Europe can only wean itself off Russian gas by pivoting to LNG, which presents opportunities but also high risks. This year's LNG imports cover over one-third of the region's gas consumption but, based on volumes in September-October, replaces barely half of the lost Russian supplies. S&P Global Ratings therefore expects Europe's gas balance will be very tight until at least 2025 and depend heavily on LNG until the end of the decade, by which time renewables expansion should have kicked in and demand would have reduced.

At the same time, European utilities, which typically have a weak position on global LNG markets, will be competing with established Asian buyers that can agree supply contracts for 15-20 years or longer. China, for example, has secured twice as much LNG as Europe from the next global LNG capacity buildup. In addition, portfolio supply diversification--at the right place and the right time--is crucial for Europe's utility sectors and the countries they serve. Europe could face a bitter winter if regasified LNG doesn't reach areas where it is most needed, for example due to infrastructure constraints.

For some utility companies, the risk of investing in new or larger LNG business could outweigh the rewards. In our base case, we assume a TTF (Title Transfer Facility) spot price of $40 per million British thermal unit (mmBtu) in 2023 (see "S&P Global Ratings Raises European Gas Price Assumptions On Uncertain Supply," published Aug. 1, 2022), similar to the average so far this year, and $25 thereafter since we believe supply constraints will gradually ease. In third-quarter 2022, the TTF averaged $61.0/mmBtu, triggering significant liquidity stress at certain utilities, but then more than halved this quarter. We believe that, at current levels, provided they are not too volatile, utilities' liquidity can absorb initial and variation margins. We think the LNG landed price (at European regasification terminals) should gradually converge with the TTF as physical and exchange prices converge, relieving the pressure on utilities somewhat. If further gas shortages or an extremely cold winter push market prices above our base case, utility companies could face a drop in earnings and liquidity.

Europe's Hunger For LNG Will Decrease At Some Point

We see weather-adjusted natural-gas demand reducing by just over one-tenth this year to about 430 bcm, primarily as industries, notably in Germany, Italy, Belgium, and Netherlands, respond to price signals. Encouragingly, EU demand in August-September was 14% below the 2017-2021 average. Gas demand should dip slightly next year as stronger nuclear and hydro power reduces the need for gas to generate electricity (see chart 1), and residential and commercial customers adjust power use to higher prices, even with energy affordability-protection policies. Natural gas accounted for 24.3% of Europe's current primary energy demand in 2021; for Italy, the Netherlands, Hungary, and U.K., this was more than one-third, whereas France, Sweden, and for now Poland are much less dependent on gas (see chart 2).

Chart 1

Chart 2

Gas for conversion into power (gas-to-power) accounts for about 30% of demand and, based on movements in 2022, we do not expect demand for it to subside despite high prices. Rather, if all EU countries were to adopt Iberia's scheme to limit the price of gas used to generate power, as is being discussed, that could revive demand for gas-to-power. We've seen, for instance, a 4% increase in gas consumption in Spain as of Sept. 30, year on year. From 2024, demand should gradually decline as heat pump installations accelerate and renewable sources replace gas-to-power, net of coal and nuclear retirements. Each year, a one-to-one substitution would save about 3% of gas, roughly 10% after three years (see chart 3)). To illustrate, over March-September 2022, wind and solar generated 345 terrawatt hours of electricity across the EU, saving about 70 bcm of gas, about 8 bcm more (+13%) than during the same period in 2021.

Chart 3

From 2030, Europe's natural gas demand, notably for heating and power generation, should reduce significantly, since renewable capacity is forecast to triple by the end of this decade. Hydrogen, both locally produced and imported, alongside a rampup of biomethane, could reduce Europe's demand for natural gas by, respectively, about 27 bcm and more than 20 bcm.

Non-LNG Supply Options Are Limited

We don't expect a rebound in gas supply from Russia, with the Nordstream and Yamal pipelines remaining idle. And there's a risk that the three other Russian sources--the Ukraine pipeline, Turkstream's European leg, and the Europe-bound portion of Yamal LNG supplies--could be cut off. Together, these currently contribute over 3 bcm of Europe's monthly gas imports, enough to meet on average about 8% of demand. In our base case, we exclude supplies from train 1 of Arctic LNG, Russia-based Novatek's second facility, which is due to be commissioned next year.

What's more, gas production in the U.K. and continental Europe will likely remain flat or decline slightly, and the potential for additional Mediterranean pipeline imports is low; each of these three sources cover barely one-tenth of European demand currently. Apart from LNG, by far the largest and most reliable supply pillar for the U.K. and EU is Norway, whose approximately 120 bcm of gas exports per year cover about 30% of Europe's consumption and should be fairly steady through 2030 but with no significant upside. That said, Norway's production barely exceeds half that of Pennsylvania, the U.S.' second largest gas-producing state. Positively, from November, Poland (and via Poland, Slovakia and the Baltic states) could receive gas directly from the Norwegian Continental Shelf.

Storage, albeit almost full in most countries (see chart 4) apart from Austria and Hungary, caters for only about one-seventh of annual demand. This factors in drawings of about 60% from stored LNG during winter and 30% being available at the end of the heating season. Europe has more capacity relative to consumption than both the U.S. (whose storage capacity is similar but for a market that's almost 2.5x larger) and Northeast Asia, but this offers only modest sourcing flexibility. Other than the reopening of the U.K.'s Rough undersea 0.76 bcm storage facility at 20% capacity, no discussions on a meaningful increase of capacity are taking place.

Chart 4

2025 Will Be A Pivotal Year For Europe's Gas Balance

Essentially, the security of Europe's gas supply hinges on the region's ability and willingness to contract sufficient additional liquefaction capacities in the U.S. from 2025 and Qatar from 2026. Most of Europe's LNG imports currently go to the U.K., Spain, France, Belgium, and Netherlands. Europe's only new regasification capacity is the 8 bcm per year Eesmshaven plant in the Netherlands, commissioned mid-September. However, even if there were enough regasification plants, which new German floating storage regasification unit (FSRUs) should ensure by next winter, they need stable supply; plus, there are difficulties in shipping the gas further eastward. Consequently, through 2025, Europe's gas balance will remain tight (see chart 5).

Chart 5

What Might Derail Europe's LNG Supply Plan

The renewal of supply contracts, possibly with larger volumes, and contracting new LNG sources are vital for Europe to keep the lights on over the next few years. According to the International Energy Agency, about 180 bcm of active LNG contracts are set to expire by 2025. However, Europe was able to contract less than 10 bcm of the total market volume of 70 bcm-90 bcm in 2017-2021, which paints a dim picture. The situation is similar in 2022 despite Europe's gas woes. We see three main supply hurdles:

Lack of a cohesive sourcing approach.  Europe continues to contract piecemeal. So far this year, gas suppliers have each, separately, contracted small opportunistic volumes of 1 bcm-2 bcm per deal for five to six years rather than for the long term. Such contracting, while positive, doesn't reliably strengthen Europe's security of supply.

Stiff competition from countries in northeast Asia, especially China.  European utilities need LNG for only a few years, since decarbonization will accelerate early in the 2030s and demand for hydrocarbons should drop. By contrast, Asian buyers can offer up to 25-year terms for supply contracts. Typically, the bulk of LNG shipments from the Middle East and Australia go to China, Japan, South Korea, and Taiwan. Although Europe's LNG imports are expected to increase by about 65% this year, they are still less than half of Asia's, which account for about two-thirds of the global total (see chart 6). The top five importers are all in northeast Asia, and each imports at least 50% more than any European country. This year, tepid GDP growth in Asia has resulted in flat gas demand and freed up about 20 bcm of LNG to Europe's benefit. However, Asia's gas demand will rebound at some point and (except in South Asia) can withstand relatively high prices. In particular, this is because its overall blended pricing remains moderated, unlike Europe's, by substantial indexation to oil products. As demand rises, it would absorb the 20 bcm freed up in 2022 and nearly all of the global liquefaction capacity additions in 2023.

Chart 6

China, whose gas market is now equivalent to the E.U.'s in size after almost doubling over 2015-2021, can sign very long-term LNG contracts because it needs to satisfy increasing demand from industries and city gas and power-generation plants, while implementing its long-term decarbonization strategy. According to S&P Global Commodity Insights, China has secured twice as much LNG as Europe from the U.S.' third wave of LNG capacity, which comes on stream in 2024-2026; China actually serves as the baseload customer to launch new capacity, with pricier spot exports to Europe helping to boost profit for newbuilds. Total gas demand from China will keep rising and peak only by about 2040, while the country's demand for LNG quadrupled in 2015-2021. This intake will be well supported by ongoing regasification capacity additions, which S&P Global Commodity Insights estimates at about 35 bcm yearly through 2024, as much as Europe's 2022-2024 total.

Apart from Japan, most Asian economies' GDP and energy consumption are set to expand rapidly from 2024. This will fuel gas demand further even if nuclear restarts or newbuilds, already ongoing in China, gain traction in Japan and South Korea.

European utilities' operating models put them at a disadvantage against national oil companies   National oil companies like Qatar Petroleum, and European integrated oil companies like Shell PLC and TotalEnergies SE, manage LNG portfolios of 55 bcm-80 bcm per year, with direct access to LNG sources. Integrated oil companies' very diversified sources also enable them to reap considerable arbitrage profits across regional markets, especially when they have regasification capacity (TotalEnergies estimates that it commands 24 bcm per annum in Europe, or 15% of the total).

By contrast, European utilities--unlike Japanese and Korean offtakers and European integrated oil companies, including BP PLC and Eni SpA--rarely take equity stakes in liquefaction projects that could stabilize relationships through the chain (physical supply and cost of procurement) and allow them to procure gas at cost. This exposes them to higher, more volatile prices on spot/short-term supply contracts, which made up 37% of the global LNG market in 2021, effectively putting the other 63% out of reach. It also makes them less attractive as buyers, since liquefaction players prefer longer contract terms and could increase dependence on the U.S., which represents one-third of the global LNG supply on spot markets.

However, based on the European Commission's Oct. 18 proposal, EU governments seem ready for joint mandatory procurement of up to about 13.5 bcm per year (15% of the 90% refilling obligation), and more on a voluntary basis. This may help utilities contract larger volumes to support security of supply. There appears to be less progress on joint storage management, which affects gas injections and withdrawals, whereas within the EU the proportion of national demand potentially served by domestic storage varies from less than one month (Belgium, Ireland, Portugal, and Sweden), to just over 12 months (Austria) or 24 months (Latvia).

Prices Will Stay High As U.S. Supply Replaces Gazprom

Fundamentally, as Gazprom's supply dwindled, Europe lost its largest, most flexible, and often cheapest source of gas. Its ability to source gas, and the price at which it does so, now depends on global supply and demand dynamics. Europe will therefore continue to contribute to high prices, which however are unlikely to go beyond this year's peak (see chart 7). Norway provides a strong supply of baseload piped gas supply. However, Europe needs LNG from the U.S. and Qatar for additional baseload and swing capacity. Separately, from an environmental point of view, according to the Natural Resources Defense Council, greenhouse gas emissions from U.S. LNG supplies to Western Europe may be about one-quarter lower than from Siberia through Gazprom's pipes, which run over 4,000 kilometers to the German border. Liquefaction, tanker transport, and regasification account for only one-tenth to one-fifth of total LNG-to-power emissions.

Chart 7

Europe's forced-march purchasing has been a key driver of rising prices. Since the second quarter of this year, Europe has bought cargoes at virtually any price and diverted spot and even long-term cargoes (implicitly paying the supplier's breakup fee) from Asia Pacific. It doubled to two-thirds its share of the U.S.' rising LNG exports. To achieve this, Europe outpriced South Asia and benefited from weaker-than-expected demand from northeast Asia.

In the longer term, LNG landed in continental Europe will price high, likely at a continuing premium to Asia Pacific, keeping gas and power prices in Europe elevated. This carries considerable risks for inflation, affordability, state budgets, power markets, and utilities' earnings and liquidity. LNG will continue to feed the EU's large and increasing trade deficits on energy products, which for January-August 2022 totalled €423 billion, up €271 billion or 2.5x year on year, thus swinging the overall trade balance into a €310 billion deficit, its first since 2011, after a €92 billion surplus in 2021. This has prompted a number of E.U.-level policy responses.

On Oct. 18, the European Commission proposed a new LNG-based complementary price benchmark to TTF that it expects would be available early next year. Regardless of the success of this initiative, and an apparent preference for a mix of regional gas indicators (LNG is currently most often priced from oil or Henry Hub), solving the root cause of the current situation by addressing internal physical bottlenecks for TTF to converge with LNG landed prices might provide a more sustainable solution. We believe the last five quarters marked a structural increase in gas prices, and therefore also power prices in the EU (and U.K. except when its gas interconnectors with the continent are full). This reduces the competitiveness of Europe's industrial sectors versus those in the U.S. and Middle East, where domestic prices per mmBtu should remain in the low- to mid-single digits. To illustrate, as of Oct. 26, 2022, global chemicals leader BASF stated that over January-September the natural gas costs at its European sites almost tripled to about €2.2 billion year on year. Its German operations generated a loss (EBIT before special items) versus contributing one-third to the group's global earnings in 2015.

Another policy being discussed at the EU level is whether to impose a general price cap, either for imports including LNG or for wholesale trades within Europe. Yet such a move, seen as direct political intervention, may discourage LNG suppliers. Moreover, a price cap, even when effectively moderating prices--as in Iberia's gas-fired power; or in France, where it supports government's affordability objectives--also encourages demand and doesn't address the fundamental issue--Europe's physical gas gap--since households and small businesses would feel less price pressure.

Supply will be at its tightest in 2023-2024 as demand from Asia Pacific rebounds at a time when there are few liquefaction capacity additions globally. Prices should trend down afterward as over 130 bcm of new supply (nearly equivalent to Europe's 2021 imports from Gazprom) is commissioned, broadly evenly split between the U.S. in 2025--making the U.S. the global leader within seven years of starting exports--and Qatar's massive North Field East and South facilities in 2026-2027 (see chart 8).

Chart 8

Europe could somewhat reduce its vulnerability to global LNG demand and supply by controlling the region's volume and price risk, ensuring LNG arrives where it's most needed. This will increasingly occur since, from 2024, Italy and Central and Eastern Europe (CEE) will have enough landing and regasification capacity. S&P Global Commodity Insights estimates that, by winter 2023-2024, regasification capacity in CEE should have quadrupled to about 29 bcm per year. If fully used, this will be equivalent to about one-quarter of annual local demand. Continental northwestern Europe and Italy would then have about 73 bcm per year between them. Until then, we see the southern and eastern German, Czech, and Slovak markets as most at risk of gas shortages, while Iberia, the U.K., France, Belgium, and now the Netherlands, can balance supply and demand using LNG after replenishing their underground storage. More than 60% of Iberia's and the U.K.'s regasification capacity remains unused and is equivalent to that of France, Belgium, Netherlands, and Italy combined (see chart 9), which are nearly fully used this year. The wide gap between LNG and TTF prices since April shows the cost of supply setbacks and missing interconnections.

Chart 9

Diversification Of Sources Will Help Balance Gas Replacement And Risks

Europe still has to find a long-term solution for replacing Russian gas while avoiding a new supply predicament. It needs a lot of spot LNG, which is risky, pricy, hard to control, and requires ongoing tanker chartering in a market where supply has become tighter and chartering for six to 12 months has become popular. Also, apart from the U.S., nearly all alternative sources involve geopolitical risks.

We believe the key to mitigating these risks lies in Europe having highly diverse sources, ideally through joint procurement, thereby reducing reliance on one country. That said, the U.S. will likely remain Europe's safest and largest source of gas, given its impressive production and technology dynamics; over 2017-2021 alone its production rose 26% or by 203 bcm, equivalent to nearly half the EU's consumption in 2022. The U.S. is also one of the first supplier countries to add a significant amount of capacity, although capturing spot volumes from these sources will come at a cost.

Risks linked to LNG imports from the U.S. include tropical storms (with nearly all capacity on the Gulf coast), local regulations, and continued availability.  The U.S. first needs to cater to domestic consumption, which is about 6x its forecast 2026 LNG exports. Also, there could be constraints to getting feed gas into the large liquefaction plants east of the Henry Hub in Louisiana, especially when local consumption peaks. Added to this are the need for continued technical availability of liquefaction facilities and timely completion of large projects (only two and a half years planned for major capacity additions underway). There's also a risk of negative reactions from U.S. gas consumers if domestic prices spike as Europe's purchases boost export netbacks. We saw in August-September that the Henry Hub marker increased 2.3x from its 2021 average to $8.8 per thousand cubic feet, in part because the TTF was 7.3x higher.

LNG imports from Qatar hinge on completion of the North Field expansion, the world's largest single liquefaction project.  Even today, there's exposure in the form of reliance on the massive Ras Laffan facility, a critical plant in this region, and transit through the narrow strait of Ormuz, both potential targets of military attacks.

We foresee higher internal country risks and competition from rising domestic demand with respect to imports from northern Africa.  Europe sources gas from Algeria via both pipe and LNG, from Azerbaijan by pipe, and potentially from Egypt through LNG (for example as Israel exports more gas to Egypt). These channels all carry risks, albeit to varying degrees. A year ago, for example, Algeria stopped exporting gas to Iberia after doing so for 25 years through the 13.5 bcm Gazoduc Maghreb-Europe pipeline, reflecting its tense relationship with Morocco. Both of Egypt's liquefaction plants have been idle for long periods as increasing domestic consumption crowded out LNG exports. Meanwhile, new LNG sources from Africa (such as Eni's projects in Mozambique and Congo) are small and subject to stability in the respective country.

LNG Can Reshape Certain Utilities' Business Models

This year and next, certain European utilities will likely benefit from LNG and term trading profits, like Naturgy (see "Naturgy Ratings Affirmed; Outlook Neg; Outstanding Hybrids' Equity Content Now Minimal On Redemption Without Replacement," published Oct. 13, 2022). In the longer term, we anticipate that some will seek to capture business opportunities from the increasing importance of LNG, especially since certain EU countries have recently designated LNG infrastructure (along with storage) as being of critical importance to energy security.

Governments may therefore initiate a change in utilities' business models. For example, the German government, in implementing its massive rescue plan for Uniper SE (BBB-/Negative/--)--the country's largest importer of Russian gas--and addressing certain contracting issues at VNG (not rated), a subsidiary of EnBW (A-/Negative/A-2), clearly mandated these groups to build floating and fixed regasification infrastructure as soon as possible and contract sufficient LNG supply to fully use it. The rescue plan for Uniper includes €8 billion of equity and at least €18 billion in credit (see "Uniper 'BBB-' Rating Affirmed After Announcement Of German Government's Full Takeover; Outlook Remains Negative," published Oct. 12, 2022). This was shortly after the government took over Gazprom Germania (renamed SEFE; not rated) and provided €15 billion of financing for SEFE to buy gas, notably LNG, to speedily replenish storage facilities. Companies like Netherlands-based Gasunie (AA-/Stable/A-1+) and Poland's PGNiG (not rated) are already more advanced than their peers in northern or eastern Europe in meeting increasing LNG import needs, by establishing or increasing their regasification capacity.

LNG is also well suited to utilities looking to expand into countries or regions otherwise hard to reach by natural gas supply. Russia-dependent Hungary, for instance, has started importing LNG from neighboring Croatia, which could double its annual LNG receipts to 6.1 bcm, and potentially serve Russia-dependent Serbia. Other areas include Sardinia, as illustrated by Snam SpA's (BBB+/Stable/A-2) chartering of an FSRU, to be commissioned by 2024; Cyprus, until offshore gas fields are commissioned; or potentially Ireland. The commissioning of terminals in Poland and Lithuania in 2015 and 2014, respectively, and currently the development of the Lubmin floating unit on Germany's Baltic coast, aim at supplying otherwise gas-poor regions.

Interestingly, regasification capacity additions are often in countries that already have substantial underground storage, as if Europe is transitioning to a more agile supply-securing combination of both in the same country. By contrast, each country typically focused on LNG capacity (such as the U.K. and Spain) or underground storage capacity (as in northern Europe, Italy). Indeed, we see companies combining some or all of LNG regasification, transmission, storage infrastructure, and supply. For example, Italian gas transmission company Snam has purchased two FSRUs for deployment at Ravenna in 2023 and Piombino in 2024, and Gasgrid Finland (not rated) has chartered an FSRU to be installed at Inkoo in January.

How We Assess The Business And Financial Impact

Although expanding or building LNG infrastructure may strengthen a European utility company's long-term credit quality, it also carries credit risks. Increasingly strict decarbonization policies imply a steep drop in demand for hydrocarbons, including LNG, from the early 2030s. Utilities with LNG as a core business face a drop in earnings alongside fixed costs for stranded assets, whereas amortization periods are typically 20 years-25 years.

Our analytical approach to assessing the impact on business profiles starts by understanding the company's long-term strategy. We then assess in particular:

• Prospects for adding a potentially profitable business.
• The possible business diversity benefit.
• How the company evaluates and addresses the risk of new assets being stranded, particularly from the early 2030s.
• Likely challenges related to procuring spot and medium-term cargoes, especially when there's a commitment to the government to use all of the new regasification capacity.
• How the company evaluates and mitigates intense competition from established competitors like energy traders and integrated oil companies with long-standing LNG experience and assets, including operational and equity stakes in liquefaction plants. We also look at access to tankers, FSRU chartering (such as for TotalEnergies at Lubmin, Germany, and Le Havre, France, both planned for commissioning within 10 months), and supply management in general. Several competitors have global LNG ambitions, considerable investable cash flows, and much-stronger balance sheets than European utilities. They include Europe-based leading global LNG players Shell, which has booked half of Eemshaven's 8 bcm per year capacity; TotalEnergies, which for third-quarter 2022 disclosed a 54% year-on-year rise in its average equity LNG price to $21.5/mmBtu as it leveraged on the 30% spot component of its portfolio, contributing to record cash flows; BP; and Eni.
• The benefit to national security that may prompt governments to support such companies, as illustrated in Germany since July.

From a financial perspective, we assess in particular:

• The amount and pace of capital expenditure (capex) needed.
• Long-term lease commitments taken.
• Whether LNG investments are structured as stand-alone projects or part of joint ventures or partnerships with other market participants, and--if so--whether the rated utility has control of and consolidates the LNG operations.
• The degree to which the related capex is self-financed or increases borrowings.
• The utility's exposure to the risk of mismatches between supplied cargoes and its own local sales, and to large reprocurement costs. For example, the idling of the Texas Freeport liquefaction facility on June 8 led to significant losses at its Japan- and Europe-based utility clients.
• The impact on liquidity, including through additional hedging activity.

The Next Two Years Will Be Critical

Overall, we see 2022-2024 as a crucial period for Europe to stabilize its gas and power landscape through LNG contracting and infrastructure buildup. This is happening just as many utility companies are generating negative free cash flow as they invest heavily to increase their renewables capacity. Likewise, government policies and regulations need to ensure continuity of gas supply at affordable prices, but only for a relatively short period while supporting utilities effecting the energy transition.

Related Research

• Utilities Handbook 2022: Western Europe Regulated Gas, Nov. 4, 2022
• Naturgy Ratings Affirmed; Outlook Neg; Outstanding Hybrids' Equity Content Now Minimal On Redemption Without Replacement, Oct. 13, 2022
• Uniper 'BBB-' Rating Affirmed After Announcement Of German Government's Full Takeover; Outlook Remains Negative, Oct. 12, 2022
• What Europe's Energy Redesign Might Mean For Its Power And Gas Markets, Sept. 13, 2022
• Nord Stream 1 Shutdown: Will Utilities And Markets Freeze This Winter?, Sept. 6, 2022
• S&P Global Ratings Raises European Gas Price Assumptions On Uncertain Supply, Aug. 1, 2022
• Energy Transition: Gas' Role Varies By Sector And Region Amid Security Of Supply Concerns, July 20, 2022