Energy after Covid-19 [NGW Magazine]
Covid-19 featured prominently at the Energy Intelligence Forum – formerly trading as Oil & Money – this October.
The pandemic caused global economic turmoil, impacting energy production and demand, with longer-term effects. These come on top of older problems that had beset investors in hydocarbons, largely related to the Paris Agreement.
They include capital flight to greener projects; structural and strategic shifts at corporate level; the growing role of renewable energy; and national emission reduction targets.
Emissions and renewables
The forum heard that Covid-19 could accelerate the process of global emission reduction. But without structural changes, 2020 lockdown-driven declines may end up being only temporary. Keeping global warming below 2°C above pre-industrial levels is achievable only with immediate, drastic emissions cuts, sustained year after year for decades. That is also the message from the International Energy Agency (IEA) in its World Energy Outlook 2020.
China’s ambassador to the UK Liu Xiaoming repeated the position announced by his president Xi Jinping that the country will scale up its nationally determined contribution, strive to hit peak carbon dioxide emissions before 2030 and achieve carbon neutrality before 2060.
He said that China will promote green development and the global energy transition. China's 14th Five-Year Plan will map out routes to a green, circular and low-carbon economy that includes investment and financing to tackle climate change, giving priority to biodiversity and ecological conservation.
He said China was determined to “support the implementation of the Paris Agreement and promote global climate governance firmly.” But he did not give any details how this will be achieved and side-stepped questions on coal-fired power plant construction.
Renewables costs are continuing to fall through innovation, rapid growth, economies of scale and efficiency gains. In Europe, onshore wind lifetime costs have already reached parity with gas, with solar PV soon to follow. That said, despatchable power is not the same as intermittent and so the costs of renewable energy do not reflect the bigger picture.
Offshore wind may take a bit longer but costs are coming down there too. The US is also following closely behind with renewables gaining market share: not only are costs falling but renewables also enjoy lower financing costs.
According to Carbon Tracker, despite the pandemic, announced clean energy investments in 2020 are on track to surpass 2019 by value, propelled by low-carbon power generation. Low-carbon investment activity has risen sharply in the past five years and does not show any signs of slowing.
But more is needed. The CEO of Saudi Arabian investor ACWA Power, Paddy Padmanathan, said: "The market that is front of us is so massive we really need as many participants as we can, and I really hope that the oil companies are able to transform themselves and truly step into this market…I see them as a very value-adding partner, potential collaborators but definitely partners that are much needed in the marketplace."
However he went on to say solar energy, wind energy and battery integration are relatively simple and have a very different business model from oil companies with high exploration risks and operating costs: "We are in a much more stable business. We invest a lot of money. We sit there collecting $0.017/kWh for 25 years. So, it's very stable but thin returns."
European oil companies have adopted net-zero emissions targets and are accelerating their renewables spending. French Total has announced more than 5 GW of new projects this year and UK BP, Anglo-Dutch Shell, Spanish Repsol, Norwegian Equinor and Italian Eni are committing an increasing share of their future business to low-carbon energy.
The competitiveness of natural gas has been given a short-term boost by low prices, but in terms of power generation it is still on the way to be overtaken on cost by onshore wind and solar in the 2020s – even without subsidies.
The natural gas industry often pins hopes on the intermittency of renewables, but the expansion of renewables, development of smarter and more integrated grids, and advances in battery technology will limit this role to relatively small volumes. The closure of coal plant in Europe has not only benefited gas.
However, there is a greater role for gas in meeting wide seasonal demand variations, given current limits on longer-term storage. But even this could eventually diminish if and when green gases – hydrogen and biomethane – are developed and heat pumps are deployed widely.
Hedging its bets, Saudi Aramco is also investing in gas. CEO Amin Nasser said that Aramco has made gas production at home a priority. It also plans to develop domestic renewable energy which must account for half the national energy mix by 2030.
Aramco is also exploring blue hydrogen for heavy transport and blue ammonia, some of which it has sold to Japan for power generation. But Nasser said that much work needs to be done to reduce processing costs and ensure the availability of suitable reservoirs for carbon capture and storage (CCS), or using it in polymerisation. He said Aramco is working on a pilot CCS programme.
But in Europe, where majors have long championed natural gas’ bright future as a ‘destination fuel’, rather than a bridge fuel to renewables, the goal of net-zero emissions by 2050 is changing priorities. Even though natural gas has a strong medium-term outlook, questions about its long-term viability in a carbon-constrained world – and EU’s Green Deal – are mounting. Even though natural gas is still likely to retain a role, based on European Commission scenarios use of unabated natural gas will start declining from mid-2020s onwards and faster post-2030 (Figure 1).
OIES director Jonathan Stern said: “In electricity, renewables have won the battle in Europe, but in industry and buildings natural gas is still key. Hydrogen still has a long-way to go.”
However, so far gas is proving to be resilient. For example, Total sees gas retaining a steady 40% of total sales in 2050, but more and more of this will be green gas.
Ultimately the future of natural gas will depend on maintaining competitiveness against other fuels and against increasingly cheaper renewables, particularly in Asia. This means low prices and tight margins are here to stay. Priority is being given to reducing project costs and carbon footprint – especially elimination of methane emissions.
Future of LNG
According to EI’s LNG Outlook, growing LNG dependence, macroeconomic concerns, environmental necessity, acute electricity needs, climate compliance and competitive renewables are all variables influencing LNG demand.
EI examined a number of scenarios. Its base-case scenario considers policy measures to ease LNG affordability challenges and diversify gas, LNG or other fuel supply in markets where gas and electricity demand are growing, along with consequences of structural changes to base-load generation capacity.
Based on this, EI sees excess capacity around the mid-2020s (Figure 2) and US LNG will continue to take the hit during particularly weak conditions, raising both questions about the need for new US LNG projects and the stakes for competitive developments.
In an alternative long-term supply case EI assumed that fewer projects will advance through 2022. With US projects being the most exposed, it takes incremental US capacity out of the equation. Assuming other projects move forward, this reduces the late 2020s global capacity surplus.
According to EI’s base-case, demand will grow 4%/yr until 2030, but slow down thereafter with China and south Asia accounting for two-thirds of incremental deliveries to 2035.
China will account for around 23% of the growth to 2035, with Europe continuing to serve a critical balancing role when the LNG market is oversupplied, particularly around mid-2020s.
The need to bridge gas supply gaps will remain the primary LNG demand driver in the largest growth markets. The 2020 Covid-19 and oil market crises have presented both challenges and opportunities that could have some LNG demand impact beyond the short term, but EI expects long-term demand drivers to remain intact.
A higher demand trajectory would require more widespread, targeted policy supporting natural gas use over other fuels, or if renewables fail to fill the gap left from phasing-out coal, which in the present environment is unlikely. On the other hand, decarbonisation, particularly in electricity, would see LNG demand growing at less than 4%/yr.
EI sees decarbonisation and faster-than-expected adaptation of renewables remaining a key long-term headwind for gas and LNG, making the low demand growth scenario a real possibility. The long-term growth of LNG demand looks less certain.
Future of oil
Opec is "cautiously optimistic" about oil demand recovery but will continue to "adapt to the changing realities," its secretary general Mohammed Barkindo, of Nigeria, said. "We are determined to assist the market to restore stability by ensuring that stock drawdowns continue in order to restore the supply and demand balance.” But Opec has no illusions that recovery will be quick.
The IEA said that it expects demand to return to pre-pandemic levels by 2023, based on existing and announced policies and targets, and assuming that the pandemic is under control by next year. The US and the EU have already reached their highest demand for crude oil, but China and India are still developing and will drive growing oil demand forward in the years to come.
The CEO of international energy trader and operator Vitol, Russell Hardy, said that Asian demand for all refined products bar jetfuel would probably grow above pre-pandemic levels by the end of this year.
Nasser was also confident that "the worst is definitely behind us," adding that "my prediction is that hopefully we will recover by 2022. I know the IEA is talking about 2023." He cited China’s recovery to support that. “What we see in Asia, especially China, which is our biggest market, is a strong recovery. In China, almost all demand for oil products is back to pre-Covid-19 levels.”
Nasser also referred to an IEA warning earlier this year that global investment in upstream energy is down by a third, year on year (Figure 3), and if that trend were to continue through 2025, "9mn barrels/d of supply will disappear."
He warned: "Yes, there is a concern we might end up with a supply crunch if these levels of investment continue." He added that most investments are going into short-cycle projects, but there is a need for investment in long-cycle projects. Aramco plans to increase its sustainable capacity from 12mn b/d to 13mn b/d at the Saudi government's request.
Hardy shared that view. He warned that massive under-investments in oil production could lead to a new oil price spike in three to five years.
Opec+ is in the middle of a 7.7mn b/d production cut, scheduled to reduce to 5.8mn b/d from January 2021 until April 2022. It then hopes that demand will recover as the world comes out of Covid-19.
But with a second pandemic cycle looming and oil prices hovering around $40/b and Libya restoring production, Opec+ may have to extend production cuts, or even tighten them. These options will be considered when Opec+ meets on November 30.
Occidental CEO Vicki Hollub said that she is expecting US crude oil output to grow modestly next year, with oil market supply and demand rebalancing by the end of 2021. Unlike European majors, Hollub – which bought US shale oil producer Anadarko for a high price – sees strong long-term demand for oil. She said: “I expect we’ll get to peak supply before we get to peak demand.”
However, there is great uncertainty that oil demand will ever return to pre-Covid-19 levels. This is reflected in the huge range of forecasts by reputable organisations, ranging from continuously growing demand – albeit at a slow rate – to demand declining to 30mn bls/d by 2050.
In the absence of a larger shift in policies, it is still too early to foresee a rapid decline in oil demand. But one thing is clear: oil growth as a defining strategy is over.
In addition, the push for low-carbon energy sources and the commitment of many European majors to evolve into energy companies put additional pressure on them to divest low-margin and high carbon-intensity assets.
Norwegian consultancy Rystad Energy estimates that majors may have to sell oil and gas resources of up to 68bn barrels for an estimated total value of $111bn, to adjust to the energy transition.
Commitment to shale
Chevron CEO Mike Wirth reconfirmed and defended his commitment to shale with fewer large, non-shale projects than in the past. But he did acknowledge a less “enthusiastic” outlook for the shale sector generally.
He said: “We’ll continue to prefer a pretty significant weighting on shorter cycle things that frankly offer higher returns and more flexibility.” He added that when it comes to non-shale projects, “Number 1 is you do fewer of them so you can focus more attention on the ones that you’re executing…We’ve got to learn how to really scope things well and prepare well for execution on these.”
Wirth acknowledged the change in investors’ view of shale even before Covid-19, saying that looking ahead, “We certainly won’t see an upturn in activity and the commensurate production response as we come out of this.”
He acknowledged that “demand questions are weighing heavily on the market, but the capital discipline that the industry has lacked is beginning to re-emerge.”
He said: “Investors are holding the industry accountable. You will see the eventual resumption of development in the US being done in a less enthusiastic way, a more disciplined way. I think that means a shallower growth curve…, Whether or not that gets back to 13mn b/d, I don’t think it does in the next couple of years.”
This was echoed by ConocoPhillips’ chief technology officer Greg Leveille, who said the shale sector “had out-run demand levels ahead of this year's crisis, and had now to focus on low-cost, high quality prospects, coupled with technological improvement…. The key for the industry is to get some discipline, run a business like it really needs to be run, returning cash to investors, and end up with a much more profitable industry overall."
Buyers have plenty to choose from, with the risk that in a low price environment less attractive or heavily indebted assets may become stranded.
A former US congressman Dennis Kucinich expressed confidence that “whenever the pandemic ends, the US will resurrect and continue fracking, expand fracked gas infrastructure…completing oil pipelines, exporting gas and oil, while strategically inhibiting production and competition abroad, by whatever means necessary.”
All indications are that the US shale industry will emerge from the pandemic more streamlined and efficient than before and continue to play a major role at home and abroad.
SEASONAL GAS GLUTS MEAN MORE SHUT-INS: OIES
Global gas production capacity will most probably exceed demand next year again, which will mean more shut-in of LNG plants globally, according to a new report by the Oxford Institute of Energy Studies.
There have been shut-ins at pretty much all the plants around the world, with the exception of the lowest-cost producer Qatar, the report’s author Mike Fulwood told NGW, although not below the offtakers’ take-or-pay levels. And even Qatar did some cargo diverting.
Mainly as a consequence of the gas demand reduction caused by Covid-19, the year-on-year rise in output from the US was only about half what it could have been. “With global LNG trade up 10bn m³ and US LNG up 20bn m³, other countries went down 10bn m³,” Fulwood said in an October 22 interview.
The OIES report, $2 Gas in Europe: Groundhog Day, referring to the 1993 Bill Murray film, asks how long might the time “ Whenever the pandemic ends, the US will resurrect and continue fracking, expand fracked gas infrastructure…completing oil pipelines, exporting gas and oil, while strategically inhibiting production and competition abroad, by whatever means necessary.”— US CONGRESSMAN DENNIS KUCINICH loop last for the European gas market? But it points out the uncertainties too, which are partly weather-related and partly to do with Covid-19 as more or fewer people work from home in Q1 2021.
Other uncertainties include further erosion of coal and lignite demand for power generation as gas becomes more competitive; producers such as Norway and Russia curtailing flows again; and LNG demand in Asia, which is already projected to rise by 30bn m³ in 2021, back to the volume growth seen in 2017 and 2018.
The report concludes that although gas demand is expected to rise next year, it might be insufficient to justify the higher price that comes then: “In Europe, pipeline imports have taken the bulk of the reduction in demand... However, our model suggests that pipeline imports will rebound in 2021 and, for prices to rise back as projected, this would imply that LNG supply would again need to be shut in to balance the market at those prices.”