Moscow manoeuvres to neutralise threat from Europe’s latest hydrogen push
Energy transition ushers in new chapter of EU-Russian co-dependence
Editor’s note: Welcome to the very first edition of Energy Flux. For the uninitiated on today’s topics, a brief overview of EU-Russian gas co-dependence and the various forms of producing hydrogen follows at the end of this article.
European policies on climate emissions and clean energy are reshaping the balance of power between the EU and one of its main external energy suppliers: Russia.
Europe’s headlong rush to replace natural gas with clean hydrogen has prompted a strategic rethink at Gazprom, Russia’s state gas company that holds the monopoly over Russian pipeline gas exports. While forcing Russia’s hand is a triumph of EU climate leadership, Europe will need to develop alternative non-Russian sources in tandem to ensure Gazprom does not corner what is hoped to be a growing market for hydrogen supply.
The co-dependency between the EU and Russia around natural gas has long divided opinion across European capitals. While the old debate rages on, the next frontier is opening up: the race for market share to supply low- or zero-emissions hydrogen to the bloc.
Not for the first time, Europe is embarking on a quest for the Holy Grail of decarbonisation: a green hydrogen-based economy that pushes unabated natural gas out of the market. In response, Russia is embracing hydrogen to maintain Gazprom’s sales volumes. Kremlin officials by their own admission see this as both a threat and opportunity.
The European Commission’s proposed new hydrogen strategy calls for 40 gigawatts (GW) of European green hydrogen production capacity to be installed by 2030, and another 40 GW “in Europe’s neighbourhood with export to the EU”.
That’s an almighty undertaking. Spain’s Iberdrola will next year bring online Europe’s largest dedicated green hydrogen production facility for industrial application in Puertollano, with a rated capacity of 20 MW. To achieve only the within-EU 2030 target, Europe would need to build around 200 such facilities every year for the next decade.
To help deliver the other 40 GW, the EC is seeking to put hydrogen on the EU’s international diplomatic agenda. Brussels hopes to kick-start development of huge North African solar farms equipped with arrays of electrolysers to produce vast quantities of green hydrogen. This initiative might well bear some fruit; but reaching tens of gigawatts with associated H2 supply infrastructure within a decade is less certain.
Transporting hydrogen over long distances comes with myriad technical and economic challenges. Hydrogen can be liquefied or bound in bigger molecules that are easier to transport (e.g. ammonia), but widespread global trade of hydrogen aboard ocean-going tankers is not a realistic commercial proposition this side of 2030. Even if intercontinental trade does take off, waterborne hydrogen will command a premium to cover transportation costs.
It is more straightforward and cost-effective to allow existing natural gas pipelines to carry a small percentage of hydrogen in the methane stream, but the EC is not keen on so-called ‘blending’. If each member state has a different proportion flowing in its pipes this would fragment the internal gas market and undermine security of supply, which can cause price spikes in times of scarcity.
Hydrogen production will therefore be developed initially in industrial clusters close to end-users, as is the plan in Puertollano where an adjacent fertiliser plant will absorb all the volumes. As hydrogen demand increases, larger volumes will be piped as pure H2 over longer distances in new or adapted pipes and across wider hydrogen networks.
Moscow saw all this coming a mile off. Gazprom’s Nord Stream 2 (NS2) gas pipeline project, which is nearly complete and would already be in operation today had US sanctions not scared off a Swiss offshore pipelaying contractor late last year, has been future-proofed to carry pure hydrogen, if needed. The existing Nord Stream 1 pipeline running beneath the Baltic Sea from Russia to Germany could also carry around 80% hydrogen, according to Gazprom.
NS2 will probably be completed some time next year, despite Washington’s best efforts to kill it off. When operational, Russia will have the infrastructure in place to deliver a large chunk of the hydrogen called for in the EC’s own strategy. The next challenge will be to produce large volumes of hydrogen cost effectively in Russia.
Gazprom has been exploring production techniques for several years now. Until recently, the Kremlin saw Russia’s vast domestic natural gas reserves as convenient feedstock to produce either ‘blue’ hydrogen using carbon capture (CCS) technology, or ‘turquoise’ hydrogen formed via pyrolysis with CCS.
Last month, Russia’s ministry of energy changed tack by launching an initiative for Gazprom to team up with state nuclear company Rosatom to produce ‘green’ hydrogen using nuclear powered electrolysers.
This seems to be a tacit acknowledgment from Moscow of two things: one, that Europe sees only a limited role for blue hydrogen as a stepping-stone towards the 100% zero emissions green alternative; and two, that if CCS technology fails to commercialise as many predict, Russian gas will effectively be barred from EU markets—potentially stranding Russian pipelines such as Nord Stream 1 and 2.
The EC’s H2 strategy confirms that policymakers in Brussels are wary of over-reliance on blue hydrogen, as this would lock Europe into investing in fossil fuel and CCS infrastructure that is quickly rendered redundant. Infrastructure owners would more than likely lobby to prolong asset life, so shifting from blue to green hydrogen could end up being as difficult and slow as shifting from coal to unabated gas in power generation—something that should have happened decades ago but is only today starting to happen meaningfully across Europe.
It is not yet commercially viable to produce large volumes of green, blue or turquoise hydrogen without some form of subsidy, and if anything Russia is hedging its bets on how Europe’s latest hydrogen odyssey will pan out. But the bottom line is this: Gazprom is well-placed to succeed in ramping up some form of hydrogen exports to meet European demand, should it materialise. If other sources do not keep up, EU leaders will have to sell the politically awkward narrative that augmenting Russian market power is a necessary part of decarbonising European economies.
Seb Kennedy | Energy Flux | 3rd August 2020
For the uninitiated: The rainbow world of hydrogen
The conventional form of hydrogen production is a heat- and carbon-intensive process called steam methane reformation (SMR), which uses natural gas as feedstock. If the carbon emissions are not captured, the end product is known as ‘grey’ hydrogen. If the CO2 is sequestered with carbon capture and storage (CCS), it is called ‘blue’ hydrogen—but this is more expensive than ‘grey’ H2. Also, only around 90% of the emissions are captured, meaning blue hydrogen can be deemed low carbon, not zero carbon.
‘Turquoise’ hydrogen is also derived from natural gas but via pyrolysis: the thermal cracking of methane into hydrogen and solid carbon. Pyrolysis requires much greater volumes of natural gas than blue hydrogen, and continuous production is hindered by soot clogging up the system. Again, pyrolysis with CCS is low carbon, not emissions-free.
‘Brown’ hydrogen is derived from ‘gasification’ of brown coal, or lignite. This process creates synthesis gas (syngas): a mix of hydrogen with steam, carbon monoxide and carbon dioxide. When the hydrogen is separated, CCS can be used to capture the carbon emissions, meaning brown hydrogen can in theory be low carbon too.
All of these low carbon H2 production techniques rely on CCS, or CCUS (where the ‘U’ stands for utilisation). Carbon capture features prominently in the climate pledges of many countries around the world, and those of oil companies (e.g. Shell) seeking to decarbonise their operations. There is a wide gap between the scale of investment required to commercialise capital-intensive CCS projects and the amount of concrete financial support actually committed by industry and governments. While the technology is at least attracting renewed interest, there is still not enough clarity around its cost reduction trajectory.
The zero-emissions alternative is to produce ‘green’ hydrogen using electricity from wind farms or solar parks with electrolysers to separate water into its constituent hydrogen and oxygen molecules. Green hydrogen does not require CCS but is currently more expensive than blue H2. However, the plunging cost of renewable power generation is narrowing that gap. Some analysts see green H2 as being cost-competitive with grey hydrogen as early as 2023, although some experts debate this claim.
Here’s a neat graphic to illustrate the many ways of making hydrogen (courtesy of Resources for the Future):
For the uninitiated: EU-Russian gas co-dependency
Europe relies on Gazprom to meet around one-third of the continent’s gas demand. Europe also receives gas via pipelines from North Africa and increasingly from global markets in the form liquefied natural gas (LNG). Soon, piped gas from Azerbaijan will join the mix via the Southern Gas Corridor. But with indigenous production declining, Europe will continue to need Russian gas well into the 2030s, most experts agree.
Gazprom has also sought to diversify its customer base, and this year started modest pipeline exports to China. But its efforts to get into the LNG game have born little fruit, and Gazprom still relies on Europe for more than half of its net sales revenue. The rest comes from sales within the Russian Federation and to semi-captive former Soviet Union countries.
The European Commission imposed a number of binding obligations on Gazprom in 2018 after conducting an investigation that concluded the company breached EU anti-trust rules by partitioning gas markets along national borders in eight EU member states (Bulgaria, the Czech Republic, Estonia, Hungary, Latvia, Lithuania, Poland and Slovakia). This strategy may have enabled Gazprom to charge higher gas prices in five of these (Bulgaria, Estonia, Latvia, Lithuania and Poland). The obligations, which are detailed here, did not include any form of fine or financial penalty against Gazprom.
In June 2020, Gazprom repaid USD 1.5 billion to Poland’s state oil and gas company PGNiG after failing to overturn an international arbitration ruling that judged Gazprom over-charged PGNiG over many years for Russian gas sold in Poland. Despite coughing up, Gazprom continues to appeal the ruling and award.