10 Questions (and Answers) on Russian Gas Going Forward
With the eyes of the world focused on whether Russian gas supplies through the Nord Stream 1 (NS1) pipeline will return as its maintenance ends this Thursday (Jul 21st), let’s go over the most frequently asked questions we’re asking ourselves on this subject over the past two weeks. Energy experts maintain the view that the most likely scenario is that NS1 returns to operation at a 40% of capacity, consistent with recent media reports and back to the observed pre-maintenance flows. From a price perspective, in this scenario it would take 3Q22 TTF prices remaining around 170 EUR/MWh, in line with the 160–180 EUR range observed in the past two weeks, to help incentivize enough demand destruction to take end-Oct22 storage to 90% full in NW Europe. A lack of rebound in Russian export flows would instead require both higher prices and likely higher government-driven demand destruction.
1) Why would Russia not keep NS1 at zero?
Most of market seem to be split between the 40% and the 0 flow scenario for NS1 post maintenance, with many market participants in Germany in particular expecting the pipeline to indeed remain at zero. However, the consensus is that NS1 staying at zero is an unlikely scenario, as (1) it would remove flexibility from Russia’s supply decisions (once you’re at zero, there’s only one place to go: up); (2) it would significantly reduce Russia’s gas revenues, limiting its upside from a potential spike in European gas prices under that scenario; and (3) it would force an even faster rate of gas production shut-ins in Russia. Although shut-ins don’t seem to be a geological/technical issue for Gazprom, they effectively delay an increasing share of its gas revenues to the end of the life of the wells. The large number of market players that have expected the pipeline to remain at zero post maintenance suggests a sell-off in European gas prices from current levels is likely in case NS1 returns to at least 40% of capacity from July 21st. This is in line with today’s TTF move, down 5 EUR at 154 EUR/MWh, following media reports suggesting NS1 will restart below capacity as scheduled. To be clear, under a 40% NS1 flow rate scenario, it’s unlikely such lower prices would be sustainable, with a return to a 170 EUR TTF range likely in order to generate enough demand destruction to help take NW European storage to 90% full by end-Oct22.
2) What’s the risk to European gas markets if NS1 flows remain at zero?
Under this tightest outcome, even taking into account offsets to the supply losses like coal restarts and government-driven demand destruction, among others, the expectation is that TTF will average over 210 EUR/MWh in 3Q22. This is based on the assumption that markets (and governments) will act to take NW European gas storage to 90% full ahead of the winter and an estimated demand elasticity of 1 mcm/d per 1.8 EUR/MWh move in price. This scenario would also likely push the Euro area into a clear recession.
3) What changes with the return of the turbine from Canada?
Not much. Despite the recent focus around the timing of the repaired turbine’s return to Russia, now expected around Jul 24th, after NS1 maintenance is scheduled to end, it is difficult to believe this will be the sole driver of NS1 flows. In addition to the opaqueness behind the scale of the volume curtailments via NS1 last month, the absence of any Gazprom-driven re-routing of the reduced flows via an alternative pipeline to mitigate the impact to supply suggest Russia’s gas exports are as much a political/economic decision as a technical one.
4) Is it possible to track NS1 flows?
Maintenance is scheduled to end 6am CET this Thursday, July 21st. Intra-day flow data is available on Bloomberg using the OPAL (OPAMRXIF Index) and NEL (NELFPMIF Index) intra-day tickers, which added together show NS1 flows.
5) What is Gazprom’s recent force majeure declaration about?
The recent Gazprom force majeure (FM) declaration retroactively refers to realized export cuts (the NS1 cuts) over the past month, and does not reflect any new changes to gas flows. This looks like an effort by the company not to be seen as liable for the supply cuts to long-term customers observed since mid-June. It is not clear that this FM claim should be particularly relevant to NS1 flow expectations going forward.
6) Can Russian gas be diverted elsewhere, if it doesn’t flow to Europe?
Not really. The lack of pipeline connectivity between that particular producing region and alternative buyers has resulted in Russian gas export curtailments being split between domestic storage injections and production shut-ins. Specifically, Gazprom’s published data suggest its production is down 10% year-on-year year to date, and down more than 35% year-on-year for the fist half of July. This is not expected to pose a geological issue, though, given Gazprom’s demonstrated ability to historically swing production up and down without damage to gas well pressure. The most recent example of that was its 50 Bcm production swing in 2020, during the peak of the pandemic. By 2021, Gazprom brought it all back and more, as demand recovered. Also noteworthy is that, because Gazprom does not rely significantly on associated gas, its gas shut-in process has not impacted Russia’s oil production.
7) Why are winter gas price forecasts so much lower than summer?
Although we are used to thinking of natural gas prices as being higher in winter than in summer, as that’s when demand is highest, markets believe the current tightness in European gas balances flips that around. Without a recovery in Russian gas flows to Europe, the region’s blackout and heating risks in winter are potentially so high that markets (and governments) are expected to act now, in summer, to fix the problem. In particular, the 171 EUR/MWh TTF price forecast for 3Q22 under a 40% NS1 flow rate scenario solves for end-summer storage at 90% full. And the more work (i.e., storage building) is done in summer, the lower the work for prices to do in winter. This is especially the case in 1Q, because winter weather uncertainty drops significantly in the second half of winter vs the first half, taking the spot gas price forecasts then below 80 EUR. That said, this lower price would ultimately be driven higher once again during summer 2023 in all likelihood, as price-driven demand destruction would likely be top of mind once more in the absence of normalized Russian gas flows.
8) Has European gas demand dropped further given the currently high gas prices?
We’re seeing an accelerated year-on-year drop in gas demand this month vs June in Germany, Netherlands and Belgium, but not yet in the UK or France, where storage levels have been higher relative to average and gas prices, lower vs TTF. On net, NW European consumer demand for gas remains more resilient than expected, 11% above July expectations under current prices. This relative strength in demand despite exceptionally high gas prices has been exacerbated by the heat wave Europe is experiencing currently. While air-conditioning is typically much less present in NW European homes vs in Southern Europe, the heat affects nuclear reactors’ ability to discharge water used for cooling in rivers that are already too warm for wild life, potentially reducing nuclear and lifting gas-fired generation at the margin. In addition, low water levels at the Rhine river is negatively impacting shipping, including the transportation of coal to power generators in Germany.
9) Can LNG imports into Europe remain high?
The resilience observed thus far in gas demand across NW Europe relative to expectations has been offset by higher-than-expected supply, driven by LNG imports into the region. NW European LNG imports have averaged 28% above expectations month-to-date, helped by weak LNG imports from China, as well as from a few more price-sensitive buyers. To be clear, the slow recovery in Chinese natural gas demand from its April trough has helped keep Chinese gas storage well supplied, reducing the country’s demand for LNG imports, hence leaving additional cargoes available for Europe. As Chinese economic activity continues to recover, its competition for LNG cargoes poses a risk to European LNG supplies. Further, recent declines in Japan gas stocks owing to a heat wave, as well as low inventories also in South Korea reinforces the view that Asia LNG demand will increase sequentially from here, reducing available LNG supply for Europe over the next few months.
10) Can European gas demand switch towards other fuels?
Since European natural gas prices have been well above coal and oil prices since last Fall, the markets believe that the price-driven fuel substitution that was possible has largely already happened, particularly into coal burn in power generation. Measures such as the removal of a cap in coal burn in the Netherlands and the restart of coal generation capacity that had been put on reserve in Germany can add to that, though markets expect its impact on gas demand to remain well bellow the ongoing shortfall in Russian supplies. Fuel substitution in industrial processes is also possible, though it has thus far been seen as a potential response to gas rationing, as opposed to a substitution driven by current gas prices. If implemented, such substitution measures would contribute to sustaining economic activity while managing gas storage levels. Substitution towards fuels like oil or coal for industrial boilers would not be without its challenges, however, with European coal sourcing increasingly difficult from August, when the European ban on Russian coal imports is implemented. And while oil prices have come off from its highs earlier this year, oil product balances remain exceptionally tight — and would be made even tighter from this switching demand — with prices poised to rally from current levels, especially once refinery maintenance season returns in the Fall.