22nd World Gas Conference June 1-5, 2003 Tokyo, Japan
Report of Working Committee 7
“ Industrial Utilisation & Power Generation ”
Rapport du Comité de travail 7
“ Utilisations des gaz industrielle et production d'electricite”
Chairman/Président
Dr Robert Harris
United Kingdom
1 ABSTRACT
This report provides a formal record of the work undertaken by IGU Working Committee 7 focussing on key issues relating to industrial gas utilisation and power generation during the triennium 2000-2003. Details are also provided on membership of the committee during this period and separate reports are included on the results and conclusions generated from the work specifically carried out by three study groups focussing on:-
• Opportunities for gas in distributed power generation.
• New developments to improve the competitiveness of industrial gas applications.
• Future business opportunities for the Gas Industry in a Hydrogen economy.
RESUME
Ce rapport constitue la synthèse du travail effectué par le comité 7 de l’UIIG. Il présente les problématiques essentielles des utilisations industrielles du gaz naturel dont, en particulier, la production d’électricité, pour la période 2000-2003. Il fournit aussi des informations sur la participation des membres au comité durant cette période. Les résultats et conclusions des travaux sur les sujets spécifiques menés par les trois groupes d’études font l’objet de rapports séparés :
• Opportunités pour le gaz naturel en production d’électricité répartie n
• Nouveaux développements pour l’amélioration de la compétitivité des utilisations industrielles du gaz.
• Opportunités futures pour l’industrie du gaz dans une économie de l’hydrogène
2 TABLE OF CONTENTS
1. Introduction
2. General conclusions and recommendations
3. Acknowledgements
4. Report of Study Group 7.1 – Opportunities for gas in distributed Power Generation
5. Report of Study Group 7.2 – New development to improve the competitiveness of industrial gas applications
6. Report of Study Group 7.4 – Future business opportunities for the Gas Industry in a Hydrogen Economy
Appendix 1. Membership of Working Committee 7
Appendix 2. Committee Meetings
3 1. INTRODUCTION
This report provides the formal record of the significant studies undertaken by WOC 7 during the triennium 2000 – 2003 specifically related to Industrial Gas Utilisation and Power Generation.
In many countries of the world industry is the largest gas-using sector and offers important potential for future growth in gas consumption. However, whilst gas offers many advantages over other forms of energy and is a key fuel for almost every aspect of industrial production, the industrial gas market faces many challenges. Deregulation of both gas and electricity markets throughout the world is promoting increased competition and industry restructuring supported by the accelerating developments in information technology is changing the way customers purchase, use and monitor energy. In addition, increasing focus on environmental issues is promoting requirements to improve energy efficiency and reduce emissions.
Demand for electricity continues to grow significantly throughout the world and as a result of increasing availability of gas supplies and combined cycle gas turbine technology developments, natural gas has been taking an increasing share of the centralised power generation market. Decentralised, or distributed power generation, however, offers advantages in higher energy efficiency, reduced emissions and integrated energy services. Adding technology to provide a cooling option, to co-generation can also be attractive. However, despite the advantages offered by co- generation, market barriers exist which need to be carefully evaluated and addressed if the full potential for gas in this market can be realised.
Opportunities also exist to promote the use of gas as a feedstock for conversion into other products including hydrogen, necessary for example in many types of fuel cells. Looking to the future, consideration is needed of the issues and opportunities for the gas industry in the possible development of a hydrogen based economy.
In preparing its report for the 22nd World Gas Conference, Committee 7 has directed, reviewed and co-ordinated the work of three Study Groups.
Study Group 7.1 has reviewed the continuing opportunities for gas in distributed power generation identifying and providing access to key information on both the current barriers and incentives relating for example to fuel price, regulations such as interconnection issues and technology developments.
Study Group 7.2 has concentrated on assessing new and emerging technology developments in combustion and process control techniques for the use of gas in industry, in order to share knowledge and information which in turn can help improve the competitive position of gas in different countries. The results should also allow individual gas companies and suppliers of gas equipment to target further R&D or marketing activities towards industries and applications which offer potential for growth.
Study Group 7.4 has surveyed the current gas industry’s role in hydrogen, considered the future of hydrogen in the energy business and identified short, medium and longer term opportunities for the Gas Industry in a future hydrogen economy. The report, which builds on earlier studies within IGU provides the industry with an informed basis for business decisions.
The committee also began its work with an intention to complete a further study (SG 7.3) relating to the impact of information technology in creating new opportunities in the sale, purchase and use of gas in industrial applications. This work was subsequently combined with an equivalent project in WOC6 (Domestic Gas Utilisation). However owing to organisational difficulties compounded to some extent by the tragic events of September 11th responsibility for the topic was subsequently transferred to IGU TFA. The latter planned and organised a very successful conference on Information and Communication Technology in the gas industry in Prague, Spring 2002.
During the course of the current triennium two special reports have also been prepared within the remit of WOC7 on behalf of IGU and published and presented at major international conferences
4 by the WOC7 Chairman Dr Bob Harris (references 1 and 2 below), helping to promote the status and influence of IGU in the developing energy market. Finally, the committee was also responsible for the development of the WOC7 programme at WGC 2003. This programme includes presentations on all three study group reports included in this document supported by Round Table discussion sessions focussing on distributed power generation and the role of gas in the future hydrogen economy. WOC7 was also very encouraged to receive many offers of papers to be selected for inclusion in technology forum sessions to be held at WGC 2003 and subsequently selected some 34 papers to be presented in interactive poster sessions.
• The Potential for Natural Gas to contribute to a Hydrogen Energy Future, Harris R.J., Saint-Just. J., Asaoka Y., Thatcher D.R.P., World Energy Conference, Buenos Aires, November 2001
• Safety Aspects of Natural Gas Utilisation in Power Generation and Industry, Harris R.J., and Sheperd K.D., China Gas 2001, Chonqing, November 2001
5 2. GENERAL CONCLUSIONS AND RECOMMENDATIONS
The results and conclusions from each study group in WOC 7 are presented in separate succeeding sections of this report. However, key points arising out of the Study Group (SG) work, together with some general recommendations for IGU to consider in future, are drawn together here.
First it is clear that whilst substantial interest in gas fired distributed power generation (DPG) remains and significant technology improvements continue, the market opportunity is very sensitive to the price of both gas and electricity. During the period of this study, gas prices – usually linked to the price of oil – have risen, whilst electricity prices – influenced in many countries by market liberalisation and deregulation – have fallen, rendering the economics of gas fired DPG much less attractive. Without other incentives, for example promoting reduced CO2, the fully potential for gas fired DPG will not be realised.
Since the last World Gas Conference in 2000, no major breakthroughs have been reported in industrial gas applications. However, a number if improved technology developments have been made, as described by SG7.2 in their report and they have also shown that even in a mature market, there are still possibilities to find new applications for gas. SG7.2 have also drawn attention to a reduced concern/demand for new developments as one consequence of market liberalisation. This means that trading companies and transport companies become less willing to spend on technology developments, particularly where as a result of competition it may be more difficult to receive a sufficient return on the investment concerned. Co-operation between equipment suppliers and gas companies is still important but new mechanisms to encourage wider support for research, development and demonstration will have to be found.
Finally, it is important to note that the comprehensive report prepared by SG 7.4 is not intended as a plea for hydrogen economy has begun and even if somewhat controversial and not of immediate market relevance, it cannot and should not be ignored. The report aims to help a well informed gas industry make the right decisions about the level of its future involvement and identifies potential business opportunities in the short, medium and longer term. It is worth noting that following the tragic events of September 11, ensuring security of supply has become an important argument for the proponents of a hydrogen future, which now include the US and European Union governments.
It is recommended that IGU perpetuate the existence of a dedicated group on hydrogen. Along with electricity, hydrogen will be a major carrier of energy in the future. It will be a threat if the gas industry ignores it but could provide a wealth of opportunities if the gas industry is involved in its development. The group should ideally be given the status of a Programme Committee of Task Force, cutting across the different technical committee areas and should maintain an objective to keep the gas industry informed of the threats and opportunities created by hydrogen, whilst establishing closer links with those companies and organisations, including government organisations, supporting and investing in hydrogen related studies.
More generally, the value of IGU membership linked to opportunities for international networking and information exchange need to be promoted. WOC 7 has found particular value in ensuring at each meeting time for members to report on developments and related issues in their countries and would recommend the new IGU co-ordinating committee to consider ways of ensuring that this valuable information can be accessed and share more widely as a benefit of IGU membership. WOC 7 would also support the intended concept of using WOC contacts for benchmarking relevant business processes on a confidential non-attributable basis.
6 3. ACKNOWLEDGEMENTS
The undertaking of the studies described and the preparation of this report would not have been possible without the dedication and support of many people. I would wish therefore to record my sincere thanks to all members of WOC 7 and the Study Groups but in particular to the Study Group Chairman, Dr Sam Bernstein (SG 7.1 – USA) Dr Klaas Beukema (SG 7.2 – Netherlands) and Dr Jacques Saint-Just (SG 7.4 – France) without whose unstinting efforts and expertise, none of the work would have been possible. I would also wish to record my sincere appreciation to the WOC 7 Vice- Chairman Jean-Pierre Roncato (France) for his support and wise-counsel and to the secretary of WOC 7 Colin Heap (UK) for organising our meetings and helping ensure they were always conducted in a supportive, informal but business focussed way. Last but not least my grateful thanks on behalf of IGU to all those WOC 7 members, their companies and/or national member organisations, who respectively arranged and provided financial support for the meetings held by WOC 7 and its Study Groups. Their warm hospitality, support and commitment to IGU has been greatly appreciated.
Dr. R. J. Harris 31 January 2003
7 4. REPORT OF STUDY GROUP 7.1
“Opportunities for Gas in Distributed Power Generation”
Rapport du Groupe d’étude 7.1
“ Opportunités pour le gas natural en production d’ electricité”
Chairman/Président
Sam Bernstein
United States of America
8 TABLE OF CONTENTS
1. Introduction
2. Definition and General Information
3. Liberalisation of Gas and Electricity Markets
3.1 Asia
3.2 Europe
3.3 North America
4. Member Country Perspectives
4.1 Belgium
4.2 Chech Republic
4.3 Denmark
4.4 Finland
4.5 France
4.6 Germany
4.7 Italy
4.8 Japan
4.9 The Netherlands
4.10 Norway
4.11 Spain
4.12 Sweden
4.13 United Kingdam
4.14 United States
5. Barriers
6. Incentives
7. Reference Material
8. Acknowledgements
9 1. INTRODUCTION
The focus of this paper is to assess the worldwide perspective of distributed generation (DG) and combined heat and power (CHP). Some of the following questions will be addressed: • What is the status of deregulation and liberalization? • What impact has deregulation and liberalization of the gas and electric markets had on DG and CHP? • What are the barriers to implementing DG and CHP? • What incentives are promoting DG and CHP?
2. DEFINITION AND GENERAL INFORMATION
Distributed generation (DG) systems are parallel and stand-alone electric generation units located within the electric distribution system at or near the end user. DG systems range in size and capacity from a few kilowatts up to 10 MW. They comprise a portfolio of technologies, both supply- side and demand-side, that can be located at or near the location where the energy is used. Many of these technologies are commercially available or under development. Distributed power generation systems include microturbines, combustion turbines, internal combustion (IC) engines, Stirling engines, fuel cells, photovoltaic (PV) systems, and wind turbines.
DG technologies are playing an increasingly important role in the world-wide energy portfolio. They can be used to meet baseload power, peaking power, backup power, remote power, power quality, as well as cooling and heating needs.
Combined heat and power (CHP) systems produce electricity at or near a thermal load, utilizing waste heat produced by the DG equipment. In applications where thermal energy (i.e., heat) is required, the total efficiency of separate heat and power systems may total only 45 percent. However, there is a tremendous efficiency opportunity to combine electricity generation with thermal loads in buildings and factories, converting as much as 85 percent of the fuel into usable energy (Figure 1). CHP systems can provide electricity, hot water, heat for industrial processes, space heating and cooling, refrigeration, and humidity control to improve indoor air quality and comfort.
10
Figure 1. Combined Heat and Power versus Conventional Power Generation
DG technologies are typically installed for one or more of the following purposes: • Overall load reduction — using energy efficiency and other energy-saving measures to reduce total consumption of electricity, sometimes with supplemental power generation (see below). • Energy independence — using on-site power generation to meet all energy needs, usually to ensure power reliability and/or power quality, in one of two configurations: • Grid-connected — using grid power as a backup electricity source during failure or maintenance of the on-site generator. • Off-grid — stand-alone power generation for the purpose of self-sufficiency, usually including energy-saving approaches and an energy storage device for backup power. This includes most village power applications in developing countries. • Supplemental power — augmenting grid electricity with distributed generation for one of two reasons: • Standby power — using a generator as a backup electricity source to ensure power availability during grid outages. • Peak shaving — reducing demands for grid electricity during peak periods, usually to avoid the higher rates ("peak demand charges") imposed on big electricity users at these times. • Net energy sales — homeowners and entrepreneurs generating more electricity than they need and selling the surplus to the grid. • Combined heat and power — capturing waste heat from a power generator and using it in manufacturing processes, for space heating, or for water heating, thereby significantly improving the efficiency of fuel utilization. • Grid support — installed by power companies for a wide variety of reasons, including meeting higher peak loads without having to invest in infrastructure (line and substation) upgrades.
11 High capital costs are presently the norm for many DG technologies and serve as a deterrent to their widespread implementation. However, as production levels and sales increase, it is expected that economies of scale will result in decreased equipment costs. Table 1 illustrates the variation in initial equipment costs and those costs associated with the operation and maintenance (O&M) of the DG system.
Table 1. Capital Cost of Selected DG Equipment
DG Technology Capital Cost ($/kW) O&M Costs (¢/kWh)
Microturbine 700-1,100 0.5 - 1.6 (estimated)
Combustion Turbine 300-1,000 0.4 – 0.5
IC Engine 300-800 0.7 – 1.5 (natural gas) 0.5 – 1.0 (diesel)
Stirling Engine 2,000-50,000 ---
Fuel Cell 3,500-10,000 0.5 – 1.0 (estimated)
Photovoltaic 4,500-6,000 1% of initial investment per year
Wind Turbine 800-3,500 1.5% – 2% of initial investment per year
A 1999 U.S. Department of Energy report, Distributed Utility Perspectives, examined 275 distributed energy resource (DER) projects in the United States, managed by 121 different companies, to find out why the distributed resource was being used (see Figure 2). The report found the top three applications of DG, in order of importance, are: • Electricity supply • Deferral of transmission and/or distribution system upgrades • Power quality and reliability
12
Figure 2. Applications of Distributed Generation Installations (total of 407 occurrences for 275 projects) Source: Distributed Utility Associates
Many stakeholders are expected to benefit from DG and CHP system implementation. These stakeholders include the following:
• Developers and manufacturers of DG and CHP systems and components
• Support service providers (e.g., fuel and equipment maintenance providers)
• Homeowners
• Business owners (including commercial facility managers)
• Industrial facilities
• Construction community (e.g., A&E firms, homebuilders, urban developers, etc.)
• Utilities
• Regulators (e.g., state public utility commissions)
• Policy makers (e.g., senators, state reps, federal agencies)
• Bodies that develop codes and standards
• Fire and building code officials
• Permitting agencies (e.g., environmental, land, etc.)
13 • Investment community (e.g., venture capitalists, investment banks, stockbrokers, etc.)
Two of the largest stakeholder groups include power consumers and power providers. Each of these groups can realize significant benefits from the use of DG and CHP. Primary benefits of DG and CHP to the electric consumer may include: • Better power reliability and quality • Lower energy costs • More choice in energy supply options • Greater predictability of energy costs (lower financial risk) with renewable energy systems • Energy and load management • Combined heat and power capabilities • Environmental benefits — including cleaner, quieter operation, and reduced emissions • Faster response to new power demands — as capacity additions can be made more quickly
Benefits of DG and CHP to power providers include: • Reduced energy losses in transmission lines • Reduced upstream congestion on transmission lines • Reduced or deferred infrastructure (line and substation) upgrades • Optimal utilization of existing grid assets — including potential to free up transmission assets for increased wheeling capacity • Less capital tied up in unproductive assets — as the modular nature of distributed generators means capacity additions and reductions can be made in small increments, closely matched with demand, instead of constructing central power plants sized to meet estimated future (rather than current) demand • Improved grid reliability • Higher energy conversion efficiencies than central generation • Faster permitting than transmission line upgrades • Ancillary benefits — including voltage support and stability, contingency reserves, and black start capability
14 3. LIBERALIZATION OF GAS AND ELECTRICITY MARKETS
3.1 Asia
Many Asian countries have permitted private foreign participation in areas such coal mining, production and exploration of oil and natural gas fields, and production of electric power. At a domestic level, Korea has deregulated its oil refining industry and conceived a comprehensive energy reform strategy, with a progressive and committed electricity deregulation program. China too has begun to take steps towards opening up the power generation sector. Since March 2000, electric power supply to customers who have a contract over 2,000 kW has been liberalized in Japan, with the liberalization of the power generation market to be expanded in the future. Nonetheless, more work remains to further deregulation as well as regional and multilateral integration of energy markets. Distribution and transmission remains largely state controlled in these economies, and there is no commitment as yet from these economies on opening up this service sector to multilateral trade liberalization.
The political and economic systems of the ten Association of Southeast Asian Nations (ASEAN) member countries are varied (Figure 3). But, all are heading towards adopting the consumer-market-based economic model for power. As a consequence of this shift from mainly centrally planned government dominated power systems national power utilities are being unbundled, privatized, and deregulated.
The Heads of ASEAN Power Utilities/Authorities have adopted a roadmap towards regional power interconnection and promotion of electricity trade. The master plan study to establish the ASEAN Power Grid is expected to be completed in March 2003.
Vertically Wholesale Full Customer Unbundled Integrated Competition Choice
Indonesia 2007 Brunei Malaysia ? ? Cambodia Philippines 2004
Singapore Lao PDR 2002 Thailand 2003 Myanmar Vietnam 2010
Source: “Overview of the Privatization and Deregulation Initiatives in the ASEAN Power Sector” presented by Guillermo R. Balce, DSc. at Metering Asia-Pacific 2002 – Singapore, 9-11 April 2002.
Figure 3. ASEAN Member Deregulation Plans
15 3.2 Europe
According to the EU’s second benchmarking report detailing the implementation of the internal electricity and gas markets, liberalization is progressing. In electricity, there has been a general increase in the level of market opening. There also has been progress in the degree of unbundling, and greater clarity and transparency in regulation. Progress in the gas market is limited and more uneven. Key problems remain in both segments1.
Electricity Market Problems
• Differential rates of market opening continue to reduce the benefits of competition to customers and promote distortion of competition between energy companies. • Disparities in access tariff due to the lack of transparency caused by insufficient unbundling and inefficient regulation. • Impeding new entrants due to the high level of market power among existing generating companies associated with lack of liquidity in wholesale and balancing markets. • Insufficient interconnection infrastructure between member states and, where congestion exists, unsatisfactory methods for allocating scarce resources.
Gas Market Problems
• Unequal levels of market opening. • Inappropriate tariff structures and large and unexplained disparities in network access tariff between countries and regions for transportation and distribution transactions, which form a barrier to competition and provide revenue for cross-subsidies. • Lack of transparency regarding the availability of infrastructure capacity, both internally and cross-border, as well as capacity-reservation procedures which do not allow third parties the flexibility to change their gas sources or customer base without incurring increased costs. • Concentration of gas production and importation in a few countries and slow development of trading hubs, which often means that new entrants find it very difficult to buy wholesale gas on reasonable terms. • Balancing regimes that are unnecessarily stringent, being non-market based and not reflective of the costs incurred.
1 Energy Markets, Benchmarking Study Shows Progress in Liberalization, December 2002.
16
Figure 4. Status of Liberalization in Europe (Source: European Commission and The Energy Efficiency Center, Prague)
With the liberalization of the electricity market (Figure 4), more market-based methods are being demanded over direct support systems. After a certification system that is growing in interest for renewable energy system (RES) plants, it is now the turn for CHP plants to establish possible CHP- certificates or at least certification of the CHP electricity coming from such plants. Even with existing support schemes there may be a value in linking support to certification of the electricity production.
Some certification systems for CHP plants have already been introduced, like the CHP-QA (Quality Assurance) system in the UK from April 1, 2001. So far, real trading with the certificates has not yet taken place, but the British and Dutch systems provide some tax breaks. In Italy exemption from the obligation on fossil producers of electricity to meet a quota of renewable electricity, and priority dispatching after renewable energy are given. Combinations with more traditional support schemes and certificates might develop in some countries.
The main method for supporting CHP, used in the majority of cases, is linked to the production of electricity: dispatch priority and/or fixed price or a price premium on produced kWh. Under such national schemes, the grid company is obliged to offer the fixed price for CHP electricity (in France, the difference between the fixed price and the avoided cost will be returned to EdF from a special fund, paid by all generators). The price premium on generated kWh is paid from central sources.
Today many European countries provide support for CHP, either for installation of CHP plants and/or for the operation of the plants. The support given varies from country to country. Some supports are given for a certain portion of the investment cost and are common as well as different forms of tax breaks. Even in some countries there is a feed-in system that guarantees the purchase of the produced electricity at a price higher than the market value. Table 2 summarizes various forms of CHP support incentives for selected countries.
17 Table 2. Support Schemes for CHP Plants in Selected European Countries
Type of support Country Investment Fuel Production Other Belgium Special fiscal status Lower price for certified CHP Denmark Subsidies for small Price premium per and industrial CHP; kWh, depending on natural gas, RES, type and fuel. biogas, straw, wood, Dispatch priority for waste selected small CHP plants. France Fixed price for certified CHP Netherlands Exemption from Price premium per Low tax scheme energy tax for quality kWh for CHP; CHP exemption from energy tax for heat Italy Dispatch priority (after RES) for quality CHP; eligible gas customer Spain Dispatch priority for quality CHP; price premium per kWh Sweden Investment support Price premium per of max 25% of the kWh for plants investment cost for < 1,5 MW biomass-fired CHP plants UK Enhanced Capital Exemption from Tax breaks Allowance Climate Change Levy for quality CHP. Source: Eurelectric
A draft Directive on CHP was published in July 2002. The EU Commission confirmed a goal to double CHP electricity production from 9% to 18% of the total EU electricity production by 2010. The Directive is roughly modeled after the Renewable Directive; allowing member states to choose their implementation strategy and support mechanisms.
The draft Directive will oblige member states to: a) Guarantee that electricity from cogeneration will be transmitted and distributed on the basis of objective, transparent and non-discriminatory criteria b) Publish the following: • Analysis of the national potential for high efficiency cogeneration • Analysis of the barriers to high efficiency cogeneration • Report on progress towards increasing the share of high efficiency cogeneration, including the measures taken to promote it c) Facilitate access to the grid for electricity produced from cogeneration units using renewable energy sources and from units with a capacity less than 1 MW(e) d) Introduce basic cogeneration definitions. Member states will have to amend national legislation to comply with the basic definitions within the Directive for:
18 • “electricity from cogeneration”: Member states will eliminate the current ambiguity resulting from the different definitions of cogeneration • “high-efficiency cogeneration”: Member states will determinate high efficiency cogeneration in terms of energy savings in comparison with separate production. Only cogeneration production providing energy savings of at least 10% will qualify as high-efficiency cogeneration e) Introduce guarantee of origins. Member states will have to ensure that guarantee of origin of electricity from cogeneration can be issued on request by one or more competent body.
The vision of the draft is also that a market-based system with trading of CHP certificates could be established in a similar way as certificate trading systems for renewables energy sources has been introduced in some countries of the EU.
3.3 North America
The status of electric deregulation in the United States is illustrated in Figure 5. Twenty-four states and the District of Columbia have either enacted enabling legislation or issued a regulatory order to implement retail access. The local distribution company continues to provide transmission and distribution (delivery of energy) services. Retail access allows customers to choose their own supplier of generation energy services, but each state's retail access schedule varies according to the legislative mandates or regulatory orders.
In Canada, Alberta and Ontario are fully deregulated while British Columbia and New Brunswick have both introduced bills to the legislature. The remaining areas of Canada have seen minimal activity toward deregulation.
Figure 5. Status of Deregulation in the United States as of February 2003 (Source: U.S. Department of Energy)
19 In the United States, deregulation has caused instability in the power market. Deregulation problems experienced in California has significantly slowed deregulation nationwide. The distributed generation market in the U.S. decreased significantly in 2002 in comparison with the previous year. Reasons for the decreased market potential for DG in the U.S. include: • Poor economy and decreased capital spending • California blackouts did not expand nationwide, decreasing the urgency to invest in distributed generation • Electricity prices stabilized
The primary market segments continuing to utilize DG are industrial sites with heat-recovery potential.
4. MEMBER COUNTRY PERSPECTIVES
Member countries are at varying stages of market deregulation. This process has had significant effects on distributed generation in many of the countries, ranging from countries creating incentive programs promoting DG to countries lacking a gas infrastructure, eliminating the potential of gas-fired DG adoption.
4.1 Belgium
Belgium has opted for a gradual opening of its natural gas market (Law of April 1999): 66 percent in 2006 and 100 percent in 2010. It is currently transposing the European Directive into Belgian law at the federal level. The situation is complicated by a second (different) set of laws for each of the 3 regions of Belgium. Belgium has not yet appointed regulators to coordinate this effort. The transmission and distribution system chosen, in principle, is that of regulated TPA. Access may only be refused on the grounds of lack of capacity or breach of technical regulations.
There are currently reduced tax rates for wind generators, renewables quotas and penalties if the targets are not reached, and price guarantees. But tough application and approval procedures to connect to the network act as a barrier and many operators are currently waiting for approval of their wind power installations. But the main barrier is and will remain the lack of harmonization between the three Belgian regions' legislative bodies, deterring investors.
4.2 Czech Republic
The Czech Republic is currently a candidate to become a member of the European Union. The Czech Republic legislation is currently in the early stages of being conformed to the EU legislation.
4.3 Denmark
20 Denmark played a waiting game in power sector liberalization, watching the evolution of Nordpool and contemplating how to make a smooth transition from a planned to a liberalized market without compromising the future of its district heating/cogeneration and renewables market. The resulting 1999 Electricity Supply Act comes into force gradually with full implementation in 2003.
Involvement with Nordpool offers intermittent generators in Denmark (and the other member regions) several sizeable advantages over those operating within national boundaries: expanded electricity demand, a load profile with many different peaks and troughs and relative price stability.
DG capacity was largely established during the 1990-1998 period and is today estimated at 28 percent of total production capacity. However, there is not much economic potential left for building new plants. The expansion of local CHP is expected to continue at a decreasing rate although increase in onshore and offshore wind turbines is expected to continue at an unchanged rate until the year 2005. CHP is primarily located at residential and industrial facilities.
The national target is for renewables to account for 12-14 percent of energy consumption by 2005. The government has given the highest priority to maintaining present levels of cogeneration plus further development. Eighty percent of the country's energy research program is devoted to energy saving and renewable energy sources.
4.4 Finland
Finland, like Norway and Sweden, has deregulated its electricity market ahead of the EU schedule. The country is advancing rapidly toward full liberalization, the most important development in this respect being the Electricity Market Act of 1995 that extended competition to all customers in January of 1997.
DG capacity is estimated to be around 10 percent of the total installed capacity, mainly in the form of hydropower. The government supports DG by granting a tax refund for producers of wind power (0.69 eurocents/kWh) and biomass and micro-hydro of up to 1 MW (0.42 eurocents/kWh). Investments subsidies of up to 40 percent of the cost are also available.
Some areas of Finland do not have a gas distribution network and this is a major barrier for gas-fired DG technologies.
4.5 France
The EU directive was implemented in France in February 2000 through the "Loi Electricité". One of the main components is the purchasing obligation for electricity produced by cogeneration installations of up to 12 MW.
France's current DG installed base is estimated to be around 5 percent of the total installed generating capacity. This includes CHP, wind power, and small hydropower. At the moment, there is no real political incentive to support DG. Designing effective DG regulations will be difficult given the current dependence on nuclear power generation and the concurrent weakness in competing fuels. The French government is focused on increasing the share of renewable energy sources.
There is not a specific regulation for small cogeneration systems, however, the law recently expanded the definition of cogeneration; there is no longer a lower limit therefore any installation
21 between 0 and 12 MW (provided it meets certain efficiency targets) is defined as cogeneration. Feed- in tariffs are currently under discussion.
Concerning the access to the grid, indications are that France will adopt a solution halfway between regulated and negotiated TPA with a regulated base, which does not exclude negotiations. There are no real interconnection standards, currently.
Although some testing has been performed with fuel cells and micro-gas turbines, one of the main problems with DG is the French gas network norm; it is not really compatible with the gas-fired DG technology requirements (The French norm is 20 millibar). France is more likely, therefore, to focus on renewable energy sources in the near future.
4.6 Germany
Germany is the front-runner in terms of implementing the European electricity and gas directives. As of April 1998, it opened 100 percent of its electricity and gas markets to competition. The utility market is highly fragmented in Germany, with about 70 regional utilities and 900 municipal utilities, which together account for about 20 percent of power generation and about two-thirds of distribution.
Non-discriminatory access to the transmission and distribution system is required. In general network access has to be negotiated. There is an optional alternative implemented, applying the single buyer model in municipalities supplied solely by a utility across their whole area.
Despite the overall success of liberalization, third party access to transmission networks remains a contentious issue. The Verbändevereinbarung that determines access to the grid system was first agreed to in May 1998 and left transmission control mostly in the hands of the six major utilities. After much criticism, a new Verbändevereinbarung was revised in December 1999. This agreement has encountered even more criticism than its predecessor, and EU competition authorities have expressed concern. The most criticized aspects of the agreement include a lack of price transparency and the division of the German market into two distinct trading zones.
DG capacity is estimated to be around 10 percent of total installed capacity and annual growth rate is expected to be 10 percent for the next five years. The most important DG technologies are currently CHP and wind power. The government strongly supports renewables and CHP. Replacing the Electricity Feed Act, the Renewable Energy Sources Act (EEG, February 2000) regulates the prioritization of grid-supplied electricity from renewable sources. It specifies mechanisms for implementing the option of granting priority to renewable power generation envisaged in the EU Directive on the internal market in electricity.
Energy utilities will also now benefit from the compensation for supplying the grid with electricity from renewable sources. By guaranteeing compensatory payments, the act turns energy production with renewables into a very lucrative business. Moreover, there are generous grants and low-interest loans for solar energy, and CHP has recently received additional government.
4.7 Italy
22 In April 1998, the Italian Parliament issued the guidelines to be following by the government to transpose the EU directive into Italian law. In February 1999, the government issued the decree opening the electricity market to competition. The main regulations are as follows:
• Freedom to construct new generation facilities
• Progressive creation of a competitive electricity market
• Free and non-discriminatory access to the transmission grid at tariffs to be set by the regulator (although Enel will maintain ownership of the grid)
• Creation of an electricity pool (borsa dell'energia) in the near future.
The shape of the regulatory framework is not yet clear, though it will contain some policies favoring energy efficiency, renewables and energy security. For example, by 2002 electricity from renewable and indigenous sources and from CHP plants was to be given dispatch priority and generators are obliged to produce 2 percent of their electricity from renewable energy plants commissioned after 1997. A tradable green certificate scheme was launched linearly in 2002 to fulfill the obligation.
Regulations for purchasing excess electricity are under discussion. There is only a regulation providing that grid operator has to provide access for energy produced by renewable sources and some cogeneration plants. Micro-CHP is not considered as renewable unless fuelled by biogas. There is an open debate on the new Electrical Authority regulations. The new parameters and indexes to define a plant as a cogeneration plant were issued by Authority in 2002.
Small-scale gas fired systems could offer significant market potential if technologies such as fuel cells and microturbines become mainstream. There is no micro-CHP currently in use in Italy but gas supply companies are likely to investigate the market for gas-fired DG and accept some electricity market risk to secure sales volumes.
Currently the individual consumer pays a single tariff but in few years, there could be free access to the pool and thus different shades of prices, which would make micro-CHP very attractive to individual consumers.
The future for DG is uncertain in Italy but no dramatic change is expected over the next 4 to 5 years.
4.8 Japan
In Japan, ten privately owned electric power companies operate as independent suppliers, and they are responsible for providing local operations from power generation to distribution and supplying their respective service areas. Electricity was only supplied by electric utilities until a turning point in the 1970’s when the gas industry initiated a project to import natural gas, and promoted environmentally benign gas-fired power generation along with a strong requirement of reducing energy costs by industrial and commercial customers.
Customers were pursuing various measures designed to level the electricity load by reducing the growing seasonal and hourly demand gap. One such measure was CHP or on site generation with heat recovery system to take advantage of their large heat demand to economize the energy usage. The first CHP in Japan began operation in 1981, and the installation rate steadily increased. After a
23 guideline for grid-connection was established in 1986, the installation rate rapidly increased, especially from 1989 to 1991.
However, for the last decade, annual installed capacity of CHPs was almost saturated, at roughly 300MW to 400MW per year due to both the sluggish economy and the recent deregulation of electric industry, by which electric rate had been reduced to impact midsize DG systems.
As of March 2002, gas-fired CHP capacity in Japan has reached about 2,400MW with the total CHP capacity including diesel engines at about 6,500MW. This numerical value represents around two percent of total generation in Japan. To achieve the goals, some incentives were established such as one third of facility investment paid by subsidy. The target installation of gas-fired CHP systems and all CHP systems were amended to 4,550MW and 10,020MW, respectively.
Although in March 2000, power supply was partially liberalized to allow Power Producer Suppliers to sell to extra high-voltage users over 2MW of capacity. As a result, 30% of total demand had been opened to free market, however, less that 1% has been actually provided by new entrants.
With regard to the future market of DG, the shape of the regulatory framework is still not clear. However, since the DG market is economically driven, not only the regulatory framework but also electric rate will have significant impact on its market acceptance.
4.9 The Netherlands
The Dutch Electricity Act entered into force in August 1998. The Netherlands was among the pioneers of European electricity market deregulation. In the last years the amount of small- decentralized plants grew very fast as a consequence of state subsidies for CHP. In the Netherlands, environmental concerns and issues have been built into policy making for many years and, as a result, highly efficient cogeneration facilities are considered as the mainstay rather than an alternative to conventional power generation.
At the moment, DG capacity meets about 25 percent of the national demand for electricity. This share could grow further in the future. DG capacity is mainly CHP (about three quarters) followed by waste and renewables. There are special subsidies for CHP, as the government wants to increase its installed base by 50 percent over the next 10 years. Renewables benefit from energy tax exemption and other tax relief, designed to help achieve the country's target for renewables to account for 10 percent of Dutch energy demand by 2020.
4.10 Norway
Norway is well ahead of EU liberalization with full deregulation already underway. The control of the central grid is a natural monopoly. The publicly owned Statnett is now the power grid company responsible for the construction and operation of the central grid and for coordinating operations. Norway's transmission and distribution infrastructure consists of the central grid, the regional grids, and the distribution grids. The utility operating the regional grid to which a distribution grid with local production (DG) is connected, will stipulate a fixed output for the DG in question when forecasting the short- term electricity trade. Should the DG production deviate from the stipulated value, this difference must be balanced out in the regulatory market.
24 The total DG capacity in Norway is estimated to amount to 2 percent of the production capacity. This is mainly small hydropower and to a minor extent wind turbines. The stations can be utility or privately owned. In the short- and mid-term, DG is not expected to go beyond 2 percent of total production capacity. Hydropower will remain the main DG technology due to the lack of gas infrastructure to support gas-fired DG technologies.
4.11 Spain
The Electricity Directive was implemented into Spanish law through the Electricity Act of 1997, which came into effect on January 1, 1998. The act represents a fundamental reorganization of the Spanish electricity market, aiming for full liberalization ahead of the EU schedule; it accelerates the pace of liberalization by reducing the eligibility threshold.
Customers are free to set commercial agreements with any "agent" or to buy energy from the pool. The system for access to the transmission and distribution network is based on regulated TPA. Concerning gas markets, the hydrocarbon law approved in October 1998 initiated the process of liberalization in the Spanish gas market. The new law came into effect in April 1999 and full liberalization is planned for January 2008.
As of the end of 2001, there were 2,060 installed DG plants producing 10,900 MW of power. This is approximately 20 percent of Spain’s total installed capacity, mainly from the 800 CHP plants (5,600 MW), 200 wind stations (3,300 MW), and mini-hydropower plants (1,500 MW). DG provides 30 TWh/year to the electric grid, totaling 15 percent of the energy transported and distributed by the grid.
Legislation is favorable to wind power and there is a regulation for buying prices concerning energy produced by DG. Utilities are planning to get more involved with DG in Spain, in particular in the renewables field. Wind power and solar PV are currently favored among utility planners. Forecasts for 2010 predict 8,000 MW CHP and 13,000 MW of wind power will be installed.
4.12 Sweden
Sweden's reform of its electricity market came into effect in January 1996. The main characteristic of its free market is that the distribution networks are accessible to all and power transmission is managed separately from electricity generation and trade. By paying a grid fee, a customer can gain access to the national grid and is therefore able to choose its electricity supplier. Electricity generation is fully deregulated: anyone wishing to generate or trade electricity is free to do so (subject to standard legal and regulatory requirements).
DG capacity is estimated to be around 5 percent of total installed capacity.
4.13 United Kingdom
The main regulations influencing the DG market are:
• The Climate Change Levy (C.C.L) – This is a downstream tax on energy that started to apply in April 2001, charged to all final consumers, with the exception of the domestic
25 sector. Electricity and heat supplied from renewable energy sources are exempted from the CCL. The government has a manifest commitment to develop renewable sources of energy, which has translated into targets of 5 percent of UK electricity requirements met from renewables by the end of 2003 and 10 percent by 2010. The UK environmental policy is also driven by European legislation and by national greenhouse gas emission reduction commitments of 12 percent agreed as part of the EU's Kyoto commitment
• New Electricity Trading Arrangements (NETA) – The basic principle of NETA is that those wishing to buy and sell electricity should be able to enter into any freely negotiated contracts to do so. Markets participants will contract bilaterally over a range of periods from a few days to a year or more ahead of real-time delivery. NETA aims to treat all forms of generation equitably. But a power exchange approach in general rewards plants with a flexible and predictable output, as intermittent generators are likely to miss their contractual output more frequently and hence suffer financial penalties (imbalance charges). This brings additional risks for many types of decentralized generation especially wind and those reliant on continually varying weather patterns.
• Distribution Systems – On average, it takes 10-15 percent of total investment costs to connect to the distribution system, due in part to outdated technical standards not designed with the needs and benefits of smaller, decentralized plants in mind. The technical state of many UK distribution systems is inadequate to support significant growth in DG, especially due to difficulties to cope with power flows in both directions. Infrastructure investment is needed. Utilities are forecasting an annual growth rate of 1 percent for DG in the next 6 years. They think DG will be mainly composed of renewable energy sources in the next 5 years. Some new regulations are to be issued: there is a pending CHP strategy paper, a DTI/OFGEM paper to be produced on ways to develop DG, and proposals from the embedded Generation Working Group are expected. The proposals are likely to study the type of connection in the UK: while connection to the grid is qualified as "deep" in the UK (the generator who wants to connect to the grid pay charges for all the way through to customer end-point), it may change to "shallow" connection, where the generator pays only the cost to connect to the nearest connection point. There is an estimated 7.3 GWe of decentralized generating capacity in the UK, or 12 percent of the total capacity. This is comprised predominantly of gas-fired plants and renewable energy sources. The UK target for cogeneration was to achieve 5 GWe by the end of 2000 with a further target of 10 GWe by 2010 as part of the climate change program.
4.14 United States
The distributed generation market in the U.S. decreased significantly in 2002 in comparison with the previous year. Reasons for the decreased market potential for DG in the U.S. include: • Poor economy and decreased capital spending • California blackouts did not expand nationwide, decreasing the urgency to invest in distributed generation • Electricity prices stabilized
Niche markets, however, remain promising. Among those market segments still interested in DG are industrial sites with heat-recovery potential. These companies have the strongest interest in the use of onsite generators to meet their base load power requirements while utilizing any waste heat from the DG system in order to save money. Other potential niche applications for DG include companies that rely on computers and electronics, such as data processing centers and
26 telecommunications companies; commercial and industrial facilities with a potential to benefit from heat recovery; continuous manufacturing processes that will incur significant losses in a power outage; and sectors that produce methane gas as a by-product.
According to a study conducted by Primen2, an estimated 1,700 large establishments in the U.S. and Canada, representing 1.6 gigawatts of load, are strong near-term prospects for DG systems. The study found these companies to be more sophisticated energy buyers in general that understand their distributed energy options more than most companies.
In a February 2003 Electric Light & Power article3, the market for small gas turbines (1 – 10 MW), fuel cells (PEM, SOFC, MCFC, PAFC, and AFC), reciprocating engines, and microturbines (30 – 200+ kW) is summarized, identifying the key factors expected to influence the future of these systems. Figure 6 illustrates the growth of the estimated market size of small gas turbines, fuel cells, and microturbines through 2007. The reciprocating engine market is considered a mature, slow growing market with an estimated size in North America ranging from $1.5 billion to $2.5 billion.
200.0 Small Gas Turbines Fuel Cells Microturbines 150.0 ze ($M) i 100.0 S t rke Ma
50.0
0.0 2002 2003 2004 2005 2006 2007 Year
Figure 6. Distributed Generation Market Potential 2002 – 2007
The fuel cell market is expected to grow from $40 or $45 million in 2002 to approximately $110 million in 2007, with the most significant growth occurring in 2005 through 2007, as many vendors predict commercialization during that time. The article identified thirty-five factors that will influence the future of fuel cells. The eight most influential include: • The end user’s need for backup power • Reduction in initial costs • Development of interconnection standards • Successful commercialization schedules • Development and enforcement of emissions regulations
2 Energy User News, Distributed Energy Market Has Softened, Smaller Niche Market Remains Promising. 3 Electric Light & Power, Dissecting the North American Market for Distributed Generation, February 2003.
27 • Developments in reforming technologies • Utilization of resource recovery potential • Utilization of CHP potential
Solid oxide fuel cell commercialization is not expected to begin in North America until 2005, following significant delays in the commercialization process. Phosphoric acid fuel cells have over ten years of commercial availability, accounting for over 85% of the fuel cell dollar amount in 2002. PAFC growth is expected to slow as other technologies reach commercialization. Most proton exchange membrane fuel cells are being developed for residential applications (1 – 10 kW). With a large number of developers working on PEM systems, several products should be commercially available by 2005. The only major player in molten carbonate fuel cells in North America is FuelCell Energy. MCFC’s are targeting the industrial and CHP markets with systems in the 300 kW to 3 MW size range. Alkaline fuel cells are not expected to play a large role in the fuel cell market. AFC’s have been used almost exclusively by the government (NASA) since the 1960’s.
The microturbine market is expected to grow from $46 million in 2002 to over $173 million by 2007. Twenty-nine factors impacting the future of the microturbine market were identified, with the following five being the most influential: • Utilization of CHP potential • Reduction in initial costs • Development of interconnection standards • The end user’s need for backup power • Potential of the 200+ kW market segment
Commercial microturbines have been available in the 30 to 100 kW range for several years; however, higher output microturbines (greater than 200 kW) are now beginning to enter the market. The real potential for the market segment requiring 200+ kW systems has yet to be proven.
Small gas turbines range in size from 1 to 10 MW for this discussion. The market size is estimated at $125 million in 2002 and is expected to approach $150 million by 2007. Gas turbines are a proven technology in a mature market experiencing slow, steady growth at roughly 2-3 percent per year.
In total, DG represents roughly 4 to 8 percent of the total installed electric power generation capacity in the United States.
5. BARRIERS
The most significant barrier to the adoption of distributed generation technologies is the high initial cost. Many factors impact the overall costs of owning and operating a DG system, including:
• Core technology problems or hurdles
• System integration, fabrication, and manufacturing
• Markets and applications
28 • Installation requirements
• Operation and maintenance (O&M) requirements (e.g., fuel prices, replacement parts, personnel, etc.)
• Rules, regulations, and policies: