This model estimates the line-by-line costs of an FPSO project, across c45 distinct cost lines, in order to quantify the potential savings of a tieback or a ‘fully subsea’ development.
Our estimates drawing on four technical papers, as illustrated in the backup tabs of the model. For a full discussion, see our recent note ‘The future of offshore: fully subsea‘.
We estimate c$750M of cost savings for a tieback, and c$500M of cost savings for a fully subsea development, as compared against a traditional project with a traditional production facility. Please download the model to see the different cost drivers, line-by-line.
This data-model calculates the contribution of Platform Supply Vessels (PSVs) to an offshore oil and gas asset’s emissions profile, as measured in kg/boe.
Our base case estimate is 0.1kg/boe for a productive asset in a well-developed basin. The numbers can be increased c4x in a remote basin, or by another c4x for smaller fields, so emissions >1kg/boe are possible.
Initatives to lower these emissions by 10-20% through LNG-fuelling or hybridization are described in the final tab. They will likely save 0.01-0.02kg/boe from most PSVs and other supply vessels.
This model presents the economic impacts of developing a typical, 625Mboe offshore gas condensate field using a fully subsea solution, compared against installing a new production facility.
Both projects are modelled out fully, to illstrate production profiles, per-barrel economics, capex metrics, NPVs, IRRs and sensitivity to oil and gas prices (e.g. breakevens).
The result of a fully offshore project is lower capex, lower opex, faster development and higher uptime, generating a c4% uplift in IRRs, a 50% uplift in NPV6 (below) and a 33% reduction in the project’s gas-breakeven price.
Please download the model to interrogate the numbers and input assumptions.
This data-file captures all the subsea-focused patents from ten of the largest subsea service providers around the industry, to quantify who has a technical edge (chart above).
The balance has been shifting. During the oil downturn, large, industrial conglomerates effectively halved their pace of technology development, while some subsea service companies accelerated (chart below).
The relative rankings are interesting. The data-file shows clear leaders in the categories such as subsea pumps, wellheads or umbilicals. Other areas are more competitive, with 2-3 companies vying for leadership in, flexible risers, subsea power or pipe-lay. One large subsea EPC screens as ‘Top 5’ on most categories, but is facing strong competion across the board.
Covered companies include: ABB, Aker, Cameron, FMC, GE, OneSubsea, Saipem, Siemens, Subsea7, Technip.
This download is a full economic model for the development of Exxon, Hess and CNOOC-Nexen’s Stabroek block in Guyana.
The output is our base case expectation for the block’s ultimate value, resources, production volumes, cash flows, capex and per-barrel economics.
Sensitivities can modeled as a function of oil prices, WACCs, resource volumes and other costs.
Exploration results to-date are also tabulated in the ‘E&A’ tab, underpinning our resource estimates.
After the COVID crisis, our NAV estimate has arguably increased by c9%, despite oil crashing in 2020 and a 1-year delay to FPSOs 4&5.
This data-file tabulates over 20 next-generation subsea robots, being pioneered around the industry. Each one is described and categorized, including by technical readiness.
These electric solutions could be very material for offshore economics, improving oilfield decline rates and maintenance costs. Innovations include:
- Residing subsea for c1-year at a time, by re-charging in subsea “docking” stations. This provides greater availability for lower cost.
- Increasing autonomy means these robots can be free-swimming, as a communications tether is no longer necessary, improving ranges.
- More intervention work will be conducted, rather than just inspections.
8 of the concepts in our database have all three of these capabilities above. They are at TRLs 5-6, and should be commercially ready in the early 2020s.
The leading companies are tabulated in the data-file, by Major and Service firm (chart below).
These solutions can save c$0.5-1/boe for a typical offshore oilfield, we estimate: performing inspection tasks 2-6x faster than incumbents, as well as halving costs and eliminating the weather-dependency associated with launching-recovering traditional ROVs. For full details, please download the data-file.
Technology leadership determines offshore capex. Specifically, this data-file measures a -88% correlation coefficient between different Major’s offshore patent filings in 2018 and their projects’ capex costs.
The details: We have tabulated the number of Offshore Patents filed in 2018, across 25 leading Majors, from our sample of 3,000 patents. We have also tabulated a dozen, recent, offshore greenfields operated by these companies, which were sanctioned in 2017-19. Investments from Aramco, BP, Equinor, Exxon, Petrobras, TOTAL and Shell are included.
The lowest-cost projects are not “easy oil”. The most economical project in the entire sample, at $17M/kboed, has a complex gas cap with a risk of asphaltene precipitation. Also in the ‘Top 5’ are an Arctic greenfield, an ultra-deepwater carbonate with unusually high-CO2 and an ultra-high pressure deep-water field. Economical development depends on leading technology.
To see the projects included in the analysis, please download the data-file…
We have estimated the cost savings for de-manning an offshore oil platform, based on recent technical disclosures from Technip-FMC, as “the oil price slump in the past few years combined with the latest advances in technology [and] led to the evolution of these minimal unmanned floating platforms”.
Our numbers are built up of fifteen line items, in order to quantify both capex and opex savings; both in USD terms and in $/boe.
Our notes are also included in the download, summarising the philosophy behind the cost-savings, the technical enablers and some of the changes recommended. To get the most out of de-manning, automation should be fully embraced, as more hesitate early forays have had “mixed” results.
The appetite to invest in new offshore oil projects has been languishing, due to fears over the energy transition, a preference for share-buybacks, and intensifying competition from short-cycle shale. So can technology revive offshore and deep-water? This note outlines our ‘top twenty’ opportunities. They can double deep-water NPVs, add c4-5% to IRRs and improve oil price break-evens by $15-20/bbl.
This data-file quantifies the impact that technology can have on offshore economics. We start with a 250-line field model, for a typical offshore oil and gas project. We then list our “top twenty” offshore technologies, which can improve the economics. In a third tab, we update our base case model, line-by-line, to reflect these twenty technologies. Finally, the “before” and the “after” are compared and contrasted.
