Germany is the EU’s largest consumer of Russian natural gas. The threat of weaponizing Russian supplies as we approach winter persists, and Gazprom’s recent cut to Nord Stream 1 volumes to 20% of capacity from June 27 onwards is a case in point. To put the volumes at stake into perspective, this article provides a quantitative assessment of the pre-war baseline, the current status quo, as well as possible future developments. Our conclusion examines the degree to which measures that are currently being taken by Germany can counter cuts in Russian supply.
In pre-war times, Russia supplied around half of Germany’s natural gas consumption
Germany needs to import 95% of its natural gas needs (BDEW), inflows which accounted for 3.2% of the country’s overall import costs last year. The surge in European TTF spot prices from Q3-2021 onwards saw this metric jump by 1.5pp vs 2021.Thereby, Germany’s yearly import cost for natural gas exceeded that of crude for the first time, in spite of an elevated oil price environment.
As Germany’s largest natural gas provider, Russia supplied around 50% of German demand via three pipeline systems last year:
· Nord Stream 1 (NS1) which arrives in Greifswald and boasts a nameplate capacity of55 bcm (all bcm figures on a yearly basis unless stated otherwise). According to Reuters data, NS1 has been operating well above capacity at around 63 bcm over 2018-2021.
· The Yamal-Europe pipeline to Mall now via Poland (capacity 29 bcm), imports through which have already been on a decline since mid-2021, coming in at 23 bcm that year (all Reuters).
· Additional volumes from the Volga region and Central Asia arrive through the Czech and Slovak Transgas pipeline, an extension of the Brotherhood trunk line via Ukraine and of Yamal II, which bypasses Ukrainian territory.
Norway is Germany’s #2 supplier, having provided around a third of natural gas imports last year (56 bcm; Reuters). Out of five Norwegian natural gas export trunk lines to continental Europe, three are going into Germany (combined capacity 58 bcm). Additional Norwegian volumes are channeled to Germany via Belgium. The third major provider is the Netherlands; however, exports have been on a steady decline following the phase out of natural gas extraction from the giant Groningen field from 2014 onwards. In addition, LNG volumes from the import terminals in Zeebrugge and Rotterdam are already being shipped to Germany via pipelines and potentially trucks going forward.
Overall, Germany’s natural gas imports totaled 171.3 bcm in 2021 while domestic consumption amounted to 93.6 bcm (Destatis, Eurostat). Hence, almost 78 bcm were re-exported as natural gas wholesalers marketed volumes elsewhere within the EU. While raw import/export data does not allow for a conclusion on the amount of Russian natural gas used in Germany domestically, the German Ministry of Energy pegs this number at 46 bcm in 2021, which gives us a Russian import dependency of more than 49%.
Remaining Russian imports are re-exported to buyers elsewhere with major recipients being France and the Czech Republic, despite significant natural gas imports via the Transgas system, testimony to the interconnectedness of the European continent. Had Nord Stream 2 become operational, it would have further boosted Germany’s role as a European gas trading hub, potentially pushing re-exported volumes above 130 bcm (for comparison, total EU-27 LNG imports came in at around 80 bcm in 2021).
Russian natural gas flows to Germany remain on a steep decline
Germany is aiming for independence from Russian gas by summer 2024. Since the onset of the Russia-Ukraine war, Germany’s import mix has already undergone significant changes:
· Since June 18, NS1 volumes were pegged at just 40% of pre-war levels (except for the10-day maintenance this month) and dropped to 20% on July 27.
· Volumes through Poland (Yamal-Europe pipeline) came to a complete halt for most of 2022amid Poland’s dispute over rouble payment term. Flows even reversed, and Germany sent some 2 bcm of mostly Russian natural gas to Poland over H1-2022.
· Flows via Ukraine (Brotherhood pipeline) are trending below 50% of pre-war levels since early June, curbing flows not only to Germany, but also Austria and Italy(all Reuters).
Overall, Russian flows via the three main trunk lines are currently coming in at around a third compared to the 2021 average. At these levels, it is unlikely that Germany will reach its new stock fill target which the German Ministry of Economy raised from 90% to 95% by November 1. Latest confirmed data from AGSI sees storage fill rates at 66%, slightly above the EU average and some 19pp above heavily subdued levels from a year ago. Nonetheless, inventories remain well below the 88% level from July 2020.
In its latest energy security report (the third since the start of the war), the German Ministry of Economy declared that by the end of June the share of Russian gas deliveries had fallen to 26%.
Germany’s countermeasures go beyond LNG import infrastructure
Germany is pressing ahead with plans to establish its own LNG import infrastructure. The German government already secured 10-year time charters for four FSRUs, a notable feat given the fairly small global fleet of some 50 vessels.
Two units with a capacity of 5 bcm (maximum 7 bcm) each were chartered in directly by the government from Norway’s Höegh LNG (facilitated by utility RWE). The other two units were chartered by now-state-owned utility Uniper from Greek shipper Dynagas, with both units having an annual regasification capacity of 5bcm (maximum 7.5 bcm). Three FSRUs will be located at the North Sea(Wilhelmshaven, Brunsbüttel, and Stade) while one will be operating in the Baltic Sea (Lubmin). A private investor (Deutsche ReGas) is set to install a fifth FSRU (4.5 bcm) which is provided by TotalEnergies. Anchored off Lubmin too, it targets a ramp-up in December, potentially ahead of the two Wilhelmshaven and Brunsbüttel FSRUs (early 2023). In Brunsbüttel(construction start set for September) and Stade (FID yet outstanding) permanent import terminals with a capacity of 8 bcm (expandable to 10 bcm) and 13.3bcm, respectively, are planned, both targeting a ramp-up in 2026.
To put these numbers into perspective, LNG imports into EU-27 reached 80.6 bcm last year, covering almost 20% of the bloc’s 412 bcm natural gas demand(Eurostat). LNG inflows have surged since February, climbing to a H1-2022 total of 63.6 bcm, compared to 40.9 bcm over the same time period in 2021.
The choice of the Baltic Sea port of Lubmin adds more than 500 nautical miles to an LNG carriers’ voyage compared to the other three North Sea locations. Furthermore, draft restrictions require LNG carriers to offload into an FSU anchored offshore from where three shuttle tankers deliver the LNG to the Lubmin FSRU. It is, however, existing onshore pipeline infrastructure that outweighs these drawbacks, turning Lubmin into the location of choice for two FSRUs as the vicinity to Greifswald, end point of both Nord Stream 1 and 2, provides easy access to several major onshore trunk lines. Two pipelines already act as operating extensions to Nord Stream 1, the 20 bcm NEL pipeline supplying northern Germany, and the 36.5 bcm OPAL line supplying eastern Germany. Even if Russian natural gas flows via Nord Stream 1 should continue, Lubmin imports could be channeled via the idle EUGAL (see map), the inland extension for Nord Stream 2 which was finalized in 2021 and would have supplied Germany with up to 55 bcm of Russian volumes.
German utilities are still facing the task of sourcing sufficient LNG supply which is a difficult endeavor considering that markets are already extremely tight, especially in the Atlantic Basin. Henry Hub prices are closing in on double-digit territory and TTF is approaching the $60/mmBtu mark, exceeding JKM prices by 50%.Furthermore, the only major LNG supply addition from now until Germany’s first floating terminals become operational will be Eni’s 4.35 bcm FLNG project off Mozambique, targeting an early-October ramp-up. At the same time, 20%of US LNG export capacity remain shut in following an explosion at the Freeport LNG terminal in early June, and no reopening schedule has been provided as of now.
Other strategies are being deployed as well. Germany natural gas imports have vastly outpaced domestic consumption (see chart), hence curbing availability for volumes to be re-exported could be a possibility. In fact, Destatis data for January to May shows a noticeable reduction in German export volumes both in absolute and relative terms vs imports (see chart). Germany appears to be retaining more gas at home than is normal, a move that could ultimately prove politically unpopular with fellow EU-member states. Reducing gas re-exports is likely to accelerate. The need for German exports to Poland (2bcm over H1-2022) is likely coming to an end soon as the Baltic Pipe (10 bcm),an integral part of the EU’s Baltic Energy Market Interconnection Plan (BEMIP),is scheduled to become operational in early October, linking Poland to Norwegian natural gas supplies via Denmark.
Another approach consists of maxing out existing transport capacity (pipeline and trucks). Uniper is aiming for an additional 1 bcm of regasified LNG from the 12 bcm Dutch Gate LNG hub which is developing further truck loading bays. Dutch Gate will not remain the Netherlands’ only import terminal as Gasunie’s 8 bcm Eemshaven hub is set to come online later this year too, potentially attracting much needed volumes to NWE.
German imports of Norwegian natural gas came in at a strong 30.7 bcm overH1-2022, which – if these export levels were to be maintained – would add an incremental 5 bcm in 2022 vs 2021. However, the ramp-up of the Baltic Pipe is likely to curb the availability of excess Norwegian production.
Even in an ideal scenario with all of the above measures coming into effect as planned, a complete cut to Russian volumes cannot be balanced in the short-to mid-term. By the end of 2023, the four floating import terminals will boast a combined LNG import capacity between 20 bcm to 29 bcm (contrary to Uniper and RWE, the German government is calculating with a more conservative estimate of 5 bcm for each of the four FSRUs). The privately financed fifth unit is targeting 4.5 bcm.
Assuming German utilities manage to secure sufficient LNG supplies we can add up the import capacities of the five FSRUs (24.5 bcm to 33.5 bcm) as well as the additional volumes from Norway (maximum 5 bcm) and the Netherlands (1 bcm). Even in a scenario of maximum incremental volumes of 39.5 bcm, a 100% cut to Russian supplies for German consumption (46 bcm) would imply that some amount of demand goes uncovered. The delta of 6.5 bcm translates into a need for domestic consumption savings of 7% basis 2021 demand levels (93.6 bcm). In amore moderate case where non-Russian supplies add 27.6 bcm (70% of proposed maximum) and the cut to Russian volumes consumed in Germany returns to 60% then no demand cuts would become necessary.
Excluding the two FSRUs chartered by the government (Stade and Lubmin) which are only expected to start operations in H2-2023, from above calculation, Germany’s scope of action is further narrowed down:
On July 26, the EU members (except Hungary) agreed to voluntary 15% natural gas consumption cuts from August to March, vs their average annual use over2016-2021. The above tables put these 15% into context from Germany’s point of view.
To summarize, if Germany were to face a total cut in Russian flows, a curtailment to domestic consumption appears inevitable, even with the maximum addition of 39.5 bcm from non-Russian sources by late next year. Full supply/demand balance would not be achieved until the start of the two permanent LNG import facilities around 2026.
From an equity’s perspective, the valuation of Uniper took centre stage over the past month. The company has only received a fraction of its contracted natural gas volumes from Gazprom since mid-June, meaning it had to buy missing volumes at soaring spot prices. In accordance with Germany’s Energy Security Act, section 26, Uniper is currently not legally entitled to pass on higher cost to its clients, which reportedly resulted in losing tens of millions of Euros per day. From October 1 onwards, Uniper will be allowed to pass on higher costs to consumers and the German government is considering bringing forward its introduction to September 1.
The German government is currently providing fiscal support to Uniper, including an equity injection of €8bn as well additional liquidity support from German state-owned bank KfW which increased a loan facility from €2bn to €9bn.The government is also buying a 30% stake via 157 million newly issued shares in Uniper, thereby diluting existing shareholders’ positions, for example the share of Finland’s Fortum (in turn owned by the Finnish state)dropped from 80% to 56%. Further capital could be provided against the issuanceof a €7.7bn mandatory convertible bond.
Still, since the bailout announcement, Uniper’s share price took yet another step lower, currently trending at -84% ytd. It appears that the market does not deem the above measures sufficient to keep the company afloat in the long-term. Even though Uniper started construction of the floating LNG import facility in Wilhelmshaven in early July, with a ramp-up scheduled for early 2023, the recent surge in natural gas spot prices in the US (despite 20% of US LNG export capacity still shut in) likely weighed on Uniper shareholders’ sentiment. Similar to the situation around the EDF bailout in France, a delisting of the stock might be on the cards.
Equinor, on the other hand, is a potential beneficiary of how things unfolded lately. Natural gas pipeline export volumes to Germany reached multi-year highs over H1-2022, and the scheduled October opening of the Baltic Pipe to Poland will open up additional export capacity for Norwegian volumes. Timing appears to be good, as Equinor lately announced it expects natural gas production from the Njord field to resume in Q4-2022, after the Njord A floating steel platform and the Njord Bravo storage vessel underwent a 6-year maintenance, making them ready for another 20 years of production.
Amid the growing pull on non-Russian natural gas from Europe and Germany in particular, Equinor successfully managed to ramp up its North Sea output. In fact, Q2 earnings show that across all upstream segments (liquids and gas in Norway, US, International) Norwegian equity gas production was the only section to record y-o-y supply growth in H1-2022, reaching 782 kbd (+13.8%y-o-y). Lower gas supply elsewhere saw overall group equity gas production grow by 4% y-o-y in H1-2022. Thereby, Equinor’s gas production (50.5%)overtook liquids production (49.5%) on a boe basis.
By applying average realized prices for liquids and gas to production figures (not sales volumes!), one can obtain a proxy for the gas/liquids split of Equinor’s E&P revenues, which comes in at 57%/43% in favor of gas, after H1-2021 still saw liquids well ahead (33%/67%). It is worth noting, that E&P accounted for 57% of Equinor’s H1-2022 revenues, up by 9.5pp on the year, a reflection of the commodities boom.