As some choose between heating their homes and feeding their children in the UK, scrutiny of market dynamics that led us here has increased.
Investment in North Sea production has declined significantly in recent years as the majors have pulled back despite energy demand remaining high. This is not unique to the UK, as investors have called for higher shareholder returns from energy companies and green financing mandates have cut financing options. The question is whether a major new rush of investment would help avoid this situation in the future.
The UK government is stuck between its net-zero pledges that see further reductions in North Sea output, and its desperation for solutions to high energy prices. Less than a month ago, Kwasi Kwarteng, business, energy and industrial strategy minister, said additional domestic gas production wouldn’t “materially affect the wholesale market price” of electricity. By this week Kwarteng was sticking to his line about gas being a transition fuel, but also strongly backed continued extraction in the North Sea for decades to come: “that gas is our gas…it means that we’re energy independent”, he said.
So what does that mean for producers? Will they open up the taps to get oil and gas markets back to balance? Not quite.
The CFO for top independent North Sea producer Harbour Energy (HBR), Alexander Krane, put it plainly during last week’s results call: the added cash flow driven by higher oil and gas prices would go to debt reduction and shareholder returns, not an immediate increase in expansion or exploration spending. “... [If] this higher commodity environment remains with us, then yes we will not have much debt by the end of the year and potentially debt-free next year [then] we'll reassess and see if it makes sense to either increase dividend levels or institute buybacks,” he said. “But we think the responsible thing is to have a few months and see how 2022 develops. It's just insane volatility we're seeing.”
Harbour is already increasing production through existing expansion plans, to be clear, and the start-up of the Tolmount field will add 6 per cent to the UK’s domestic gas production. At the same time, the the company's 2021 books showed write-downs for several greenfield exploration assets that it decided were not worth pursuing, including Falkland Islands and Brazil projects. "We believe there are lower risk and lower emissions intensive options to replace our reserves and grow than via frontier exploration or multi-billion dollar greenfield development," the company said.
Just a few months ago, Shell (SHEL) announced it would not go any further in developing the Cambo field in the North Sea. Now there are reports that it is reassessing that decision in light of the new energy environment.
Slower transition
A Shell spokesperson said the December Cambo decision remained in place – “we have concluded the economic case for investment in this project is not strong enough”. But the head of the licensing authority the North Sea Transition Authority (the newly rebadged Oil and Gas Authority) told the Financial Times this week he was keen to issue new licences for explorers this year, the first since 2020.
Harbour chief executive Linda Cook was clear on how the current crisis would impact the majors’ strategies: “I can’t see [them] changing course”. Cook is well positioned to comment: she served on Shell’s executive committee and ran Shell Gas and Power in the UK. “Are [the majors] enjoying the cash flow they're getting today from their upstream assets that they may otherwise be thinking about divesting at some point? Well, of course they are,” she said. “A lot of them will plough that back into other areas of the business, though, not into exploration or not into major new multibillion-dollar oil and gas developments that may not pay out for 10 or more years.”
But despite hesitation to dive right back into projects that might take years to make it to production, investors do have options: on top of Harbour’s expansion plans, Aim-traded developer IOG (IOG) just this month announced first gas at the Blythe and Elgood fields in the North Sea.
IOG ‘recommissioned’ old infrastructure off the Norfolk coast and has started feeding in to the Bacton terminal. BP (BP) signed up IOG to an offtake agreement just before first gas, while broker Peel Hunt has forecast sales of £222mn this year and cash profit of £188mn, giving it a margin of 85 per cent. Investors have already doubled its share price in the past 12 months but an 8 per cent increase year-to-date indicates a recent lack of attention.
Serica Energy (SQZ) is a much more established player and has operated on the standard plan of buying majors’ cast-offs in the North Sea, with a production split of 85 per cent gas, 15 per cent oil. A recent production outage has now been fixed, and management has floated using its cash for acquisitions, while a new exploration well that could be tied back to existing infrastructure is in the works. These players won’t be able to quickly ramp up UK production, but could provide a handy play for shareholders looking for direct exposure to local gas and oil.
Ex-UK supply
The UK and Europe operate on a global trading system and so any new supply would not make a difference to prices. The key player here is the top exporter Saudi Arabia, which has so far not committed to quickly increasing its output. But new spending announced by state producer Saudi Aramco (SA:2222) will make a difference in the medium term.
Consultancy Rystad Energy laid out the options this week as the Opec-plus meeting at the end of the month draws nearer. An “Opec max” response would see around 3mn barrels of oil per day (bopd) in supply brought on, around 3 per cent of global supply, although Rystad also sees potentially for a 2mn bopd loss in supply from Russia sanctions.
“We believe oil prices will stay elevated and balance at around $100-$130 per barrel through the third quarter this year, with some higher spikes likely,” said the consultancy’s chief executive, Jarand Rystad. He added that “core Opec countries” were “unable and unwilling” to fill demand gaps.
Looking further ahead, Saudi Aramco chief executive Amin Nasser said his company’s plans to put an extra $10bn into the capital budget this year on top of what analysts had expected ($36bn) would see production increasing “gradually”. “We've brought a lot of rigs to expedite [it], but it will come in increments, as they say, a slight increase in 2024, and then the big increases you will see from 2025, 2026 and 2027,” he said.
Aramco’s 98 per cent shareholder, the Saudi government (including the 4 per cent held by the Public Investment Fund), determines the production level. “We are producing based on the guideline, the target that we receive in a monthly basis from the government,” Nasser said. Saudi production hit a 10-year low in 2020 of just over 9mn bopd, compared with capacity of over 12mn bopd.
RBC Capital Markets only sees global supply meeting demand in the first quarter of 2023.
Energy industry leaders have pointed the finger at net-zero carbon emissions plans and environmental, social and governance-focused investment strategies for the current supply failures.
The chief executive of Diversified Energy (DEC), Rusty Hutson, told Investors’ Chronicle he was “shocked” the administration of Joe Biden was “doubling down” on climate policies that limited new oil and gas project development. “It’s great for our business, but bad for people,” he said, forecasting another 12-18 months of very high oil and gas prices.
President Biden has said there are plenty of licences to extract oil and gas already issued, and that companies were not putting up the capital. Hutson – whose company produces around 90 per cent gas – said he wanted to send more to Europe, but the infrastructure was not there. “Unleash LNG, it’s the biggest green initiative,” he said.
The EU has already said LNG exports would need to be increased to help wean countries like Germany off Russian gas, but global capacity is limited.
It’s electric
New offshore wind farms and solar plants could bring down wholesale power prices but financing, project permits and construction mean this would be at-best a 2024-2025 solution.
Bloomberg Intelligence (BI) has forecast a four-year, €300bn (£250bn) investment splurge could see renewables replace gas demand in the EU and UK. Wind capacity would need an 11.5 per cent compound annual growth rate and solar 27.5 per cent. BI said this would be possible given 2017-2020 annual growth for turbine deliveries from major European renewables companies was 17 per cent.
The chief executive of Aim-traded retailer Good Energy (GOOD), Nigel Pocklington, said a complete u-turn on net-zero carbon emissions plans in response to the crisis would be the wrong approach.
“Given fossil fuels have been the primary cause of our current energy crisis, it seems wrongheaded to suggest they are the solution,” he said, arguing that the UK did not have an energy security issue and would benefit from “diversity and flexibility of technologies”.
The UK government’s plans will become clearer next week when the energy policy is announced. It has already dismissed oil demand reduction ideas such as encouraging people to drive less, while it’s clear many people are already cutting gas use to save money.
For investors, it’s clear an immediate splurge on new North Sea capacity won’t solve our current crisis. But projects like IOG’s continue will maintain key domestic production for years to come.
