The role of policy instruments for promoting combined heat and power production with low CO2 emissions in district heating systems

Policy instruments clearly influence the choice of production technologies and fuels in large energy systems, including district heating networks. Current Swedish policy instruments aim at promoting the use of biofuel in district heating systems, and at promoting electric power generation from renewable energy sources. However, there is increasing pressure to harmonize energy policy instruments within the EU. In addition, natural gas based combined cycle technology has emerged as the technology of choice in the power generation sector in the EU. This study aims at exploring the role of policy instruments for promoting the use of low CO₂ emissions fuels in high performance combined heat and power systems in the district heating sector. The paper presents the results of a case study for a Swedish district heating network where new large size natural gas combined cycle (NGCC) combined heat and power (CHP) is being built. Given the aim of current Swedish energy policy, it is assumed that it could be of interest in the future to integrate a biofuel gasifier to the CHP plant and co‐fire the gasified biofuel in the gas turbine unit, thereby reducing usage of fossil fuel. The goals of the study are to evaluate which policy instruments promote construction of the planned NGCC CHP unit, the technical performance of an integrated biofuelled pressurized gasifier with or without dryer on plant site, and which combination of policy instruments promote integration of a biofuel gasifier to the planned CHP unit. The power plant simulation program GateCycle was used for plant performance evaluation. The results show that current Swedish energy policy instruments favour investing in the NGCC CHP unit. The corresponding cost of electricity (COE) from the NGCC CHP unit is estimated at 253 SEK MWh^?1, which is lower than the reference power price of 284 SEK MWh^?1. Investing in the NGCC CHP unit is also shown to be attractive if a CO₂ trading system is implemented. If the value of tradable emission permits (TEP) in such as system is 250 SEK tonne^?1, COE is 353 SEK MWh^?1 compared to the reference power price of 384 SEK MWh^?1. It is possible to integrate a pressurized biofuel gasifier to the NGCC CHP plant without any major re‐design of the combined cycle provided that the maximum degree of co‐firing is limited to 27–38% (energy basis) product gas, depending on the design of the gasifier system. There are many parameters that affect the economic performance of an integrated biofuel gasifier for product gas co‐firing of a NGCC CHP plant. The premium value of the co‐generated renewable electricity and the value of TEPs are very important parameters. Assuming a future CO₂ trading system with a TEP value of 250 SEK tonne^?1 and a premium value of renewable electricity of 200 SEK MWh^?1 COE from a CHP plant with an integrated biofuelled gasifier could be 336 SEK MWh^?1, which is lower than both the reference market electric power price and COE for the plant operating on natural gas alone. Copyright © 2005 John Wiley & Sons, Ltd.     

National energy policies: Obstructing the reduction of global CO2 emissions? An analysis of Swedish energy policies for the district heating sector

The effect of national energy policies on a local Swedish district heating (DH) system has been studied, regarding the profitability of new investments and the potential for climate change mitigation. The DH system has been optimised regarding three investments: biomass-fuelled CHP (bio CHP), natural gas-fuelled combined cycle CHP (NGCC CHP) and biomass-fuelled heat-only boiler (bio HOB) in two scenarios (with or without national taxes and policy instruments). In both scenarios EU’s tradable CO₂ emission permits are included. Results from the study show that when national policies are included, the most cost-effective investment option is the bio CHP technology. However, when national taxes and policy instruments are excluded, the DH system containing the NGCC CHP plant has 30% lower system cost than the bio CHP system. Regardless of the scenario and when coal condensing is considered as marginal electricity production, the NGCC CHP has the largest global CO₂ reduction potential, about 300 ktonne CO₂. However, the CO₂ reduction potential is highly dependent on the marginal electricity production. Demonstrated here is that national policies such as tradable green certificates can, when applied to DH systems, contribute to investments that will not fully utilise the DH systems’ potential for global CO₂ emissions reductions.     

Implementation strategy for small CHP-plants in a competitive market: the case of Lithuania

Within five years from now, Lithuania is going to close down Ignalina, the only nuclear-power plant in the country. Since Ignalina generates more than 75% of the Lithuanian electricity production, new generation capacities are needed. Traditional steam-turbines, fuelled with fossil fuels, would mean further imports of fuel as well as a rise in CO₂ emissions. At the same time, several small district-heating companies one suffering from high heating-prices. Typically, the price in small towns is 20–50% higher than the price in large urban areas. Consequently, alternative strategies should be considered. This article analyses the conditions for one such strategy, namely the replacement of boilers in the existing district-heating supplies with combined heat-and-power production (CHP). Compared with new power stations, fuel can be saved and CO₂-emissions reduced. Also this strategy can be used to level the difference between low heating prices in the large urban areas and high prices in small towns and villages.     

Regulatory potential for increasing small scale grid connected photovoltaic (PV) deployment in Australia

The last decade has seen significant innovation and change in regulatory incentives to support photovoltaic deployment globally. With high fossil fuel dependency and abundant solar resource availability in Australia, grid connected photovoltaics are a viable low carbon technology option in existing electricity grids. Drawing on international examples, the potential to increase grid PV deployment through government response and regulation is explored. For each renewable energy certificate (REC) earned by small scale photovoltaics until 2012, the market provides four additional certificates under the current banded renewable targets. Our analysis indicates that REC eligibility is not accurately estimated currently, and an energy model is developed to calculate the variance. The energy model estimates as much as 26% additional REC’s to be obtained by a 3 kWp PV system, when compared to the currently used regulatory method. Moreover, the provision of REC’s increases benefits to PV technologies, in the process distorting CO₂ abatement (0.21 tonne/REC) by 68%, when PV displaces peaking natural gas plants. Consideration of the secondary effects of a banded structure on emissions trading market is important in the context of designing a range of initiatives intended to support a transition to a low carbon electricity sector.     

Compromises in energy policy—Using fuzzy optimization in an energy systems model

Over the last year in Germany a great many political discussions have centered around the future direction of energy and climate policy. Due to a number of events related to energy prices, security of supply and climate change, it has been necessary to develop cornerstones for a new integrated energy and climate policy. To supplement this decision process, model-based scenarios were used. In this paper we introduce fuzzy constraints to obtain a better representation of political decision processes, in particular, to find compromises between often contradictory targets (e.g. economic, environmentally friendly and secure energy supply). A number of policy aims derived from a review of the ongoing political discussions were formulated as fuzzy constraints to explicitly include trade-offs between various targets. The result is an overall satisfaction level of about 60% contingent upon the following restrictions: share of energy imports, share of biofuels, share of CHP electricity, CO₂ reduction target and use of domestic hard coal. The restrictions for the share of renewable electricity, share of renewable heat, energy efficiency and postponement of nuclear phase out have higher membership function values, i.e. they are not binding and therefore get done on the side.     

Biomass and bio-energy utilisation in a farm-based combined heat and power facility

Five different renewable energy technologies located at an agricultural and environmental research centre in Northern Ireland, were monitored to assess the cost, performance and efficiency in real-time operation of solar and bio-energy produced from crops and farm wastes utilised for energy generation in industrial grade equipment. Monitoring was conducted over a six year period, with power units running simultaneously or intermittently according to demand from the local district heating system. The purpose of the work was to investigate fossil fuel (oil) displacement, carbon dioxide emission (CO₂e) reductions, financial and environmental sustainability of these technologies in a farm based scenario. Between 2009 and 2014, total heat output from the centre was 7.75 GWh with contributions of 47.2%, 17.1%, 9.8% and 13.5% from the biomass, biogas, multi-fuel boiler and biogas CHP unit respectively. Solar thermal produced 0.49% and the back-up oil boiler 11.9%. Total electrical output was 572.6 MWh with 95.2% generated from biogas CHP and 4.8% from the solar PV system. Fossil fuel and average CO₂e reductions ranged from 20.1% to 54.1% and 23.3–55.7% respectively, reductions that combined with financial savings to present a viable and sustainable renewable energy system.     

Fuel price and technological uncertainty in a real options model for electricity planning

Electricity generation is an important source of total CO₂ emissions, which in turn have been found to relate to an acceleration of global warming. Given that many OECD countries have to replace substantial portions of their electricity-generating capacity over the next 10–20 years, investment decisions today will determine the CO₂-intensity of the future energy mix. But by what type of power plants will old (mostly fossil-fuel-fired) capacity be replaced? Given that modern, less carbon-intensive technologies are still expensive but can be expected to undergo improvements due to technical change in the near future, they may become more attractive, especially if fossil fuel price volatility makes traditional technologies more risky. At the same time, technological progress is an inherently uncertain process itself. In this paper, we use a real options model with stochastic technical change and stochastic fossil fuel prices in order to investigate their impact on replacement investment decisions in the electricity sector. We find that the uncertainty associated with the technological progress of renewable energy technologies leads to a postponement of investment. Even the simultaneous inclusion of stochastic fossil fuel prices in the same model does not make renewable energy competitive compared to fossil-fuel-fired technology in the short run based on the data used. This implies that policymakers have to intervene if renewable energy is supposed to get diffused more quickly. Otherwise, old fossil-fuel-fired equipment will be refurbished or replaced by fossil-fuel-fired capacity again, which enforces the lock-in of the current system into unsustainable electricity generation.     

Estimation of the potential for reduced greenhouse gas emission in North-East Russia: A comparison of energy use in mining,mineral processing and residential heating in Kiruna and Kirovsk-Apatity

The energy demand at Murmansk Oblast in North-East Russia is covered at 60% by fossil fuels and at 40% by electricity. This study estimates the potential for reduction of fossil fuel consumption and CO₂-emissions at Murmansk Oblast. The study focus on the municipalities of Apatity and Kirovsk and the apatite ore mining company Apatit JSC . The potential for energy efficiency, reduced fossil fuel consumption and greenhouse gas emissions is estimated by comparison with the of city Kiruna in Northern Sweden, with a climate similar to that of North-East Russia, and with the iron ore mining company LKAB. This study shows that the potential for reduced CO₂-emissions is about 630,700 tons CO₂ annually in the municipalities of Apatity and Kirovsk or 6.3 tons of CO₂ per capita, Apatit JSC not included. These results applied on Murmansk Oblast gives a potential for reduced CO₂-emissions of about 6 Mtons annually in the municipalities together. The specific energy consumption at Apatit JSC is 6–7 times per ton product compared to LKAB. The mining has 4 times higher specific energy consumption per ton raw ore compared to LKAB.     

Biomass gasification in district heating systems – The effect of economic energy policies

Biomass gasification is considered a key technology in reaching targets for renewable energy and CO₂ emissions reduction. This study evaluates policy instruments affecting the profitability of biomass gasification applications integrated in a Swedish district heating (DH) system for the medium-term future (around year 2025). Two polygeneration applications based on gasification technology are considered in this paper: (1) a biorefinery plant co-producing synthetic natural gas (SNG) and district heat; (2) a combined heat and power (CHP) plant using integrated gasification combined cycle technology. Using an optimisation model we identify the levels of policy support, here assumed to be in the form of tradable certificates, required to make biofuel production competitive to biomass based electricity generation under various energy market conditions. Similarly, the tradable green electricity certificate levels necessary to make gasification based electricity generation competitive to conventional steam cycle technology, are identified. The results show that in order for investment in the SNG biorefinery to be competitive to investment in electricity production in the DH system, biofuel certificates in the range of 24–42 EUR/MWh are needed. Electricity certificates are not a prerequisite for investment in gasification based CHP to be competitive to investment in conventional steam cycle CHP, given sufficiently high electricity prices. While the required biofuel policy support is relatively insensitive to variations in capital cost, the required electricity certificates show high sensitivity to variations in investment costs. It is concluded that the large capital commitment and strong dependency on policy instruments makes it necessary that DH suppliers believe in the long-sightedness of future support policies, in order for investments in large-scale biomass gasification in DH systems to be realised.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

Electricity consumption and CO2 capture potential in Spain

In this paper, different electricity demand scenarios for Spain are presented. Population, income per capita, energy intensity and the contribution of electricity to the total energy demand have been taken into account in the calculations. Technological role of different generation technologies, i.e. coal, nuclear, renewable, combined cycle (CC), combined heat and power (CHP) and carbon capture and storage (CCS), are examined in the form of scenarios up to 2050. Nine future scenarios corresponding to three electrical demands and three options for new capacity: minimum cost of electricity, minimum CO₂ emissions and a criterion with a compromise between CO₂ and cost (CO₂-cost criterion) have been proposed. Calculations show reduction in CO₂ emissions from 2020 to 2030, reaching a maximum CO₂ emission reduction of 90% in 2050 in an efficiency scenario with CCS and renewables. The contribution of CCS from 2030 is important with percentage values of electricity production around 22–28% in 2050. The cost of electricity (COE) increases up to 25% in 2030, and then this value remains approximately constant or decreases slightly.     

CO2-emissions reduction potential and costs of a decentralized energy system for providing electricity,cooling and heating in an office-building in Tokyo

Decentralized energy systems are thought to have great potential for supplying electricity, cooling, and heating to buildings. A decentralized system combining a solid oxide fuel cell (SOFC) with an absorption chiller-heater (ACH) is proposed. The CO₂-emissions and costs of using different configurations of this SOFC-based system to provide an office building in Tokyo with electricity, cooling and heating are calculated by using an SOFC-model and an absorption-chiller model together with data for cooling and heating loads measured at an office building in downtown Tokyo. The results are compared with the CO₂-emissions and costs of a conventional system that obtains the base electricity requirements as well as electricity for an electric chiller–heater system from the central power grid. The fully decentralized SOFC-based energy system could result in a potential CO₂ reduction of over 30% at an estimated cost increase of about 70% compared to the conventional system.     

Spanish energy roadmap to 2020: Socioeconomic implications of renewable targets

The European Union has established challenging targets for the share of renewable energies to be achieved by 2020; for Spain, 20% of the final energy consumption must be from renewable sources at such time. The aim of this paper is the analysis of the consequences for the electricity sector (in terms of excess cost of electricity, investment requirements, land occupation, CO₂ emissions and overcapacity of conventional power) of several possibilities to comply with the desired targets. Scenarios are created from different hypotheses for energy demand, biofuel share in final energy in transport, contribution of renewables for heating and cooling, renewable electricity generation (generation mix, deployment rate, learning curves, land availability) and conventional power generation (lifetime of current installations, committed deployment, fossil fuel costs and CO₂ emissions cost). A key input in the estimations presented is the technical potential and the cost of electricity from renewable sources, which have been estimated in previous, detailed studies by the present authors using a methodology based on a GIS (Geographical Information System) and high resolution meteorological data. Depending on the scenario, the attainment of the targets will lead to an increase in the cost of electricity from 19% to 37% with respect to 2007.     

Power and cogeneration technology environomic performance typification in the context of CO2 abatement part I: Power generation

In this series of two articles, the concepts and approaches of environomic (thermodynamic, economic and environmental) performance ‘Typification’ of power generation technologies (Part I) and of combined heat and power (CHP) cogeneration technologies (Part II) in the context of CO₂ abatement are introduced. A methodology is then proposed for a flexible and fast project based power or CHP cogeneration system design evaluation though post-optimization integration of the operating and capital costs. This allows to effectively deal with the uncertainty of the project specific design and operation conditions (fuel, electricity and heat selling prices, project financial conditions such as investment amortization periods, annual operating hours, etc). Furthermore, the uncertainties linked to the external cost such as the CO₂ tax level under a tax scheme or the CO₂ permit price in the emission trading market can be assessed.     

Conversion of individual natural gas to district heating: Geographical studies of supply costs and consequences for the Danish energy system

Replacing individual natural gas heating with district heating based to increasing shares of renewable energy sources may further reduce CO₂-emissions in the Danish Building mass, while increasing flexibility of the energy system to accommodate significantly larger amounts of variable renewable energy production. The present paper describes a geographical study of the potential to expand district heating into areas supplied with natural gas. The study uses a highly detailed spatial database of the built environment, its current and potential future energy demand, its supply technologies and its location relative to energy infrastructure. First, using a spatially explicit economic model, the study calculates the potentials and costs of connection to expanded district heating networks by supply technology. Then a comprehensive energy systems analysis is carried out to model how the new district heat can be supplied from an energy system with higher shares of renewable energy. It can be concluded on the basis of these analyses that the methods used proved highly useful to address issues of geographically dependent energy supply; however the spatio-economic model still is rather crude. The analyses suggest to expand district heating from present 46% to somewhere in between 50% and 70%. The most attractive potential is located around towns and cities. The study also suggests that CO₂-emissions, fuel consumption and socio-economic costs can be reduced by expanding district heating, while at the same time investing in energy savings in the building mass as well as increased district heating network efficiency.     

Micro-cogeneration based on solid oxide fuel cells: Market opportunities in the agriculture/livestock sector

Bio-waste embeds an extraordinary renewable potential, and it becomes a source of energy savings when transformed into a valuable resource, like biogas. Cogeneration (CHP) from biogas employing high-temperature Solid Oxide Fuel Cells (SOFCs) scores a high sustainability level, thanks to improved environmental and energy performances. The synergy between the niche market of small/micro biogas producers and SOFCs might act as a springboard to open market opportunities for both SOFC commercialization and business upgrade of small farms. However, local regulations, waste management, renewable energy subsidies and, above all, availability of eligible sites, determine real chances for on-the-ground implementation.Through a detailed analysis of the application scenario, this research aims at investigating opportunities for the experimentation of SOFC–CHP in small biogas plants and identifying the possible bottlenecks for future deployment. When it becomes relevant, energy conversion of livestock (especially cattle and swine) and agriculture waste requires SOFC modules from 10 kW_e to 35 kW_e. This is in line with the current status of SOFC suppliers. Moreover, considering the fuel cell market roll-out, the average levelized cost of electricity is expected to decrease from 0.387 €/kWh to 0.115 €/kWh, when electricity is produced from livestock waste available on-site.     

Impact of the Kyoto Protocol on the Iberian Electricity Market: A scenario analysis

This paper presents an assessment of the impact of the Kyoto Protocol on the Iberian Electricity Market during two periods: the first phase (2005–2007) and the second phase (2008–2012). A market-equilibrium model is used in order to analyze different conditions faced by generation companies. Scenarios involving CO₂-emission prices, hydro conditions, demand, fuel prices and renewable generation are considered. This valuation will show the significance of CO₂-emission prices as regards Spanish and Portuguese electricity prices, generation mix, utilities profits and the total CO₂ emissions. Furthermore, the results will illustrate how energy policies implemented by regulators are critical for Spain and Portugal in order to mitigate the negative impact of the Kyoto Protocol. In conclusion, the Iberian electricity system will not be able to reach the Kyoto targets, except in very favorable conditions (CO₂-emission prices over €15/ton and the implementation of very efficient energy policies).     

Examination of energy price policies in Iran for optimal configuration of CHP and CCHP systems based on particle swarm optimization algorithm

The current subsidized energy prices in Iran are proposed to be gradually eliminated over the next few years. The objective of this study is to examine the effects of current and future energy price policies on optimal configuration of combined heat and power (CHP) and combined cooling, heating, and power (CCHP) systems in Iran, under the conditions of selling and not-selling electricity to utility. The particle swarm optimization algorithm is used for minimizing the cost function for owning and operating various CHP and CCHP systems in an industrial dairy unit. The results show that with the estimated future unsubsidized utility prices, CHP and CCHP systems operating with reciprocating engine prime mover have total costs of 5.6 and $2.9×10⁶ over useful life of 20 years, respectively, while both systems have the same capital recovery periods of 1.3 years. However, for the same prime mover and with current subsidized prices, CHP and CCHP systems require 4.9 and 5.2 years for capital recovery, respectively. It is concluded that the current energy price policies hinder the promotion of installing CHP and CCHP systems and, the policy of selling electricity to utility as well as eliminating subsidies are prerequisites to successful widespread utilization of such systems.     

Techno-economic evaluation of medium scale power to hydrogen to combined heat and power generation systems

The European Hydrogen Strategy and the new « Fit for 55 » package indicate the urgent need for the alignment of policy with the European Green Deal and European Union (EU) climate law for the decarbonization of the energy system and the use of hydrogen towards 2030 and 2050. The increasing carbon prices in EU Emission Trading System (ETS) as well as the lack of dispatchable thermal power generation as part of the Coal exit are expected to enhance the role of Combined Heat and Power (CHP) in the future energy system. In the present work, the use of renewable hydrogen for the decarbonization of CHP plants is investigated for various fossil fuel substitution ratios and the impact of the overall efficiency, the reduction of direct emissions and the carbon footprint of heat and power generation are reported. The analysis provides insights on efficient and decarbonized cogeneration linking the power with the heat sector via renewable hydrogen production and use. The levelized cost of hydrogen production as well as the levelized cost of electricity in the power to hydrogen to combined heat and power system are analyzed for various natural gas substitution scenarios as well as current and future projections of EU ETS carbon prices.     

Biomass assessment and small scale biomass fired electricity generation in the Green Triangle, Australia

Coal fired electricity is a major factor in Australia’s greenhouse gas emissions (GHG) emissions. The country has adopted a mandatory renewable energy target (MRET) to ensure that 20% of electricity comes from renewable sources by 2020. In order to support the MRET, a market scheme of tradable Renewable Energy Certificates (RECs) has been implemented since 2001. Generators using biomass from eligible sources are able to contribute to GHG emission reduction through the substitution of coal for electricity production and are eligible to create and trade RECs. This paper quantifies the potential biomass resources available for energy generation from forestry and agriculture in the Green Triangle, one of the most promising Australian Regions for biomass production. We analyse the cost of electricity generation using direct firing of biomass, and estimate the required REC prices to make it competitive with coal fired electricity generation. Major findings suggest that more than 2.6 million tonnes of biomass are produced every year within 200 km of the regional hub of Mount Gambier and biomass fired electricity is viable using feedstock with a plant gate cost of 46 Australian Dollars (AUD) per tonne under the current REC price of 34 AUD per MWh. These findings are then discussed in the context of regional energy security and existing targets and incentives for renewable energies.