With only days to go before the end of what has been a very disappointing year for offshore support vessels, we look ahead to 2021, identifying the opportunities that lie ahead
In January, owners were looking ahead to an improving market in 2020 with opportunities to bring idle vessels out of lay-up, and better day rates and utilisation expected. But coronavirus and the resulting slump in oil prices brought further misery and drove owners to send more vessels into lay-up.
At the end of 2020, there are slivers of light emerging from the end of the Covid tunnel, with the vaccine roll out and interest from other sectors.
From Riviera’s virtual conferences Offshore Support Journal Middle East and Asia in Q4 2020, there are themes to consider for 2021 giving owners opportunities for growth.
Covid did not have a major impact on offshore renewables, especially offshore wind, unlike in the oil and gas sector. More nations are either progressing with offshore windfarm projects or putting in firm foundations for new ones. These have delivered new work opportunities for OSV owners and contractors able to leverage experience from offshore oil.
The opportunities for existing OSVs include supporting subsea cable laying, maintenance and logistics support to construction vessels.
In the longer term, there will be opportunities for anchor handlers to deploy floating wind turbines, one of the first being the Hywind Tampen project in the Norwegian sector of the North Sea to power offshore oil production platforms.
Owners have diversified their investments to include crew transfer and service vessels for offshore windfarms, with further opportunities for building new heavy lift crane vessels for offshore renewables.
Mergers & acquisitions
A strong theme from Riviera’s virtual conferences was the expectation for mergers and corporate acquisitions in 2021. Consolidation in this fragmented sector was discussed in great depth during the virtual conferences and consensus was that mergers and supporting vessel scrapping would be required to reduce the huge oversupply and laid-up fleets.
In 2021, there will be opportunist companies ready to acquire or merge with struggling companies to produce a more-balanced market. There will be low-cost assets available for purchase for owners with available funds and more owners in financial trouble, unable to invest and survive, ready to be picked off by strengthened operators. Expect to see some big-name mergers in 2021.
Deepwater Latin America
There has been one bright light in 2020: deepwater Latin America. While the industry has seen heavy investment in Brazil’s deepwater basins for decades, it has only recently seen considerable interest in the deep waters off Guyana and Suriname.
This sub-region is similar to Angola in the late 1990s. I remember writing for Deepwater Review & Outlook in 1999 when Girassol was the one major project in Angola and there were interesting new developments being proposed.
Roll on 10 more years and Total had four huge production centres in Block 17, BP had developed Block 18, ExxonMobil was in the midst of a huge investment campaign. Other projects followed by BP and Eni, plus fill-in work by Total and ExxonMobil – all through subsea networks and FPSOs
In 2020, Guyana-Suriname is in a similar position with ExxonMobil the early trend-setter with Liza production and two more FPSOs on order. Watch out for other energy companies developing deepwater fields in this highly prospective basin with subsea networks linked to FPSOs.
When drilling activity had subsided elsewhere worldwide during the Covid pandemic, it continued unabated in Guyana-Suriname, and so will the opportunities for OSVs.
What is installed in the sea eventually needs to be removed, especially if regulation frameworks are in place to encourage energy companies to do so. Coronavirus has stifled decommissioning activity in 2020, but in the North Sea it continued.
With low oil prices remaining a burden on operators into 2021, there is likely to be an acceleration for field closures and well abandonments.
There is also a growing realisation that decommissioning outside of the North Sea and US Gulf of Mexico is becoming a key environmental requirement. But there are hurdles, least of all if the energy company operating the field goes bankrupt, which BW Offshore is only too aware of in New Zealand.
There are also serious implications for energy companies lumbered with unexpected decommissioning costs, as Chevron seems to be heading towards in Thailand.
Nonetheless, decommissioning is increasingly becoming a long-term aspect of offshore operations and OSVs owners are in prime position to benefit well into the future.
On the other side of the coin, energy companies with opportunities to extend field life will do so, instead of facing decommissioning costs.
The latest example of this is Equinor’s Nkr19.5Bn (US$2.2Bn) Snorre increased oil recovery project, which extends production on this tension-leg platform until 2040, compared with a previous closure estimate of 2015.
But many more developments have lower costs. Incremental investments are more attractive to those with limited budgets than grand projects. Low-cost developments have better net present value than larger projects if the barrels are there to be drilled.
Brownfield developments from a fixed installation have kept these production centres flowing, in some cases decades longer than expected. This opens opportunities for quick subsea tiebacks that help to optimise production.
This activity has been increased over the years, with oil majors selling assets to companies with lower cost overheads, which have invested in tiebacks and maintenance.
In 2021, with energy companies postponing major investments, many will reconsider their incremental developments and benefits from prolonging production. These smaller projects will become more attractive and provide opportunities for subsea contractors and OSVs.
Australian LNG back-fill
This is a variation on a theme, but on a far greater scale. Energy companies in Australia, principally those with LNG production centres, will need to invest in offshore gas field developments to feed these plants as the primary fields’ output decline. These projects become even more attractive if they contain condensate resources as these are prized over gas.
After a two decade-long LNG construction boom, operators are considering projects to keep production and exports at near maximum levels.
There has been more than US$200Bn in investment in seven LNG plants, propelling Australia’s export capacity to nearly 90 million tonnes per annum (mta). Companies will want to maximise their output.
North West Shelf (NWS) LNG processes a mixture of gas from various fields and new ones are needed for this capacity. NWS venture partners have agreements to process third-party gas to extend the Karratha gas plant output for decades.
First up will be development of Mitsui’s Waitsia field, with production scheduled to start in Q4 2023. Other developments are likely to include gas from the Brecknock, Calliance and Torosa reservoirs in Browse Basin, with floating production systems tied to the exiting North Rankin complex and NWS infrastructure, with construction potentially ready to begin in 2022.
Woodside is also considering developing the huge deepwater Scarborough gas field with a floating production platform and pipeline to the Pluto LNG plant.
This is part of a proposed brownfield expansion that includes a second LNG train and hundreds of miles of new subsea pipeline. A final investment decision is expected in 2021 for this 7.5 mta project.
There could also be a Pluto-NWS interconnector pipeline as part of the Burrup Hub strategy.
Inpex has started engineering and contracting on a new phase of development at the Ichthys field in the Browse Basin, which feeds an LNG plant in Darwin.
Chevron has struggled with operational problems at Gorgon, but gas resources are huge at this centre. It has also been exporting LNG from Wheatstone since 2017, with a second train online in 2018.
Shell’s Prelude floating LNG plant has been offline since February 2020 and is likely to remain so until February 2021.
Middle East offshore gas
While other regional offshore markets were under pressure in 2020, the Middle East had consistent requirements and long-term investment. It was a warm bed for OSV activity and will be in 2021.
Despite some budget restraint, there was evidence offshore projects will continue well into this decade, albeit with a year or so delay.
The United Arab Emirates (UAE) approved a US$120Bn energy budget including multiple offshore oil and gas projects for the next five years.
Abu Dhabi National Oil Co (Adnoc) will invest to raise UAE’s oil production capacity from 4M barrels per day (b/d) in 2021 to 5M b/d by 2030 through a combination of new projects and existing field upgrades.
Synergy Offshore chief executive Fazel Fazelbhoy expanded on the expected budget and Covid-induced delays during Riviera Maritime Media’s Offshore Support Journal, Middle East virtual conference on 12 November.
He said funds allocated to the US$30Bn expansion of the Upper Zakum field infrastructure were delayed by Covid. So was the Dalma Sour Gas development project (US$1.5Bn investment), Hail and Ghasha projects, where investment is anticipated to be US$12Bn.
Meanwhile, field optimisation projects at Umm Shaif, Lower Zakum, Satah and Umm Al Dalkh fields are underway to increase and sustain production.
There are similar large investments planned for offshore projects in Saudi Arabia and Qatar, particularly focused on expanding gas production this decade.
Saudi Aramco plans to invest US$334Bn across the oil and gas value chain over six years, representing US$55Bn per year. This includes up to 24 offshore platforms on the delayed Marjan production extension project, drilling islands and 11 offshore platforms on Berri and more platforms for Zuluf field expansion.
In the Kuwait/Saudi Arabia neutral zone, activity is restarting on Wafra and Khafji. In Qatar projects are ongoing on the North field expansion, Al Shaheen, Bul Hanine, Idd Al Shargi North Dome and Mayden Mahzan fields.
With increasing demand for batteries and mobile communications devices, there will be rising requirements for rare Earth elements and rare metals. But, with few new resources discovered onshore, exploration and mining will be focused offshore.
Subsea mining has been developing over the past decade with tests and trials with the technology for deepsea resource recovery.
Seafloor deposits of cobalt, manganese, nickel, lithium and other minerals could become commercially available when demand rises for batteries as nations switch away from gasoline and diesel engines.
Global expansion of this nascent sector is being held back by lack of regulation. However, in 2021 this could change with the International Seabed Authority set to finalise regulations for the exploitation of deepsea minerals.
These should cover the seabed beyond the limits of national jurisdiction. This will be on top of the national regulatory frameworks being implemented.
It is likely commercial deepsea mining will be enacted within five years. However, there are concerns from environmentalists about the impact on marine environments, which could delay the first mining projects.