What could the outlook be for the European gas market?
Global gas prices reached unprecedented levels in 2021, with record prices hit on both sides of the globe. Asia’s JKM LNG price and Europe’s TTF gas price breached the $30/MMBtu milestone. Much has been written to dissect the causes of 2021’s price rally addressing the impacts of COVID-19, China’s move away from coal, pipeline permitting in Europe and low gas storage levels on the back of a cold 2020/21 winter. In this blog we attempt to address whether this is a one-off event or representative of a “new normal” to be expected in European gas markets
It will be a tale of two regions. Europe’s gas woes and those of Asia are increasingly being driven by different fundamentals. Europe increasingly by geopolitical issues / Asia by an increasingly dominant China and continuing issues re contracting and pricing structures.
Renewables dominated Energy systems
The EU has elevated climate change mitigation to form a central focus of its policy setting agenda. In 2021 achieving the bloc’s target of Net Zero greenhouse gas emissions by 2050 became legally binding. This represented the latest step in a pathway of accelerating climate mitigation policy decisions, in motion since 1990, when the EU discussed the first report by the Intergovernmental Panel on Climate Change. This led to a target of stabilising greenhouse gas emissions at 1990 levels by the year 2000.
The penetration of renewables into national generation mixes has been one of the most readily observed impacts of decarbonisation goals. This has been particularly pronounced since 2010, as the dual forces of maturing cost reduction curves for solar/wind power generation and widespread subsidy support enabled a realistic competition with fossil-based generation. The result is an average EU28 generation mix which is made up of 35% renewable sources. This trend looks set to continue as the push of renewables into generation mixes remains one of the easiest ways to slash emissions without incurring economy-disrupting levels of capital costs.
Despite the success in cutting emissions in power generation, this has led to issues related to supply security. Solar and wind power are intermittent in nature and an economic means of energy storage has not been developed to fill the gap when the wind is not blowing nor the sun shining. Europe now experiences an increasingly unpredictable electricity supply, with troughs in renewables production largely mitigated by the firing up of gas fuelled CCGT plants. Grid-Scale Storage is now becoming a much bigger issue particularly with regard to who pays for it within the context of an increasingly connected European grid.
In turn, this has led to an unpredictable and inelastic portion of gas demand which is difficult to contract for on a long-term fixed-price basis. This leaves Europe reliant on spot gas prices to balance the generation mix, leading to significant price volatility for energy wholesalers. As renewables continue to penetrate the energy mix, the magnitude of unpredictable gas demand will increase, leading to increasing challenges in balancing gas markets.
Baseline gas demand in Europe is holding steadfast, despite the rhetoric of an increasingly accelerating energy transition. Gas demand in the generation sector is buoyed by coal-phase out programmes driven by emission reduction targets (with penalisation via the EUETS remaining the EU’s major policy tool to nudge states in this direction). Nuclear phase-outs continue, driven by government reactions to the Fukushima incident. This is against the backdrop of an increasing electrification of society to mitigate carbon emissions at the consumer level (with electric vehicles the clearest example of a large generation demand growth driver). Renewables are not able to keep up with growing electricity demand whilst at the same time replacing large swathes of the existing generation mix, leading to a continued need to run the continent’s CCGTs.
Gas demand in industry remains stable year-to-year due to the lack of available alternatives, with demand destruction caused by COVID-19 and gas price spikes a short-term phenomenon. Natural gas is still the only feasible option for processes which require sustained, intense temperatures. Clean hydrogen, mooted as a like-for-like replacement, is still in the formative stage, with widespread adoption still at least a decade away.
A similar dynamic is present for space heating, with the replacement of gas boilers by either hydrogen boilers or heat pumps not yet having significant momentum. Hydrogen boilers require a hydrogen grid and rapid growth in clean hydrogen supply, both of which remain in the feasibility study phase. Heat pumps are limited by the high costs of retrofitting (~£10K), where most of society is proving unwilling to pay for a product which is not obviously superior to existing gas boilers. Government (taxpayer?) support would be needed for meaningful replacement, which is not yet forthcoming.
The reality faced by Europe is one of steady baseload gas demand, supplemented by an unpredictable section of demand driven by inherently unstable renewable generation.
European natural gas production is in long-term decline, with volumes down 17% between 2018 and 2021. The heartland European gas production regions have entered systemic decline.
The loss of Groningen production has led to the removal of almost all flexibility in European domestic gas production leading to significant challenges to the balancing of an unpredictable gas demand profile. Producing as much as 50 BCM of gas in the middle of last decade (comparable to a quarter of current EU28 production) the field will be completely shut down from 2022. This loss was not due to a lack of reserves, but is a reaction by the Dutch Government to seismic events caused by production
The decline in North Sea production is however caused by declining reserves. Low hanging fruit of the Southern North Sea gas basin has been exploited with new hydrocarbon fields presenting increasingly marginal economics. This has led to an exit by the world’s supermajors, recently evidenced by the retreat of Shell from the Cambo project, West of Shetlands, a cornerstone project for the prospective region. Private equity backed players entering the void are more concerned about cutting costs and squeezing production tails than funding exploration wells. The trend of North Sea decline is unlikely to reverse
These factors have combined to create a continuously declining domestic gas supply and the removal of any flexibility cushion. Much is made of gas storage infrastructure, with the decision to close the Rough storage site (a depleted gas field located approximately 29km off the east coast of Yorkshire), in the UK in 2017 a contentious decision (previously responsible for more than 70% of storage capacity). However, Europe’s primary issue during 2021’s price spike has not been available storage capacity, but the struggle to procure gas to fill sites. Europe now relies heavily on its import partners to meet its supply needs and is fully exposed to the type of market volatility typical seen in import-dependent Asia (the US forms a counter example where robust domestic production has muted recent price spikes). It has little choice but to take global market prices to balance gas supply/demand imbalances
European Energy Policy
EU strategy regarding gas has in recent years focused on a continued “liberalisation” of the market, building on the Third Energy Package. Considerable pressure was placed on Russia (responsible for ~45% of the EU’s natural gas imports) to move away from long-term oil-linked pricing (with international oil markets being deep and mature) for its gas supply towards gas hub-based terms and to reduce the length of supply contracts. Russia has agreed to these requests, though this has proved a somewhat pyrrhic victory, leaving Europe in a situation in which it is more exposed to the gyrations of spot market prices and, through these, the global gas market. The price of Russian gas supply to Europe is now indirectly influenced by gas market dynamics in booming Asian demand hubs, a linkage that was not previously seen. Throughout the supply crunch seen this winter Russia has stuck to the letter of its contractual agreements regarding volumes shipped, to the frustration of Europe which expects more flexibility and seems to have been surprised by the price volatility introduced by a move to a hub-linked price mechanism. This restructuring of contracting seems unlikely to reverse and with revenues increasingly tied to European hub prices, Russia is not at all incentivised to act to reduce European prices by shipping incremental supply
Eastern European states, more reliant on Russia, have been most impacted by this new dynamic, increasing the tensions caused by existing differences of opinion between EU member states about the pace of the energy transition. It has proved challenging to form a common energy policy across the union. Individual countries are adopting differing strategies and timelines leading to an increasingly patchwork energy system. North-West Europe rushed to phase out coal fired power generation and aggressively built out wind power, only to find the wind stopped blowing. For most of the summer and the autumn of 2021, wind speeds were at some of the lowest levels for the past 60 years. The reaction was a panicked rush for natural gas, procured at painfully high spot market terms, the only other alternative being the firing up of coal-based generation. Eastern Europe has been reluctant to give up coal, with this likely leading to an increased reliance on Russian gas. This has fractured relationships with Western states who want Europe to act as an energy transition leader. A lack of consistent direction and planning means back-up and flexibility are missing, forcing Europe to rely on spot-linked gas to balance energy markets.
Relationships between Europe and Russia have become key now. Russia clearly sees Europe’s current political weakness as a major lever to apply economic pressure especially with US being increasingly focused on domestic issues.
Lack of Capital for Oil & Gas Companies
The roll-out of governmental decarbonisation policies has been mirrored by an acceleration of corporate pledges from the financial sector to support Net Zero efforts. This was brought to the fore in the formation of the United Nations Glasgow Financial Alliance for Net Zero, stimulated by COP26, in which more than 160 firms managing $70 trillion in assets pledged to steer investment to support a global Net Zero 2050 target. This crystallised a trend seen in the past decade towards the increased importance of ESG (Environment, Social, Governance) considerations by investment committees weighing up capital allocation options in the energy sector. It has proven easy to find and communicate the ESG advantages of renewables projects, however fossil fuels have found it harder to clear this hurdle. Even gas’ role as an immediate coal replacement (responsible for much of the carbon reduction progress to date) has not been enough to convince some investors, who have completely retreated from the fossil fuel sector
The resulting lack of capital investment for fossil fuel projects is leading to increasingly tight supply as existing fields in decline fail to be replaced. There is an increasing reliance on national energy companies to bring forward projects. This has recently been exacerbated by the tightening of purse-strings which occurred with the COVID-19 pandemic. The financial industry’s adjustments to the allocation of capital has been immediate, jarring with the reality of a multi-decade transition to a new energy system. This has increased the risk of energy shortfalls as renewables are unable to fill the gap in energy production caused by the lack of funding for new fossil fuel projects. A tight global gas market has led to rising prices in an increasingly import dependent Europe. Future investment in gas will increasingly be driven by Asian-focused investment which will present significant angst to European markets given current policies directed at aggressive reduction in hydrocarbons markets.
Increased Trader Involvement
The long bull run in gas prices has attracted speculators, who in the past had focused more on the crude oil market. In recent months, financial players and traders have been committing to deep positions, not only in natural gas markets but also in electricity markets. Analysis of the commitments of traders’ report of ICE Europe data on TTF futures trading shows that speculation has been a major driver behind the current price spikes and shortages, rather than fundamental shortages.
Financial players have been betting on higher prices since the beginning of this year. A leading investment bank pitched a commodities “supercycle” in April 2021. All other major financials followed suit very soon after, leading to a community wide energy price spike expectation. Initially the driver of their price surge forecast was low crude stocks in the USA (which is not unusual for this time of year) but then the crude oil hysteria jumped over to natural gas, after Gazprom’s condensate processing facility at Amur in Siberia was destroyed by fire, despite the fact that this had very little impact on natural gas supply.
This hot pool of money has exacerbated a trend of rising prices beyond the on-the-ground realities of supply/demand dynamics. Financial players and traders now have extreme exposure in their portfolios and billion-dollar margin calls have become the norm. This has led to a whipsawing of energy pricing as the long-term thinking of the energy supply chain has been superseded by short-term paper trading. When it comes to energy trading in Europe, financial players are increasingly holding all the cards and are able to influence, or drive, the market. Volatility has spiked, leading to more traders entering the market and a feedback loop which does not seem likely to reverse any time soon. Traders benefit from price volatility as opposed pricing going one way or the other. They will continue to promote volatility in all markets as best they can. Lack of new development capital is no doubt feeding the flames of increased volatility. Right now, the US alone has power to quell them.
What happens next…
The price spike seen in European gas prices is not a one-off but driven by long-term trends:
- Gas demand is increasingly erratic due to the role it plays in plugging the gaps in electricity supply caused by volatile renewables generation
- The combination of robust baseline gas demand and declining production, eliminating the usual supply cushion has led to a market reliant on imports to smooth unpredictable supply/demand imbalances
- EU energy liberalisation policy has inevitably led to gas import pricing which is increasingly linked to global spot markets
- Global gas markets are tight due to the lack of funding for major fossil fuel capital projects, leading to high prices, to which Europe is fully exposed
- The involvement of financial participants in gas trading has led to increased amplitude during price swings
None of these factors seem likely to reverse anytime soon and European governments and consumers will need to get used to increasingly volatile gas market prices. Nobody has said a global energy transition would be easy to implement, or that consumers or taxpayers would not be impacted.
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Tom Fox, Lead Gas, EMEA
Tony Regan, Lead Gas & LNG, Asia Pacific
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