European energy security and Europe's power structure issues

Recent shifts in the international political landscape have fully exposed Europe’s long-standing energy security vulnerabilities. Europe has historically relied heavily on energy imports: approximately 45% of its natural gas imports and about 27% of its oil imports come from Russia. Ensuring a secure, stable supply of energy and electricity—and reducing exorbitant energy prices—has thus become an urgent priority for Europe. Starting in 2022, Europe’s new-energy vehicle sector may accelerate further, directly linking energy solutions to end-use applications. Note: Currently, Europe appears to be acting hastily and without clear strategic direction—akin to ‘treating a serious illness with indiscriminate remedies.’ Part 1: Overview of Europe’s Energy Situation Recently, the U.S. and the EU reached an agreement aimed at securing energy supplies: the U.S. will supply an additional 15 billion cubic meters (bcm) of natural gas to Europe this year, and help Europe phase out its dependence on Russian energy by 2027. By 2030, the U.S. pledges to supply Europe with 50 bcm of liquefied natural gas (LNG) annually. In contrast, Russia currently delivers roughly 1,500 bcm of natural gas to Europe via pipelines each year, plus another 14–18 bcm of LNG. Given current figures, U.S. supply volumes remain negligible relative to European demand. In 2021 alone, Russia delivered 35.9 million tons of crude oil to European refineries via the Druzhba pipeline—equivalent to approximately 720,000 barrels per day. Russia supplies gas to Europe through four major pipeline routes: (1) Nord Stream 1, running under the Baltic Sea to Germany; (2) the Yamal–Europe pipeline, traversing Belarus and Poland to Germany; (3) multiple Ukrainian pipelines feeding Slovakia, Hungary, Romania, and Poland; and (4) Turkish pipelines (Blue Stream and TurkStream), connecting to Bulgaria, Serbia, and Hungary. Crude oil, natural gas, and coal constitute the three largest components of Europe’s energy consumption—all heavily import-dependent—rendering Europe’s overall energy structure fragile. In 2021, Europe consumed around 480 bcm of natural gas, of which ~90% was imported. The European Commission now aims to mitigate energy risks by diversifying hydrocarbon supply sources—increasing LNG imports from major producers such as the U.S. and Qatar—while simultaneously improving energy efficiency and conserving consumption, targeting a reduction of 90 bcm in natural gas usage. In the short term, it is virtually impossible for Europe to resolve its structural import dependency—‘strangling-point’ vulnerabilities—in energy. Structural contradictions persist throughout the energy transition period. Part 2: Europe’s Electricity Sector Situation The report ‘European Electricity Review 2022’ contains many insightful statistical findings; below are selected highlights for clarity. Historically, Europe’s growing renewable generation has displaced coal-fired power. However, due to soaring natural gas prices in the second half of 2021, renewables growth has increasingly substituted for gas-fired generation—a trend likely to intensify under current conditions. 2021 marked Europe’s first step toward post-pandemic normalization: electricity demand has largely recovered to pre-pandemic (2019) levels, and overall demand is projected to rise further in 2022. ● Except in September, renewable electricity generation in Europe set new monthly records every month during the second half of last year. Wind and solar power jointly generated a record 547 TWh in 2021—surpassing natural gas generation (524 TWh) for the first time. Solar power is thriving across both northern and southern Europe: its 2021 output rose 27% over 2019 levels, while generation in the Netherlands and Spain doubled over the same period.

Senior CNOOC experts analyze the LNG import industry chain and business model; recommended reading for energy and chemical professionals

In South Korea, LNG import operations—aside from the Gwangyang LNG terminal (commissioned in 2006 through special government approval for joint investment by SK Group and POSCO Steel, exclusively for self-use with no third-party sales)—are monopolized by Korea Gas Corporation (KOGAS). LNG import pricing is linked to the Japan Crude Cocktail (JCC) index. On the sales side, KOGAS maintains monopoly control over supply to city gas distributors and power plants (except for large industrial users); city gas providers and power plants then resell gas and electricity to end consumers. Like Japanese gas utilities, KOGAS signs long-term ‘take-or-pay’ supply agreements with resource suppliers, with pricing also tied to the JCC. Leveraging its monopolistic position in the import segment, KOGAS passes through both take-or-pay obligations and price volatility risks to downstream customers via full cost pass-through pricing. 3. LNG Import Business Models in Europe Marked by the completion of natural gas market reforms across EU member states around 2008, Europe’s LNG import business models fall into two distinct phases. Pre-reform, Europe’s model resembled Japan’s on the import side and South Korea’s on the sales side: a monopoly-based system wherein major LNG importers held exclusive regional import rights, signed long-term take-or-pay contracts with suppliers, and transferred associated take-or-pay risks downstream via monopolistic sales practices. However, following maturation of Europe’s gas markets and near-completion of supporting infrastructure, EU-wide gas market reforms were launched—primarily aiming to liberalize the natural gas sector. Key reform measures included mandatory third-party access (TPA) to LNG terminals and transmission pipelines (though in practice, many terminals secured temporary exemptions from full TPA requirements). Post-reform LNG import business models are illustrated in Figure 3. Under the reformed model, natural gas procurement (import) companies are financially and legally separated from transportation and storage operators; transport and storage firms provide only logistics services and are prohibited from trading gas; and LNG terminals must offer open access to third parties. Gas companies—or independent third-party entities—purchase LNG from resource suppliers and contract infrastructure providers for storage, regasification, and onward delivery services. Sales are conducted via bilateral gas supply agreements between sellers and end-user buyers. Given Europe’s mature gas markets and robust infrastructure, stable demand allows upstream take-or-pay risks to be dispersed across a well-functioning market environment. Regarding import pricing, two mechanisms now coexist in Europe: one links LNG prices to domestic alternative fuel benchmarks (e.g., oil), while the other ties them to national gas trading hubs—such as the UK’s National Balancing Point (NBP), the Netherlands’ Title Transfer Facility (TTF), Germany’s NetConnect Germany (NCG), and Italy’s PSV. Currently, hub-linked pricing accounts for over 50% of all LNG import contracts. III. Analysis of China’s LNG Import Business Models 1. Integrated Resource–Market Model The integrated resource–market model is epitomized by China’s first-generation LNG projects. Market context for this model: Internationally, trade participants enjoyed limited autonomy; LNG sellers required firm, committed offtake markets before finalizing investment decisions. Domestically, China’s natural gas market remained in its infancy.

Italian energy regulator approves gas liquidity service to narrow PSV-TTF spread

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The Italian energy regulator ARERA has approved a gas liquidity service aimed at narrowing the price spread between PSV and TTF benchmarks. The final regulatory document is expected by October 21 following market consultations.

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2026-10-20

Italian energy regulator approves gas liquidity service to narrow PSV-TTF spread

Italian energy regulator approves gas liquidity service to narrow PSV-TTF spread

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