When navigating uncertainty, finding the right market is everything
Meeting global oil demand will continue to require offshore oil and gas resources. While shale, onshore and renewable energy sources fight for market share, the global offshore industry has responded by re-thinking ‘business-as-usual’. Costs are coming down, rewarding the industry with a wave of new projects to be tested on.
Offshore sanctioning looks to build on 2019’s success
This past year saw a wave of offshore sanctioning activity. After Chevron and partner Total sanctioned the Anchor project in the deepwater US Gulf of Mexico, offshore commitments crossed the $100 billion mark in 2019 (Rystad Energy’s Project Sanctioning Report). This was an increase of more than $25 billion compared to 2014, and these commitments are expected to rise even further in 2020. Nearly $60 billion of the expected greenfield commitments this year are for fields with breakeven oil prices below $40 per barrel. However, close to $55 billion worth of projects have breakeven oil prices above $40 per barrel. Despite current engineering efforts supporting the timing of these funding decisions, the ability of the oil and gas companies’ project teams to further reduce costs will greatly influence the number of actual commitments in 2020 and beyond.
Heated FPSO market will test service industry’s capacity
Riding this offshore wave of sanctioning, the floating production, storage and offloading (FPSO) market had a strong year in 2019, with 13 contracts awarded. According to Rystad Energy’s Global FPSO Report, Modec was the most aggressive FPSO contractor, capturing four of those 13 contracts. The large number of awards has swelled the global backlog of FPSOs under construction or on order to 28 vessels, only two of which will start producing in 2020 (Petrobras’ P-70 and Yinson’s Allan). The remaining 26 vessels are expected to reach first oil between 2021 and 2025, with the bulk of projects forecast to start producing in 2023. As contractors get to work to bring all these new units on stream, clients may face longer lead times or higher prices for future projects, as the industry’s capacity to take on new assignments shrinks.
Subsea collaboration is gaining momentum
Integrated subsea contracts also showed strong growth in 2019, with a record-high of 150+ subsea trees awarded under such deals. This is in stark contrast to the mere seven subsea trees that were handed out using integrated contracts in 2016, when the concept was initially adopted. Integrated contracts – where service providers often partner with each other to provide the full subsea scope, covering subsea production systems (SPS) as well as subsea umbilicals, risers and flowlines (SURF) – have become increasingly popular over the past four years.
Integrated contracts initially gained popularity in the North Sea and the US Gulf of Mexico, but have more recently been gaining traction globally. Australia has now emerged as the third-largest hub for integrated contracts, where three subsea field development projects – Julimar, Pyxis and Ichthys Phase 2 – were all awarded using this contract strategy. Interestingly, the largest integrated subsea contract awarded to date, Total’s Area 1 project in Mozambique, was awarded outside of the three main hubs. With several subsea awards set to be handed out in 2020, it will be interesting to monitor where the integrated contracts trend will evolve to.
Operational changes are cutting costs
Operational production costs in the oil and gas industry have fallen across the globe. Rystad Energy’s Cost Benchmarking Report shows the United Kingdom emerging as a cost-cutting powerhouse among global offshore regions. Fields in the UK have seen increasing production, changing rotation cycles, the closing of older fields and lower salaries, which all contribute to the reduced cost levels. A majority of UK offshore operators switched from two-week to three-week personnel rotations in 2015-2016, generating salary and logistics savings by reducing the number of flights required to shuttle personnel to and from offshore facilities. Still, despite this significant decrease in operational costs, the UK exhibits the highest opex per boe of all major offshore regions due to smaller field size, a fragmented operator landscape, a more mature continental shelf, and a higher number of personnel on board (POB) per produced barrel.
Continuing to be cost conscious will help the industry stay competitive with other energy sources. This will enable operators to fund more work, and prolong the current up-cycle of offshore commitments.