Gloom overshadows North Sea exploration hits
Two pieces of good news in the UK and Norway are buried by cost-cutting and depressed prices
The renaissance of the North Sea since the 2014 oil price crash has largely been a technical, economic and corporate triumph. How it survives the twin challenges of another bout of unconstrained supply coupled with a demand-side hit unprecedented outside of wartime remains to be seen.
Already, North Sea operators are announcing capex and opex cuts they admit will impact production. The optimistic view is that the post-2014 bloodletting has left a province well prepared to weather a sustained downturn. The less-rosy view is that a province that has taken out so much of its fat will be cutting painfully into muscle—with good projects and efficient supply chains jettisoned.
One cloud on the previously more promising UK and Norwegian continental shelf (UKCS and NCS) horizons had been the lack of exploration drilling and success, particularly in the search for substantial new discoveries rather than near-field exploration. The latter is understandably more popular in terms of the reduced risk of dry holes and the cost savings offered by proximity to existing infrastructure.
But the size of near-field discoveries is almost inevitably smaller—leading to concerns over reserve replacement. These will only be exacerbated by promised cost-cutting, with exploration spend an obvious quick-win solution.
Upping the pace
The NCS sees more wells drilled as a result of its fiscal system, which offers refunds of 78pc of unsuccessful exploration costs. But even it saw a post-2014 downturn from 44 wildcats that year to a low of 21 in 2017, according to Petroleum Economist analysis of data from the Norwegian Petroleum Directorate (NPD). Activity recovered to match 2014’s 44 wells in 2019, with six bores completed so far this year, the NPD reports.
The UKCS saw a similar trend of decline, to as few as seven exploration wells in 2018, according to the UK’s Oil and Gas Authority (OGA), before activity rebounded in 2019 to 18 exploration wells. Even while noting the improved count compared with 2018, Nick Richardson, head of exploration and new ventures at the OGA, was late last year cautioning that the number of spuds was still two shy of what had been planned, and saying an “injection of pace [is] needed around resource progression”.
“Injection of pace [is] needed around resource progression” Richardson, OGA
The timing of the announcements by Total and Hungary’s Mol of exploration success on the UKCS and NCS respectively is therefore somewhat ironic. Mol was hunting close to the existing Balder and Ringhorne fields in the Norwegian North Sea.
The Iving discovery it made has initial estimates of 12-71mn bl oe of oil and gas resource in place, c.85pc of which is light oil of 40° API, and with further upside potential. Its Evra probe also hit hydrocarbons, but further appraisal work will be required to determine the resource potential.
The project partners aim to tie back the discoveries to existing nearby infrastructure, according to Swedish producer Lundin, which, like Mol, holds a 40pc stake in the licence— emphasising its near-field nature. Follow-up prospectivity also exists, says Lundin.
On the UKCS, Total sees its success at the Isabella prospect as “encouraging”, although it will continue to analyse data to determine an appraisal approach aimed at confirming commerciality.
Again, the focus is on proximity to existing infrastructure—Isabella is 40km south of the Total-operated Elgin-Franklin complex in the Central North Sea. “Our exploration strategy in the North Sea to explore for value-adding prospects nearby to our infrastructure is working,” says Kevin McLachlan, senior vice president for exploration at Total.
But, as Isabella is a gas-condensate find, the current price environment has put a dampener on enthusiasm. The TTF front-month gas price is trading around the €8.50/MWh mark, hardly a price level to encourage rapid development of a gas field.
12-71mn bl oe – Estimated size of Iving discovery
“Progression is likely to be put on the backburner at current prices,” says Glenn Morrall, an upstream research analyst at consultancy Wood Mackenzie. He notes that the find’s high pressure/high temperature (HP/HT) nature will add complexity and cost.
“But given the abundance of nearby infrastructure, the discovery could be commercial should we see a pick-up in sentiment—some HP/HT fields around the world are commercial at as little as 15mn bl oe,” he continues. Total’s HP/HT experience with the Elgin-Franklin and the Culzean fields makes it a well-qualified operator for this challenge.
UK independent Neptune Energy holds a 50pc non-operated stake in Isabella—Total’s share is only 30pc, but the major is known to place an onus on operatorships in its UKCS business. Neptune made it a good exploration week by also announcing an oil discovery at the Schwegenheim onshore exploration well in the Rhine Valley, Germany.