Offshore Floating Production Hits Headwinds
Floating Production inventory continues to grow, but rising costs, shale oil and gas are starting to create significant headwinds
Floating production has been one of the most significant developments in the oil and gas industry over the past four decades. Since the first floating production unit (Argyll) was installed in 1975, more than 350 offshore fields too deep, too remote or too small for fixed platforms have been developed using floating production facilities. Looking forward, the future of the sector continues to look very promising, but some barriers and threats to growth have appeared.
Three hundred and twenty (320) oil/gas floating production units are now in service, on order or available for re-use on another field. FPSOs account for 65% of the existing systems, 74% of systems on order. Production semis, barges, spars and TLPs comprise the balance.
Another 29 floating LNG processing systems are in service or on order. Liquefaction floaters account for 14%, regasification floaters 86%. No liquefaction floaters are yet in service: all four are on order. Several of the 12 active FSRUs are interim regasification units being used until the long term unit is delivered. In addition, 102 floating storage units are in service, on order or available. (See Chart 1, top left on page 40)
Ten Year Growth Trend
The number of production floaters in service or available has increased 84% over the past 10 years. At end of 2003 there were 152 units; by the end of 2013 the total increased to 279 units. With scheduled deliveries this year, by end-2014 the inventory will grow another 8% to 300 units in service or available, assuming no units are scrapped. Composition of the operating/available inventory has changed over the past decade. FPSOs accounted for 59% of the units in 2003. At end of 2013, FPSOs were 62% of the total. This reflects the faster growth of FPSOs since 2003. FPSOs increased 96% over the 10 year period. All other units grew 67%.
Ownership of Production Semis, Spars, TLPs and Barges
In the March MR we profiled the ownership of FPSOs. Here we profile ownership of other types of production floaters. Five field operators own ~50% of the 108 production semis, spars, TLPs and barges now in service or on order. Petrobras is the clear leader, with 16% ownership share of the inventory.
(See Chart 2, bottom left on page 40)
Production unit preferences of various operators are indicated by the type units owned. Petrobras has almost entirely production semis. Anadarko has almost entirely spars. Shell has mostly TLPs. Statoil, Chevron and Total have a mixture of units.
Unlike FPSOs where leasing contractors own 48% of the units in service, all but a few of these other type production units are owned by field operators. The exceptions include several GOM production units owned by midstream companies, a few small production barges operated in Africa and a production semi in the GOM (Thunder Hawk) owned by SBM and supplied to Murphy under a production handling agreement.
Also differing from FPSOs, 83 of the 108 units (77%) are built on new hulls. Only 25 were converted from existing hulls; 22 using drill rigs as the conversion hull. In contrast, 35% of FPSOs have been built on new hulls, 65% have used an existing tanker for conversion.
Another difference is the scarcity of redeployment in this group of production units. Compared to FPSOs, they are harder to relocate. Only three of the existing units (all semis) have been redeployed from a previous field. In contrast, 24 FPSOs have been redeployed over the past ten years.
Production Floater Orders
Sixty-six (66) production floaters are currently on order. The figure includes 37 FPSOs, 13 other oil/gas production units and 16 LNG processing units. In the latter are four floating liquefaction plants and 12 regasification terminals.
Orders for 203 production floaters have been placed over the past 10 years, an average of just over 20 units per year. As indicated in the chart below there has been significant variation in number of orders during this time period.
The peak was in 2010 when 29 production floaters were ordered. Partially responsible for the 2010 spike was the deferral of orders resulting from the 2008/09 global financial collapse. In two other years (2006 & 2012) the ordering pace reached 27 units. The low point was in 2009 when the financial crisis shut down orders for 12 months.
The backlog of production floater orders has had several peaks and troughs over the past two decades. The most recent low was hit in late 2009 when the financial collapse created havoc in the offshore sector. Crude prices dropped into the $40s, production floater orders dried up and the order backlog dropped to 30 units in November 2009. Since then order backlog has climbed to a new high that has remained between 65-70 units since mid-2012.
Growing backlog reflects a strong business sector. But as backlog grows, delays and cost growth eventually appear in the supply chain. Bottlenecks in the industrial base create inefficiencies, lower performance and ultimately cause financial problems and delays throughout the industry.
The source of problems can be from many directions. Industry capacity to supply floating production equipment is constrained by available manpower, facilities and management capability at all levels of the supply chain. Capacity limits could be set by specific components, such as availability of compressors. Or limits can be set by engineering capability for concept design, FEED and detailed design/engineering involving production floaters.
Capability to manage multiple projects simultaneously could also be the limiting factor – as even the largest field operators and EPC contractors have a finite number of experienced project managers. Two to three projects executed simultaneously may be feasible for major contractors, but more projects at one time could result in performance problems.
There are indications that overheating in the sector is now occurring.
For example, Statistics Norway in a December 2013 report said “the high activity in the oil and gas sector has resulted in higher costs in many of the development projects.” In a November 2013 review of Norwegian offshore projects, the NPD said “a high activity level has resulted in increased prices for input factors and scarcity of certain resources … and is a contributing cause of the major time and cost overruns incurred in some of the projects in this review.”
Backlog of Planned Floater Projects – 243 floating production projects are in various stages of planning as of beginning April. Of these, 57% involve an FPSO, 15% another type oil/gas production floater, 23% liquefaction or regasification floater and 5% storage/offloading floater.
Brazil, Africa and Southeast Asia are the major locations of floating production projects in the visible planning stage. We are tracking 50 projects in Africa, 50 in Brazil and 44 projects in Southeast Asia – 59% of the visible planned floating production projects worldwide.
The composition of projects by region varies. Projects in Africa and Brazil mostly involve FPSOs, a significant portion of which are big units. In SEA there is a mixture of FPSO, FLNG, FSRU and FSO requirements. The GOM has a mixture of Semi, Spar and TLP projects on the U.S. side, FPSO projects on the Mexican side and FLNG export terminal projects on the U.S. GOM coast. In North Europe there are a mixture of FPSOs, a few Semi/TLP projects and several small projects that might use a production buoy. In Australia the projects are mostly FLNGs.
Near Term Outlook for Orders
Around 25% of the 243 projects in the planning stage are at an advanced stage of development. These projects have either entered the FEED phase, pre-qualification of floater contractors has been initiated or bidding/negotiation is in progress. Award of the production floater contract in these projects is likely within the next 2-3 years.The remaining 75% of the planned projects are in an early development stage. Contract awards are more likely in the 3+ year time frame.
Longer Term Outlook
Over the next five years we expect orders for 104 to 150 production floaters. Our most likely forecast is 126 orders. In the most likely scenario FPSOs will account for 65% of the orders. The balance will consist of other types of oil/gas production floaters (15%) and LNG liquefaction/regasification floaters (20%). Differences in the high and low scenarios will be primarily in the number of smaller and intermediate size production units to be ordered. These units tend to be more sensitive to market conditions. Assumptions in each scenario are shown in the accompanying box.
We see the order pace continuing to grow. Compared to actual orders over the past five years, our most likely forecast is 25% higher than the number of orders between 2009/2013. Looking further back, our most likely forecast figure is up 31% over actual orders between 2004/2008.
But our forecast is significantly lower than the forecast made last year. There we forecast orders for 124 to 190 production floaters over the five year period 2013/2017, with the best estimate being 160 units. Now we are forecasting 104 to 150 orders, with a best estimate of 126 units.
Why the big drop?
Over the past year it has become clear that supply chain and other constraints are much stronger than previously thought. Deepwater project start opportunities keep growing – evidenced by the growing backlog of projects in the planning stage. But capability limitations in the supply chain, increasing project complexity, escalating costs, access to financing and bottlenecks created by local content targets appear to have worsened. These factors have been constraining – and will continue to constrain – deepwater project starts.
Another reason for the drop is the mounting pressure on oil company capital spending budgets. Many oil companies have been cutting capex budgets. ExxonMobil, for example, said its capex spending for 2014 will be 6% less than last year. Chevron said it will cut 2014 spending 5%.
Perhaps more ominous, alternative opportunities to invest in shale oil/gas development appear to be eroding investment in deepwater development. There have been indications that better investment opportunities have been squeezing deepwater projects from oil company capex budgets. Several deepwater project starts have been delayed or cancelled within the past year. Different reasons have been given for each decision – but ultimately management decided there were better uses of available funds.
Strategic moves by Marathon illustrate the shift in investment priorities taking place in the industry. Marathon has recently sold its interest in Block 31/32 in Angola and is marketing its interests in the North Sea. Explaining the company’s strategy, the CEO in March said the divestiture “is a continuation of our portfolio optimization to simplify and concentrate our portfolio toward higher margin and higher growth opportunities.” Marathon sees these opportunities in unconventional oil. The 2014 capital budget of $5.9 billion includes $3.3 billion in spending in the Eagle Ford and Bakken shale/tight oil and wet gas plays.
Looking forward, as the cost of deepwater development escalates and shale/tight oil development costs fall – which is happening – we see the diversion of resources becoming greater over the next several years.
Bottom line– deepwater is still a growth sector. But it has hit headwinds and serious competition.
We have the capability to prepare detailed customized reports on all aspects of the floating production systems market. For further information, please contact Jim McCaul at email@example.com or call 202 333 8501. We will be pleased to discuss how we might be of assistance.
FPSO – Floating Production, Storage and Offloading Vessel
FSO – Floating Storage and Offloading Vessel (no production plant)
FSRU – Floating LNG Storage and Regasification Unit
FLNG – Floating LNG Liquefaction Plant
Semi – Production Semisubmersible
TLP – Tension Leg Platform
SPAR – Production Spar (cylindrical shape)
FPS – Floating Production System (all types)
EWT – Extended Well Test
FEED – Front End Engineering and Design
UDW – Ultra Deepwater
Ten Year Growth in
Floating Production Systems
(No. of Units in Service or Available
As of End Each Year)
Below are some of the projects most likely to produce production/storage floater contracts during the next 12 months or so..
• Bream (Norway)
Teekay is likely to receive a contract from Premier to build/lease a cylindrical 30kb/d FPSO for use off Norway
• Catcher (U.K.)
BWO is likely to get a build/lease award from Premier
for a 60kb/d + 60mmcf/d FPSO for use offshore the U.K.
• Kaombo GC & CLM (Angola)
Saipem and Modec are competing for an award from Total for two similar FPSOs with 100kb/d + 105mmcf/d processing plants
• Atlanta (Brazil)
QGEP is set to award a ten year lease for an 80-100kb/d
FPSO and a three year lease for a 25kb/d EWT FPSO to use
until the large unit is completed
• Tartaruga Verde (Brazil)
Petrobras has invited bids to supply a 150kb/d + 140mmcf/d FPSO under a 20 year lease in Campos Basin
• Sul Parque Baleias (Brazil)
Petrobras in 2H 2014 will likely invite offers for a 150kb/d FPSO
to produce a cluster of light oil discoveries in Campos Basin
• Libra EWT (Brazil)
Petrobras has invited bids to lease a 50kb/d + 140mmcf/d FPSO to use as an EWT unit on the Libra complex
• FLNG Export Terminal (U.S. GOM)
Likely that construction of at least one of the half dozen proposed
U.S. FLNG export terminals will be contracted within this year
• Ayatsil (Mexico GOM)
Pemex is evaluating offers from Exmar and BWO to supply a 300kb/d $2bil+ FPSO for use in shallow water off Mexico
• EWT Pemex (Mexico GOM)
Pemex will likely lease an FPSO with ~15kb/d and DP2
to use for well test/early production in the GOM
• Mad Dog 2 (US GOM)
BP will likely proceed with KBR into the FEED stage to acquire a production semi for Mad Dog, but the EPC contract could slip into 2H 2015
• Rosebank (U.K.)
Chevron will probably revive the suspended contract with Hyundai to
build a 100kb/d + 190mmcf/d FPSO for use off the Shetlands
• Abadi LNG (Indonesia)
Inpex will likely contract with either JCG/Technip/Modec or Saipem/Chiyoda/SBM for a 2.5 mtpa FLNG
• Gehem/Gendalo (Indonesia)
Chevron will likely choose McDermott or Saipem to supply two 25-30kb/d + 420-700mmcf/d production barges for East Kalimantan
• Ubon (Thailand)
Chevron is likely to award the contract to supply a 650-750kbbl condensate FSO for use in the Gulf of Thailand
(As published in the April 2014 edition of Maritime Reporter & Engineering News - http://magazines.marinelink.com/Magazines/MaritimeReporter)