In this deliverable from the SeCoHeat project, profits that can be made with 1 MWh of electricity production capacity on existing ancillary service markets are evaluated in 2020 and 2021. Profits are evaluated for four different marginal production costs corresponding to the following fuels for a CHP power plant: waste (assumed fuel price: 0 kr/MWh), recycled wood (10 kr/MWh), wood chips (20 kr/MWh) and wood pellets (30 kr/MWh). The results show that except for wood chips and wood pellets in 2020, the most profitable ancillary service markets are FFR (fast-frequency response) and aFRR down (automatic frequency restoration reserves for down-regulation). The reasons are that (1) producers don’t have to withhold capacity from the day-ahead market when their participate in these two markets and (2) producers get compensated for the capacity reserved for the ancillary service markets. For wood chips, the FFR market was the most profitable in 2020, followed by the mFRR down market (manual frequency restoration reserves for down-regulation). The reason for the mFRR down market to be more profitable than the aFRR down market for this fuel is that the profits from mFRR down depend on the avoided fuel costs, which are higher for wood chips than for waste and recycled wood. In 2021, all prices started increasing significantly, which decreased the relative profitability of the mFRR down compared to other markets. For wood pellets, the mFRR down market was also the second most profitable market in 2020, for the same reasons. The most profitable one in 2020 was the mFRR up market (manual frequency restoration reserves for up-regulation). The reason is that the higher fuel price of these two fuels entails low participation in the day-ahead market. Therefore, withholding capacity from the day-ahead market to be able to participate on the mFRR up market brings additional profits. In 2021, however, day-ahead prices started increasing significantly (a trend that continued into 2022) and the mFRR up market became the least profitable market for these two fuels. The profit evaluation performed in this deliverable is purely economic. It does not include the sector coupling to the heat sector (which entails limitation of the available electricity production capacity but also a possibility to store heat if storage is available) nor does it include other technical limitations such as ramp rates. These aspects will be considered in follow-up work in this project. This report has been compiled within the scope of the project SeCoHeat - Sector coupling of district heating with the electricity system: profitability and operation. The project is financed by the Research and Development Foundation of Göteborg Energi.

I och med omställningen till ett energisystem med en större andel förnybar el står elmarknaden inför flera utmaningar. Traditionella kraftslag som kärnkraft är ofta styrbar, men förnybara kraftslag som vindkraft är väderberoende. En ökad mängd förnybar produktion kan därmed innebära ett ökat behov av fysisk handel närmare leveranstimmen. Intradagmarknaden är en marknad för fysisk handel mellan leveranstimmen och dagen före marknaden, där majoriteten av all handel sker. Den planerade expansionen av förnybara kraftslag är en indikation på att intradagmarknadens betydelse kommer att öka. Av den anledningen är det viktigt att de aktörer som direkt eller indirekt kan påverka eller påverkas av intradagmarknaden har en god förståelse för dess funktion. Den här rapporten beskriver intradagmarknadens funktion och roll i elhandelssystemet.

The project SeCoHeat aims at assessing the additional profits that district heating systems can make by participating in new electricity markets, such as ancillary service markets. A model has been developed to schedule district heating units on an hourly basis to minimize heat and electricity production costs while maximizing revenues from electricity markets. This model works with hourly energy flows. In this report, the importance of considering temperature quality in district heating networks when scheduling district heating units is investigated. Temperature quality refers to controlling mass flows and supply temperatures to ensure acceptable confort at the end-consumers. Traditional scheduling models use an energy-only formulation where energy is related to the product of temperaturate and mass flows. They do not consider these two quantities separately and, therefore, are unable to capture temperature quality aspects. On the other hand, these traditional scheduling models are less complex than a full representation of both temperatures and mass flows. Traditional scheduling models based on an energy-only formulation can be expressed as MILP optimization problems, whereas considering both temperatures and mass flows lead to MINLP optimization problems which are must harder to solve. Several simplications and reformulations have been proposed in this report to make the full MINLP problem less complex. These simplifications reduce the number of non-linear equations and, for one of them, even leads to a MILP formulation. In addition, a literature review about exisiting linear reformulations of the full MINLP problem and the importance of considering temperature quality is performed. This report gives a ground to further develop scheduling models that make tradeoffs between model complexity and accurate representation of temperature quality.

Profits generated by district heating systems when participating in ancillary service markets in the electricity sector are studied in this report. An hourly scheduling model is developed to optimally schedule district heating units to meet the heat demand, minimize costs and maximize revenues from electricity markets. The output is used to evaluate the additional profits made by participating in the existing Swedish ancillary markets in addition to the day-ahead electricity market. Case studies are run in two district heating systems, one in Nyköping and one in Gothenburg, for the historical years of 2021 and 2022. Nyköping’s system is also used to evaluate potential profits from ancillary service markets in future scenarios for 2025, 2035 and 2045. Finally, Nyköping’s system is used to evaluate potential additional profits generated by two investments that enhance the flexibility that can be provided to the electricity sector: better CHP ramp rates and larger thermal storage. The analysis of the results shows, for both historical and future years, that participating in ancillary services brings about additional profits. These vary depending on the year, studied district heating system. Profits from electricity markets are shown to increase by up to 40% in Nyköping and 200% in Gothenburg when looking at the historical years. Doubling the CHP ramp rates ability for delivering ancillary services or doubling the size of the heat storage are shown to result in up to another 6% of additional profits. In the future scenarios, profits from electricity markets are shown to increase by up to 94%.

District heating systems can play key roles in the energy transition. The transition to a production mix based on renewable intermittent generation will create a larger need for ancillary services including frequency-regulation services. District heating systems typically participate in the wholesale electricity market (the so-called day-ahead market) today but do not, in general, participate in ancillary service markets. Previous studies have shown that it is technically possible to participate in these markets and that district heating systems have a role to play in these markets in the future. This requires investigating how further integration of district heating systems with the electrical grids and markets will impact operation and planning of these units. In addition, while it may be beneficial on a system level for district heating systems to participate in ancillary service markets, district heating system owners and operators will only do so if there are economic incentives to do so. The SeCoHeat project has therefore explored topics related to the profitability for individual district heating systems to participate in other electricity markets than just the day-ahead market, such as ancillary service markets. Studying sector coupling between the heat and electricity systems requires a thorough understanding of both sectors. This project has contributed to this by bringing together experts from both sides which has led to fruitful knowledge exchanges. Furthermore, some deliverables from the SeCoHeat project have been especially written to provide introduction about the heat sector to experts from the electricity sector, and vice versa. This includes an overview of the electricity markets in which district heating systems can participate, the technical requirements to participate in these markets and explanations about how profitability of participating in these markets can be computed. This also includes explanations about how the flexibility on the heat side can be sourced and provided to the electricity system and what limits this flexibility. Another important contribution of this project is the development of a Python-based open model for scheduling district system units on an hourly basis to minimize heat and electricity production costs while maximising revenues from several electricity markets. This model has been used in this project to evaluate the additional profits of participating in ancillary service markets. The results show that substantial additional profits can be made by doing so, both in historical years and in scenarios for future years. This report is a guide to the separate deliverables produced within this project. It offers an overview of the goals, methods and results from the project. The interested reader is referred to detailed descriptions in the corresponding deliverables. The SeCoHeat project was funded by Göteborg Energi AB:s stiftelse för forskning och utveckling. The work has been performed by RISE with the support of reference group members from Göteborg Energi, Vattenfall, Svenska kraftnät, IVL Svenska Miljöinstitutet, Chalmers and Profu.

The project’s objective is to assess whether flexible bio-based power generation can be an effective and profitable technology option for balancing power system with large amounts of weather dependent production (wind and sun). It includes an analysis which estimates the potential income levels that can be gained by different types of bio-based power plants from selling electricity products and determines if the extra cost of having a combined heat and power (CHP) plant instead of having a heat only (HO) plant is worth investing.

The project's subgoals, how they have been addressed and some follow-up directions are presented below:

Subgoal 1: Increased knowledge about revenues that can be gained by different technology solutions from selling electricity in different markets, e.g., day-ahead and balancing markets (also called manual frequency restoration reserve market – mFRR market).A model has been developed to estimate the profits that can be made by district heating owners on day-ahead and balancing (mFRR) markets. The model has been applied in two case studies using historical price data for 2019: one using Borås Energi och Miljö’s (BEM) district heating system and one using Vattenfall’s system in Nyköping. In both cases, the results show an increase in profits when participating in balancing markets. This increase is, however, very small compared to the profits made by only participating in day-ahead markets (less than 0.1% increase in overall profits).

Subgoal 2: Increased knowledge about investment and operating costs (CAPEX/OPEX) of different bio-based technologies, both HO and CHP plants. A literature survey was done to identify comprehensive sources of costs. Two reports were identified as relevant sources: [1] and [2]. The first one dates from 2014 and the second one from 2019. They provide a wide-ranging collection of investment and operation and maintenance costs for units of different sizes and types.

Subgoal 3: Increased knowledge about the market conditions needed to justify the extra cost of building a bio-based CHP plant instead of a bio-based HO plant. Two investment case studies have been performed using BEM’s system to compare investment in CHP and HO units. The previous model has been used to evaluate the profits from participating in the day-ahead electricity market for three representative years: 2019, 2030 and 2040. Price conditions for 2030 and 2040 were obtained from Svenska kraftnät’s long-term market analysis [3]. The investment and O&M costs of the new units were obtained from [1] and [2]. The first investment study investigates an investment in new units for redundancy purposes (to ensure sufficient production capacity in case the largest unit is unexpectedly out of operation). The investment results show that profits from selling heat and electricity are not enough to cover the investment and O&M costs. The economic losses are smaller when going for the HO option. The second investment study investigates an investment in base-load units (units meant to run most of the time). In this case, both CHP and HO plants are profitable but the HO plant achieve a higher profitability.

Subgoal 4: Increased knowledge about the financial risks and uncertainties in such an investment.This was achieved through discussing the results with the industry partners and identifying aspects that could be further investigated in a follow-up project. The lifetime of new investment is around 25 years. Many sources of uncertainties enter the evaluation of the financial indicators. Among these, the most relevant ones that could be further investigated are: assumptions on the underlying heat demand (colder and warmer years), assumptions on future electricity prices, assumptions on the price for green certificates and purpose of an investment (an investment for redundancy purposes may not recover its costs but is still needed – how to value redundancy?). Many other input parameters to the investment studies - such as O&M costs, fuel prices and discount rate - may also play a role in the results. A thorough sensitivity analysis would shed more light on the magnitude of each one and could be included in a follow-up project.

In this report, a framework was developed to assess the profits from participating in the different ancillary services for frequency regulation in Sweden. The framework considers forecasting errors on both production and prices, market clearing times and technical requirements of the difference ancillary services. The framework was applied to evaluate potential profits for a real wind power plant of 2 MW in SE3 in 2020 and 2021. The economic analysis points out to aFRR down as the most profitable market today with additional revenue of as much as 35% compared to day-ahead only in case of perfect production forecasts, and as much as 22 % with consideration of standard production forecast errors. It is also shown that developing bidding strategies based on price forecasting to act on several ancillary service market may increase the revenues by up to 70% compared to day-ahead only. Future work in the topic includes evaluating the profits in other price areas and evaluating different production and price forecast methodologies and their impact on the profits.

A review of sector coupling possibilities between the heat and electricity sectors in Sweden is made in this report. First, a review of the way the heat sector works in Denmark, Finland and Sweden works is performed. Finland and Sweden have similar setups with deregulated heat sectors in which district heating companies set their billing price freely considering different cost factors, including costs for alternative technologies to which consumers could switch. Denmark has had a more regulated approach with prices being reviewed by the regulator. The sector coupling between the electricity sector in Denmark has been stronger than in both Sweden and Finland. District heating companies had an obligation until 2019 to participate in both the day-ahead market and the balancing market (mFRR). CHP plants in Denmark have also participated to frequency regulation (aFRR). There is still a non-negligible share of CHP plants in Denmark running on fossil fuels such as natural gas and coal. Large investments in heat pumps, biofuels and solar thermal facilities have been identified as alternatives to these CHP plants to enable a fossil free heating sector. Second, the current electricity and ancillary service markets in Sweden are described. Recent experiences with local and regional flexibility markets in Sweden are reviewed. District heating companies are particularly well-fitted for participating in these markets thanks to their geographical location close to the electric consumption centres in the cities. Third, a review of the state-of-the-art research on the participation of district heating systems to the electricity and ancillary service markets is performed. It is shown that the flexibility in district heating systems that can be used in the electricity sector can take many forms: changes in the electricity production / consumption of heat production units, by-product usage of the excess heat (e.g. fuel drying), thermal storage in water tanks or other kinds of storage facilities, thermal storage in the pipeline network and thermal storage at the customers’ site (for example in buildings). Research on the technical capabilities shows that many units in the district heating systems can fulfil the requirements for delivering ancillary services. Many research works have identified possible economical gains by participating in more markets on the electricity side (for example ancillary service markets). However, many research works in this field have focused on single CHP plants instead of considering the whole portfolio of units in the district heating systems. To get a more detailed assessment of the profitability of increasing the participation of district heating companies in the electricity sector, it is advocated to develop operational planning and operations tools for district heating systems that can capture the hourly variability of prices of the electricity and ancillary service markets, as well as consider the order in which decisions have to be taken on these markets (i.e. the time order in which the different markets operate). These tools will be developed in the coming work in the project. 

Det svenska elsystemet står inför en rad utmaningar. En ökande andel intermittent energi ställer ökade krav på balansering i våra nät, dessutom pågår en samhällsomfattande elektrifiering samtidigt som nyetablerade industrier ställer höga krav på tillgängligheten av effekt. Parallellt pågår ett omfattande arbete att minska Sveriges utsläpp av växthusgaser. Vätgas väntas anta en nyckelroll; främst inom industrin men även inom transportsektorn. Etableringen av en storskalig användning av vätgas öppnar samtidigt upp för att skapa energinyttor i andra delar av samhället, inte minst vad det gäller att stötta upp elnäten genom att erbjuda energilagringskapacitet och flexibilitet. I denna studie har ett framtidsscenario (år 2045) utretts. Det bygger på data från Svenska kraftnät samt på två hypotetiska utvecklingstrender; 1. Vätgas har antagit en dominerade roll inom elektrifieringen av transportsektorn. Vätgastankstationer är lika vanligt förekommande som dagens bränslestationer för vägbundna fordon. 2. Nämnda vätgastankstationer skalar upp vätgaslagringskapaciteten för att parallellt med att tillgodose transportbehovet även skapa nätnytta på transmissionsnätsnivå och därigenom minska behovet av investeringar i nätförstärkningar. Studiens syfte har varit att utreda den tekniska potentialen för ovanstående framtidsscenario, samt att undersöka hur en sådan utveckling av tankstationernas verksamhet skulle kunna komma att påverka priset på vätgas som bränsle. Dessutom har det i studien utretts om den ekonomiska besparing som de uteblivna nätförstärkningarna medför hade varit tillräckliga för att skapa politiska styrmedel i form av ett investeringsstöd riktat till ägare av tankstationerna för att täcka installationskostnaden för de utökade lagren. De nättekniska analyserna har i studien begränsats till att utreda vätgasens potentiella nätnytta vid handelsgränser på stamnätsnivå mellan elområden i Sverige samt vid förbindelser till våra grannländer. Studien har också begränsats till att enbart undersöka nätnyttan vid de handelsgränser som har ett förväntat behov av nätförstärkningar i framtiden. Resultat av studien visar: • Utökade lager vid vätgastankstationer kan skapa ett visst stöd till transmissionsnätet där handelsflödet når gränsen för den maximala handelskapaciteten. Förutsättningen är att det enbart inträffar stundtals och vid tidpunkter utspridda över året. Den totala nätnyttan är således väldigt begränsad. Ett fåtal undantag för detta har noterats där nätnyttan blir mer betydande. I dessa fall krävs dock en betydligt större bränslecellskapacitet vid de tänkta tankstationerna än vad som kan tänks vara standard för en vätgastankstation för att kunna tillhandhålla tillräcklig effekt i nätet. • Den utökade lagringskapaciteten vid tankstationerna har stor påverkan på vätgaspriset. Två parametrar som är av stor betydelse för detta är elpris och 6 (72) CAPEX (investeringskostnad). Ett investeringsstöd på minst 50% behövs för att priset på vätgas ska bli lägre för en tankstation med ett lager på 4 000 kg (utökat lager, även inkluderande en bränslecell på 300 kW), jämfört med ett lager på 100 kg (standard-lager). • Det råder begränsade förutsättningarna för ett betydande investeringsstöd för vätgastankstationer enbart baserat på den nätnytta som vätgastankstationer kan generera på transmissionsnätnivå. Två faktorer som visats ha stor betydelse för resultatet är valet av styrstrategi för hur lagerkapaciteten ska kunna nyttjas av näten samt tillgänglig bränslecellskapacitet vid tankstationerna. • Mer omfattade stödsystem blir möjliga först när fler ”vätgas-nyttor” vägs in. Det sakas dock idag kunskap om hur ett sådant stöd skulle utformas. Utöver ovanstående resultat genomförs en inventering av andra ”nyttor” som tankstationerna skulle kunna bidra med, både mot nätet men andra energimarknader. Sammanfattningsvis kan det konstateras att decentraliserade vätgastankstationer utgör ett intressant inslag i den framtida energimarknaden med flera potentiella användningsområden. Det råder också goda möjligheter för att bygga mer komplexa affärsmodeller/ekonomiska styrmedel då fler nyttor tas i beaktande. Av studien framgår det tydligt att även om nyttan av tankstationernas lager är begränsad på stamnätsnivå är möjligheterna betydligt större på lägre nätnivåer. I dessa sammanhang är det mer troligt att vätgasen kan komma att ta en mer betydande roll.

The overall objective of the VABISYS project was to develop new technologies and concepts that improve the value of bioenergy resources in an energy system dominated by variable renewable energy (VRE) such as wind and solar. When an energy system becomes dominated by VRE generation, completely new types of flexible resources are needed to maintain a stable and reliable supply of energy.

The objective of the Swedish work was to extend the flexibility of known bioenergy technologies and accelerate the deployment of flexible bioenergy technologies via market assessments and business plans. The specific objectives were:1. To assess the operational limitations of liquid biofuel-based energy production in low load and load changing conditions bio-oil boilers.2. To find the operation limits of an Organic Ranking Cycle (ORC). 3. To produce data to support energy system modelling and technology assessment of biofuel-based energy production in WP2 and WP6. 4. To create scenarios for the design of future energy markets. 5. To generate adequate production portfolios for bio-based flexible electricity production addressing future system needs and demands. 6. To estimate potential revenues for electricity production from bio-based production. 7. To analyse the replication potential for flexible bio-based electricity production in a European context and from a market design and policy perspective. 

The objectives were addressed in the following way:- Objective 1 and 2: A measurement campaign was performed to investigate the performance of the energy system at Falbygdens Energi with respect to emissions, ramp rates and flexibility limits for a bio-oil boiler (8,8 MW) and an ORC (2,4 MW electricity and 10 MW heat). The results will improve the possibilities of manufacturers to offer technologically and economically attractive bioenergy solutions to a market based on strengthening the robustness of VRE dominated energy system.- Objective 3: This was done by VTT and is not in the scope of this report, which only documents RISE work.- Objective 4: Scenarios for future electricity prices and fuel prices have been collected from (Svenska kraftnät, 2018) to serve as inputs to investment studies for the plants identified as interesting in the created portfolio (see objective 4 below).- Objective 5: A portfolio of current and future CHP plants was designed. The aim of this was to identify data sources that provide both economic and technical parameters for investments in new CHP plants.- Objective 6: An operational planning model has been developed to simulate operational planning of all units in district heating systems. It gives the optimal hourly schedules of all units for the coming week so as to maximize profits on the day-ahead electricity market and minimize fuel, start-up and shut-down costs.- Objective 6: continued: An investment model has been developed to study the profitability of investments in new plants in existing district heating systems. It uses scenarios covering the full lifetime of the new plants to be studied. It takes the results from the operational planning model to compute financial profitability indicators.- Objective 7: The developed models have been applied to case studies in Sweden. However, they are flexible enough to be used in other contexts. Moreover, the day-ahead electricity market has a common design in most European countries, which makes the model valid without any changes in countries included in the same coupling region as Sweden.

Some conclusions from the projects are:A biopower plant needs to have a stored resource that can produce electricity when it is needed and to be a flexible resource in the energy system. Bio-oils can be used for these purposes since they have high starting availability and are a fuel that can be stored for several years. The results showed that it is possible to obtain a fast start from 80 seconds to 13 minutes depending on operational mode and the emissions from the bio-oil boiler is not significantly affected during start-up or when changing load.

Flexibility and storage solutions will be important to meet the needs, and despite rapid development in terms of such solutions, in the longer term, a powerful expansion of Swedish electricity production and the electricity grid will also be needed. For smaller district heating plants, the ORC technology can be a good option. One of the most interesting features with the ORC is that it can operate at low load with maintained efficiency. The maximum decrease in electricity production for the studied ORC plant when running the wood chip boiler at constant load and when bypassing oil in the three-way valve was approximately 85 kW/min and when increasing the load in the ORC the ramp rate was approximately 172 kW/min. The emissions from the ORC-solid fuel boiler system was overall low and was not affected by changes in electricity production or load.

District heating can play key roles in meeting the challenges associated with the energy transition by coupling the electricity and the heat sector. District heating can provide local electricity production, decrease the share of electric heating and could be able to participate in ancillary services. To fulfil these roles, the profitability of investments in for example combined heat-and-power units needs to be evaluated, which the operational planning and investment models developed in this project can do. Future electricity price scenarios for Sweden show that higher electricity demand leads to both higher average electricity prices and larger variance in the electricity prices, the latter being due to the largest variation in available capacity from VRE from hour to hour. The results of the investment models on these scenarios indicate larger potential revenues from electricity markets in the future compared to today, which increases the profitability of investments in CHP units.

Nowadays, transmission system operators require higher degree of observability in real-time to gain situational awareness and improve the decision-making process to guarantee a safe and reliable operation. Digitalization of energy systems allows utilities to monitor the system dynamic performance in real-time at fast time scales. The use of such technologies has unlocked new opportunities to introduce new data driven algorithms for improving the stability assessment and control of the system. Motivated by these challenges, the IEEE Task Force “Application of Big Data Analytic on Transmission Systems for Dynamic Security Assessment” have worked together to highlight and establish a baseline set of these common concerns within the power system community, which will be used as motivation to propose innovative analytics and data-driven solutions in future efforts. In this document, the results of a survey on 10 transmission system operators around the world are presented and it aims to understand the current practices of the participating companies, in terms of data acquisition, handling, storage, modelling and analytics. The overall objective of this document is to capture the actual needs from the interviewed utilities, thereby laying the groundwork for setting valid assumptions for the development of advanced algorithms in this field. © 2021 The Author(s)