Ilian Vassilev
The need to move beyond the Balkan Gas Hub “Russia-only” or “Russia-mainly” paradigm seems indispensable if the ‘hub’ project – in the broad sense – has any chance.
The talk of billions of cubic meters of natural gas from non-Russian sources deserves a serious look to the north, but mostly to the south – The Southern Gas Corridor.
Yet what seems logical to everyone, does not inspire the management of the TSO of the Bulgarian gas system. The fact that none of these routes – TANAP, TAP or the Greek-Bulgaria Interconnector – contain specific numbers for potential gas flows makes things seem pre-ordained. The BGH essentially seems to be conceived as a redistribution center for Russian gas.
The likelihood of non-Russian gas emerging both at the Bulgarian borders with Turkey and Greece is both imminent and substantial, yet is seems unaccounted for in the BGH scheme. Azeri, Iraqi, Israeli, Egyptian, Cypriot, Qatari, US and any other gas could help balance off regional demand and compete with Gazexport, but could concurrently help Russian gas accommodate the 50% capacity cap or third parties access requirements. Such quantities should first emerge in Turkey, then be redundant in order to seek exit and transit routes to Italy via TAP or appear at the Bulgarian-Turkish border bound for the northern routes.
The fact that the Azeri SOCAR and Bulgartransgaz have entered into a cooperation agreement should not be overlooked – Baku does not have additional spare quantities of natural gas above those declared by Shah Deniz – 2. Analysts draw attention to the import of Russian gas in Azerbaijan, which seems essential in freeing quantities from the domestic market for export contracts.
The assumptions on the project map of the Balkan Gas Hub for locally produced Black Sea gas inputs are too speculative to be considered. In the Khan Asparuh block there is not yet to a second well, which is expected to be drilled in October. In the Silistar block, Shell is still evaluating seismic data – again a long shot before anything could be assumed.
If we test the viability of the Balkan Hub as a commercial project, the first and foremost condition would be to engage in a full set of feasibility studies – market, financial, economic, commercial, legal, technological, etc. Once a financial model has been prepared and the deal gets a structure, then judgments can be passed. Not now.
The Balkan Gas Hub project has been developed as an in-house work within Bulgartransgaz, without the involvement of external independent consultants or investors.
Similar assumptions to the ones made in the BGH map above could hardly find place in a professional report, without a clear argumentation base and indicated sources.
The project presentation begs a serious investigation of the non-Russian alternative to feed the Balkan Gas Hub.
To start with, there is a genuine chance to load up and utilize the direct and backhaul capacity of the Trans-Balkan gas pipeline with gas produced in Romania’s offshore area, and the 2 billion cubic meters indicated seem more than credible, even modest. One needs to incorporate into the potential supply base of the BGH the excess gas that could emerge in the gas systems of Slovakia, Ukraine and Romania after 2020, which might seek clients in Turkey and along the TAP.
The gas arriving in the BGH from Greece alone is not specified, yet it could easily exceed 5 billion cubic meters, mainly via the IGB. Moreover, more than half of the fixed direct and reverse capacity of the interconnector has been booked. There is not a word on that in the Balkan Gas Hub illustrative map, nor on the major source for fresh gas liquidity from the new LNG terminal at Alexandroupolis.
Key shortcomings of the Balkan gas hub project include the absence of a market test and its static and schematic nature. The concept does not account for dynamic shifts in the gas market and infrastructure developments, driven by demand, rather than supply. In its present format the Balkan gas hub project is Gazprom biased, not neutral to the diverse alternative options for gas flows and traders. The BGH has been carefully calibrated mainly and almost exclusively to service Gazprom and its attempts to retain market shares in the CEE gas market.
There is a huge loophole in identifying the potential sources for substantial gas flows to Bulgaria and via the Balkan gas hub from the Caspian Sea, the Middle East, the Eastern Mediterranean and the global liquefied natural gas market to the CEE region.
Developments plans and investments in the Bulgarian gas transmission system should not be driven by the idea to serve any exclusive supplier or trader. The BGH project, judged against the backdrop of projected additional capacity of 120 billion cubic meters for transmission in Europe by the year 2023, with declining occupancy rates for current transmission and transit capacities (around 40 percent), invites a troublesome conclusion – that project grandeur often ends up in heavy losses and unredeemed investments.
Another potentially critical weakness of the Balkan hub project is that there is no relevant Bulgarian gas company that could feature an expanding and diversified business geography and gas services portfolio, functioning as a genuine regional-scale player that could undertake the role of a project anchor and consolidator. On the contrary, Bulgargaz is further bound to lose market share and reduce traded volumes and remote interest in the hub idea.
Even one billion cubic meters per annum gas purchase under the Shah Deniz-2 contract presents a challenge for the company’s management.
It is hard to conceive how Bulgargaz could play a significant role as a business and market maker for the gas hub “Balkan.”
The BTG’s idea of an isolated transit pipe serving Russian gas as an extension of Turkish Stream into the EU, crossing Bulgaria without connection to the transmission or transit network in Bulgaria is absurd and implausible.
Bulgaria’s national gas champion – Bulgargaz – is the only gas supplier in the SEE that sees no other role for itself beyond the classic routine – one supplier, one contract, one route – which in time, will inevitably lead to the company’s self-marginalization.
BTG’s argument that Bulgaria should invest for the hub’s sake, driven by a vision and an insight to attract future gas flows by the allure of a wide range of services and capacities, sounds not only superfluous, given the company’s track record in managing projects and success in attracting non-Russian gas clients, but dangerous, as these investments serve as an expense base when determining high tariffs.
Investments in interconnectors have been dragging on for years, with the saga of the ‘eternal’ laggard – the Chiren UGS expansion – inspiring even less confidence.
Bulgaria has been slow to develop and introduce a trading platform for short-term gas. In general the TSO is behind schedule with everything that constitutes the soft infrastructure of the Balkan gas hub, especially in comparison with processes in neighboring countries.
The planned investments in the development of the gas transmission system and the new connections with the Romanian gas transmission system at Oryahovo are necessitated by the push to resurface the South Stream project with Russian gas under one form or another.
Unless the authorities are secretly breastfeeding a new darling to replace Bulgargaz directing cashflows via inflated projects costs, there is no logic to stake over € 2 billion on speculative schemes without market verification.
The argument that we need to invest “to boost capacity” — given that our transmission system has a lot of unused capacity, that there are no built-in and functioning interconnectors with any of the neighbors, that there is no expanded gas storage in Chiren USG, and especially that there is no real trading platform that offers gas outside Gazprom’s terms — is a sure sign of future losses and especially of a lack of direction.
BTG’s pride – the bidirectional gas compressor stations (GCS) – are essential for short-term trading with direct or reverse flow capacities trailing fluctuations in gas demand. However, in parallel to the demise of long-term fixed contracts and the declining security of revenues, excess or underutilized capacity in compressor stations can easily become a liability, since there is no demand for these services or income from the business from which to recover investments. And these developed and fixed operational costs at low occupancy rates again end up in higher earnings projections, i.e in higher tariffs applicable only to Gazprom’s competitors.
Without securing a backhaul or reverse flow capacity via the Trans-Balkan Pipeline at Negru-Voda (fixed reverse capacity is not offered) Bulgartransgaz will effectively dump the chance for any significant quantity of gas originating in the Southern Gas Corridor to reach markets in the CEE, as the only ‘option’ would be the low-capacity interconnector at Rousse-Giurgiu.
Bulgartransgaz has yet to master the necessary skills of corporate governance, needed to make the Balkan gas hub a reality. With projected earnings of just over € 140 million and a roughly identical record for project scale involvement, the company will hardly convince banks and clients to manage or provide funding for a project over two billion euros. Suffice to allude to the recent looping Lozenetz-Nedyalsko with net cost (without land alienation and permits) of 51 million leva for 20 km for 3 years!? These costs ultimately are covered via the customers.
After October 1st, the system operator, BTG, will replace the post stamp with the entry-exit tariffs system. Although the regulator still approves the company’s annual business plan and earnings, the level of tariff rates, including all additional service charges, will be determined by the TSO at its discretion in accordance with a methodology approved by the regulator. This makes possible, in view of the company’s history, the discrimination between entry and exit tariffs at different points in the gas system, including reverse and reverse flows. Changing the tariff model entails a reciprocal shift in tariff structure with a higher share weight for short-term, three-month and one-month tariffs, which are more expensive. Against the backdrop of rising fixed costs on lower occupancy rates, higher tariffs may be a serious impediment for new shippers.
Higher entry tariffs for gas imports via interconnectors or on reverse routes from Turkey or Greece via Siderokastro Kulata or Lozenetz-Kirklareli can easily discourage gas flows from the Southern gas corridor to the north, including LNG via the terminals and through the interconnector Greece-Bulgaria (at an entry point in Stara Zagora), which could seriously undermine their economic viability — especially in the absence of free capacity and sustainable back flow in TBP.
According to BTG, after October 1, when the new entry-exit system will come into effect, the new system will not apply to Gazexport.
The transit of Russian gas will continue to be subject to the terms of the old contract and the old tariffs. On a cumulative basis, BTG provides Gazexport with a non-market advantage of a minimum of 12 dollars per thousand cubic meters, and this is just on the territory of Bulgaria at the expense of Bulgargas, the Bulgarian customers and all other shippers and traders, which get charged more. This is difference in the access and transmission costs for gas entering Bulgaria via Siderkastro-Kulata for any shipper and the transit charges for Gazexport gas.
BTG’s approved annual earnings are BGL 277 million, which is roughly Euro 140 million. The share of earnings from Gazexport for booking 17 bcm transit capacity is roughly USD 111 million. The 8.5 % depreciation of the US dollar denominated transit tariff rates has effectively shrunk the Russian transit proceeds in the last year in the BGL earnings base of BTG – which is approved by the regulators – by BGL 18 million. Respectively the transmission system earnings – that will have to cover the difference in the BTG total earnings base, i.e. until BGL 277 million approved by the Regulator, will have to be reflected in the entry-exit tariffs, after October 1, and paid by Bulgargaz and all other traders and shippers. Whereas the transmission services of BTG had generated in 2016 only BGL 70 million, in the next ‘gas’ year the figure jumps to BGL 95 million (a 35% increase!?) on 3 billion cubic meters of natural gas sold in Bulgaria. While BTG could claim that for annual product – the cumulative entry and exit tariffs – things won’t change much, shorter term products – for one and three months – that will be most in demand, the shippers will take the brunt. The net effect is that the spread between Gazexport tariffs on one side and Bulgargaz and all other traders is further widening with the Bulgarian gas users being asked to pay the bill. All this is garnished with the usual EU-to-blame verbiage and an almost pious inculcation that BTG is eternally and intrinsically bound to ’cooperation’ with Gazprom.
These facts contradict the claims of the Bulgarian government that it is pursuing a common European energy security policy to protect Bulgarian and EU consumers and seeks the success of the Southern Gas Corridor.
Natural gas suppliers and consumers have already interpreted these actions by the Bulgarian government and the TSO as a deliberate attempt to shield Gazprom’s interest and market shares in the region.
If the Balkan gas hub ever stands a chance, the policy and the message behind it have to be altered. Instead of servicing and adapting to Gazprom’s strategy as a junior partner, BTG should start implementing EU policy – attract and facilitate gas flows from all possible directions, effectively mediating between the Southern Gas Corridor and the gas systems of countries in Southeastern, Central and Eastern Europe, encouraging competition to Russian gas.
Instead of succumbing to the political glamour associated with the Balkan gas hub, efforts should be focused on achieving practical and immediate results – without much hassle, quietly and gradually substantiating the content of what is generally understood as a “hub” – high capacity occupancy rates, large quantities of gas shifted in different directions and high volumes of gas traded at competitive and affordable tariff rates.
Changing the tariff model implies a change in the structure, with a higher share of short-term, three-month and one-month term tariffs, which are more expensive. And against the backdrop of low occupancy and high fixed costs, the change could be a serious impediment for shippers.
The to-do list starts with connecting the Bulgarian transmission and transit system with Serbia, completing the regional interconnection on the initial level and gradually upscaling to the level needed.
Second, as it is unlikely that Bulgargaz will change its management pattern, i.e. by adopting a more expansionist and independent policy, instead of persisting on acting as a local Gazprom representative, Bulgaria will need to attract the energy majors in Europe to provide a corporate anchor or promote the Balkan gas hub project. They could balance off and serve as a counterweight to Russian gas dominance. Instead of picking favorites or winners, the government should seek to apply rules and equal treatment.
Third, the government must accelerate the liberalization and diversification of the Bulgaria gas market by freeing up transmission capacities and redefining national interests in the field of energy security. Instead of providing security of supply through a public supplier, the mode should be shifted to guaranteeing security through functioning markets and enhanced competition. The idea of a public supplier of last source is worn out as the market has long since moved from a state of natural gas deficiency to sustainable and substantial gas abundance.
Bulgargaz is trying to tie the hands of consumers by imposing on them ‘voluntarily’ advance booking for gas purchases with long lead time, which is an antithesis to the liberal market. The government should simply stop trying to shield Bulgargaz from healthy market competition and by default protect Gazprom’s interests.
The Bulgarian Government should speed up any project that leads to material diversification – from local gas extraction to leasing capacity at LNG terminals and improved capacity management.
Fourth, the terms of use of the transmission and transit grid should be harmonized and the exceptions made for Russian gas immediately revoked as contravening European Law. Gazexport should not be entitled to guaranteed capacities, while all other companies have to bid for often limited capacities at auctions, or wait until Gazexport frees up space in the pipe.
If all “competitors” of Gazprom have to overpay two or more times for access or long-term capacity, direct and reverse, both fixed and interruptible, the market is captured. Gazexport at the moment would pay annually for transport – access and transmission – to ship gas from Negru-Voda to Bulgaria slightly more than 9 leva ($ 5.8) per 1000 cubic meters. For any competitors to Gazprom gas from the entry point in Siderokasto-Kulata, the cost skyrockets to 30 leva ($18.6) per 1000 cubic meters. Competing with Gazprom then becomes a mission impossible.
In practice this amounts to unlawful state aid that deprives Bulgarian and other consumers in SEE and CEE, both individual and corporate, from the benefits of price competition and the best market terms of trade.
What’s even more absurd, not only is Gazexport spared due competition by being exclusively granted the lowest tariffs and guaranteed transmission capacities through Bulgaria, but the TSO sits idle while the Russian company offers transit services to its European partners, depriving Bulgartransgaz of legitimate earnings.
Fifth, the work on bundling, integrating and harmonizing tariffs and on cooperation agreements between system operators in Greece, Turkey, Romania, Hungary, Serbia, Ukraine and others is sine qua non. Preferential treatment, when possible, should be granted on a reciprocal basis. Arbitrarily high tariffs for transmission by the Greek DESFA – well above $ 24 per 1000 cubic meters, in practice, kill the competitiveness of alternative gas supplies originating at the Revithoussa LNG terminal across Greece to and beyond Bulgaria. This seems odd against the low average occupancy rates at the terminal and in the transmission system.
Bulgartransgaz should immediately stop double charging for the use of the transit (backhaul from Greece) and the transmission systems.
Sixth, Bulgaria could hardly hope to attract significant gas flows for transit and provide sufficient liquidity as the gas hub at these low levels of local gas demand. There is a significant “sleeping” potential for a substantial increase in local consumption through gas power generation, increased use in the chemical industry and mass gasification.
The critical watch list on the Balkan gas hub is probably two or three times longer. The European market slowly but irreversibly moves towards full integration and harmonization of national gas segments, which would marginalize the notion of national gas “hubs”. In gas trading these days, gas prices could be referenced to relatively remote EU hubs such as the TTF. Tomorrow the price benchmarks could move even further – across the Atlantic – to the Henry Hub in the United States. Such processes will intensify alongside with the globalization of the gas market.
Therefore, it will be too naive to expect that the Balkan gas hub will ever reach a status of a regional price benchmark.
Some things just will not happen, at least anytime soon.
With the paradigm of serving “only” or “mostly” Russian gas, the Balkan gas hub seems a fiction. By stubbornly pursuing serving Gazprom’s interests in the region, instead of becoming a bridge between the South Gas Corridor and the CEE and SEE markets, Bulgaria might become a genuine barrier. And the EU will not let that happen.
The statements, opinions and data contained in the content published in Global Gas Perspectives are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.
This article was originally published in two parts by Bulgaria Analytica on September 1, 2017 (part one) and September 3, 2017 (part two).
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