European gas prices skyrocketed in August-September 2021 after showing extreme volatility in recent years. This leaves many households grappling with higher electricity and gas bills at a time when they are still recovering from the impact of COVID-19. Some market participants put most of the blame on geopolitical tensions, such as those linked to the controversial Nord Stream 2 project. This 55 billion-cubic-meter gas pipeline, running to Germany from Russia across the Baltic sea, has been completed but is still awaiting certification to start operations.

S&P Global Ratings believes that, geopolitical factors aside, the simultaneous occurrence of fundamental technical, economic, and weather-related factors led to the unusually high gas prices. We reflect this in our latest gas price assumptions (see "S&P Global Ratings Revises Oil And Natural Gas Price Decks," published Oct. 5, 2021).

Gas stocks were low after a long winter and Europe's strong economic recovery; then low wind in the summer reduced generation from that source and increased gas consumption. Also, energy producers have few alternatives to gas before sufficient electricity storage is in place and after they retire coal-fired and nuclear generation in line with Europe's decarbonization strategy; so demand for it remains high. At the same time, gas production in Europe has declined; and liquified natural gas (LNG) shipments to Europe were also lower, owing to limited upstream investments, still-subdued LNG capacity utilization, and stiff competition from Asian and Latin American buyers. Pipeline gas volumes from Russia have not increased sufficiently to balance the market, raising doubts about how much spare production capacity is available there.

Given the size of the current supply-demand gap, we don't expect a permanent solution to be found soon. Some contributing pressures may gradually subside, but we believe others represent structural shifts. These include Europe's dependence on imports and increasing exposure to global gas markets amid regulatory and technical uncertainties stemming from the energy transition. Europe's so-called gas bridge for its energy transition may therefore prove quite costly.

Europe's Grand Reopening And Weather Conditions Fueled Gas Demand

The surge in gas consumption after economic activity restarted, following the pandemic-led lull in 2020, was to be expected. However, it came after an unusually long and cold winter that led to increased demand for gas, as did lower wind power generation in the summer than usual. Gas prices increased to such levels that gas became less cost-competitive than coal and sometimes even liquid fuels.

In response, some price-sensitive industrial gas users, such as fertilizer producers Yara and BASF, have announced cuts to production. In the U.K., several coal-fired power plants ramped up in September. Yet the high price of coal and carbon dioxide (CO2; more than €60 per ton in September) reduced the relative cost disadvantage of gas. Also, since gas is the price-setting fuel in many European electricity markets, this drove up electricity prices across the region.

Chart 1

Despite the high prices, demand for gas in Europe is somewhat inelastic. In certain industrial applications and for heating, it is difficult to quickly find a substitute. Europe also faces mandatory retirements of a vast amount of coal-fired and nuclear generation capacity and is increasing the share of generation from renewable sources in line with decarbonization policies. S&P Platts Analytics estimates that about 12.8 gigawatts (GW) of coal, lignite, and nuclear capacity closed in 2021, and 26.2 GW will follow in 2022. For example, Germany plans to phase out about 4 GW of nuclear capacity, 6 GW of hard coal, and 3 GW of lignite by the end of 2022, while Belgium has decided to phase out its 5.9 GW of nuclear capacity by 2025, including about 1 GW in 2021.

Before sufficient energy storage capacities materialize, the inherent intermittency of renewables does not leave too many practical alternatives to gas as a back-up option. Although continued use of unabated gas is not compatible with Europe's long-term decarbonization policies, CO2 emissions from burning gas are 2x lower than from coal, and gas-fired generation is flexible. Belgium plans to expand its gas-fired generation to fill the void after the planned decommissioning of its nuclear units. Central and Eastern Europe relies heavily on coal and nuclear energy, and the share of renewables is still minimal. Therefore, we expect gas to remain an important part of Europe's energy mix for at least the next five to 10 years.

Chart 2

The Region's Gas Stocks Are Still Quite Low

Europe is heading into the next autumn and winter with its gas stock averaging only 75% as of Oct. 4, after heavy usage during winter 2020-2021 and weak wind conditions in August. This figure is well below the region's five-year average (see chart 3), and especially that for large storage facilities in Austria (now only at 54%), Netherlands (58%), and Germany (68%). In addition, Ukraine's gas-storage facilities, which have traditionally been used to cover seasonal winter demand peaks in Europe, are only 46% full.

Chart 3

Decreasing Local Gas Production Means Increasing Reliance On Imports

Europe's gas production is in structural decline, exacerbated in 2021 by maintenance works and tightening regulations. The large Groningen field in the Netherlands is down, in line with the accelerated phase-out schedule approved by the government to limit the risk of earthquakes. Its gas production quota for October 2020 to September 2021 was 8.1 billion cubic meters (bcm), and for October 2021 to September 2022, 3.9 bcm, with a complete stop planned in 2023. The U.K. has reduced production in 2021 by 5 bcm year on year because of maintenance delays. In October, Norway-based Equinor obtained permits to increase production at its Troll and Oseberg fields, but only by 1 bcm each. Overall, mounting environmental and social pressures make any significant expansion of upstream gas activities in Europe highly unlikely.

Over the past decade, however, Europe has been building up its LNG regasification capacity to reduce reliance on its largest supplier--Russia--after interruptions of gas supply from Russia via Ukraine in 2009. This coincided with a spike in global LNG capacity growth in 2019-2020, especially in the U.S., when gas supply seemed abundant. As a result, LNG has become a material part of Europe's gas mix, at 23% of total imports in 2020 (see chart 4). In addition, this year, the 10 bcm TAP pipeline started supplying gas to Southern Europe from Azerbaijan.

Chart 4

LNG Supply Will Remain Tight

This year, Europe's LNG imports were lower than anticipated (see chart 5). In 2018-2019, the market expected a glut from U.S. capacity but the actual production increment in 2021 was much smaller. The use of LNG capacity has been low globally, reflecting limited capital expenditure (capex) on upstream gas activity despite healthy prices, as well as LNG facility outages and downtime in 2021 because of overdue maintenance from 2020. We do not expect any significant new LNG capacity before 2023-2024 to materially boost global supply since LNG plants are multibillion dollar, multiyear projects, and not that many are under construction.

Chart 5

In addition, Europe faces increasing competition for LNG cargoes with expanding markets such as Asia and Latin America. The strong rise in gas demand in those markets, supported by economic growth and weather conditions (heatwave in Asia, draught in Brazil), took some LNG shipments away from Europe. Moreover, a large portion of the LNG supply to Asia is under long-term contracts. It appears that, this year, many European customers were relying on short-term gas arrangements that were suddenly not available.

S&P Global Platts' JKM (Japan Korea Marker; LNG price assessment) presently maintains a significant premium to TTF (Dutch Title Transfer Facility), implying that most of the world's flexible LNG supply will head toward Asia through the core winter months. This underlines our expectation that, although Europe's LNG imports will increase in the coming weeks as Latin American demand wanes and supply builds up, the total amount delivered will not materially surpass last year's levels.

Russian Gas Supplies Haven't Made Up For Shortfalls

Historically, Russia has been the swing supplier to Europe, and this year its gas production exceeds its five-year range and is well above that in 2020 (see chart 6). Still, Russian pipeline gas supplies have not been sufficient to balance the European market. In our view, this raises doubts about Gazprom's spare upstream capacity and marketing strategy. We believe high spot market prices, increasing political pressure, and Gazprom's strong incentive to maintain its reputation as a reliable supplier to the massive European market should support pipeline exports in the coming months.

Chart 6

Gazprom faces strong criticism in Europe and the U.S. for not increasing exports to Europe further. Certain members of the European Parliament sent a letter to the European Commission requesting an investigation into possible market manipulation. In addition, the U.S. energy secretary said the rise in prices had "raised serious concerns and questions on the reliability of the existing supply and security in Europe." The International Energy Agency (IEA) has stated that "Russia could do more to increase gas availability to Europe and ensure storage is filled to adequate levels," and that this could be "an opportunity for Russia to underscore its credentials as a reliable supplier to the European market."

Yet Gazprom complies with its commitments under long-term contracts. This was confirmed by the company's CEO and its large European customer Uniper, and reiterated in an official statement by the IEA in September 2021. For the time being, Gazprom does not fully satisfy additional gas applications, which are not commitments; and most of the volume on its electronic sales platform is scheduled to be delivered only in 2022-2023.

Gazprom estimates its total exports to Europe and Turkey at 183 bcm for 2021, which is close to historical averages (see chart 7). This volume compares with 179 bcm in 2020, and a record 199 bcm in 2019, when European customers were stockpiling gas in case of supply interruptions ahead of a major transit-contract renegotiation with Ukraine, and Europe experienced a major gas oversupply. Gazprom eventually signed a five-year ship-or-pay contract with Ukraine for 65 bcm in 2020 and 40 bcm thereafter, with additional capacity available at an extra cost. In 2021, Gazprom did not book any additional Ukrainian transit capacity on top of precontracted volumes. It focused on other routes, namely Nord Stream 1, Yamal-Europe (via Belarus), and the new TurkStream route that replaced the old Trans-Balkan route across Ukraine and Romania. Nord Stream 2 has been completed but is still awaiting the approvals needed to start operating.

Chart 7

How Much Spare Capacity Is There?

Gazprom's proven reserves are massive. At year-end 2020, they stood at 124.7 billion barrels of oil equivalent, of which 91% was gas. That said, Gazprom's old fields in Nadym-Pur-Taz are in irreversible natural decline and, like other gas majors, the company substantially cut capex in 2020 in response to the pandemic's impact and low-gas-price environment, with the TTF plunging below $2 per million British thermal unit.

A large fire at its Novy Urengoy condensate-processing plant in August 2021 caused Gazprom to cut gas supplies to Europe for several days. It was able to pump gas from European storage units to meet its contractual obligations and resumed exports to Europe much faster than most analysts expected. The company also brought the closed Urengoy-Purovsk pipeline back into operation and signed an agreement to use Novatek's Purovsky gas condensate-processing plant.

In addition, Gazprom has a legal obligation to secure the domestic gas supply in Russia, where heating is a social imperative and gas stocks need to be replenished.

Gazprom's realized prices are well below market average, which reduces the economic incentive   Gazprom doesn't fully benefit from current high gas prices because of the smoothing mechanism in its pricing formula. This reduces economic incentives to export more. On the other hand, Gazprom's offtakers in Europe should now be able to get gas at well below spot market rates. That said, even with the price-smoothing formula and cost of additional Ukrainian transit capacity, we estimate that exports should be highly profitable for Gazprom via any route. We understand the formula contains caps, floors, a high share of sales of forward-linked pricing (and forward prices are well below spot levels), and a still-significant, although reducing, share of oil-linked sales (13%). Although this mechanism protected Gazprom when gas prices dropped in 2020 to an average $143 per million cubic meter (mcm), it also reduces potential gains from the favorable price environment this year. For example, in the second quarter of 2021, Gazprom realized an average export price of only $224 per mcm, well below the spot market price; for the full year, it expects its average price to be $270 per mcm, substantially below the market.

The European market remains key for Gazprom but Asia offers growth prospects.   The European market is key for Gazprom's profitability, and we estimate it provides about 70% of EBITDA in 2021 and more than 50% under normal market conditions. With massive pipeline infrastructure and long-term contracts in place, Gazprom is strongly tied to the European market (see chart 8).

Chart 8

In the longer term, the company is exploring opportunities to supply expanding Asian markets with LNG, and increase exports to China via the Power of Siberia pipeline to 38 bcm by 2025 from about 4 bcm in 2020. However, the gas for the Power of Siberia pipeline comes from the new and otherwise stranded Kovykta and Chayanda fields. The volume envisioned is only about 20% of Gazprom's planned exports to Europe and Turkey for 2021.

A real game changer could come via the new Power of Siberia-2 pipeline, which Gazprom is thinking of building to supply China from its core reserve base in Western Siberia. But we believe such a project would require several billion dollars of investments and is unlikely to happen before a long-term offtake agreement is in place.

Nord Stream 2 Can Ease Only Some Of The Pressure

We believe Nord Stream 2 could help Europe's gas market settle but is unlikely to be enough. This project is obviously strategic for Gazprom, and its commissioning may create an incentive to increase supply. This pipeline would also reduce the short-run marginal costs for European exports since Gazprom could avoid paying for additional Ukrainian transit capacity. The route is also much shorter than the traditional one, adds transit flexibility, and starts closer to Gazprom's newer Yamal fields.

However, Nord Stream 2's certification is still pending. Nord Stream 2 was already 94% complete by year-end 2019, but had to wait for environmental approval from Denmark and was subsequently delayed again by U.S. sanctions that prevented contractors from working on the project. Construction was technically completed by September this year and is awaiting certification from the German regulator BNetzA to start sending gas to Europe.

We understand BNetzA's approval could take until January 2022. Also, Nord Stream 2's capacity utilization can be limited to 50% because of the amended EU gas directive on ownership unbundling and third-party access. We believe that, if needed, at least in theory, third-party access could be managed via export contract structures, which would shift the point of delivery from Gazprom to European customers. What's more, although under Russian law, Gazprom--as the owner of the Unified Gas Supply System--is the sole exporter of pipeline gas, other Russian producers such as Rosneft have been lobbying for access to gas exports via Nord Stream 2, which would require approval from the Russian authorities.

The Gas Bridge Is Now Shakier

We believe the extreme price volatility calls into question the role of gas in Europe's energy transition.   The current situation highlights the need to manage security of supply as well as social risks and energy affordability throughout the energy transition. Initially, gas-fired generation was seen as a flexible power source that can bridge the gap while the region expands renewables generation before sufficient utility-scale energy storage develops.

However, the energy transition implies the need for a much larger safety cushion, while reducing other options for that role because of shutdowns of coal and nuclear generation.   This puts a heavier burden on gas. But enlarged gas stocks, spare gas production capacity, transport, storage, and gas-fired generation come at a significant cost. Gas producers are unlikely to invest in this unless they are assured of sufficient returns through higher prices or long-term offtake arrangements.

Reliance on gas also brings additional exposure to prices, global market forces, and geopolitical risks.   We believe such risks could encourage Europe to strive for greater energy efficiency and faster replacement of gas for heating and other applications, to the extent technically possible. The EU's long-term energy policy is focused on expanding renewables and hydrogen to limit exposure to fuel imports, in line with the Fit for 55 package under the European Green Deal. Gas is not part of the current draft of Europe's Green Taxonomy, and recent investments in gas terminals and interconnectors did not prevent the gas shortage, which reduces the allure of new gas projects.

Europe's strategy has been to address security of gas supply through diversification and interconnection, while reducing the role of long-term contracts that historically supported that purpose.   It remains to be seen whether this year's gas-supply bottlenecks will push customers back to long-term contracts as a way to reduce supply risks. This is because, ultimately, customers' goal is to limit commitments to fossil fuel amid increasing decarbonization targets and higher perceived geopolitical risk related to gas. We see for example that the new 15-year contract Gazprom and Hungary signed in September 2021 has sparked political debates. In our view, high price volatility may complicate agreements on long-term pricing.

Without sufficient long-term contracts, it will be increasingly difficult for Europe to compete for gas with other markets in the coming years.   Gas demand in Asia, for example, is projected to rise rapidly and a large portion of pipeline and LNG supply is precontracted. Eventually, the lack of long-term offtake arrangements can limit access to funding for new LNG projects across the globe. Hence new LNG projects increasingly focus on expanding Asian markets as a key destination, as highlighted by Qatar's new long-term LNG supply contract with China's CNOOC, and Russia's Arctic LNG2's focus on supplying Asian customers via the North Sea Route.

Future Price Stability Will Likely Be Fragile

In our base case, we assume a pickup in gas supply, a demand correction, and political actions to limit the rise in gas prices, which should help bring the market closer to relative stability. Still, the risk of an unexpected gas price hike or shortages through the winter cannot be ruled out, depending on the weather in Europe and Asia.

We believe continued gas price volatility will further complicate the already ambiguous role of gas in Europe's energy transition and complicate power companies' investment decisions. The current exclusion of gas from the European Taxonomy adds to the uncertainty. This situation makes it hard for investors to engage in any new long-term gas investment in Europe.

Editor: Bernadette Stroeder.

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