Existing gas-fired power plants of at least 20MW already add up to 2.4 million MW of power generation capacity; planned plants are set to increase this to three million MW. There are currently around 2.3 quadrillion cubic feet of recoverable natural gas reserves in active oil and gas fields; this is set to increase by another 800 trillion cubic feet (another likely significant underestimate) once planned new gas fields come online. Countries everywhere are maximising gas extraction. The US Environment Information Administration estimates that 7.3 trillion cubic feet of natural gas exists in proven reserves.
Analysts spoken to by Energy Monitor say the data shows an industry heading in the wrong direction, posing significant climate and financial risk.
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“Gas is not a transition fuel, it is part of the oil and gas sector, which has had its heyday for over a century,” says Deborah Gordon, senior principal at think tank RMI and a senior fellow at the Watson Institute at Brown University, US. “We will likely never get entirely off oil and gas, but we need to dial it down rather than put the development of these resources on steroids.”
Dennis Wamsted, from the Institute of Energy Economics and Financial Analysis (IEEFA), agrees. “The discussion now is all about decarbonising by 2050 – and that has to mean gas is essentially a non-starter. If we are serious about tackling climate change, these projects cannot happen.”
Energy transition policy discussions have been largely focused on phasing out coal but, argues Joanna Flisowska at Greenpeace Europe, the discussion needs to move to other fossil fuels like natural gas. “This is the next big issue that must be targeted in the fight against climate change,” she says.
Upstream data shows many hundreds of gas fields set to continue producing gas in the second half of the century. These include more than 4,000 active fields, such as the huge Bovanenkovskoye Field in Russia, with 98,368 billion cubic feet (bcf) of remaining reserves that are set to produce until 2091, or the 20,116 bcf Kroll Field in Norway, set to last until 2051.
Upstream data also includes fields where extraction has yet to begin, but which have either received a final investment decision (around 150 in total), or are en route to one (around 280). Such fields include the 43,377bcf North Field East in Qatar and the 41,439 cf Prosperidade field in Mozambique. A further 5,016 fields are listed as “discovered”, meaning the presence of gas has been confirmed, but their commercial viability is yet to be determined.
“Data that charts how gas fields will remain [in production] up to 2100 is testament to the fact that gas is abundant,” says Gordon. “We will never run out, and therein lies the rub. We cannot solve our climate problems through demand shifts only. The oil and gas industry typically acts like a herd. When they are in, they are all in. You can see this in the trillions of dollars of planned investments.”
New gas infrastructure
Once gas is extracted, it is usually transported through pipelines, which can be thousands of kilometres in length and cross continents, or turned into liquefied natural gas (LNG). For an LNG facility to be economical, there must be a resource large enough to provide natural gas for around 20 years.
The data nevertheless shows a massive scaling up of LNG production. There are 306 gas liquefaction plants worldwide and another 366 on the way. There are also 156 regasification plants, with another 182 coming online. LNG is “on the cusp of becoming a global commodity like oil”, says Sreedhar Kona at Moody’s Investors Service.
A proliferation of new regasification plants can be found notably in China and India, suggesting these countries are looking to transition from coal to gas, and amass “future geopolitical clout”, says Gordon. Data also shows 298 gas tankers are under construction, on top of the 598 that already exist. Global pipeline capacity of 200,000 million standard cubic feet per day (mmcfd) is being added to the roughly one million mmcfd of existing capacity.
Power plant data, meanwhile, shows total gas-fired power generation capacity is set to soar, from 2.4 million MW to three million MW. Asia-Pacific is leading the charge, with pipeline capacity of 230,000MW, set to make the region the world leader for gas-powered electricity generation, overtaking North America.
A huge concentration of future gas power plants is under development in the US, western Europe, Japan and South Korea: affluent regions with ambitious climate pledges. Countries in the Global North will benefit most from a gas build-up, Gordon says, while those in the South will suffer most from climate change. “The environmental equity and injustice of this future must be recognised before it is too late,” she adds.
Hydrogen, CCS and no more coal: attempts to justify natural gas
Many in the energy industry maintain that natural gas and its associated infrastructure are relevant to the energy transition.
Franck Neel, president of the Oil and Gas Employers’ Federation in Romania, recently penned an article arguing natural gas is a “mature low-carbon technology” that can “ensure no European citizens are left behind” as coal is phased out. However, Greenpeace’s Flisowska argues that transitioning from coal to gas and then again to renewables would mean “putting workers through unnecessary difficulty, in what is already a very complicated process”.
In the US, utilities are investing in natural gas infrastructure “with the specific thought of incorporating hydrogen”, says Ryan Wobbrock at Moody’s Investors Service. “There is a lot of uncertainty around this strategy and companies will absolutely need public policy to drive change.”
The IEA anticipates global production of hydrogen will increase from 87 megatonnes (Mt) in 2020 to 528Mt in 2050, in a net-zero scenario. This figure would produce around 75 exajoules (EJ) of energy, according to conversion factors provided by the industry-led Hydrogen Council, equivalent to around 75 days of the world’s current final energy demand. This represents a huge scaling up, but still remains much less than the 138.7EJ of natural gas produced in 2020, according to the 2021 BP Statistical Review of World Energy. Hydrogen produced in the future will also have uses in transport and industry where natural gas is not currently used.
The IEA’s net-zero pathway also anticipates around 25% of future hydrogen production going to buildings, compared with 65% of natural gas going to those sectors in 2018. The modelling suggests it is unwise to plan as though hydrogen will be used in the same way as natural gas.
Oil and gas companies advocate carbon capture and storage (CCS) as a means of mitigating the future impact of natural gas, but while the IEA anticipates significant use of CCS in a net-zero scenario, the agency adds that around 55% of the cumulative emissions reductions anticipated from CCS are from technologies still “at the demonstration or prototype stage today”.
CCS technology has proved difficult to get right. Company data shows oil and gas major and self-proclaimed “global leader” in CCS technology ExxonMobil captured just 6.8 metric tonnes of CO2 equivalent (MTCO2-e) of emissions in 2019, compared with a total of 690MTCO2-e scope 1, 2 and 3 emissions produced.
Climate and economic risk of natural gas
Given the headwinds facing natural gas, analysts interviewed by Energy Monitor generally believe a significant chunk of the global natural gas pipeline will not come into existence.
“Oil and gas has traditionally been thought of as a high return development arena, but that is becoming less so as we go forward,” says IEEFA’s Wamsted. “A lot of the projects listed in the data will increasingly not make economic sense, and will likely not get built.”
We will likely never get entirely off oil and gas, but we need to dial it down rather than put the development of these resources on steroids. Deborah Gordon, RMI
Robbie Andrew at the CICERO Center for International Climate Research, a think tank in Norway, adds: “A lot of these plans [are] based on forecasts made a number of years ago. Big industries don’t always move quickly, and it will take time for them to respond to climate pledges made in more recent months.”
Both Andrew and Flisowska suggest the natural gas pipeline could follow the pattern of cancellations seen in the coal industry. Between 2015 and 2020, the number of coal plants at the pre-permit stage of development fell by 72%, shows data from Global Energy Monitor. The number of coal plants that started construction in the preceding 12 months also fell 72% in the same period.
Cancellations have started in the natural gas industry. “One of the largest utilities in the US, Duke Energy, is proposing massive new gas-fired generation in North and South Carolina, but regulators have recently told them to essentially go back to the drawing board,” says Wamsted.
In 2020, Dominion Energy sold its natural gas transmission and storage business to Berkshire Hathaway for $9.7bn, signalling not only a realignment towards renewables, but also the need to generate significant capital to pay for the energy transition. In 2019, Dominion and Duke cancelled their ambitious Atlantic Coast Pipeline, citing “an unacceptable layer of uncertainty” arising from permit challenges from environmentalists.
Nevertheless, to expect economics alone to wind down gas demand would be a tall order. As it stands, gas is by no means a declining industry: global demand for gas is set to grow 3.2% in 2021, anticipates the IEA, more than erasing the 1.9% drop in demand witnessed in 2020.
The failure of companies to phase down gas in line with emissions pledges can be attributed to “a lack of coordination between policymakers and oil and gas companies”, says Dmitry Marinchenko, a senior director at Fitch Ratings. “The main problem is that the pace of the energy transition is unknown, policies lack clarity, and companies and commodity exporters may have very different views on the most probable scenarios.”
The EU continues to debate the status of gas in its taxonomy for green investments, creating significant uncertainty for the sector in Europe and beyond. Given how recently countries like China and the US have signed up to net zero, “there remains a lot of uncertainty in the industry, as companies don’t know how serious countries are with their pledges”, says CICERO’s Andrew.
Although renewables are now cheaper than gas in most markets, “expertise remains in the traditional fossil fuels sector and in building power stations”, he adds, meaning these industries are likely to remain of interest even as they become less economical options.
If companies fail to transition towards a pathway that makes economic sense, their natural gas assets risk becoming stranded, unable to continue offering returns before the anticipated end of their economic lives.
Already, recent years have seen oil and gas majors write down massive chunks of their portfolios after deciding they were no longer economically viable in current market conditions. The oil and gas industry in the US, Canada and Europe wrote down a combined $145bn in oil and gas assets in the first nine months of 2020, shows recent analysis.
“Many gas drillers in the US have been over-investing in the past ten years,” says Wamsted. “There has been an explosion of gas production in the country, but a lot of very poor returns.”
Stranded assets: who pays?
When projects fail, it is not simply corporations that lose out. Significant financial hits have to be absorbed by investors, ranging from extremely wealthy individuals to middle-income individuals building up their pensions. The establishment of the Climate Action 100+ initiative in 2017, which now includes 575 fund managers controlling $54trn in assets, demonstrates investors’ increasing desire for the companies they invest in to move away from fossil fuels.
Equally, when it comes to utilities’ investments in infrastructure and the power sector, it is often end users who end up bearing the costs when things go wrong
“Utilities expect investments to be repaid by the end user, and so often it is customers who bear the risk,” says Wobbrock from Moody’s. “And when government subsidies are involved, these will come back around in bills charged to the end user.” The more turbulent the energy transition is and the more bad investments utilities make, the greater the risk customers are sent more expensive energy bills.
For very large investments, such as beginning extraction from a new gas field, public finance is often involved. State-owned energy companies hold around 90% of known oil and gas reserves, while national and multinational public finance institutions continue to heavily support gas extraction overseas, even as they move away from backing coal. If public money is directed towards bad investments, “it is the taxpayer who bears the risk – and as the natural gas data shows, that risk is massive”, says Lisa Fischer from the climate think tank E3G.
Wealthy countries with good credit ratings and diversified economies can, to some extent, absorb bad investments, but developing countries that over-invest in natural gas assets could potentially suffer catastrophic impacts.
“If gas developments go ahead, it is likely countries like Mozambique, Guyana and Suriname will see their assets become unprofitable midway through, as gas demand falls, but if the market allows them to keep extracting, it is likely they will suffer severe climate damage they cannot afford to easily adapt to,” says RMI’s Gordon.
Ultimately, a more coordinated global exit strategy is required for natural gas, which includes economic support for more vulnerable countries.
“From an environmental standpoint, we would not invest in any more gas from today onwards, but the way the global economy is structured means gas is still needed for some time," says CICERO’s Andrew. "A kind of coordinated response, which has been lacking throughout the climate negotiations, will have to be better navigated if countries are to meet climate pledges.”
This article was amended on 30 July 2021 to correct the costs of future infrastructure as recorded in GlobalData's database. The costs of future gas pipelines is $423bn, not $907bn as previously stated, while the cost of future liquefaction plants is $456bn rather than $480bn. Similarly, the cost of future midstream storage is $58bn rather than $92bn, while the cost of future regasification is $86bn rather than $89bn.
Nick Ferris is a data journalist based in London.