October 7, 2015
Since it was signed in 1996, the Panrusgáz contract with Russia has dictated the structure of Hungary’s natural gas market. While this contract’s expiration will be delayed until closer to 2018, it is clear that a new agreement will be negotiated on entirely different terms than before.

Like other Central and Eastern European (CEE) countries, Hungary has benefited from the rising tide of interconnectivity and hub-based trading across Europe. With demand unlikely to rebound to pre-2008 levels in the medium term, and more competitive import capacity than ever before, Hungary must consider how a new arrangement with the Russian energy giant Gazprom will reshape its domestic market.

The Panrusgáz legacy contract has traditionally met a majority of Hungary’s annual gas needs, although the share has declined along with Hungary’s total demand following the European financial crisis (losing about 25 percent between 2008 and 2013). It consistently accounted for more than 80 percent of total Hungarian consumption, but in 2013 it had fallen to 59 percent. This is also representative of the downward sliding annual contracted volume (ACQ) that Gazprom endorsed, the terms of which have not been released publicly.  

Even after E.ON, the Germany-based power and gas firm, won concessions from Gazprom in 2012 that applied to all of its country-level contracts, the sales position of its Hungarian subsidiary, EFT, continued to deteriorate due to declining demand and spot competition through the Hungary-Austria pipeline (HAG). These conditions led to a unique settlement in 2013 that allows for unpurchased take-or-pay (TOP) volumes in the past several years to be rolled over for repurchase by the current contract holder, Magyar Földgázkereskedő Zrt (MFGK), after 2015. MFGK is a subsidiary of MVM, the state-owned Hungarian utility company. Under this temporary agreement, Panrusgáz will effectively govern a significant proportion of Hungary’s gas consumption until close to 2018 before a new contract can replace it. While this form of ex-post restructuring helped E.ON EFT at the time, financial losses associated with the contract will continue to drag on MFGK until the repurchase is complete.

The problem with traditional long-term natural gas TOP commitments of this nature is that they do not readily adjust to changes in the market. The non-market pricing mechanisms imposed by monopolistic producers will also continue to face pressure from increasingly open and interconnected markets and exposure to diversified competition. Today, more than 50 percent of European demand is met by short-term hub trading or some form of contract-based spot indexation, and even though the share of market-based volumes is much higher in northwest Europe than in CEE, liquidity is still growing in the latter. Thus contractual flexibility in the form of shorter length, reduced TOP volumes and increased spot indexation are becoming the norm.

It is also worth noting that although oil-indexed prices were consistently at a premium to spot prices in the early stages of Europe’s gas market liberalization, this is not a given, particularly in times of high demand or shortage. The prolonged discrepancy we observed was largely a product of exceptionally weak demand and high oil prices; while TTF (Title Transfer Facility, the Dutch virtual trading point widely referenced for contractual indexation) continued to sink on poor fundamentals in 2009, Brent crude began to surge from under $50/bbl to well over $100/bbl by 2011, propping up oil-indexed natural gas prices after the six-to-nine-month lag. The spread would have been even more pronounced if not for the Fukushima nuclear disaster in 2011 that led to insatiable Japanese demand for spot LNG, effectively tightening supply and buoying spot prices in Europe.

Relief came in 2014 when the Japanese Korea Marker (JKM) began to fall, allowing Europe to compete for LNG cargoes at lower prices and relieving a segment of the northwest European portfolio. By the second quarter of 2015, the dramatic drop in oil prices resulted in a very low spread between the oil-indexed and TTF price.

The other factor behind this downward long-term contract (LTC) price trend is the wave of Gazprom’s concessions that raised LTC exposure to spot prices. A majority of Russian legacy contracts have been readjusted in the past few years to include a standard of 15-20 percent spot indexation towards what is becoming a hybrid pricing system. Gazprom even experimented with its first competitive auction in early September, selling 1 billion cubic meter (bcm) of gas for delivery in the upcoming winter period.

Like other CEE countries, Hungary is in a far-improved position with regard to what Russia was twenty, or even six, years ago, but unlike the others it has an earlier window to capitalize in 2018. (Gazprom contracts with Bulgaria, the Czech Republic, Poland, Romania, and Slovakia end anywhere from 2022 to 2037). Significant HAG capacity has been opened to competition, the Slovakia-Hungary (SK>HU) interconnector was commissioned in June, and the High Level Group on Central East South Europe Connectivity (CESEC) has prioritized LNG from its Krk terminal in its 2020 agenda.

In order to evaluate Hungary’s existing options, the Regional Centre for Energy Policy Research (REKK) carried out a scenario analysis in early 2015 comparing two choices of entry points and wholesale price and supplier profit.

The best outcome for consumers is the low-volume contract limited to the Ukrainian delivery point. In this scenario, the counterparty is prevented from booking HAG or SK>HU capacity for its contracted volumes that frees capacity for hub-based western gas via Austria and Slovakia, leading to a lower market price. Currently approximately 20 percent of the Panrusgáz gas is imported through HAG.

Alternatively, the worst-case scenario is the high contract with the availability of all three interconnectors, crowding out cheaper Western-sourced gas, as is the case in Hungary. The optimal scenario for the counterparty is in the case of a low-volume agreement with all available interconnectors.

The contract holder loses money in every scenario because oil-indexed prices are presumed to be higher than market prices until competition undermines Gazprom’s monopolistic price scheme. Thus, the counterparty prefers the smaller contract so that it can meet the remainder of its obligations with cheaper non-Russian volumes.

On the other hand, the high-volume contract limited to delivery via Ukraine results in highest losses for the company. The important point is that a low-volume contract limited to Ukraine delivery is still a significantly better alternative than either of the high-volume scenarios. It remains to be seen which path Hungary will take, but it is certain to seek a much lower TOP threshold.

Looking ahead to 2020, Hungary can also consider the potential to contract some of its minimum (low scenario) long-term needs from Krk LNG terminal, which will compete directly with Russia’s pipeline offerings if commissioned. This is one of a group of priority projects identified by CESEC for accelerated infrastructure investment and is scheduled to come online in 2020. The binding open-season procedure was released in July and bids were to be submitted by September. This is a project that has been “on the agenda” for years, but if it moves forward with renewed interest in the region it would create an opportunity for diversification that MVM will have to take into account as it continues negotiations with Gazprom.

Nolan Theisen is an energy analyst at the Regional Centre for Energy Policy Research (REKK) in Budapest, Hungary. He was a delegate at the Atlantic Council's 2014 Energy and Economic Summit in Istanbul.

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