After a torrid summer, European power and gas utilities now face an even harsher winter following the indefinite closure of the Nord Stream 1 (NS1) pipeline. Gazprom announced the closure of NS1 on Friday, Sept. 2, 2022, its only supply route to Germany. When running at its full capacity of 55 billion cubic meters per annum (bcmpa) in early 2022, the pipeline covered 12% of European demand. Since mid-June, it had only been running at 20%.

We view NS1's "indefinite closure" as permanent in our updated rating base-case scenario. While it reduces Europe's winter supplies by only about 2% versus the August flow level, all marginal reductions exponentially weigh on Europe's market prices for gas and power, as Monday's double-digit price increases confirm. We already significantly raised our European Title Transfer Facility price assumptions on Aug. 1, to far higher levels than had prevailed until mid-2021 (see "S&P Global Ratings Raises European Gas Price Assumptions On Uncertain Supply," on RatingsDirect).

Supply pressures and governments' drive for gas storage "at whatever cost" to enhance supply security despite the Russian gas cutoffs are not the only factors that we expect will continue supporting very high gas and power prices over the next few months. Added to this are low hydro availability in Southern Europe, low French nuclear generation, the slow ramp-up of coal-fired generation, and residential and commercial slowness in moderating consumption.

High prices will aggravate the already acute question as to who should bear the resulting massive financial burden. We estimate Europe's energy bill will exceed its pre-pandemic levels by well over €1 trillion. Governments have intervened in markets and specific utilities in unprecedented ways. Europe as a whole is discussing this month how to moderate consumer prices, and the EU Commission President is expected to make further announcements on Sept. 9. Yet, implementing a potential market redesign would be complex and long, leaving many risks for rated utilities this winter. Furthermore, windfall taxes may dent earnings upside for largely fixed-cost power generation on unhedged output.

We believe European governments are increasingly willing to support liquidity on energy exchanges and at European utilities against massive hedge collateral posting movements. Some utilities also face heightened basis risks on diverging index moves. So far this summer, our rating actions on European utilities have been skewed to the downside (see chart 1), confirming the trend in place since 2021 (see chart 2).

Chart 1

Chart 2

NS1's Closure Adds To Existing Supply And Pricing Pressure

NS1's shutdown, which we view as permanent in our base case, adds to Europe's gas supply pressures.  It removes about 11 bcmpa (versus the pace observed since mid-June) to regions most in need--Italy, Germany and Eastern Europe. Overall, Europe needs to replace over three-quarters of 2021 Russian supplies, or about 110 bcm-120 bcm per year. While lower demand has offset about a quarter of that, around half has been compensated by raising liquified natural gas (LNG) imports 55%-60% year on year as of July, a trend we expect will continue (see chart 3).

Chart 3

That said, NS1's closure reduces by only one-quarter the August pace of Russian supplies, to about 35 bcm per year.  Of this residual amount, while we see the third that comes via Ukraine as particularly at risk of geopolitical-driven cuts, the other two-thirds, which cover about 6% of European demand, appear relatively safe for now: Yamal LNG's exports should remain remarkably resilient and TurkStream, the last other active pipeline, supplies notably Serbia and Hungary.

For September, despite NS1's closure, we expect Northwestern Europe (NWE, including the U.K.) will continue exporting to Eastern Europe and raise its storage by over 100 million cubic meters (mcm) per day (or about 6% of NWE's storage capacity, over the month).

Nevertheless, the sensitivity of Europe's gas balance and energy prices to each bcm missing is extremely high;  and, with persistently high and volatile prices, certain utilities particularly exposed to residual Russian supplies may suffer more. For a given company, collateral posting requirements may swing by one to several billion euro over a day or a week.

With Limited Supply Options, Europe Must Cut Gas Demand Further

Restoring Europe's gas balance now depends on reducing demand in line with the EU's 15% target for the winter.   Until June, replacing missing supply was still the main strategy for coping with Gazprom cuts. However, key supply sources are maxed out for now, even for LNG.

U.S. LNG imports--the key pillar to rebalance Europe's gas market--will only gradually will creep up in fourth-quarter 2022.  The Freeport plant in Texas, which covered as much demand as NS1 did until it closed June 8, will reopen in late November, and the Calcasieu Pass plant in Louisiana, mostly sold to European customers, is still ramping up its capacity to 10 million tons per year by year-end 2022.

While paying $40-$60 per metric million British Thermal Unit (mmBTU0), or 3x-4x the price of LNG landing in China, over the summer allowed Europe to outprice importers in emerging Asia-Pacific, we believe this may not last. If China's notable 20% reduction in LNG imports year on year to July, which freed up some 12 bcm, is mostly due to its economic slowdown, this trend could reverse if the economy rebounds. Price-led demand destruction is clearer for South Asia, but we expect demand in the key markets of Japan, Korea, and Taiwan will only modestly erode, if at all, as Japan restarts several nuclear reactors as announced in late August.

Europe's summer progress in raising 2024-2025 LNG deliveries was slow.   As in previous quarters, Europe does not appear to have signed significant LNG long-term contracts to secure future supply. This is particularly true for the "third wave" of LNG projects in the U.S., which present the next key opportunity to secure volumes and enhance Europe's supply security. Furthermore, Qatar's strong LNG increase will occur in 2026 rather than 2025. As such, securing these volumes may matter less, since U.S. volumes and Europe's continued renewables ramp-up will make it less and less attractive for Europe to sign long-term contracts.

Thus, despite healthy storage, Europe needs to compress demand significantly more than it has to date.  This is true across all three sectors: industrial, the only to really reduce demand to date; power generation; and above all residential and commercial. The latter will be key in the winter months.

So far this year, on a weather-corrected basis, Europe's overall gas demand has been on a slight downward trend of about 6%-8%. This will be insufficient in case of an early and/or harsh winter, and at any rate to derisk for the 2023-2024 winter.

Governments continue to face the challenging task of trying to simultaneously ensure affordability, compress demand, and support the reduction of greenhouse gas emissions.  On July 26, EU governments collectively called for a 15% voluntary reduction in gas consumption from Aug. 1 to March 31, equating some 45 bcm, with the exception of Italy and Spain, which have promised cuts of 7%-8%. Meanwhile, Germany raised its target to 20%; this would partly offset the shortfall from Italy and Spain, but it could be challenging to implement. To date only the Netherlands has managed such significant cuts, while purely on an industrial basis Germany and the U.K. have come close. Regarding Germany, if households reduced consumption by an unprecedented 16% and this winter depletes storage to 20% (a level that raises risks on the following winter's supply), the industry would have to cut demand by 25%, which may require some forced curtailment (see more in "Europe Braces For A Bleak Winter," published Aug. 29, 2022).

Much depends on the residential and commercial segment, and how effective price signaling is at reducing demand.   This should become clear from October, at least in the U.K. and Germany, which appear to be the most advanced in price signaling to end consumers. From Oct. 1, 2022, U.K. energy bills may rise by 80% (as proposed by Ofgem, unless the new government freezes tariffs, as rumored this week) and Germany put in place a supply-related gas levy of €24 per megawatt-hour (MWh); in both countries, poorer households would receive a subsidy of a fixed monetary amount, to still incentivize consumption reduction; interestingly, Germany's €65 billion package announced Sept. 4 suggests a new mechanism of capping the price for a family's first 3 megawatts consumed.

Industrial demand must reduce much more drastically than the approximately one-tenth decrease registered to date to avoid a shortfall.  While many factors seem to support such reductions, they appear slow to translate into actual lower volumes, beyond the early measures of fuel switching. We now turn to why, to date, powerful market forces have not reduced European demand more.

What's Behind The Slow Pace Of Demand Cuts So Far

The slow pace of reducing demand stems from multiple factors, including the need to actually raise gas-fired generation and government mandates to aggressively store ahead of the winter.   The urgency is particularly acute in the gas-short regions of Germany, Italy, and Eastern Europe, both because of their more limited supply options and because to date they haven't reduced demand considerably beyond weather effects and the easiest gas-to-liquids switches, such as at oil refineries. The summer has highlighted an increasing fragmentation of the European market between these and the more gas-supply rich regions, namely the U.K., Iberia, France, Belgium, and increasingly the Netherlands. These regions have large LNG import capacity and (in the case of the U.K. and Netherlands) significant indigenous production. While we expect the latter to continue eroding, it should still cover almost half of demand for the U.K and the Netherlands.

Gas-fired generation gas has not reduced in Europe so far this year, despite extremely high fuel costs. And this may remain the case for a while.  Up to August, Europe's gas-fired generation didn't decrease, despite already-high gas prices, according to data we received over the summer and in line with our previous assumptions. It effectively was near-flat (up 1%) August, although there were stark regional contrasts, with Spain's 41% increase more than offsetting Germany's 22% reduction. Why such support to gas-fired generation, when gas is so precious and costly, and what could reverse the situation next winter?

Gas-fired generation is filling the gap created by low hydro availability in Southern Europe, record-low French nuclear generation, and the slow ramp-up of coal-fired generation.   While many placed high hopes on coal, we continue to see it as only a marginal contributor to restoring the gas balance; for example, only in late August did a second German coal-fired power plant--of the potential four with 2.9 gigawatt (GW) combined capacity--come back on line; for the quarter, even including Italy's four plants generating over 4GW, Western Europe's 13GW coal-fired generation is under a third of gas-fired generation.

The gradual buildup of renewables capacity should help provide relief on gas demand though.   If we focus on Europe's five biggest economies--which consume about 70% of Europe's gas--over January-July 2022, their wind and solar generation increased healthily about 15% year on year to 281 TWh (of which two-thirds was wind). Gas-short Germany contributed 41% (equally from wind and solar) to total generation, and the U.K. and Spain 18% each. If sustained to year-end and fully allocated to reduce gas-fired generation, for these countries renewables growth would save some 12 bcm more than in 2021, relieving their gas balance by 4% (5% for Germany alone) and offsetting a tenth of the Gazprom cuts since January when most of its export pipelines were running at full capacity.

"Storing At Any Cost"

Europe now faces the policy dilemma of how to derisk winter supply without aggravating price pressures.  While injecting gas worth some €0.7 billion daily, at August's $50/mmBTU average LNG Zeebrugge landing cost, gravely raises Europe's energy bill by pressing prices up, accelerated and often-government-supported storage appears successful in meeting its key objective of reducing winter physical shortage risk.

We expect the EU gas storage will reach 90% filling in early October, up from 82% as of Sept. 4, 2022 (see chart 4).   On average over July-August, storage increased some 36 basis points daily. Germany, which started late, has caught up noticeably to 86%, ahead of Italy's 84%. By regulation Italy will further increase storage to at least 95% by year-end.

France has remarkably raised fullness to 93% already and Belgium to 90%, which this fall could moderate pressures on European prices as they wind down injections. Poland, Portugal, and Denmark, all within the 94%-99% range, are already doing so. By contrast, if Austria and Hungary, and to a certain extent the Netherlands (all within 65%-80% fullness), raised levels further, they could further derisk their winter supply, or that of their neighbors.

Chart 4

To refine our understanding of how current storage reduces next winter's physical shortage risks, we will continue monitoring how "European solidarity" is meant to direct withdrawals from storage during the winter.  For example, if a gas-short country willing to maintain consumption of nonprotected customers asks a gas-long one to withdraw and export significant quantities.

We understand solidarity focuses almost exclusively on EU-defined protected customers, mostly residential and essential collective services (for example, hospitals), effectively subordinating industrial supplies. Thus, European solidarity may be triggered too late to sustain supplies to a gas-short country's industry, if that country can invoke it only when its protected customers are at risk; for example, the Dutch government confirmed on Aug. 9 that Groningen's production is currently not expected to increase above the planned 2.8 bcm in the year to September 2023 (it exceeded 50 bcm in 2013); and we understand reactivating the U.K.'s only significant storage facility, Rough (3.3 bcm of targeted annual capacity, or over 4% of U.K. demand) may now be more likely, but for the very next winter would provide under 1 bcm of capacity.

Unprecedented Intervention From European Governments

European governments' interventions are likely to further support market and company liquidity while potentially introducing windfall taxes on unhedged fixed-cost generation.  In our view, over the summer several governments intervened in very varied ways that would previously have been seen as remote possibilities. Objectives varied from helping to restore more normal physical and trading market functioning to directly supporting select utilities' operations and/or credit quality.

On the one hand, certain measures are broad based and not directly financial: 

• In light of the summer's developments, at this week's Sept. 9 summit EU energy ministers will discuss at a high level a major market redesign. We understand more specifics could come during fourth-quarter 2022 for implementation in first-quarter 2023 and that the objective is to decouple gas and power prices across the EU, and possibly cap power and/or gas prices; non-gas generated electricity could be split from the gas-to-power market. While there seems to be a consensus on the need for action with tangible results already this winter, not all governments may agree on the same scheme. Options include the Iberian gas-to-power price cap; clawbacks on profits, or caps on prices, for "inframarginal," that is non-gas-to-power supplies; "administrative" caps; tariff deficits that smoothen bill increases over many years; and contracts for difference, among other mechanisms.
• Governments have clearly directed the summer's accelerated storage refill, providing price protection in certain cases, or directly as in the case of Germany's Securing Energy for Europe GmbH (previously Gazprom Germania), which received €15 billion in liquidity, including to raise the major Rehden storage facility's fullness to 70% as of Sept. 5 (Gazprom had left essentially empty this facility, which represents a sixth of Germany's storage capacity).
• In France and Switzerland, nuclear safety authorities agreed on temporary waivers to production cuts when rivers dropped to certain minimum thresholds.
• On the grounds of solidarity with EU importers, on July 5 the Norwegian government imposed "compulsory arbitration," that is effectively canceled a strike in its hydrocarbon production sector that could have halved the country's gas exports.
• As mentioned above, certain countries could soon implement unprecedented tariff hikes aimed at constraining demand.
• On Sept. 5, German announced it will keep two of its three remaining nuclear power plants in reserve until April 2023, instead of closing all three in December 2022.
• By contrast, the Dutch government has not yet changed its stance on winding down the Groningen gas field.

On the other hand, some measures are more of a financial nature: 

• Early July, the French government announced it would buy out the 16% of common shares it does not yet hold in Electricite de France S.A. (EDF), the sole generator of nuclear power in France and the U.K.; also, EDF's debt position would be relieved by €2.4 billion through bond conversion to equity.
• Windfall taxes imposed in first-half 2022 do not appear to burden utilities with considerable amounts, and we perceive a growing realization among governments that in general such taxes, even if likely to increasingly focus on non-gas generation, can only partly finance massively rising energy bills, especially as long as a high proportion of generation output is hedged (often one year out, and in a decreasing proportion for a couple of more years) at prices far below current spot prices.
• Late July, the German government announced the largest (€17 billion) support package ever extended to an industrial company, Uniper SE. Its equity stake goes to some 30% from nil, the company may issue up to almost €8 billion in hybrid equity, and KfW, Germany's development bank, has expanded to €9 billion the €2 billion facility it extended last winter (on Aug. 29, Uniper requested a further expansion of €4 billion). We believe NS1's idling further raises financing needs of former importers, including Uniper.
• As collateral requirements surged on electricity exchanges late August, government liquidity support has become more widespread. In the same week, three examples emerged. In the first week of September, on financial-stability concerns the Swedish and Finnish governments separately announced they will provide the equivalent of nearly €35 billion in aggregate in liquidity guarantees to their respective power markets' participants. In addition, on Sept. 6, the Finnish government extended a €2.35 billion liquidity facility to Fortum, which earlier had announced its margining position stood at about €5 billion, up about €1 billion in the week ending Aug. 26, 2022, after an unprecedented increase in power prices; the new facility should support Fortum's liquidity and help it withstand potential further spikes. Finally, the Austrian government decided to support liquidity of a domestic power utility covering under a fourth of the country's population, Wien Energie, to the tune of about €2 billion.

More generally, we see European governments as increasingly willing to support utilities' liquidity needs.   This is certainly the case in Germany, Sweden, and Finland. At the same time, though, utilities may see governments introduce windfall taxes on excess profits for unhedged fixed-cost generation. These moves help to justify tariff hikes and finance the part of additional supply costs that they don't cover. Generation technologies most at risk, in our view, include merchant hydro, renewables, nuclear, and biomass.

Hedging Is Fueling Credit Risks By Weakening Liquidity

European utilities' hedging strategies need to derisk future earnings without actually endangering liquidity.  Even though we expect rated utilities will continue posting healthy earnings as most did in first-half 2022, we try to assess the actual and potential impact on their liquidity of (i) energy hedges on wholesale markets, often entered into on a multiyear basis to prudently protect earnings, and (ii) rating triggers, whether related to margin call requirements or not. Unfortunately, public information is often scarce relative to the risks and dynamics involved. However, we do expect European governments, even previously noninterventionist ones, will strongly consider supporting solvent European utilities' liquidity (as announced over the weekend by Sweden and Finland, and in the spring by Germany), at the very least to preserve continuity of physical and energy-exchange operations. Under our criteria, we expect to treat government support extended to the broader industry and market in rated companies' stand-alone credit profiles.

In such a tense context, we focus notably on the following:  

• We expect to receive more frequent and insightful information from rated utilities on which key wholesale markets they plan to be present in; variations in collateral amounts related to their positive and negative hedge positions; their key selling and buying positions (rather than the net position); and where basis risk is mostly likely to arise, relative to the company's own physical generation.
• We assess financial policy, in particular hedging policies and their adequation in this new, extraordinary context that is set to last for several more quarters.
• We continue to see rating triggers on margin call requirements and/or debt financings as credit-negative to the extent they reinforce cliff risks. If any is present, we seek to understand the related amounts and rating proximity, and potentially, the company's approach to managing related risks.