Soaring gas prices put North Sea back on exploration map
In March, the valves on an offshore pipeline 30 miles off the Norfolk coast were opened for the first time to release gas drilled from more than 7,000 feet under the seabed.
Aim-listed IOG will pump it to the nearby Bacton terminal where it will be processed for sale to BP’s gas marketing arm, which will distribute it to households, power stations and industrial groups making goods such as plastics and medicines.
From the North Sea’s 1970s heyday until the early 2000s, the UK was able to meet all its own gas demand. But production has declined sharply over the past two decades and the country now imports more than 60 per cent of its needs via pipelines from Norway and the EU, and ships carrying liquefied natural gas from the US and Qatar.
After years of falling investment in North Sea infrastructure, soaring gas prices are prompting a new wave of interest in gas exploration on the UK’s continental shelf.
With some oil and gas majors such as BP and Shell divesting assets in recent years, much of the rejuvenation is being led by smaller companies such as IOG, Neptune, Kistos and Serica.
“There’s a lot more interest in exploring North Sea gas,” said Ashley Kelty, analyst at Panmure Gordon. “Small discoveries that were deemed uneconomical at 50p a therm are now worthwhile and companies are thinking, ‘how quickly can I develop this?’. Companies are going over old acreage that was deemed fallow and seeing what they can find.”
IOG’s chief executive Andrew Hockey said the company was aiming to “increase production in the near term via our existing infrastructure to support energy security over this winter”.
The producers’ interest has been helped by a resurgence in bank lending and by the government, which is subsidising investment and this month opened the application process for more than 100 exploration and development licences.
“There’s a huge opportunity to reboot oil and gas in the UK,” said Sam Laidlaw, executive chair of Neptune Energy, which has already doubled production at one of its fields over the past six months.
Despite huge progress in the transition to renewable energy, gas remains essential to the UK because of the intermittency of wind and solar power and limited battery storage. Gas is used to heat 85 per cent of homes and generate 40 per cent of the UK’s electricity.
But although there is some hope that an increase in North Sea production and the reopening of storage will protect Britain from the most severe energy price shocks, few expect it to arrest the continental shelf’s long-running decline — or to drive down energy costs or prevent blackouts this winter.
New fields take two to five years before they can produce and the gas is sold at prices set by international markets.
“Finance for North Sea oil and gas projects has started to come back but this isn’t a quick fix” to the gas supply crisis, said Jim Bradly, director at consultancy RPS.
Gas prices soared 400 per cent in 2021, largely as a result of the recovery in demand following coronavirus lockdowns and adverse weather conditions that led to a decline in wind power and a renewed reliance on gas.
“The rise in gas prices has nothing to do with the war in Ukraine,” said Panmure Gordon’s Kelty. “It was rising well before Russia’s invasion, though obviously the forced removal of the world’s second-biggest energy supplier has exacerbated the crisis.”
As the gap between supply and demand persisted, competition for the fuel sent prices spiralling higher.
“If Asia is paying more than Europe for LNG, those cargoes will go there and that will drive up prices,” he added. “When the prices start spiking, you’ll literally see the ships doing a U-turn because they’ve found a higher bidder.”
The surge in prices turbocharged profits in the first half of the year at North Sea gas producers including Serica, where they jumped 8,840 per cent on revenues up 250 per cent, and Kistos, where they leapt 745 per cent, though this includes the effects of an acquisition.
The government in July imposed a temporary windfall tax on excess profits that the Treasury expects to raise £5bn this year. It also introduced a development subsidy for producers that, according to the Institute for Fiscal Studies, means “investing £100 in the North Sea will cost companies only £8.75, with the rest paid by the government”.
UK businesses and consumers are paying the cost. Average household energy bills have risen to £2,500 a year despite a cap on bills expected to cost taxpayers £90bn, and there is little expectation that prices will fall soon. Gas prices averaged 295p a therm last week compared with a historical average of 70p to 80p, or just 40p to 50p once seasonal swings are taken out.
There is no obligation on companies to prioritise supplies for the UK, although unlike North Sea oil, 80 per cent of which is exported, most of the gas produced on the continental shelf has to come to shore.
But a surplus of gas in the UK means producers can earn more in Europe and has led to record exports. At the end of last week, European month-ahead prices were €154/MWh compared with €110/MWh in the UK.
“Why sell to the UK if they can sell it to Europe?” said Kelty. “UK companies have been selling their gas into Europe via the interconnector pipes because the price is higher there and the Europeans have been racing to fill gas storage facilities ahead of winter.”
The UK typically buys gas back from Europe in winter months but there is no guarantee this would happen if there was a shortfall on the continent this winter.
And the UK’s gas storage facilities are among the smallest in Europe — enough to meet just 2 per cent of annual demand.
Centrica, which closed the country’s largest facility at Rough in 2017, is in the process of reopening the site, which used to have capacity for 10 days in winter. But it is still negotiating a funding deal from the government and is likely to provide only minimal storage this winter.
“If we had functional gas storage, we wouldn’t need to rely on cross-border flows coming into the UK,” said Kelty.