Russian gas disruptions start to trickle in; TTF risks heavily skewed to the upside

Uncertainty related to the Russian gas payment system, a disruption of flows via Ukraine and the Russia sanctions illustrate that gas supply disruptions, even if small, have started to become a reality, and that risks of bigger disruptions remain in the European gas market. In the absence of alternative sources of supply or a buffer in storage, demand destruction remains the main balancing mechanism in European gas markets. Specifically, we estimate that current Russian supply disruptions require TTF prices at 110 EUR/MWh in the near term to compensate for it and maintain the current healthy storage outlook – a roughly 20 EUR impact to the 90 EUR/MWh estimated balancing price under no disruption. Further, we maintain our view that the risk of additional disruptions justifies a risk-premium to these levels, consistent with our 123 EUR/MWh 2Q22 TTF forecast, above current forwards at 105 EUR/MWh. Lastly, we reiterate our view that the significant impact of potential supply disruptions keep TTF price risks heavily skewed to the upside from current levels, despite the significant recovery in Spring inventories, which have nearly normalized at this point. Specifically, we estimate that a sustained disruption of Russian flows without any offsets would take end-Mar23 NW European storage levels to only 14% of full, in the case of an Ukraine-flow disruption, vs 37% in our base case, or to total exhaustion, in case of a total cut in net Russian flows to NW Europe. The latter, more extreme, disruption scenario would lead to TTF more than doubling from current levels in our view, as we have previously discussed.

What is the fair price for TTF at the moment? While we believe 90 EUR/MWh could balance the market under a no-disruption scenario, as shown in Exhibit 1, that is no longer the state of the world. Uncertainty related to the Russian gas payment system, a disruption of flows via Ukraine and the Russia sanctions illustrate that gas supply disruptions, even if small, have started to become a reality, and that risks of bigger disruptions remain in the European gas market. As suggested in Exhibit 1 the higher the supply disruption, the higher the price required to disincetivize demand to compensate for it to maintain the storage outlook stable. Based on our demand elasticity estimates, current supply disruptions, if maintained this quarter, require TTF prices to average 110 EUR/MWh in the near term to compensate for it and secure a healthy storage build – a roughly 20 EUR impact to the 90 EUR/MWh balancing price under no disruption. Further, we believe that the several sources of disruption risks, from sanctions, to payment systems, to war-related disruptions, justify an even higher near-term TTF price than currently priced in the market. Specifically, our 2Q22/3Q22 TTF forecasts at 123/85 EUR/MWh reflect a probability-weighted scenario-based view that assigns a 30%/10% probability to more significant flow disruptions to 2Q22/3Q22, as shown in Exhibit 1.

What are the Russian gas disruptions currently impacting NW Europe?

■     Interruption of Russian exports to Poland. Russian flows to Poland dropped from 20 mcm/d for most of April to zero. As we recently discussed, this would ordinarily lead to a net tightening of NW European gas balances via higher German outflows to Poland. But with Poland relying on high LNG imports, lower exports to Ukraine and purchases of gas from third parties through the Yamal pipeline via Belarus, the net impact to German exports has been small, in line with our expectations, around 8 mcm/d (Exhibit 3). Even if sustained through summer, until Poland starts receiving gas from Norway, this is fully offset by the April softening of NW European balances helped by warmer-than-average weather.

■     Disruption of Russian flows through Ukraine. The Ukraine gas grid operator has reported a Force Majeure (FM) at the Sokhranivka entry point of Russian gas, whose flow has dropped from 24 mcm/d prior to the disruption to zero since May 11. This was followed today (May 12) by a reported 22 mcm/d drop in Russian flows through its second entry point into the Ukraine, Sudzha (Exhibit 4). Importantly, the Sudzha cut may be temporary given the significant volatility observed in those flows year-to-date. In addition, these reductions do not necessarily imply an equal drop in net flows to NW Europe, since Russian gas that flows through Ukraine is also sold to Central/Eastern Europe. For instance, out of the net 17 mcm/d drop in Russian flows to Ukraine on May 11, net Russian flows to NW Europe fell only by 10 mcm/d. Similarly, despite the reported 22 mcm/d drop in Sudzha flows today, the Germany Economy Minister reported only a 10 mcm/d drop in flows to the Gazprom Germania company, sanctioned this week by Russia, along several affiliate companies. Net, we allocate 50% of the drop in Ukraine flows as a net impact to NW Europe, based on previously observed flow fluctuations. For now we assume the Sokhranivka FM lasts through the end of the quarter, while we’ll continue to monitor Sudzha flows. This implies a net 12 mcm/d impact to NW Europe, which we estimate would require approximately a 20 EUR/MWh increase to 2Q22 TTF prices relative to the 90 EUR figure that would balance the market under no disruption. This suggests that 110 EUR/MWh would be required in the market to compensate for the Sokhranivka losses, a price level that does not in our view embed a risk premium reflecting the probability of further supply cuts (Exhibit 1).

What are the main sources of potential incremental disruptions?

■     Rouble payment requirement. The recent interruption of Russian flows to Poland and Bulgaria suggests that gas buyers not meeting Russia’s Rouble payment  requirement would be at risk of a halt in Russian gas supplies. With several payments due later this month and no clear guidance from the EU on how payments can be implemented without a violation of sanctions, there is uncertainty whether flows will continue as normal. Statements from German gas buyers and from Italy’s Prime Minister Draghi suggest payment compliance is feasible, suggesting low risk of a blanket cut in Russian export flows. But incremental partial disruptions are still possible, with gas buyers in Finland and Denmark, for example, saying they do not intend to make the payments in Roubles.

■     Sanctions by Russia. This week the Russian Government announced retaliatory  sanctions on 31 companies. Because the list of companies affected includes companies linked to the Yamal pipeline in both the German and Polish sections of the pipe, it suggests that no Russian gas would be sold via Yamal for the time being. Despite Yamal flows to Germany being at zero for most of the past few months, this restriction would still matter. Firstly, it would potentially remove Poland’s ability to buy gas from third parties via Yamal via Belarus, potentially putting a bigger burden on German exports to the region, net tightening NW European balances. Further, sanctioning Yamal operations would remove flexibility in the system, so that, should Ukraine flows be disrupted, a rerouting of flows through Yamal would be much less likely, significantly increasing the risk of a net impact to gas flows. Lastly, the sanctions may lead to further declines in pipeline exports to NW Europe, as well as to disruptions of Russian LNG exports, as some of the sanctioned companies are existing contracted buyers of Russian gas or LNG. Such a disruption would not necessarily be permanent, however, should non-sanctioned third parties get involved to either intermediate the gas sales or to take over existing contracts.

If higher TTF prices are needed to balance the market, why are UK NBP prices so much lower? The record-high influx of LNG into NW Europe in April, at the same time that demand was declining significantly owing to a warmer-than-average start of Spring, has lent sizable support to storage builds and illustrated the limits to pipeline connectivity within NW Europe, pressuring prices lower in certain regions. UK NBP prices have stood out, showing the widest discount to TTF, as the exceptionally high levels of LNG imports combined with an outage at the 60 mcm/d Interconnector link to Belgium and with very limited domestic storage capacity (Exhibit 5-Exhibit 8).

Will TTF prices sell off towards NBP? We don’t think such a price move would be sustainable, as it would tighten NW European balances significantly. For example, the steady decline in UK gas prices from 100 EUR/MWh in early April to 55 EUR/MWh earlier this week, before rebounding to 70 EUR today, has already led to a significant drop in LNG imports into the region, which month to date have averaged 25% below April levels (Exhibit 5). If TTF followed suit, driving global LNG prices further down, this would likely support a rebound in LNG imports outside of Europe, reducing the volumes available for Europe. Further, we believe European domestic gas demand would also increase supported by higher industrial margins. This would ultimately lead to lower storage levels ahead of winter, increasing weather-related risks to the market and, hence, resulting in higher gas prices. As a result, as the NBP-TTF spread narrows with the normalization of Interconnector flows, seasonally lower summer LNG imports, and Norway allocating most of the impact of its summer maintenance towards UK deliveries, we expect NBP to move higher, as opposed to TTF moving lower.

But with storage recovering so well, won’t gas prices drop? Yes, the more high gas prices do the work now to destroy demand and attract LNG, the less work will be left in 3Q22. Our 85 EUR/MWh 3Q22 TTF forecast, well below our 123 EUR 2Q22 forecast reflects that. Higher-than-expected storage levels at that time could even take levels close to a breach of storage capacity, resulting in further downside to prices. But, even in this case, we don’t believe this downside would be sustainable, with 4Q22 likely adding winter-weather risk premium to prices. Further, in the absence of normalized Russian flows, Sum23 storage injections would once again depend on demand destruction and high LNG imports to take storage to comfortable levels ahead of the following winter. This would in our view require, again, prices high enough to get it done. Our base case Sum23 TTF forecast is 75 EUR/MWh, reflecting the minimum price level at which we can observe industrial demand destruction.

How long will this market tightness last? We believe price-driven demand destruction will be needed in NW Europe until global LNG supplies increase significantly. Higher supply availability will allow Europe to attract cargoes more cheaply throughout the year, helping lower the TTF price that balances the market. The next wave of global LNG projects that will allow this process to unfold is already under construction, but many don’t come online until 2025 or later. This suggests Sum24 TTF is still underpriced at 60 EUR/MWh, with 75 EUR/MWh the minimum price level at which we have observed industrial demand destruction. As we’ve discussed, the flip side of this increase in global LNG availability are higher LNG exports out of the US, which we expect to support Sum25 Henry Hub prices at $4/mmBtu. Further, the potential for the US to play a role in replacing Russian gas to Europe more permanently can continue to add to US LNG export demand growth further out the curve (Exhibit 9). Combined with the potential growth in US industrial demand for gas as a result of the increased competitiveness of Henry Hub vs global gas prices for the next few years, we expect this process to continue to provide support to back-end Henry Hub prices.