The EU energy transition created situations of deadweight, and this could not be any truer in 2021. The transition was initially triggered by the vulnerability of the RES in the EU primary energy sources. Мeanwhile the gas supplies were disrupted and the storage levels were critically low at the beginning of the cold season. The natural gas price skyrocketed and caused spill-over effects on electricity. Interestingly, no other key energy commodities underwent the same stress. The crude oil price, on the other hand, did not follow the same price momentum.

Тhe energy sector, and more noticeably the gas sector in 2021, were marked by a recovering demand, but still a low output with tighter-than-expected production. It turned out that demand recuperated faster than supply. Producers who were experiencing downturns could hardly catch up amid the largest EU price jumps in decades. The anticipated COP26 came to a close, making its mark through the Global Methane pledge and determination for fossil fuels abatement, although all this ended up with a phase-down rather than a phase-out.


>> Jul 2021 — The European Commission released the largest Climate law package Fit for 55 on its ambitious way towards GHG emission reduction. Тhe maritime sector would be included in the scope of EU ETS scope from 2023 onwards.

>> Sep 10th — The $11 billion Nord Stream 2 saga was near an end. EPC was finalized with just an admission certification remaining to be issued.

>> Oct 1st — Consolidation of the largest gas market in Europe, Germany, under the THE (Trading Hub Europe), after converging NetConnect and Gaspool market zones.

>> Based on the TTF historical data, the natural gas average close price, used as a standard benchmark price for performance, was around 46.16€/MW throughout the year 2021, as opposed to 10.46€/MW throughout 2020. The price briefly jumped to 180.27 €/MW in December. Compared to the highest corresponding cost of 21.70 €/MW in 2020the new one accounted for a nine-fold increase.

>> Oct — Nov — COP26 took place. Hydrogen was officially earmarked as the climate silver bullet for decarbonization and was promoted as such.

>> Gas prices in the EU followed a W-shaped recovery (double-dip recession). This can be attributed to the COVID-19 waves and in Q2 2021 it retained the price level from Q3–2018 at 25€/MW. Despite its expansion and price momentum stemming from the supply shortage and recalling the Beast-from-the-East-scenario, gas is not a true proxy for the economy. The steep and rapid surge in the second half of 2021 was an impulse rather than an accurate representation of the economic growth.

>> Dec 8th — EU Carbon emissions hit the highest price since the foundation of EU ETS— 89.47 €/t as opposed to 33.55 €/t at the corresponding time the previous year, which marks a triple jump on a YOY basis.

>> Dec 31st — As a consequence of the EU primary energy sources strategy, there was an increasing share of intermittent non-dispatchable energy sources. This led to decreasing conventional flexibility with the Nuclear plants decommissioning. The last German nuclear capacities will be phased out at the end of 2022. After abating nuclear energy, the coal plants will remain in function until 2038.

>> Dec — The tightness in the gas supply had a detrimental effect on the clean spark spreads and resulted in ramping up the electricity wholesale prices. It further aggravated the high price by including the carbon-intensive coal electricity and pricey carbon emission allowances, thus breaking a record, hovering around 400€/MW in the EU

>> Q4 of 2021 — The price differential between natural gas and crude oil got larger. Widened inter-commodity spread could boost oil demand. By convention, the natural gas commodity is priced below crude oil. Regarding the inter-commodity spread (Brent; TTF) in 2021, the two price curves intersected at the end of Q3 202, when natural gas reached $100/bl, while Brent anchored at $71.59/bl. This represents a price anomaly. In Q4 2021 this deviation gets even more pronounced with TTF following its upward trend and crude oil (Brent) tending to decrease. We can conclude that at the end of 2021, natural gas was more expensive than crude oil, which may incent consumers to switch to oil alternatives.

>> 2021 — Coal-fired electricity was set to rise. The increased electricity demand resulted in coal-fired electricity generation growth and an all-time peak of 6% in 2021. This was another example of why electrification must not be performed before fully developing the RES. Lack of sufficient base-load energy sources and decommissioning the existing ones, such as nuclear plants, appears to be the right recipe for the comeback of coal.


2021 will be remembered with the largest global electricity demand and by the predominant use of gas and coal plants, along with the largest progress coal-fired power has seen recently. The key role of natural gas for the EU gross electricity production triggered a domino effect of surging wholesale prices for electricity. The prices were exacerbated by the coal-firing power plants and carbon emission allowances.

The year reaffirmed the main LNG arbitrage route, bringing the imports into a tug-of-war situation between the Pacific and Europe with a strong positive linear relationship, at a correlation of 0.93. With South America recently included, the EU would have to deal with the challenge to lure more LNG supplies, unless it comes up with a long-term solution.

Migrating SQL to NoSQL

Migrating SQL to NoSQL

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German LNG – Just Around the Corner

German LNG – Just Around the Corner

Germany is not only the EU’s largest gas consumer but is also a large gas transit state. As of 2019, 27% of the gas imports into Europe (80 million tons LNG) came through LNG processing. There are reasonable grounds to expand the LNG industry further. Germany provides a favourable environment for the gas sector, and it is estimated that between 10 billion cubic meters and 22 billion cubic meters of additional LNG import capacity could be added.

Photo by Jacob Meissner on Unsplash

Diversifying the delivery routes for natural gas would be necessary to progressively shut down the familiar to the German energy balance between nuclear hard coal and lignite power generation. The LNG facilities will be the frontrunner of improving competition in gas supply and security. An additional aspect would be environmental sustainability. Germany’s natural gas consumption exceeds 25% of the total EU gas demand, and less emission-intensive LNG would be a good opportunity and an additional entry point. On account of this, the projected terminals in Germany would be taking the lead for importing climate-neutral liquid energy sources. This would make a significant change, and the cost-efficient energy supply and the ambitious climate protection would be all put together.

The year 2021 and the upcoming winter season are expected to bring severe repercussions for the European energy sector. 80% of total imported natural gas is imported through pipelines, as opposed to roughly 20% as LNG. Therefore, due to the high dependency on pipeline gas, Europe needs more LNG terminals more than ever, particularly in Germany.

German LNG Regulatory Control

Under European and German law, an LNG terminal is subject to tariff and network access regulation. The Federal Network Agency is the independent German regulatory authority that sets tariffs and network access rules where possible for LNG facilities to be exempted if the investment improves and boosts up the competition in gas supply. The Brunsbuettel (German LNG Terminal GmbH) Terminal is on its way to achieving exemption from network access. After constructive discussions with the German regulatory authority and submitting an application for exemption from tariff regulation under section 28a of the German Energy Industry Act (EnWG), the German LNG Terminal GmbH has received the draft exemption decision from the Bundesnetzagentur. German LNG Terminal GmbH is exempted from the network access and tariff regulation, applicable for up to 8 billion cubic meters per annum only, where it will be in force for 25 years.

German LNG Projects

Germany’s ‘road map’ for LNG import terminals directs its attention to (Brunsbüttel) Hamburg, Wilhelmshaven, and Stade. Going through the COVID-19 waves, the entrepreneurial spirit within all sectors has been blindsided, and the LNG industry has been no exception. The LNG projects in Germany have also been delayed.

LNG Hamburg Terminal

The construction site of the Terminal is in Brunsbüttel, in the greater industrial and economic zone of Hamburg. It is considered the most promising among all proposed projects in Germany (Brunsbüttel, Wilhelmshaven, Stade, Rostock), especially after the cancellation of LNG Wilhelmshaven, which unequivocally will make Brunsbüttel even more appealing to suppliers. In addition, the Terminal will step up for taking a major role in the logistic chain for the LNG supply for bunkering LNG ships in Hamburg.

Due to the pandemical situation, the expected start-up has been put off from the end of 2022 to the second half of 2024 the earliest to be fully operational. As of this date, the development has reached a milestone by applying for planning permission.

Key figures

The send-out LNG capacity could reach over 8 billion cubic meters per annum with an unloading rate of 14 000 cubic meters per hour and a loading rate of 2500 cubic meters per hour. The facility is also expected to give out storage for 330 thousand cubic meters of LNG. On top of this, there will be two berthing facilities designed to fit even LNG carriers with the size of the Q-Max. As per the provided information, the LNG shipping companies will be able to discharge their cargo on trucks, cryogenic rail tank cars or other smaller ships.

The favourable geographical proximity to the nearby port of Hamburg as well as the industrial companies located in the region offers an attractive business environment, where the Scandinavian countries and the Baltic States can be easily reached via the Kiel canal.

The shareholders in the joint venture behind the Terminal (i.e., German LNG GmbH) are Oiltanking GmbH, N.V. Nederlandse Gasunie and Koninklijke Vopak N.V. The aim of the joint venture is namely to work on building a multifunctional import and distribution terminal for liquefied natural gas.

Тhroughout the feasibility study for the Terminal, MOU with external stakeholders have been signed and several other market players are about to. This also marks out the most apparent advantage of the Brunsbüttel Terminal in comparison to others.

The capacity contract between the Terminal and RWE getting hold of a considerable part of the terminal’s capacity (5 BCM) on a long-term basis is a typical example. The LNG supply deal was signed as well, where Woodside Energy will secure the firm LNG supplies to the regasification plant.

Some of the main functions include span across berthing/unloading, LNG loading onto trucks or rail tank cars, temporary storage, regasification, and transmission.

In the end, Brunsbüttel should be taken very seriously not only because of its ample regasification capacity, but equally importantly, because of its envisaged major role as the port for the highly desirable hydrogen.

Stade LNG Terminal

The Hanseatic complex is conveniently located at the Elbe River, with access to the North Sea and the Port of Hamburg. The planned annual capacity for 12 BCM per annum makes it the largest LNG plant under consideration in northern Germany.

The expected start-up is planned to take place in 2026, where the investment cost for building this Terminal would be around US$567 million.

Hanseatic Energy Hub GmbH is behind the project and is responsible for its development, planning, construction, financing likewise the operation of the Terminal.

Key figures

The optimal send-out capacity could reach over 12 billion cubic meters, the containment system consists of two tanks with a total volume of nearly 500 thousand cubic meters of LNG. Similar to Brunsbüttel Terminal, the distribution facilities here would be ready to use rail tank cars, barges and trucks.

Throughout the feasibility study for the Terminal, Hanseatic Energy Hub(HEH) started an industrial partnership with Dow Chemical and Fluxys, together with Buss Group and Switzerland’s Partners Group. What distinguishes this plant from the others is that, by using the waste heat from the Dow’s chemical processes used for the further regasification and thus reducing the CO2 emissions during the LNG processes.

Another door could have been opened to the low-carbon LNG supply chain attained through the partnership with GNL Quebec (Liquefaction facility in Canada) and making a clear path for alternative lower-emission fuels to reach Germany. Unfortunately, the LNG facility in Canada did not get approval and as of this day is cancelled.

The provided terminal services(logistics via rail, road, small LNG ships and barges) will turn the Hanseatic Terminal into a major LNG distribution hub.

Photos by Yulia Buchatskaya and Patrick Rosenkranz on Unsplash

Rostock LNG Terminal

Among the proposed LNG Terminals, there was an opportunity for a small-scale LNG project in the port of Rostock, Germany. The joint venture behind the construction of the Terminal was 49% and 51%, Novatek and Fluxys respectively. The main concept for this Terminal is namely to fill a specific market niche and having in use entirely Russian gas.

This project has been abandoned at the very first phase, surprisingly it is not due to the lack of interest, it was rather the opposite, a ‘constructive support’ was shown from the stakeholders.

Perhaps, an explanation would make sense in the hard times for the Energy industry, as a result of the heavily impacted market powers by the Covid spread.

Wilhelmshaven LNG Terminal

The second site where the project will not be brought to a close is Wilhelmshaven port. LTeW GmbH — a fully-owned subsidiary of Uniper is in control of the project development. The FSRU only will be owned and operated by the company — Mitsui Lines. The estimated cost of the entire project is $725 million.

Here, the crucial factors for abandoning this project appear to be the lack of interest in the long run along with the climate issues and the more desirable ‘green molecule’. According to Uniper’ s Corporate spokesperson — Georg Oppermann, they switched their focus to hydrogen, in a way that ‘Wilhelmshaven LNG’ turns into ‘Green Wilhelmshaven’ to act as a central hub for climate-friendly hydrogen. In the matter of the Project lifecycle, they are currently right in the middle of the feasibility study. Ideally, there will be an ‘ammonia cracker’ installed to have production capacity for ‘green’ hydrogen bolstered by a 410 MW electrolysis plant, so that in the end Uniper could contribute to a common European hydrogen market.


German Gas Market Area Merger in IT Terms

Press Release

ROITI’s contribution to handling the Trading Hub Europe (THE) transition for a major gas player in Germany

Sofia, Bulgaria, Wednesday 6th of October

We at ROITI Ltd. are happy to announce that together with customers and partners we have managed to handle the merger of Gaspool and NCG into Trading Hub Europe (THE) for one of our Germany-based customers with a large gas portfolio – EWE Trading. The IT landscape is Endur-centric and the merger had to be managed in two versions of Endur simultaneously, as it happened just before a Greenfield re-implementation of the ETRM system.

The project team managed to handle various complexities, including updating static data on different levels to ensure portfolio management and scheduling works, the adaptation of reporting, adding functionality across the board, which could handle both worlds – the  Gaspool/NCG one, and the THE one. Furthermore, we adjusted deals to new delivery and pricing structures and integrated new zonal products (introduced through ECC) into the existing deal flow.

“The project, which was handled by renaming NCG in several places, posed some challenges related to the specifics of Endur and many decisions around the handling of two histories and one future had to be made on different deals. Ultimately, in close cooperation with affected business parties we found a working solution to enable a minimally disruptive transition throughout the IT landscape, which was key in the current period of very high price volatility”, said Ventsislav Topuzov, CEO of ROITI.

“Gar nicht so mal schlecht”, said Dr. Sven Orlowski, CEO of EWE Trading in the final preparations for the go-live. “ROITI is a valued partner and helped us deal with THE within an outdated implementation of Endur and synchronise all changes to a new instance, redesigned from scratch. The business transition went with minimal disruptions, and they were handled efficiently.”

We want to thank our customers for their trust, as well as the teammates we worked with from different companies. Now, we are off to meet the next market structure changes and are setting our eyes on the LNG growth and its impact on the IT landscape. We look forward to seeing when the DLS will be stopped and how this will disrupt the existing solutions.


ROITI Ltd. was founded in 2013 and has had experience with eight satisfied clients so far. We are a full-service technology advisory focused on clients within the energy trading sector on their journey to digitalization. We design, develop, and maintain IT solutions throughout the entire wholesale and retail value chain, and we offer ETRM system integration and enhancement services, cloud migrations, and the development of data warehouse solutions. 

For more information please contact:

Hristina Tankovska

Marketing & Business Development at Roiti Ltd., Sofia, Bulgaria

E: htankovska@roiti.com

Terminaling services — Fee Capturing Tool

Terminaling services — Fee Capturing Tool

Photo by <a href="https://unsplash.com/@chris_pagan?utm_source=unsplash&utm_medium=referral&utm_content=creditCopyText">Chris Pagan</a> on <a href="https://unsplash.com/@chris_pagan?utm_source=unsplash&utm_medium=referral&utm_content=creditCopyText">Unsplash</a>

Photo by Chris Pagan on Unsplash

Amid the prolific and expanding LNG industry worldwide, the massive influx of Liquefied natural gas in Europe makes the Old Continent the third-largest trading region for LNG import, following Asia-Pacific and Asia. The amount of LNG import into Europe has reached nearly 80mtpa out of 356mtpa total global LNG trade volume.

Despite being hard to compare with the vast quantity in the Asia-Pacific region, the overall regasification capacity in Europe amounts to 179mtpa. There are currently 37 operating terminals, and more are to be built by the end of 2021 (currently in the EPC stage, or the planning stage FEED, FID). Considering Europe’s largest LNG receipts from Spain (45 MTPA) and UK (38MTPA) in addition to the ongoing construction of new import facilities, one can conclude that stringent transparency requirements are necessary. Introducing such measures before the Terminals Operators would support a more competitive, accessible, and fair market environment. Otherwise, commercial data on roughly 37% of the total EU send-out LNG capacity will continue to stay publicly unavailable.

Not much has been done recently to tackle the information opacity and complexity, which according to the Council of European Energy Regulators is ‘evident to be a potential barrier against new LNG Imports.’ In a way, to a lesser extent, there is an existing GLE Transparency template (GIE/GLE), implemented voluntarily against the LNG system operators. However, this concerns the generic Terminal characteristics rather than the commercial information, which is more vital for making informed decisions, such as regasification costs. That being said, a substantial share of information about the European regasification capacity remains a grey area. The UK receiving terminals are such an example.

To sum up, there seem to be three peculiarities that may raise caveats to the European LNG trade:

  1. Lack of genuine level-playing field— A handful of Import Terminals (6 LNG Terminals) are under an exemption regime. In the matter of data accessibility this would mean that all the commercial information regarding Tariff and Fee structure is not disclosed, but strictly confidential (e.g., basic services such as Unloading, Storage, Regasification).
  2. Lack of service standardization— Presently, there is a substantial tariff variation.
  3. Poor-quality information— All in all, the information published is not illuminating. On the contrary, it is rather incomplete and of questionable value regarding the usage of LNG Terminal services. In addition, there is a limited understandability since national legislation for some of the European LNG Terminals is rarely translated. In the end, all this will open doors to more inefficiency, confusion, prolonged time frame for commercial information gathering, leading inevitably to market distortion.

What role can RoITi play?

RoITi Ltd. as an organization aims at bringing answers to major questions in the energy sector, sparing no efforts in going after ‘the sweet spot’ of the synergistic relationship between Energy and Software. By solidifying the role of the software in energy, through adopting our proposed digital solutions, the LNG shipping companies are expected to benefit from these smart solutions.

RoITi ‘s concept focuses on the LNG Import Terminal Services, and more particularly on all the expenses incurred between the Berthing/Mooring process ending with the Injection process into the National grid system (e.g., tariff tables, fees, all fines, and penalty charges etc). That is to empower future software users to unify the energy management across the full spectrum of LNG import locations by giving them control over the tariff structure and the ability to optimize its deployment and management for the benefit of their organization.

We are working on a design of our proposed digital solution, (e.g., “multi-Terminal” Calculator). In our framework, users would have the right tool designed to facilitate the entire process of acquiring information in a more versatile way in terms of having a good grasp on the Tariff tables and fees for more than one Terminal. This will help the LNG shipper by obtaining the necessary information at the right time with minimum effort.

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Gas Storage – Always a Good Challenge

Gas Storage – Always a Good Challenge

Gas Storage – Always a Good Challenge

In my book, gas storage is among the most complex types of contracts to implement in an ETRM system. Below, you will find the challenges that an implementation will face when gas storage is concerned.

Contract terms

There are three main aspects of a storage contract:

  • Working gas volume (WGV) – how much gas you can have in the storage at any given point during the contract period
  • Injection capacity (IC) – how fast you can inject – typically per hour or per day
  • Withdrawal capacity (WC) – how fast you can withdraw

Some operators also have additional options or limitations:

  • Overrun penalties (balance going above WGV or injecting more per hour or per day than your IC or withdrawing faster than WC)
  • Seasonal limitations on IC and WC – depending on technology and whether overall the system is in “injection mode” or “withdrawal mode”. Essentially, if you are going against the flow, it either cannot happen fast enough, you have to pay more for it – or both of these

Capturing the different terms for the payments of the above conditions are typically complex to understand and model – they may be:

  • lump sums (typical for WGV)
  • volumetric payments – price per injected or withdrawn unit (for IC and WC)
  • a combination of the above
  • based on a fixed price or indexed to pretty much anything – I have encountered summer winter gas spreads, power indexing against year ahead contract, and a combination of the two

Volume movements

Once the storage contract is captured in a system, the more interesting movements affecting the balance also require some thinking.

To start with, capturing the initial fill level may be a challenge. There are two key items to it. You have to adjust the balance under a specific storage contract, but this is not an injection – gas is already there when you sign the contract – however, if you model the contracts separately in a system, you have to move from one to the other. Also, the value at which it enters the storage is a question – especially for the initial capture of a storage deal that may have ran for years.

In storage transfers are also a topic to consider, which is similar in terms of how it affects the balance – and easier to value. With them, gas is changing hands in the storage facility itself – often done with counterparties as a swap against a hub position to save injection and withdrawal fees. The complexity coming from these is to adjust the balance without adding in the system an injection or a withdrawal. Besides affecting the balance in the facility, the actual transaction with the counterparty has to be captured – and it may be a challenge to do these in one step for some systems.

Normal injections and withdrawals are usually straightforward to capture. The interesting part is what happens when a storage user goes into overrun. Ideally, the ETRM system should automatically calculate the penalty.


For the trading/portfolio management purposes, storage is typically valued as a time spread:

MTM (storage) = (Pwth*Qwth – Pinj*Qinj) – Total Storage Costs


Pwth, Pinj  are the market prices at the times respectively of withdrawal and of injection.

Qwth, Qinj are the quantities withdrawn and injected in the storage

Total Storage Costs are the payments for WGV, IC, WC, and overruns and other penalties

Note that for the calculation to make sense, Qwth has to be equal to Qinj – otherwise there is an unaccounted for imbalance between injections and withdrawals. This means that an estimation of when injected gas will be withdrawn has to exist and be marked against a forward curve. This is often counterintuitive – and sometimes an egg or a hen question arises – do you plan injections and withdrawals and then hedge against the plan, or do you buy and sell gas, and then see how storage fits in… Both ways are valid – again, depending on market conditions and company tactics.

In the case when injections and withdrawals are planned after some optimization process, the question of how you arrive at the plan comes up. And is the optimization part of the ETRM system – or a separate tool used for inputs.

Overall, storage is a really good exercise in stretching software capabilities. In my experience, the multiple views you can have on a storage (from the market perspective, an injection is a short position, but from the storage perspective, it increases the balance), and the complexity of the contractual terms and volume movements are not covered in any system completely.

Written by Ventsislav Topuzov