North Sea FIDs suffer slippage
Two of the three most anticipated project green lights are postponed and a third looks at
The North Sea’s much-vaunted post-2014 oil price crash renaissance is under significant strain from 2020’s more extreme version. Already, two of the year’s most anticipated FIDs have been postponed. A third may also slip.
In late March, UK independent Siccar Point deferred the planned sanction date for its Cambo project to 2021 “in light of the unprecedented worldwide macroeconomic dislocation resulting from Covid-19”.
Cambo is one of the largest undeveloped fields on the UK continental shelf (UKCS). But it is also important in that its development will create infrastructure for other, smaller West of Shetland (WoS) prospects. Its delay could have knock-on effects beyond just pushing back production from the field itself.
In Norway, the Aker BP joint venture has put non-sanctioned field development projects on indefinite hold. For 2020, Aker BP guides that this will result a capex reduction of 20pc compared with its previous programme. But it also has an initial estimate of reduced capital spend of $1-2bn for 2021- 22. This suggests another expected FID, the Hod redevelopment, will be pushed back not just for 2020 but possibly further into the next decade.
Equinor, the largest player on the Norwegian continental shelf (NCS), promises to reduce 2020 capex by c.20pc, from a planned $10-11bn to $8.5bn. It explicitly identifies the US onshore as an area for “reducing investments significantly” by halting drilling and completion activities.
But it also flags that organic capex reductions will be “driven by a strict process of prioritisation where flexibility of cost and schedule for sanctioned and non-sanctioned projects have been reviewed”.
This raises questions about the non-sanctioned Breidablikk field in the Grane area, where FID had been expected this year. The UK WoS Rosebank field, where Equinor had already pushed FID back to 2022, could also be subject to further delays.
While capex deferrals will impact the North Sea’s future, the health of its existing operations may prove hardier.
“North Sea companies have generally managed to get opex comfortably below $30/bl oe and, in many cases, below $20/bl oe, driving much greater resilience at lower oil and gas prices than previously,” says Daniel Slater, oil and gas research director at London brokerage Arden. But he does warn that companies with larger debt positions may experience issues with debt covenants.
On the other hand, “North Sea oil companies are primarily exposed to the [physical] Dated Brent price,” warns Helge Andre Martinsen, senior oil analyst at Norwegian bank DNB Markets. Dated Brent was trading at only just over $15/bl in early April, reflecting, says Martinsen, “extreme stress in the physical oil market”.
But Slater expects operators to want to continue running platforms, potentially at a loss in the very short-term if required, in anticipation of a price recovery. “Deciding to shut in any facility is a big decision for an oil company,” he says.
One dilemma is that permanent shutins risk decommissioning liabilities. “[But] if this recovery does not come through quickly enough, and older fields are shut in, the Oil and Gas Authority [OGA] has already said it will adopt a flexible approach to the industry,” Slater notes.
The deferral of even smaller-scale projects such as infill drilling and facilities upgrades “will probably harm production in the medium-term”, says Slater. “There is an argument for companies to leave barrels in the ground until prices begin to recover, encouraging deferrals that would have a quick impact on production.”
Larger developments, in his view, will likely need a belief in long-term price recovery to reach sanction. But hardpushed oil services providers may lower prices to secure work, so this could bring future capex savings.
The North Sea had also been anticipating further M&A activity, with utilities Centrica and SSE’s upstream gas assets on the block and Siccar Point having initiated a sales process last year. Other deals are agreed but not completed.
Any uncompleted deal prices negotiated in a $60/bl+ oil price environment “may no longer be seen as relevant”, warns Slater. Price volatility is also a risk to deal-making in the near-term.
Volatility risks a “mismatch” between the oil price assumptions of would-be bidders and what sellers hope to achieve, a challenge Slater witnessed in the 2015-16 North Sea M&A market.
“On the other hand, some companies were able to use the last downturn to find assets at attractive prices by finding sellers with more price flexibility. There will doubtless be some firms seeing the current price downturn as a buying opportunity,” he says.