Italy has no shortage of natural gas infrastructure, from major pipelines coming from Europe and North Africa to LNG terminals. How, then, can the country still have some of the highest wholesale gas prices in Europe, rivalling even Spain, with its notorious lack of interconnections?
Solving the Italian gas market puzzle is not an easy task. But it is possible to identify factors that, taken together, create a unique and enduring ecosystem where no new big players have ever managed to emerge and to push down prices through a market share strategy.
Rather, these factors have made Italy an attractive place for gas price takers – companies interested in holding a small share of the market and taking advantage of the high price scenario, with no apparent intention to change it.
While EU rules and some changes in Italy gas markets in the past have attempted to rein in dominant shippers, this work is far from being completed.
Illiquidity and control over supply routes are the main factors that kept the premium of the Italian gas spot contract to the Dutch TTF equivalent at an average of Eur2.70/MWh during 2019.
Large shares of Italy’s gas market are in the hands of few big players and one of them, the biggest, is also in control of Italy’s major importing routes, including Italy’s most expensive and the market price maker – the Swiss Transitgas pipeline.
With 38 Bcm of gas sold in Italy in 2019 out of total Italian consumption of 70 Bcm (54%), Eni is Italy’s largest supplier. Edison is second, with 20 Bcm sold in 2019 and a 28% share, followed by Enel, with 4.7 Bcm sold in 2019 (6.7%).
On the wholesale market, Eni holds a 14% share and another 10% is in the hands of the major’s trading arm, Eni Trading & Shipping. Engie Global Markets follows with a 10.3% market share and Enel comes next with an 8% share, according to the latest annual report from ARERA, the Italian energy regulator, published July 21.
In 2019, Eni was responsible for 47% of Italy’s gas imports, according to the same report. Most of the gas that Eni supplies to Italy comes from long-term gas supply agreements signed with all of Italy’s main suppliers: Russia’s Gazprom, Algeria’s Sonatrach, Norway’s Equinor, and its own Libyan subsidiary, Mellitah Oil and Gas, an Eni-NOC joint venture.
According to the ARERA report, Italy’s PSV gas hub has seen its churn rate increase over the past ten years and reaching 3.3 in 2019 from about 2.5 in 2015. Churn rate indicates the number of times a commodity is exchanged on the hub before being physically delivered. ARERA said the 2019 increase was mostly due to increased LNG deliveries at the PSV, and also the creation of a balancing market in 2016. But Italy is still far from a churn rate of 10, at which a gas market is considered liquid and mature.
Tarvisio, no room for competitorsWhile the rise in LNG flows in recent years may have aided liquidity slightly, gas delivered via pipelines makes up the lion’s share of Italy’s supply and is far more important in setting prices.
Italy’s biggest import route, the TAG pipeline, which runs from Baumgarten on the Austria-Slovakia border to Tarvisio on the Italian border, is largely controlled by Italy’s largest supplier, Russia’s Gazprom.
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The Russian major owns about 80% of some 39 Bcm of available transport capacity at Tarvisio, under a long-term deal inherited from Eni in January 2018.
According to industry sources, while handing over its long-term transport capacity contract expiring in 2023 to Gazprom, Eni also changed the delivery point of Russian volumes imported under the Eni-Gazprom long term supply deal – which is believed to have a take or pay obligation of about 21 Bcm/year – from Baumgarten to Tarvisio.
The European Union framework for gas transport capacity ownership, called the capacity allocation mechanisms network code, does not exclude the possibility of a single company owning the large majority or even the totality of a gas pipeline’s transport capacity. It only requires that no more than 80% or 90% of the available capacity – depending on specific circumstances – is booked under long term agreements, with the remaining 10% or 20% to be kept free for spot bookings.
The same framework obliges long-term capacity holders to resell unused capacity on a spot basis, but there is no obligation to do so for longer term periods.
With 80% of the largest pipeline supply route in the hand of a single participant, little TAG transport capacity is left for companies interested in selling large gas volumes in Italy under a market share strategy.
Sonatrach’s insistence on oil formulasAs Italy’s historical buyers of Algerian gas – Eni, Edison and Enel – significantly reduced their long-term imports last year, Algeria’s oil and gas company Sonatrach has been on the lookout for new importers. But it has failed so far to find them among smaller Italian gas suppliers.
Starting from October 2019, Eni cut its long term imports to around 9 Bcm/year from 16 Bcm/year under the old deal, Edison reduced contracted volumes from 7 Bcm/year to 3 Bcm/year, and Edison cut supplies to 1.5 Bcm/year from 1.9 Bcm/year.
With a 30.2 Bcm/year technical capacity pipeline linking Algeria to Italy via Tunisia and the Mediterranean Sea – on which Eni hold exclusive operative rights – Italy has the ability to increase its gas imports from Africa. But Sonatrach’s preference for oil-indexed formulas has been so far the main obstacle, leaving Eni as the main importer.
Despite introducing more flexibility into formulas and deals with a shorter duration of 1-5 years, Sonatrach’s continued preference for oil indexation as a mechanism to set prices was seen as too risky and difficult to manage by smaller Italian market participants approached by the company in 2019, sources said, even if they were strongly interested in enlarging their portfolio.
Libya, the other African source of gas for Italy, remains a territory dominated by Eni. The major produces gas in Libya through a joint venture with NOC and imports those volumes via the Greenstream gas link, which is owned and operated by GreenStream BV, a joint venture of Eni North Africa BV (Eni) and NOC (50% each).
Switzerland, the price makerEni and Gazprom’s control of imports via Austria and those sourced from North Africa needs to be considered together with another important factor – Italy’s marginal route determining the price of the PSV spot gas.
As in every other gas market, it is the most expensive supply route that sets the day-ahead price of a hub, and for Italy, this is the Transitgas pipeline, which crosses Switzerland. Importing even small volumes via this pipeline can cause Italian spot prices to increase their premium towards the reference Dutch TTF gas hub.
In 2019, volumes imported in Italy via Transitgas stood at 10.5 Bcm, making this the second-largest source of pipeline gas after Tarvisio (28 Bcm in 2019), but only the third-largest source of gas if the 13.3 Bcm of LNG imported by Italy in 2019 is considered.
Gas is sourced in Norway, France or the Netherlands, enters the Tranistgas pipeline at Oltingue (French-Swiss border) or Wallbach (German-Swiss border), and exits at Passo Gries (Swiss-Italian border). Switzerland does not apply European rules around capacity allocation on its territory, and that is what makes this route so pricey when used on a spot basis.
More than 50% of the Transitgas transport capacity is booked by Eni under a long-term, over-the-counter (OTC) contract signed with the TSO operating 90% of the pipeline, FluxSwiss.
While in Europe long-term capacity holders are obliged to resell unused firm transport capacity on a spot basis, this “use it or lose it” principle does not apply in Switzerland, creating a shortage of spot transport capacity on Transitgas.
Moreover, Switzerland still relies on a contractual method to allocate capacity on its pipelines, as opposed to EU member states, which switched to an entry-exit system where capacity rights are booked independently at any entry and exit point of the gas system.
Traders wanting to import spot gas via Transitgas have to purchase entry and exit fees at the Oltingue, Wallbach and Passo Gries interconnection points as envisaged under EU rules, but also the pipeline capacity allocated by Transitgas operators: FluxSwiss and Swissgas.
To purchase the small volumes of available Transitgas spot capacity, traders have to call or email the TSOs’ commercial offices and cross their fingers. No regular and transparent auctions are held by FluxSwiss and Swissgas, and prices offered by the two TSOs are often very close to the premium of Italian PSV day-ahead gas contracts to the Dutch TTF, minus entry and exit fees and a small margin for the trader, sources said.
For example, on October 3 2019, when the PSV spot premium over the Dutch TTF equivalent contract reached Eur5.625/MWh, FluxSwiss sold firm spot transport capacity on Transitgas at Eur3.75/MWh to one trader speaking to Platts.
In this way, the two TSOs retain a slice of the spread between the PSV and TTF spot contracts. As a consequence, the cost of transporting gas along Transitgas is not reflective of the mere operational costs of the pipeline, but also of the commodity price.
Both operators occasionally hold auctions for firm capacity sold on a longer-term basis, offering month-ahead, quarterly or yearly products. Interruptible spot capacity is also offered. A spokesman from Fluxys told Platts that interruptible spot capacity is now sold OTC through a newly dedicated digital platform, available to registered customers only.
No other players apart from Eni have ever signed an OTC contract for long term Transitgas capacity with FluxSwiss. A FluxSwiss spokesman said the company is “constantly listening to the market in order to actively offer available capacity in line with market players’ requirements,” but would not be drawn on whether the TSO would consider signing new OTC long-term capacity contracts with other companies.
Eni declined to comment on the terms of its long term capacity and supply contracts. Gazprom did not respond to several requests for comment.
Regulatory interventions fall shortItaly’s economy ministry is well aware of the high cost of using Transitgas and that this is responsible for keeping PSV spot prices at a high premium to the Dutch TTF equivalent contracts. However, it has so far failed to find a viable solution, with the last suggestion, the 2018 Liquidity Corridor, rejected by the antitrust authority.
Some help in lowering the cost of transporting gas via Italy’s most expensive route could come from an ARERA decision in 2019 to scrap a Eur0.3/MWh commodity charge on all gas imports starting from January 2020. However, higher entry and exit fees introduced in Germany through the Postage Stamp Tariff reform will offset the impact of ARERA decision on Transitgas volumes coming via the German’s Wallbach point.
The big changes brought by the coronavirus pandemic to Italy and Europe gas markets make it difficult, so far, to analyse the real impact of this fee reduction on PSV/TTF spreads.
A law to introduce European gas market rules in Switzerland is currently being drafted by the Swiss federal energy ministry and is set to be discussed in the Parliament starting from autumn 2020. But due to the length of Swiss democratic processes, the law is not expected to be ready before 2024.
Until then, Transitgas will continue to be the price maker for Italian spot gas, to the advantage of everyone selling gas in Italy, and the disadvantage of consumers and the country’s economic competitiveness against Northwest Europe.
Will TAP change the ecosystem?With a few big players controlling Italy’s major supply routes, and the volume of imports from these pipelines, it is hard to say if the start-up of a fifth gas pipeline supply route at the end of 2020 will change this scenario.
The Trans Adriatic Pipeline, currently expected to bring first Azeri gas into Italy in Q4 2020, will deliver 8 Bcm/year of gas into Italy, or 22 million cu m/d.
There are almost as many price formulas as buyers of TAP gas, but all of them are meant to make TAP deliveries into Italy competitive on the PSV day-ahead market, market sources have said.
In a scenario replicating Italy’s gas balance on one of the coldest days of winter, total gas consumption would be 340 million cu m/d, withdrawals from stocks 110 million cu m/d, and pipeline imports excluding the Swiss route, 152 million cu m/d. LNG terminals would provide 44 million cu m/d of regasification and domestic production 13 million cu m/d. This would leave Italy’s gas system 21 million cu m/d short when supply is totaled and set against consumption.
This means that TAP’s 22 million cu m daily imports could be enough to halt imports via Transitgas for most of the year.
But this will only happen if the other importing routes are fully utilized. It will be enough for Tarvisio’s imports to be turned down by few million cubic meters for Transitgas to be back in the game.
And with few players in control of the largest volumes imported from all of Italy’s main supply routes, there will still be the possibility of creating the small shortage of gas necessary to trigger spot imports from Switzerland, and let this pricey route set the PSV hub price.
An opportunity for further competition could materialize in 2023, when Gazprom’s long-term contract on the TAG pipeline expires. At this point, the roughly 80% share of capacity in the hands of the Russian major will be sold via regular auctions on the Prisma platform, with all interested market players able to purchase it.
A similar scenario could occur in Switzerland in 2024, when the Eni long-term capacity contract expires. Should Switzerland introduce European rules for the allocation of transport capacity, shippers may be able to buy the Transitgas capacity via regular auctions.
If not, FluxSwiss may well just offer a new over-the-counter contract to one or two other major market participants, preserving Italy’s most expensive import route and the current ecosystem.