LONDON (ICIS)--The German Federal Network Agency (BNetzA) on 19 March announced the completion of the Gas Network Development Plan 2020-2030 (NEP Gas), focusing on planned LNG plants and the integration of hydrogen and green gases into the network.
BNetzA’s change request confirms 175 measures proposed by the transmission system operators with expected investment of €7.83bn. The measures call for a line expansion of 1,620 km and a compressor expansion of 405MW.
The draft plan originally outlined 215 measures totalling €8.5bn in investment proposed by transmission system operators (TSOs). The plan presented an additional 60 new measures to the ones outlined in the previous NEP for 2018-2028 mostly focusing on LNG projects, but it reduced the number of proposals requested by the German Association of the Gas Transmission System Operators (FNB Gas), removing measures related to hydrogen.
BNetzA decided that no network expansion is necessary to facilitate the German hub merger due on 1 October, arguing that transport capacity to flow gas between the two market areas can be secured using market-based instruments.
Costs of the use of market-based instruments are forecast to be €1.1m-27.6m for the gas year 2025/2026, significantly lower than the cost of physical network expansion, according to the agency.
Germany’s 16 grid operators have scheduled the merger of its two market areas, NCG and GASPOOL, into a single Trading Hub Europe (THE) for 1 October 2021. One of the merger’s main aims is to enhance liquidity. The creation of a single trading area could ease of access for new entrants, but the lack of clarity on physical interconnections within the country had been a cause for concern.
The EU deadline for the establishment of one lone German virtual trading point (VTP) was April 2022 but the TSOs have set an earlier deadline for merging the two areas, which involves adjusting IT systems, transferring balancing accounts and setting up a single market area manager. The idea of creating a single German hub was partly driven by the German government’s desire to avoid a potential market merger laid out in the EU-prescribed second gas target model (GTM 2), which would open up the possibility of the NCG merging with the Dutch TTF hub , continental Europe’s biggest market by trade.
Germany has the largest gas demand in Europe with annual consumption reaching around 85 billion cubic metres in 2020 (bcm), which is about 17bcm above both the UK and Italy – the next largest European gas users. Despite the high usage of gas, NCG and GASPOOL have remained largely balancing hubs with liquidity concentrating on short-term products. As a result, traded volumes in the German markets lag the Dutch TTF, which is Europe’s benchmark market and is used by global traders for hedging purposes, as well as Britain’s NBP.
In the year to February 2021 combined over-the-counter (OTC) and exchange volumes at the NCG reached 1,853TWh, with trade at the GASPOOL hub totalling 1,137TWh over the same period. For comparison, TTF volumes were up to 44,543TWh during the same period, while NBP trade totalled 8,821TWh.
The lack of capacity linking the current NCG and GASPOOL market areas has been considered one of the main challenges the newly created single hub could face.
Due to constrictions the amount of firm capacity offered to the market from 2021 onwards was reduced by 78% at auctions on the pan-European PRISMA platform, following instructions from BNeztA, which is responsible, among other tasks, for overseeing the liberalisation process.
Instead of increasing capacity between market areas, which was not considered feasible in time for the merger, BNetzA has introduced tools designed to alleviate network congestion.
Market Based Instruments (MBIs) will form part of an overbooking and buy-back mechanism called KAP+, these include;
• Third party network use
• Locational spreads
The wheeling and third-party network use both involve re-routing flows around a congested network point, using an interconnection point on the German border. With the wheeling MBI gas will flow from a German transmission system operator (TSO) to a neighbouring country’s network, and then back into Germany using a single cross-border interconnection point.
Third-party network use is conceptually the same as wheeling, but two separate interconnection points are used in transporting the gas.
Locational spreads will involve the use of a standardised exchange product where gas is simultaneously bought and sold in different network zones, acting like virtual transport.
Should MBIs not be sufficiently available to tackle any congestion issues, the capacity buy-back is the solution of last resort (Ultima Ratio).
Germany has nearly 70 billion cubic metres (bcm)/year of gas tied to long-term import contracts, although there will be flexibility within those deals, according to ICIS Energy Analytics.
The majority of this is through agreements with Russia’s Gazprom, which accounts for around 52bcm of the total, while Norwegian contracted long-term supply has come down to below 15 bcm – as several of their commitments were converted into shorter term supplies.
Of the Russian total, ICIS estimates around 42bcm/year is the minimum take-or-pay volume for 2021.
German contracted imports could cover around 80% demand of the country, although actual off-take is thought to be closer to 60-70% of consumption.
Contract terms have shortened to below 20 years, down from typically 25-years in the early 2000s (including extensions), with more flexibility built into the current set of agreements.
From 2023 the volume of gas tied to long-term supply contracts is set to drop to below 55 bcm/year, driven by a considerable fall in Norwegian contracted volumes.
If these deals are not renewed Germany will become more reliant on volumes secured via the wholesale market, which should act as a boost to liquidity at the THE.
There is also scope for supply to diversify from pipeline volumes with plans for several LNG import terminals currently in progress.
The 55bcm/year Nord Stream 2 pipeline is set to double German direct import capacity from Russia, making the country the key transit route for volumes delivered by Gazprom. The pipeline was originally expected to be online by 2020, but the imposition of US sanctions, as well as political and regulatory uncertainty, have delayed completion.
More transit gas being delivered via Germany could increase the country’s role as a price-setter, particularly for central European hubs, as well as creating spread trading opportunities.
Germany is also considering increasing its participation in the global LNG trade through building its own LNG terminal, although no FIDs have been made for any of them so far.
There are currently three LNG terminal projects in Germany;
• The Hanseatic Energy hub – a 12bcm/year terminal in Stade
• The German LNG Terminal – an 8bcm/year facility at Brunsbuttel
• Wilhelmshaven – a 10bcm/year Floating Storage and Regasification Unit (FSRU)
In February the Hanseatic Energy hub announced it had successfully concluded the non-binding phase of an open season, indicating sufficient interest in the 12bcm/year capacity.
Belgian infrastructure specialist Fluxys recently joined the project, which could be operational by 2026.
The Brunsbuttel terminal is supported by Dutch system operator Gasunie, German petroleum infrastructure provider Oiltanking and Netherlands-based storage specialist Vopak. Backers of the project are currently in negotiations with German utility RWE to secure binding LNG import contracts.
The Brunsbuttel terminal has also received an exemption from network access and tariff regulations from BNetzA, which the Hanseatic and Wilhelmshaven projects are still trying to secure similar provisions.
The FSRU is being developed by LNG Terminal Wilhelmshaven (LTeW), which is a subsidiary of German utility Uniper.
The project developer announced last November it was re-evaluating plans due to a lack of binding interest for import capacity.
Cross-border capacity expansion
In August last year the German Association of Pipeline Network Operators (FNB Gas) in August 2020 launched a consultation aimed at increasing cross-border transport capacity with Denmark, Poland, the Netherlands, and the entry point of the Nord Stream pipelines by a total of 51.9GW.
Planned expansions include the Greifswald and Lubmin II points to increase capacity for gas flowing to the Netherlands via the NEL pipleine and to central and eastern Europe via the OPAL and EUGAL pipelines.
Capacity at the Mallnow entry point of the Yamal transit pipeline on the German-Polish border will also be increased, with work also planned at the Ellund entry point on the German-Danish border.
The expansion is estimated to cost up to €3.1bn and should help alleviate the congestion risk between the two hubs following the merger, however, the capacity expansion is not expected to be completed until 2027, so the risk of congestion is likely to remain a key regulatory issue until this point.
L-gas phase out by 2030
With both the NCG and GASPOOL market areas having L-gas as well as H-gas zones, Germany is actually merging four markets as part of the hub merger.
Plans are in place to phase L-gas out from the German gas grid by 2030, as L-gas production from the Dutch Groningen field, which supplies the majority of Germany’s L-gas, is due to cease by mid-2022.
Just over one million L-gas domestic and commercial appliances have been converted with another 570,000 due to be converted in 2021, the most achieved in a single year, according to the Federal Association of Energy and Water Management (BDEW) and the German Association of Gas and Water (DVGW).
In total four million L-gas appliances are due to be converted by 2030, representing a total capacity of 16.89bcm (178.2TWh), according to the Task Force Monitoring L-gas Market Conversion. The phaseout means that H-gas demand is due to continue increasing in coming years, which will likely provide a boost to OTC gas liquidity by centralising liquidity into a single hub as opposed to the current fragmentation.
The construction of the Zeelink pipeline as part of the 2015 Gas Network Development Plan (NEP Gas 2015) is also expected to assist in the transition.
The 216km pipeline being constructed by Thyssengas and OGE, will have a daily capacity of 26.4mcm (9.64bcm/year) to flow H-gas from the Belgian border to northwest Germany, to satisfy greater German H-gas demand.
Despite the impact of the pandemic and a warmer spring and winter, German H-gas demand increased in 2020 by 1.28 bcm to 72.64 bcm, as L-gas demand fell by 2.2bcm to 20.2bcm, according to ICIS data.
Hydrogen infrastructure does not yet fall under the scope of the German Energy Industry Act (EnWG), and as such BNetzA is unable to make decisions on the conversion or construction of new hydrogen infrastructure within the scope of the gas network development plan.
BNetzA has, however, confirmed measures that allow for the removal of 24 gas lines or gas pressure regulating systems from the natural gas network.
Network operators would then be allowed to immediately convert this natural gas infrastructure for use with hydrogen, so long as they can meet their gas transport commitments in the existing natural gas network.
While acknowledging that it was an important step in order to be able to begin the conversion of natural gas infrastructure to hydrogen, the FNB Gas criticised the decision , arguing it would turn the hydrogen network in Germany into a “patchwork quilt”. FNB Gas maintains that “only an integrated network planning guarantees the development of a supra-regional hydrogen network as the backbone for a competitive hydrogen economy”.
FNB Gas is currently running a consultation Ion the inclusion of hydrogen and other green gases for the development of the 2022-2032 Gas Network Development Plan, until 16 April 2021.
ICIS’ daily European Spot Gas Markets (ESGM) report will launch price assessments for the THE from 1 April 2021 with the approached outlined in a recent consultation (https://cjp-rbi-icis-compliance.s3.eu-west-1.amazonaws.com/wp-content/uploads/2020/09/11083813/European-Spot-Gas-Markets-ESGM-Consultation-2020.pdf).
German gas supplies
• Germany‘s import dependency is high with more than 95% of its natural gas demand imported from a diversified supply base.
• The share of Russian gas in German imports oscillates around 50%, with growing tendency in recent years. 2020 saw the intake of Russian gas to touch minimum contractual volumes of around 45 bcm/year but making up a high share of Covid-19 hit demand. The high degree of exposure to Russia is similar to oil markets where German imports are about 36% Russian.
• German gas imports could theoretically be covered all by long-term supply contracts. Assuming that take-or-pay minimum offtake volumes are lower, we believe between 80% and 90% of German gas imports are effectively sourced via supply contracts. More than 20 bcm of gas supply contract quantities, mainly Dutch and Norwegian, expire in the coming years and might be replaced by more flexible arrangements. Maturities of German import contracts have shortened to an average of 20 years, down from more than 25 years in 2010 (including extensions) and volumes flexibilities are said to increase. We estimate that nearly all German import contracts have elements of hub-indexation already but some contracts use neighbouring gas hubs. Contract holders may contemplate a switch to the new THE hub.
• Sourcing via pipeline supply remains the likely option to fill the emerging gap as none of the three planned German LNG import terminals received FID so far (Furthest is HEH Stade with binding phase open season planned in Q2 2021).
CONCLUSION: There is scope for new entrants to fill gaps left by expiring supply contracts. The importance of the THE hub price in gas supplies is likely to rise. Andreas Schroeder