While the main theme of IEA Director General Fatih Birol’s speech at the Energy Institute event was about the coming of the age of electricity, he also predicted a near-term bump in gas. Natural gas reaching the market from the end of next year until 2030 would increase current LNG volumes by up to 50%, some 250bn m³. The source of the gas is mainly the US – which recently lifted a temporary ban on LNG export – but also Qatar, and a bit from Canada and some African countries.

Birol added: ‘If all goes well and there are no major shake-ups in the world, gas markets will likely turn from a market of the sellers to buyers. That may have implications for the gas prices, and of course they have a link to electricity prices. This will be a change in gas markets.’

The occasion, he speculated, might spark a decision from some eastern European countries to consider replacing the Russian gas they continue to buy with other sources.

Representatives of two of the largest international producers, Shell and BP, also said they are expecting increases in gas supply.

Shell’s Executive Vice President of Integrated Gas Cederic Cremers said: ‘It’s clear there will be a lot of extra supply coming on to the market. As a start, I think that’s a good thing, because it means that there is going to be more gas available to key markets that need them, and that need them as part of their decarbonisation journey.’

He continued: ‘If we look forward at the dynamics of European demand – and we see the same by the way in places like Japan – in these transitioning markets, gas is likely going to be needed for longer. As a union, although a lot of progress is being made, Europe is falling short in its ambitions in the energy transition, whether that be in solar and wind or heat pumps. We believe still in this decade LNG will play a role in that.’

Cremers also put forward a case for gas as a transition fuel. ‘Where we are today, providing more gas to the world frankly is helping to reduce emissions… Switching away from more traditional sources is actually reducing the carbon footprint by shifting to gas.’

He predicted that the total market would see an additional 170mn tonnes between now to 2030; much coming before that (130–140mn tonnes by 2028). However, Cremers qualified this by adding that some uncertainty remains with regard to the timing of the additions. ‘Is it all going to come at one time in terms of a wave, or will that be more spread out over time?’

Comparing recent versions of Shell’s annual LNG Outlook reveals that significant volumes of gas, amounting to 30mn t/y, have been delayed in the last few years. Further delays were possible due to geopolitical tension, civil unrest, construction issues such as labour shortages or supply chain constraints.

‘Where we are today, providing more gas to the world frankly is helping to reduce emissions.’ – Cederic Cremers, Shell’s Executive Vice President of Integrated Gas 

Turning to the company’s own products, he said that typically Shell produces half of the LNG it sells through operations that it owns and joint ventures, and the other half it buys from other producers.

Cremers commented: ‘Between now and 2030, we are growing liquefaction by 20–30%; that’s the fastest we’ve ever grown in a five-year period.’

LNG growth projects to 2030 include the LNG Canada joint venture in Kitimat, British Columbia, with Petronas, Mitsubishi, PetroChina and KoGas; Train 7 in Nigeria, with Nigeria’s NNPC, Total and Eni; plus two projects in Qatar; and also as a minority partner of the ADNOC Ruways plant in the United Arab Emirates.

However, despite those predictions of growth to come, for most of 2024 the gas market will remain tight in the European region for the rest of the year, because it has used up most of its winter reserves. These will need refilling before the end of the year. Cremers promised only an additional 10–25mn tonnes in the latter half of the year.

Similar pro-growth sentiments came from BP, which last week announced a wide-ranging strategic shift away from renewables and towards oil and gas production, with a new target of expanding production of both oil and gas to 2.3–2.5mn boe/d in 2030.

At the conference, Gordon Birrell, BP Executive Vice President of Production and Operation, said that oil and gas, refined products and LNG will be around for many years. He pointed to new production projects including the Greater Tortue Ahmeyim project in Mauritanian waters, whose first LNG cargo dispatches next month, and the start of the Kaskida hub in the Paleogene Basin in the Gulf of Mexico, due to come onstream in 2029. He also mentioned the company’s final investment decision on the Tangguh UCC project in Papua Barat, Indonesia, which received a final investment decision in November 2024. The company said that 10 new projects (oil and gas) were to start up by 2027, and another eight to 10 by the end of 2030.

Asked how he sees the role of BP in the transition, Birrell took a backward look through a century of operation, within the context of integrated value chains. A century ago it was putting together oil fields to refiners; 60 years ago it was connecting gas fields to industry and gas consumers, and then in the last 20 years connecting giant oil fields and giant gas fields to the markets through big trunk lines that run through multiple countries, such as the Baku-Tblisi-Ceyhan pipeline.

Green electrons are the next input, he went on to say, and drives the company's investment in solar, wind and CCS business, ‘not necessarily just to sell green electrons, but to have them be part of a value chain that can create other products, starting with perhaps green hydrogen, as well as in refineries moving on to green ammonia eventually, as well as other products’.

Asked later if the company has shifted its mindset back towards molecules from electrons, Birrell said: ‘It’s evolved. We have learned a lot over the past five years about the energy transition and where demand will be, where the margins will be. Our bias is for the end product to be the molecule, the green molecule.’

Reducing methane emissions 
Turning to the production issue of unwanted methane emissions, Birrell reported that since 2019 BP has reduced its methane emissions in CO₂ equivalent by 38%, with a target of reducing it by 50% by 2030. ‘It’s not easy; it takes a bit of investment and a bit of engineering ingenuity along the way. But with the petrochemical capability that the industry has, and certainly we have inside BP, we have been able to continue progressing.’

He explained that the company adopted the Oil & Gas Methane Partnership 2.0 (OGMP 2.0) standard five years ago. ‘Our belief is, you can only control emissions if you measure them. Our big focus and big investment was on measurement, and I’m pleased to say we now have methane measurement, that gold standard, on all our major upstream oil and gas production facilities worldwide.’

In contrast to calculated methane emissions, which carry huge uncertainty bands, measurements indicate that the company has a 0.7% methane intensity. It also has been supporting the Methane Guiding Principles (MGP) initiative.

BP now operates three electric fracking rigs in the US Permian Basin. ‘Once the regulator sees what good looks like, that often encourages us to be what good looks like – the whole industry gets pulled up.’ He added that recently the company’s gas production in the Permian was certified low-methane by third party MiQ.

‘And then markets start to take an interest in that, buying full certified methane into their products.’

Asked if the market is paying a premium for that, Birrell replied: ‘I would like to say that the market will pay in future – I wouldn’t like to say that they are paying today, but that will come.’

At Shell, Cremers added: ‘Absolutely critical for gas and LNG is the methane emissions. We are working on that within industry and really targeting it with lots of initiatives that have been there in the last few years, so I am really excited that is now firmly on the radar screen of industry.’

Cremers is Chair of the Methane Guiding Principles organisation, which the Energy Institute supports.

He reported that, since 2016, methane emissions at Shell’s upstream production and midstream transport and shipping operations have reduced. He added it is now ‘well below’ the 0.2% methane emission intensity for the operational business. The company is also on track to eliminate routine flaring by the end of 2025.

Cremers went on to discuss how Shell was approaching this problem. ‘I’ve found on this journey that one of the huge levers is making it a priority on the front line, in terms of operations. Each individual asset and each operator understanding that this is part of what they do, just as they are focused on safety and reliability of the asset.’

‘A lot of things also depend on some of the operating practices that we have in industry, so we’ve found, as well as other members of the MGP, that a lot of these things pay themselves back. Of course, also, because the gas you save, you can sell.’

• Further reading: ‘Methane: Time for our industry to accelerate action’. Bjørn Otto Sverdrup, a former Equinor Senior Vice President, now Chair of oil and gas decarbonisation body OGCI’s Executive Committee, explains why methane is one area of emissions that the oil and gas industry urgently needs to tackle.
• Reducing upstream emissions of methane has been a hot topic over the past 12 months. Find out how methane measurement standards are lagging despite the publication of significant technical guidance.