7 3,651.2 2,545.4 4,171.5 4,876.4 5,377.8
                           
% Change (Seq.)                          
Subsea Technologies             38.5% 116.7% -23.2% -31.7% 76.6% 13.8% 12.0%
Surface Technologies                 15.7% -19.5% 28.8% 42.9% -13.3%
Energy Infrastructure                 4.3% -27.5% -15.3% 27.0% 31.3%
Total Backlog     38.0% 8.6% 31.0% 29.0% 36.4% 92.5% -18.7% -30.3% 63.9% 16.9% 10.3%
                           
Revenue                          
Subsea Technologies     681.0 817.0 1,015.0 1,409.1 1,771.8 2,258.9 2,988.3 3,087.5 2,730.9 3,288.1 4,006.8
Surface Technologies               897.9 985.0 818.2 954.3 1,310.8 1,598.1
Energy Infrastructure               503.5 597.2 524.1 454.4 503.4 574.1
Intercompany Eliminations   & Other               (11.4) (19.6) (24.4) (14.0) (3.3) (27.6)
Total Revenue     1,334.8 1,565.1 1,970.4 2,369.0 2,920.5 3,648.9 4,550.9 4,405.4 4,125.6 5,099.0 6,151.4
                           
% Change (Yr./Yr.)                          
Subsea Technologies       20.0% 24.2% 38.8% 25.7% 27.5% 32.3% 3.3% -11.5% 20.4% 21.8%
Surface Technologies                 9.7% -16.9% 16.6% 37.4% 21.9%
Energy Infrastructure                 18.6% -12.2% -13.3% 10.8% 14.5%
Total Revenue       17.3% 25.9% 20.2% 23.3% 24.9% 24.7% -3.2% -6.4% 23.6% 20.6%
                           
% of Total Revenue                          
Subsea Technologies     51% 52% 52% 59% 61% 62% 65% 70% 66% 64% 65%
Surface Technologies               25% 22% 18% 23% 26% 26%
Energy Infrastructure               14% 13% 12% 11% 10% 9%
                           
Operating Income                          
Subsea Technologies                   414.9 422.2 319.9 432.2
Surface Technologies                   138.0 173.4 250.1 284.3
Energy Infrastructure                   65.6 37.8 49.3 68.2
Corporate Exp.   (33.8) (24.1) (25.3) (28.3) (30.0) (32.8) (35.6) (37.5) (35.4) (40.2) (39.4) (41.8)
Other Expense   (4.4) (9.7) (11.9) (17.5) (27.2) (29.7) (9.4) (42.3) (57.2) (48.9) (22.6) (119.9)
Total Op. Income                   525.9 544.3 557.3 623.0
                           
Operating Margin                          
Subsea Technologies                   13.4% 15.5% 9.7% 10.8%
Surface Technologies                   16.9% 18.2% 19.1% 17.8%
Energy Infrastructure                   12.5% 8.3% 9.8% 11.9%
Corporate Exp. (% of Rev.)                   -0.80% -0.97% -0.77% -0.68%
Other Expense (% of Rev.)                   -1.30% -1.19% -0.44% -1.95%
Total Op. Margin                   11.9% 13.2% 10.9% 10.1%
                           
% of Total Segment Profit                          
Subsea Technologies                   67% 67% 52% 55%
Surface Technologies                   22% 27% 40% 36%
Energy Infrastructure                   11% 6% 8% 9%
                           
                           
                           
Miscelaneous                          
Average NA Rig Count   1,496.8 1,097.0 1,403.5 1,558.9 1,838.3 2,117.6 2,110.8 2,256.6 1,306.8 1,891.3 2,298.4 2,283.4
% Change     -26.7% 27.9% 11.1% 17.9% 15.2% -0.3% 6.9% -42.1% 44.7% 21.5% -0.7%
                           
Average Foreign Rig Count   744.8 731.8 770.5 835.8 907.8 925.4 1,005.3 1,078.9 996.8 1,094.2 1,167.0 1,234.4
% Change     -1.8% 5.3% 8.5% 8.6% 1.9% 8.6% 7.3% -7.6% 9.8% 6.7% 5.8%

 

FMC   Technologies                          
Cash Flow Model                          
Fiscal Year End: December 31                          
In   Millions, Except for Percentages & per Share Amounts                  
                           
    2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                           
Net Income   34.7 (129.7) 75.6 116.7 106.1 276.3 307.5 352.9 361.3 375.9 399.8 430.0
Depreciation   37.7 40.1 48.2 53.5 53.3 56.5 64.5 57.7 78.3 80.7 86.1 113.1
Amortization   20.1 8.5 9.5 10.0 12.6 14.3 19.7 14.9 14.7 20.6 21.7 33.1
Net (Gain) Loss on Disposal         (60.4) (38.3) (1.2) (2.0) 0.1 (0.2)      
Employee Benefit Plan Cost   7.9 11.1 18.9 38.4 41.0 52.0 61.3 57.0 78.9 66.0 77.8 110.4
Other   21.5 193.8 3.4 6.5               42.0
Cash Flow   121.9 123.8 155.6 164.7 174.7 397.9 451.0 482.6 533.0 543.2 585.4 728.6
                           
Capital Expenditures   67.6 68.1 65.2 50.2 91.8 138.6 202.5 165.0 110.0 112.5 274.0 405.6
Free Cash Flow   54.3 55.7 90.4 114.5 82.9 259.3 248.5 317.6 423.0 430.7 311.4 323.0
                           
Interest Expense   11.1 12.5 8.9 6.9 5.5 6.7 9.3 1.5 9.5 8.8 8.2 26.6
Income Tax Expense   24.1 26.2 31.0 42.3 56.2 84.5 156.5 152.0 155.1 159.6 149.3 166.4
EBITDA   157.1 162.5 195.5 213.9 236.4 489.1 616.8 636.1 697.6 711.6 742.9 921.6
                           
                           
EPS, Ex. Non-Rec.   $0.22 $0.24 $0.29 $0.32 $0.48 $0.79 $1.15 $1.36 $1.44 $1.47 $1.61 $1.95
CF / Share   $0.46 $0.46 $0.58 $0.59 $0.62 $1.42 $1.69 $1.86 $2.12 $2.21 $2.41 $3.02
FCF / Share   $0.21 $0.21 $0.34 $0.41 $0.29 $0.92 $0.93 $1.22 $1.68 $1.76 $1.28 $1.34
EBITDA / Share   $0.60 $0.61 $0.73 $0.77 $0.83 $1.74 $2.30 $2.45 $2.77 $2.90 $3.05 $3.83

 

 

 

I do not hold a position of employment, directorship, or consultancy with the issuer.
I and/or others I advise hold a material investment in the issuer's securities.

Catalyst

SST OM improvement that should begin to materialize in 4Q13 and gather strength through 2014.
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    Description

    Introduction

    FTI is an exceptional energy franchise with strong exposure to two of the industry’s most compelling long term trends: offshore oil production and hydraulic fracturing.  The company’s stock has sold off in recent weeks after FTI once again reported disappointing margins for its largest segment (Subsea Technologies).  This has created an attractive buying opportunity, especially given the early stage of the industry’s upcycle and the steps that management has taken in recent years to capitalize on these robust growth opportunities. 

    The company reports results in three segments:

     

    Subsea Technologies (SST)

    SST is the leading provider of subsea wells and associated equipment used in offshore oil production.  Unlike capital equipment on a drilling rig which can be used over and over to drill many wells, SST’s type of equipment is permanently installed on each well.  Because wells’ production naturally declines, there is a constant need to drill new wells and install SST’s type of equipment.  This creates a quasi-recurring revenue opportunity since SST’s market is tied to the wells themselves as opposed to rigs drilling the wells.  FTI’s equipment is essential for the safe and reliable operation of subsea wells, and it often acts an enabling technology that expands the boundaries of which reservoirs can be produced from and how long their production can be sustained.  Key products include:

    Bear in mind that all of this equipment has to operate reliably in very harsh environments for decades.  The saltwater on the outside of the equipment is corrosive, very cold, and under extremely high pressures.  The hydrocarbons on the inside of the equipment can be very hot, corrosive, and also at very high pressures.)  Lastly, this equipment has to be serviceable underwater through the use of underwater robots (Remotely Operated Vehicles; ROV’s).  Given these technological demands and the enormous costs that will be incurred if this equipment fails, this market is limited to five vendors who already have decades of experience producing this type of equipment.  FTI is the leading vendor, and I believe that they enjoy a sustainable competitive advantage.  The five subsea suppliers and their respective marketshares are listed below:

    FTI is the technology leader which is the starting point of their competitive advantage.  As oil companies are continually forced into more challenging fields, they need new technology to help them overcome these new challenges.  As the technology leader, FTI is the natural candidate to develop solutions for these problems, and the insights that FTI gains during this process position FTI to solve the next round of challenges, perpetuating their technological leadership. 

    FTI has also become advantaged by taking a more holistic approach to solving their customers problems (as opposed to simply taking a spec sheet and building the tree).  FTI was the first vendor to begin offering integrated solutions as opposed to individual components, and their competitors were surprisingly slow to adopt this approach.  This holistic approach and technological leadership has enabled FTI to  secure numerous Alliance Partnerships and Frame Agreements with oil companies.  Through these agreements, FTI collaborates with its customers in order to develop solutions and standardize tree designs.  (Such standardization helps to lower costs and improve order turnaround times.)  These customers also involve FTI in Front End Engineering and Design (FEED) studies which gives FTI a competitive advantage in understanding their customers’ needs and developing the best solutions for a given field’s development.  A few years ago, I congratulated Jack Moore, the CEO of Cameron, on a competitive win over FTI in Brazil.  He remarked, “Thanks. . . though it would be nice to have [FTI’s] Alliance Partnerships.”  Subsea developments usually span many years, and a collaborative vendor can thus add considerable value in helping oil companies to maximize the production and reduce the costs of these extensive projects. 

    This holistic approach sometimes leads to “outside of the box” thinking that eventually expands FTI’s market opportunity.  For example, several years ago, FTI introduced a Riserless Light Well Intervention stack that was able to conduct well maintenance at a much lower cost than a drilling rig which was the conventional approach at that time.  FTI reasoned that as the population of subsea wells expanded and aged, this population would naturally require an increasing amount of maintenance work, and customers would benefit from a more economic means by which to do this.  FTI acquired Shilling Robotics for similar reasons.  Shilling produces heavy duty ROV’s, and FTI believed that as the ecosystem of subsea equipment continued to expand, it would require a larger and more capable fleet of ROV’s.  While these markets are both highly complementary to SST’s core market, neither of these moves were obvious extensions for a business that had produced well components. 

    Cameron has historically been the industry’s second largest vendor.  They too offer systems integration for large subsea projects, though not as extensively or with as holistic a vision as FTI.  About a year ago, Cameron merged its subsea equipment business into a JV with Slumberger, and this new JV is named “OneSubea.”  GE acquired its way into this market through the acquisition of Vetco Gray in 2007.  (Vetco Grey had changed hands over the years and lost important talent by the time that GE acquired it.)  Dril-Quip is a very small player, and they are somewhat unusual in that they are very focused on manufacturing the equipment itself (as opposed to manufacturing the equipment, the control systems, and providing the systems integration work to tie everything together).  For example, Dril-Quip operates its own forge, and I remember sitting through one of their investor presentations where they focused on the number of milling machines they had recently acquired and also showed a chart of their machinist headcount.  This narrower focus on manufacturing, and the lack of systems integration work has given Dril-Quip industry leading margins, but it has also prevented them from winning major subsea awards which usually require a broader solution set and a willingness to do systems integration work.  Another example of this narrow focus is the fact that Dril-Quip is the only subsea vendor that does not make control systems. 

    SST is benefitting from a host of trends including:

    I should also mention that subsea projects are large and complex which often leads to delayed awards, especially when a NOC is involved.  Projects can also sometimes become troubled, resulting in delays and cost over runs.  This makes execution a competitive advantage.  Another dimension of the competitive landscape is how each vendor’s capacity is positioned geographically.  National Oil Companies often require that a certain amount of equipment for their countries’ developments be manufactured within their own countries.  (They are under political pressure to ensure that their countries derive the maximum economic value from their natural resources, including sourcing the equipment.)  FTI is well positioned in this regard and has extremely high capabilities in Brazil which is an especially large subsea market. 

     

    Surface Technologies (SFT)

    SFT’s primarily product lines are surface wellheads, surface trees and fluid control products that are used during hydraulic fracturing.  The company has also been assembling a suite of services for niche frac operations such as frac flowback services.  The majority of SFT’s surface wellhead revenues come from international markets which happen to also be higher margin geographies since fewer vendors operate in those markets than in North America.  This portion of SFT has historically outgrown the international rig count, due in part to a trend towards higher-spec wellheads. 

    FTI’s fluid control products include the pumps that cram frac fluid into tight reservoirs as well as the high pressure pipes that convey this fluid from the pumps to the wellhead.  Due to the abrasive nature of the frac fluids, these parts wear out over time, and they carry higher margins due to the mission critical nature of the equipment.  This sub-segment has been a major beneficiary of:

    1)    The growing number of wells that are being hydraulically fractured, and

    2)    The increasing number of stages being fractured in each of those wells (i.e. greater frac intensity per well).

    This division entered a cyclical downturn in mid-2012, but appears to have troughed.

     

    Energy Infrastructure (EI)

    EI produces a number of infrastructure related products including:

     

    Recent Developments

    FTI has entered an exciting period for their business.  FTI rebounded from their industry’s downturn much faster than their competitors, and they had returned to prior-peak backlog by early 2011.  At that time, management believed that the industry would enter a major upcycle around 2013-2014, so they began a very aggressive hiring campaign in order to attract and train the technical talent that would be required during the upcycle.  This was absolutely critical because technical talent is the primary bottleneck for executing subsea projects, and subsea technologists are not readily available in the marketplace like other oil field talent such as geologists.  Subsea technologists have to be developed internally, and they take 1-3 years to become productive.  FTI’s rapidly replenished backlog made it the only subsea vendor with enough financial visibility to make this investment as well as the only vendor with enough projects on which to train new engineers.  Now that the industry has entered its upcycle and competitors’ backlogs have been replenished, FTI is uniquely positioned with enough engineering capacity to operate at this high and rising level of activity. 

    Subsea tree awards are currently in an upcycle that is expected to continue until at least 2017, and over half of these awards are expected to come from operators with whom FTI has strong relationships.  In addition, the suite of equipment and services that FTI supplies should continue to expand during this time.  For example, FTI’s initial subsea processing units have been establishing time in the field and proving the viability of this technology.  Petrobras, in particular, is currently evaluating their Subsea Separation pilot at the Marlim field in order to determine whether to extend this technology to the other 80 wells in that field.  FTI also expects significant growth in its subsea services business over this time.  These services include expanded well intervention services, refurbishing older subsea wells, and eventually asset management whereby FTI will gather data from subsea equipment in order to detect problems early and recommend corrective action to the oil companies. 

    Fluid Control appears to have troughed and should eventually benefit from a cyclical recovery in North America as well as a continuing trend towards greater frac intensity.  In addition, the techniques used to fracture horizontal wells that were pioneered in North America are just starting to be applied to international basins, and I expect this to generate growth for Fluid Control in the future. 

    Despite this very positive outlook, which has been documented by robust backlog growth in SST and a backlog recovery in SFT, SST’s margins have not recovered as sharply or as quickly as expected.  I believe this is the primary reason that FTI’s stock sold off after the 3Q13 conference call, and also the reason that its stock had been generally flat in recent quarters even as it entered a significant upcycle. 

    3Q13 SST OM’s had been expected to step up sequentially from 11% during 2Q13 to  roughly 13% in 3Q13 and roughly 16% during 4Q13.  This expectation was underpinned by:

    All three of those improvements occurred as expected except for overhead reductions in SST’s Eastern Region.  Unfortunately, four new developments materialized during 3Q13 which depressed SST margins:

    Project-Specific Problems due to Execution Issues in SST’s Eastern Region

    1)    Liquidated damages charges (i.e. financial penalties) that were incurred when several schedule dates slipped.

    2)    Abnormally high rework costs on equipment that had already shipped for legacy projects including the troubled CLOV and Laggan Tormore projects.

    Delays Reducing Structural Costs in SST’s Eastern Region

    3)    As noted previously, when FTI entered 2011, management believed that the industry was approaching a major upcycle, and they thus began an aggressive 2.5 year investment period to  increase SST’s engineering and manufacturing capacity.  What management was less confident about was how this growth would be distributed geographically, and they recognized that they might have to make adjustments as the regional order books materialized.  By mid-2013, SST’s Eastern Region’s BL was about $600MM lower than FTI had expected, and management began taking actions to right-size the region’s cost structure.  Those actions were originally scheduled for the beginning of 3Q13, but reducing headcount in Norway is difficult, and those actions were not completed until the end of 3Q13.  Since then, management has planned additional cost reductions for this region, and those will go into effect in 4Q13 and early 2014.

    Accounting Change

    4)    Direct Drive Systems (DDS) was reclassified from the Energy Infrastructure (EI) segment to the SST segment which added a roughly 50bp margin headwind since DDS has been incurring significant losses as they commercialize FTI’s helioaxial pump. 

    While these four factors have placed SST’s margin recovery about a quarter behind schedule, the segment’s profitability is likely to improve during the next 3-6 months.  Factors #1 and #2 occurred due to serious execution problems in the Eastern Region.  Costs like these could recur in the future, but much of those costs during 3Q13 were related to troubled legacy projects that are now complete.  In addition, management is aggressively working to ensure that such problems are not repeated by strengthening the region’s management team in order to improve the execution of large projects.  They are also redirecting more experienced global resources such as technical and supply chain talent to this region.  Factor #3 should go away now that Eastern Region’s cost reductions have occurred and additional measures are being undertaken.  Factor #4 should go away now that DDS’ commercialization efforts are winding down.  Lastly, the margin profile of backlog continues to improve as low margin projects are completed and the pricing of inbound orders continue to increase.  It’s also important to note that while the Eastern Region has struggled with execution issues and a lower than anticipated backlog, SST’s other three regions’ collective BL has developed better than expected, and those regions have profitably ramped up to much higher activity levels.   

     

    Valuation & Outlook

    Using 2014 estimates, FTI’s P/E is 16.6x, and its EV / EBITDA is 9.8x.  (My estimates are a bit higher than consensus.)  These compare favorably to FTI’s historic multiples, especially when considering the fact that FTI owned two slower growing segments prior to mid-2008.  These segments, Food Technology and Airport Systems were spun out as JBT Corp in mid-2008, and they should have theoretically weighed on FTI’s multiple prior to their spin-out.  FTI’s historic multiple ranges are shown below:

        2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                             
    P/E                        
    High   24.8 21.2 27.2 23.1 22.6 29.5 30.6 20.7 30.9 34.0 28.3
    Average   19.9 18.1 22.7 18.6 18.1 19.1 19.7 14.6 22.4 27.8 23.5
    Low   14.9 15.5 17.3 15.0 13.7 12.0 7.4 7.6 15.7 21.4 18.9
    Current                        
                             
    EV / EBITDA                        
    High   11.2 9.6 12.3 14.3 10.8 15.1 17.3 11.0 15.9 18.2 14.6
    Average   9.2 8.3 10.4 11.6 8.7 9.9 11.3 7.8 11.6 15.0 12.2
    Low   7.3 7.3 8.2 9.6 6.7 6.3 4.5 4.3 8.3 11.6 9.9
    Current                        

     

    I am forecasting that SST revenue will grow 12.7% to 14.2% from 2013 to 2017 due to the trends mentioned above.  This is considerably slower than the 24.1% CAGR this segment realized during its prior upcycle from 2002 to 2009, but the segment is now growing off of a much larger base, and I have attempted to calibrate my projections to anticipated industry tree awards as well as some of the projected opportunity in subsea services.  I am also forecasting that SST OM’s will recover into the mid-teen range.  This, however, could prove conservative because when FTI was recognizing revenue from projects bid at prior-peak pricing, this segment’s OM’s were in the high teens.  I also believe that Subsea Processing could eventually become an enormous market, though significant revenue from these types of projects might be beyond my forecast window.

    I believe that SFT revenues will grow in the mid-single digits from 2013 through 2014 due to the above mentioned trends, and I’m forecasting mid-teen OM’s for this segment which are lower than their historic high-teens levels.

    I’m forecasting EI to grow very slightly over time with stable 9-10% OM’s, consistent with recent years’ margins.

    These assumptions yield 2017 EPS estimates of $3.93 to $4.51.  Combining these with exit multiples of 19.5x to 21.0x implies exit prices of $76.69 to $94.66.  Annualized over three years, this implies returns of 16.3% to 24.7%.  I believe the greatest risk to my thesis is that industry delays or slower technology adoption cause FTI to reach these EPS levels a year or two later than I am projecting.  Even in that scenario, however, the stock’s return should still be respectable.

     

    Historical Financial Results

    Note that FTI was a spin-off, and over the years, it discontinued certain operations and spun out others.  This has created some rifts in the historical results shown below, as well as some segment reclassifications.  My spreadsheet is peppered with explanatory notes about these rifts, but it is not practical to include all of those details in the figures I've pasted in below.  

    FMC   Technologies                          
    Fiscal Year End: December 31                          
    In   Millions, Except for Percentages & per Share Amounts                  
    Annual   & Quarterly Results Have Been Restated as of 2006 and 4Q05 Respectively              
                               
        2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                               
    Sales   1,927.9 2,071.5 2,307.1 2,767.7 3,226.7 3,790.7 4,615.4 4,550.9 4,405.4 4,125.6 5,099.0 6,151.4
    % Change (Yr./Yr.)     7.4% 11.4% 20.0% 16.6% 20.7% 22.9% 24.7% -3.2% -6.4% 23.6% 20.6%
                               
    COGS   1,489.2 1,654.2 1,843.6 2,244.3 2,618.6 3,026.4 3,653.0 3,623.1 3,434.5 3,074.0 3,966.2 4,832.9
                               
    Gross Profit   438.7 417.3 463.5 523.4 608.1 764.3 962.4 927.8 970.9 1,051.6 1,132.8 1,318.5
    % of Sales   22.8% 20.1% 20.1% 18.9% 18.8% 20.2% 20.9% 20.4% 22.0% 25.5% 22.2% 21.4%
                               
    SG&A   292.5 264.5 301.6 340.4 369.7 410.4 452.2 351.7 389.5 432.0 479.9 596.9
    % of Sales   15.2% 12.8% 13.1% 12.3% 11.5% 10.8% 9.8% 7.7% 8.8% 10.5% 9.4% 9.7%
                               
    R&D   54.9 47.8 45.3 50.4 51.5 49.9 59.5 45.3 51.3 68.0 90.5 116.8
    % of Sales   2.8% 2.3% 2.0% 1.8% 1.6% 1.3% 1.3% 1.0% 1.2% 1.6% 1.8% 1.9%
                               
    Operating Income   91.3 105.0 116.6 132.6 186.9 304.0 450.7 530.8 530.1 551.6 562.4 604.8
    % of Sales   4.7% 5.1% 5.1% 4.8% 5.8% 8.0% 9.8% 11.7% 12.0% 13.4% 11.0% 9.8%
                               
    Restructuring & Other   15.5     (31.9) 16.6 (1.2) (23.7) 23.0 2.7 4.9 1.4 (23.0)
    Minority interests   1.2 2.2 1.1 (1.4) 2.5 2.5 1.1 1.4        
    Interest Expense, Net   11.1 12.5 8.9 6.9 5.5 6.7 9.3 1.5 9.5 8.8 8.2 26.6
                               
    EBT   63.5 90.3 106.6 159.0 162.3 296.0 464.0 504.9 517.9 537.9 552.8 601.2
    % of Sales   3.3% 4.4% 4.6% 5.7% 5.0% 7.8% 10.1% 11.1% 11.8% 13.0% 10.8% 9.8%
                               
    Income Tax Expense   24.1 26.2 31.0 42.3 56.2 84.5 156.5 152.0 155.1 159.6 149.3 166.4
    Rate   38.0% 29.0% 29.1% 26.6% 34.6% 28.5% 33.7% 30.1% 29.9% 29.7% 27.0% 27.7%
                               
    Net   Income Attributable to Non-Controlling Interests             1.5 2.4 3.7 4.8
                               
    Income from Cont. Ops.   39.4 64.1 75.6 116.7 106.1 211.5 307.5 352.9 361.3 375.9 399.8 430.0
    Ex. Non-Rec.   58.7   77.7 87.9 135.2 202.2       360.1 392.5 469.0
                               
    Income from Discont. Ops.             64.8 (4.7) 8.4 0.5 (0.4)    
    Cumulative Effect   (4.7) (193.8)                    
                               
    Net Income   34.7 (129.7) 75.6 116.7 106.1 276.3 302.8 361.3 361.8 375.5 399.8 430.0
    Ex. Non-Rec.   58.7 64.1 77.7 87.9 135.2 223.0       359.7 392.5 469.0
                               
    EPS, Cont. Ops.   $0.15 $0.24 $0.28 $0.42 $0.37 $0.75 $1.15 $1.36 $1.44 $1.53 $1.64 $1.78
    Ex. Non-Rec.   $0.22   $0.29 $0.32 $0.48 $0.72       $1.47 $1.61 $1.95
                               
    Diluted EPS   $0.13 ($0.49) $0.28 $0.42 $0.37 $0.98 $1.13 $1.39 $1.44 $1.53 $1.64 $1.78
    Ex. Non-Rec.   $0.22 $0.24 $0.29 $0.32 $0.48 $0.79       $1.47 $1.61 $1.95
                               
    Diluted Shares Out.   263.6 267.2 267.6 277.2 283.2 280.8 267.6 259.4 251.4 245.4 243.2 240.9

     

        2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                               
                               
    Financial Ratios                          
    ROS   3.0% 3.1% 3.4% 3.2% 4.2% 5.3% 6.7% 7.8% 8.2% 8.7% 7.7% 7.6%
    Asset T/O     1.47 1.55 1.59 1.62 1.65 1.62 1.34 1.24 1.15 1.29 1.21
                               
    ROA     4.6% 5.2% 5.0% 6.8% 8.8% 10.8% 10.4% 10.2% 10.1% 9.9% 9.2%
    ROE     17.8% 20.8% 15.9% 19.9% 25.5% 32.2% 41.1% 40.2% 29.8% 28.7% 28.8%
    ROTC     11.1% 12.6% 11.6% 13.6% 19.2% 26.1% 29.6% 25.4% 22.4% 19.6% 14.2%
                               
    TD / TC   39.5% 43.6% 33.3% 19.8% 26.8% 19.8% 10.5% 41.5% 27.6% 21.7% 30.4% 47.2%
    Net TD / Net TC   36.9% 40.0% 30.3% 5.6% 12.8% 13.6% -1.0% 18.2% -3.8% 3.5% 16.4% 41.4%
                               
    Net TD / EBITDA   1.6 1.2 1.0 0.2 0.4 0.3 (0.0) 0.2 (0.1) 0.1 0.4 1.4
                               
    Days Receivables     70 76 80 80 79 74 78 78 88 88 92
    Days Inventory     61 56 49 53 63 63 62 61 69 59 63
                               
    Book Value   $1.59 $1.14 $1.66 $2.39 $2.47 $3.16 $3.82 $2.69 $4.39 $5.35 $5.86 $7.63
    Tangible Book Value   $0.27 $0.69 $0.95 $1.71 $1.84 $2.49 $2.80 $1.92 $2.69 $3.65 $4.24 $3.70
                               
    Book to Bill                          
    Subsea Technologies               1.81 0.89 0.58 1.53 1.20 1.14
    Surface Technologies               1.02 1.06 0.90 1.11 1.14 0.95
    Energy Infrastructure               1.03 1.05 0.83 0.94 1.10 1.12
    Total               1.51 0.95 0.67 1.38 1.17 1.09

     

        2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                               
                               
    Segment Figures                          
    Inbound Orders                          
    Subsea Technologies               4,092.0 2,656.0 1,793.0 4,183.0 3,933.3 4,571.4
    Surface Technologies               916.0 1,049.0 736.0 1,057.8 1,488.2 1,519.5
    Energy Infrastructure               520.0 627.0 437.0 428.4 555.5 644.7
    Intercompany Eliminations   & Other               n.a. n.a. n.a. 5.6 (16.3) (13.7)
    Total Inbound Orders               5,528.0 4,332.0 2,966.0 5,674.8 5,960.7 6,721.9
                               
    % Change (Yr./Yr.)                          
    Subsea Technologies                 -35.1% -32.5% 133.3% -6.0% 16.2%
    Surface Technologies                 14.5% -29.8% 43.7% 40.7% 2.1%
    Energy Infrastructure                 20.6% -30.3% -2.0% 29.7% 16.1%
    Total Inbound Orders                 -21.6% -31.5% 91.3% 5.0% 12.8%
                               
    Backlog                          
    Subsea Technologies           1,300.0 1,800.0 3,878.0 2,980.0 2,035.0 3,593.5 4,090.0 4,580.1
    Surface Technologies               337.0 390.0 314.0 404.4 577.7 500.8
    Energy Infrastructure               279.0 291.0 211.0 178.7 226.9 298.0
    Intercompany Eliminations   & Other               (3.3) (9.8) (14.6) (5.1) (18.2) (1.1)
    Total Backlog   675.9 932.5 1,012.4 1,326.5 1,711.0 2,333.5 4,490.7 3,651.2 2,545.4 4,171.5 4,876.4 5,377.8
                               
    % Change (Seq.)                          
    Subsea Technologies             38.5% 116.7% -23.2% -31.7% 76.6% 13.8% 12.0%
    Surface Technologies                 15.7% -19.5% 28.8% 42.9% -13.3%
    Energy Infrastructure                 4.3% -27.5% -15.3% 27.0% 31.3%
    Total Backlog     38.0% 8.6% 31.0% 29.0% 36.4% 92.5% -18.7% -30.3% 63.9% 16.9% 10.3%
                               
    Revenue                          
    Subsea Technologies     681.0 817.0 1,015.0 1,409.1 1,771.8 2,258.9 2,988.3 3,087.5 2,730.9 3,288.1 4,006.8
    Surface Technologies               897.9 985.0 818.2 954.3 1,310.8 1,598.1
    Energy Infrastructure               503.5 597.2 524.1 454.4 503.4 574.1
    Intercompany Eliminations   & Other               (11.4) (19.6) (24.4) (14.0) (3.3) (27.6)
    Total Revenue     1,334.8 1,565.1 1,970.4 2,369.0 2,920.5 3,648.9 4,550.9 4,405.4 4,125.6 5,099.0 6,151.4
                               
    % Change (Yr./Yr.)                          
    Subsea Technologies       20.0% 24.2% 38.8% 25.7% 27.5% 32.3% 3.3% -11.5% 20.4% 21.8%
    Surface Technologies                 9.7% -16.9% 16.6% 37.4% 21.9%
    Energy Infrastructure                 18.6% -12.2% -13.3% 10.8% 14.5%
    Total Revenue       17.3% 25.9% 20.2% 23.3% 24.9% 24.7% -3.2% -6.4% 23.6% 20.6%
                               
    % of Total Revenue                          
    Subsea Technologies     51% 52% 52% 59% 61% 62% 65% 70% 66% 64% 65%
    Surface Technologies               25% 22% 18% 23% 26% 26%
    Energy Infrastructure               14% 13% 12% 11% 10% 9%
                               
    Operating Income                          
    Subsea Technologies                   414.9 422.2 319.9 432.2
    Surface Technologies                   138.0 173.4 250.1 284.3
    Energy Infrastructure                   65.6 37.8 49.3 68.2
    Corporate Exp.   (33.8) (24.1) (25.3) (28.3) (30.0) (32.8) (35.6) (37.5) (35.4) (40.2) (39.4) (41.8)
    Other Expense   (4.4) (9.7) (11.9) (17.5) (27.2) (29.7) (9.4) (42.3) (57.2) (48.9) (22.6) (119.9)
    Total Op. Income                   525.9 544.3 557.3 623.0
                               
    Operating Margin                          
    Subsea Technologies                   13.4% 15.5% 9.7% 10.8%
    Surface Technologies                   16.9% 18.2% 19.1% 17.8%
    Energy Infrastructure                   12.5% 8.3% 9.8% 11.9%
    Corporate Exp. (% of Rev.)                   -0.80% -0.97% -0.77% -0.68%
    Other Expense (% of Rev.)                   -1.30% -1.19% -0.44% -1.95%
    Total Op. Margin                   11.9% 13.2% 10.9% 10.1%
                               
    % of Total Segment Profit                          
    Subsea Technologies                   67% 67% 52% 55%
    Surface Technologies                   22% 27% 40% 36%
    Energy Infrastructure                   11% 6% 8% 9%
                               
                               
                               
    Miscelaneous                          
    Average NA Rig Count   1,496.8 1,097.0 1,403.5 1,558.9 1,838.3 2,117.6 2,110.8 2,256.6 1,306.8 1,891.3 2,298.4 2,283.4
    % Change     -26.7% 27.9% 11.1% 17.9% 15.2% -0.3% 6.9% -42.1% 44.7% 21.5% -0.7%
                               
    Average Foreign Rig Count   744.8 731.8 770.5 835.8 907.8 925.4 1,005.3 1,078.9 996.8 1,094.2 1,167.0 1,234.4
    % Change     -1.8% 5.3% 8.5% 8.6% 1.9% 8.6% 7.3% -7.6% 9.8% 6.7% 5.8%

     

    FMC   Technologies                          
    Cash Flow Model                          
    Fiscal Year End: December 31                          
    In   Millions, Except for Percentages & per Share Amounts                  
                               
        2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
                               
    Net Income   34.7 (129.7) 75.6 116.7 106.1 276.3 307.5 352.9 361.3 375.9 399.8 430.0
    Depreciation   37.7 40.1 48.2 53.5 53.3 56.5 64.5 57.7 78.3 80.7 86.1 113.1
    Amortization   20.1 8.5 9.5 10.0 12.6 14.3 19.7 14.9 14.7 20.6 21.7 33.1
    Net (Gain) Loss on Disposal         (60.4) (38.3) (1.2) (2.0) 0.1 (0.2)      
    Employee Benefit Plan Cost   7.9 11.1 18.9 38.4 41.0 52.0 61.3 57.0 78.9 66.0 77.8 110.4
    Other   21.5 193.8 3.4 6.5               42.0
    Cash Flow   121.9 123.8 155.6 164.7 174.7 397.9 451.0 482.6 533.0 543.2 585.4 728.6
                               
    Capital Expenditures   67.6 68.1 65.2 50.2 91.8 138.6 202.5 165.0 110.0 112.5 274.0 405.6
    Free Cash Flow   54.3 55.7 90.4 114.5 82.9 259.3 248.5 317.6 423.0 430.7 311.4 323.0
                               
    Interest Expense   11.1 12.5 8.9 6.9 5.5 6.7 9.3 1.5 9.5 8.8 8.2 26.6
    Income Tax Expense   24.1 26.2 31.0 42.3 56.2 84.5 156.5 152.0 155.1 159.6 149.3 166.4
    EBITDA   157.1 162.5 195.5 213.9 236.4 489.1 616.8 636.1 697.6 711.6 742.9 921.6
                               
                               
    EPS, Ex. Non-Rec.   $0.22 $0.24 $0.29 $0.32 $0.48 $0.79 $1.15 $1.36 $1.44 $1.47 $1.61 $1.95
    CF / Share   $0.46 $0.46 $0.58 $0.59 $0.62 $1.42 $1.69 $1.86 $2.12 $2.21 $2.41 $3.02
    FCF / Share   $0.21 $0.21 $0.34 $0.41 $0.29 $0.92 $0.93 $1.22 $1.68 $1.76 $1.28 $1.34
    EBITDA / Share   $0.60 $0.61 $0.73 $0.77 $0.83 $1.74 $2.30 $2.45 $2.77 $2.90 $3.05 $3.83

     

     

     

    I do not hold a position of employment, directorship, or consultancy with the issuer.
    I and/or others I advise hold a material investment in the issuer's securities.

    Catalyst

    SST OM improvement that should begin to materialize in 4Q13 and gather strength through 2014.
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