The energy supply sector consists of a sequence of elaborate and complex processes for extracting energy resources, converting these into more desirable and suitable forms of energy, and delivering energy to places where the demand exists. Global energy consumption has grown at an average annual rate of approximately 2% for almost 2 centuries, although energy growth varies considerably over time and among regions (SAR II, SPM.4.1). If past trends continue, energy-related GHG emissions are likely to grow more slowly than energy consumption in general and energy sector requirements in particular, due to a gradual trend toward the decarbonization of energy supply. Across the range of the IPCC IS92 scenarios, energy-related CO2 emissions are projected to increase from 6 Gt C in 1990 to 7-12 Gt C by 2020 and to 6-19 Gt C by 2050, of which the energy sector accounts for 2.3-4.1 Gt C (1.4- 2.9 Gt C in Annex I) by 2020 and 1.6-6.4 Gt C (1.0-3.1 Gt C in Annex I) by 2050, respectively.
The availability of fossil reserves and resources as well as renewable potentials is unlikely to pose a major constraint to long-term energy supply (SAR II, B.3.3). Similarly, the availability of uranium and thorium is unlikely to place a major constraint on the future development of nuclear power. There is also a large long-term potential for renewable energy resources, although the costs of achieving a significant portion of this potential are uncertain and depend on many factors ranging from RD&D activities and early technology adoption in niche markets to suitable geographic locations (SAR II, B.5.3.1). Table 9 summarizes global energy reserves and resources in terms of both their energy and carbon content as well as renewable potentials (SAR II, B.3.3.1).
Energy supply technologies and energy infrastructures have inherently long economic lifetimes, and fundamental transitions in the energy supply sector take many decades. This means that technical measures and policies will take considerable time to implement. However, within a period of 50-100 years, the entire energy supply system will be replaced at least twice. It is technically possible to realize deep emission reductions in the energy supply sector in step with the normal timing of investments to replace infrastructure and equipment as it wears out or becomes obsolete (SAR II, SPM.4.1.3).
The mitigation potentials of the individual options identified in this assessment are not additive, because the realization of some options is mutually exclusive or may involve double-counting. Thus, a systematic approach is required to assess the potential impacts and feasibility of combinations of individual mitigation measures and policies at the energy system level, while ensuring regional and global balance between demands and supplies. To assess the long- term technical potential of combinations of measures at the energy systems level, in contrast to the level of individual technologies, numerous scenarios of potential energy system futures have been constructed. In one such exercise, variants of a Low CO2- Emitting Energy Supply System (LESS) were analyzed in the SAR (SAR II, SPM.4.1.4). The LESS constructions are "thought experiments" exploring many combinations of technical possibilities of reducing global CO2 emissions to about 4 Gt C by 2050 and to about 2 Gt C by 2100 (SAR Syn.Rpt., 5.8). The literature provides strong support for the feasibility of achieving the performance and cost characteristics assumed for energy technologies in the LESS constructions, although uncertainties will exist until more RD&D has been carried out and the technologies have been tested in the market (SAR II, SPM.4.1.4; SAR Syn.Rpt, 5.9). In another scenario exercise conducted in 1993, the World Energy Council presented an "ecologically driven" scenario, in which similar emissions reductions were obtained (SAR II, 126.96.36.199). These exercises are, by their nature, speculative and involve assumptions about mitigation potentials, short- and long-term costs of technologies, and their full socio-economic and environmental consequences. Additional scenario development and analysis is required to establish the internal consistency of various assumptions over time, including possible interactions between such assumptions as those that might relate the evolution of systems for energy use, economic growth, land use, and population (IPCC 1994, II, SPM).
5.2. Technologies for Reducing GHG Emissions in the Energy Supply Sector
Promising approaches to reduce future emissions, not ordered according to priority, include more efficient conversion of fossil fuels; switching to low-carbon fossil fuels; decarbonization of flue gases and fuels, and CO2 storage; switching to nuclear energy; and switching to renewable sources of energy (SAR II, SPM.4.1.3). Each of these options has its unique characteristics that determine cost- effectiveness, as well as social and political acceptability. Both the costs and the environmental impacts should be evaluated on the basis of full life-cycle analyses.
5.2.1. More Efficient Conversion of Fossil Fuels
Generally, new technologies promise higher conversion efficiencies from fossil fuels. For example, the efficiency of power production can be increased from the present world average of about 30% to more than 60% in the longer term. Also, the use of combined heat and power production where it is applicable --whether for process heat or space heating or cooling-- offers a significant increase in fuel utilization efficiencies (SAR II, SPM.188.8.131.52). Integration of energy conversion from very high to very low temperatures--sometimes called energy cascading--offers additional efficiency improvements (SAR II, 184.108.40.206).
While the cost associated with these efficiency improvements will be influenced by numerous factors--including the rate of capital replacement, the discount rate, and the effect of research and development--there are advanced technologies that are cost- effective compared to some existing plants and equipment that are less efficient or emit larger amounts of GHGs. Some technology options (e.g., combined-cycle power generation) can penetrate the current marketplace. To realize other options, governments would have to take integrated action which may include eliminating permanent subsidies for energy, internalizing external costs, providing funding for additional RD&D of low- and zero- CO2 emission technologies, and providing temporary incentives for early market introduction of these technologies as they approach commercialization (SAR II, Chapter 19, Executive Summary). Therefore, while the efficiency of power production can be improved globally, this could incur additional costs and may not occur in the absence of appropriate GHG policies.
The theoretical potential for efficiency improvements is very large and current energy systems are nowhere near the maximum theoretical (ideal) levels suggested by the second law of thermodynamics. Many studies indicate low current values for most conversion processes based on second law (or exergy) efficiencies. Much inertia must be overcome before even a fraction of this potential can be realized, along with numerous barriers, such as social behavior, vintage structures, costs, lack of information and know-how, and insufficient policy incentives. For fossil fuels, the magnitude of the efficiency improvement potentials suggests, irrespective of costs, the areas that have the highest emission mitigation potentials (SAR II, B.2.2).
In general, the introduction of new vintages of efficient technologies is governed by the energy system's natural capacity retirement process and future demand growth prospects. In the short term, the efficiency improvement rate based on the natural turnover of capital may be largest in countries with rapid economic growth (SAR II, 19.1). Therefore, those Annex I countries that are undergoing the process of transition to a market economy and presently have inefficient energy conversion systems have high potentials for efficiency improvements.
The global average efficiency of fossil-fueled power generation is about 30%; the average efficiency in the OECD countries is about 35%. Assuming a typical efficiency of new coal-fired power generation (with de-SOx and de-NOx equipment) of 40% in Annex I countries, an increase of 1% in efficiency would result in a 2.5% reduction in CO2 emissions (SAR II, 220.127.116.11). In the longer run, new electricity generation technologies based on coal with higher efficiencies include supercritical steam cycles, pressurized fluidized bed combustion, and integrated gasification combined cycles. Some of these technologies are commercial, while others require further RD&D.
Natural gas in combined-cycle power plants has the highest conversion efficiencies of all fossil fuels--presently 45% in the short term and 55% and more in the longer term. Combined-cycle plants have approximately 30% lower investment costs than a conventional gas steam counterpart, although specific electricity costs will depend on the usually higher fuel costs of natural gas compared to coal. On the other hand, combined-cycle plants are more costly than simple combustion turbines, which are less efficient but have shorter installation times (SAR II, 18.104.22.168).
GHG reduction potential is approximately proportional to realized efficiency improvements. For improved technologies that use the same fossil fuel, the efficiency gains translate to lower fuel costs, which often can offset the somewhat higher capital needs. The technology improvements can result in significant secondary benefits, such as reductions of other pollutants [e.g., sulfur dioxide (SO2), NOx, and particulates]. Additional costs are often negligible because efficiency improvements do not require radical technology changes. Energy-efficiency improvements also have the advantage of being replicable.
Combined heat and power production (CHP) offers a significant rise in fuel utilization, of up to 80-90%, which is much higher than separate electricity and heat production (SAR II, 22.214.171.124). The economics of CHP are closely linked to the availability or development of district heating and cooling networks and sufficient demand densities.
5.2.2. Switching to Low-Carbon Fossil Fuels
Switching to fuels with a lower carbon-to-hydrogen ratio, such as from coal to oil or natural gas, and from oil to natural gas, can reduce emissions. Natural gas has the lowest CO2 emissions per unit of energy of all fossil fuels, at about 15 kg C/GJ, compared to oil with about 20 kg C/GJ and coal with about 25 kg C/GJ (all based on low heating values). The lower carbon-containing fuels can, in general, be converted with higher efficiency than coal. Large resources of natural gas exist in many areas (SAR II, SPM.126.96.36.199). New, low capital cost, highly efficient combined-cycle technology can reduce electricity costs considerably in some areas where natural gas prices are relatively low compared to coal.
Switching from coal to natural gas while maintaining the same fuel-to-electricity conversion efficiency would reduce emissions by 40%. Accounting for the conversion efficiency of natural gas, which is generally higher than that of coal (SAR II, 19.2.1), the overall emissions reduction per unit of electricity generated might be in the range of 50%.
Although natural gas is abundant, it is not available as a domestic energy source in some parts of the world. Thus, a wider shift to natural gas would lead to changes in energy import dependencies, which raises a number of policy issues. Initial investment and administrative costs may be substantial, due to the need to develop new transport, distribution, and end-use infrastructures. Hence, the actually achievable reduction potentials may differ significantly among regions, depending on local conditions such as relative fuel prices or gas availability.
A wider use of natural gas could lead to additional leakages of CH4, the main component of natural gas. Approaches exist to reduce emissions of CH4 from coal mining by 30- 90%, from venting and flaring of natural gas by more than 50%, and from natural gas distribution systems by up to 80% (SAR II, 22.2.2). Some of these reductions may be economically viable in many regions of the world, providing a range of benefits, including the use of CH4 as an energy source (SAR II, 188.8.131.52).
5.2.3. Decarbonization of Flue Gases and Fuels, and CO2 Storage and Sequestering
The removal and storage of CO2 from fossil fuel power- station stack gases is feasible, but reduces the conversion efficiency and significantly increases the production cost of electricity. Another approach to decarbonization uses fossil fuel as a feedstock to make hydrogen-rich fuels--for example, hydrogen itself, methanol, ethanol, or CH4 converted from coal. Both approaches generate a stream of CO2 that could be stored, for example, in depleted natural gas fields or in the oceans (SAR II, SPM.184.108.40.206). Because of its costs and the need to develop the technology, this option has only limited opportunities for near- and medium-term application (e.g., as a source of CO2 to be used in enhanced oil recovery) (SAR II, 220.127.116.11). For some longer term CO2 storage options (e.g., in the oceans), the costs, environmental effects, and efficacy remain largely unknown (SAR II, SPM.18.104.22.168).
For a conventional coal power plant with 40% efficiency, removing 87% of CO2 emissions from flue gases (from 230 to 30 g C/kWhe) would reduce the efficiency to 30% and increase electricity costs by about 80%, which is equivalent to $150/t C avoided (SAR II, 22.214.171.124).
For a natural gas combined-cycle plant with 52% efficiency, reducing CO2 emissions by about 82% (from 110 to 20 g C/kWhe) would reduce the efficiency to 45% and increase electricity costs by about 50%, which is equivalent to $210/t C avoided (SAR II, 126.96.36.199). Although the specific abatement costs per tonne of carbon avoided are higher for natural gas than for coal, this translates into lower incremental cost per kilowatt-hour of electricity because of the lower specific carbon content of natural gas.
Another process for decarbonization of fuels is the gasification of coal and CO2 removal by reforming synthesis gas. For an original integrated gasification combined cycle (IGCC) coal power plant with 44% efficiency, reducing CO2 emissions by about 85% (from 200 to 25 g C/kWhe) would reduce the efficiency to about 37% and increase electricity costs by 30-40%, which is equivalent to less than $80/t C avoided (SAR II, 188.8.131.52).
One future option to reduce costs that is under investigation is the use of oxygen rather than air for combustion to obtain a flue gas that is essentially CO2 and water vapor.
Another related option would be to produce hydrogen-rich gases for electricity generation and other applications. For the recovery of CO2 by steam reforming natural gas, the costs of capture and storage in a nearby natural gas field are estimated to be less than $30/t C avoided (SAR II, 184.108.40.206). The future availability of conversion technologies, such as fuel cells that can efficiently use hydrogen, would increase this option's relative attractiveness. Delivery of electricity and hydrogen as final energy would practically eliminate emissions at the point of end use, and allow carbon removal and storage from the energy sector itself.
Storage of recovered CO2 in exhausted oil and gas wells is another option (SAR II, 220.127.116.11). The estimated global storage capacity of oil and gas fields is in the range of 130-500 Gt C, which translates into a large mitigation potential. Storage costs in onshore natural gas fields are estimated to be less than $11/t C, while transport costs are about $8/t C for a 250-km pipeline with a capacity of 5.5 Mt C/yr (SAR II, 18.104.22.168). Another option is CO2 storage in saline aquifers, which can be found at different depths around the world.
The deep ocean is the largest potential repository for CO2 (SAR II, 22.214.171.124). CO2 could be directly transferred to the oceans, ideally at depths of 3,000 m or perhaps more; the deposited CO2 would be isolated from the atmosphere for at least several centuries. Concerns over potential environmental impacts as well as the development of appropriate disposal technologies and the assessment of their costs require further research.
5.2.4. Switching to Nuclear Energy
Nuclear energy could replace baseload fossil fuel electricity generation in many parts of the world if generally acceptable responses can be found to concerns such as reactor safety, radioactive-waste transport and disposal, and nuclear proliferation (SAR II, SPM.126.96.36.199). A review of opinion surveys concludes that public concerns about nuclear energy focus on doubt about economic necessity, fear of large-scale catastrophes, storage of nuclear waste, and the misuse of fissile material (SAR II, 19.2.4).
Nuclear electricity generation costs vary across a number of countries from 2.5-6¢/kWhe; costs for new plants, including waste disposal and decommissioning plants, range from 2.9-5.4¢/kWhe using a 5% discount rate, and 4.0- 7.7¢/kWhe using a 10% discount rate (SAR II, 19.2.4). Projected levelized costs of baseload electricity by the turn of the century indicate that nuclear power will remain an option in several countries with plants in operation and under construction. Since these nuclear generating costs are comparable to those of coal, the specific mitigation costs would range from $120/t C avoided to negligible additional costs (assuming conventional coal electricity costs of 5¢/kWhe, nuclear costs between 5.0 and 7.7¢/kWhe, and emissions avoided of 230 g C/kWhe) (SAR II, 188.8.131.52).
New designs, such as Modular High-Temperature Gas-Cooled Reactors are being developed to provide increased safety and improved economic performance through reduced construction lead times and reduced operation and maintenance costs. Interest in Liquid Metal- Cooled Reactors and other new designs, such as high-energy accelerator devices, has been revived in view of their potential use in management and disposal of fissile materials. Other concepts are being developed with the objective of enhancing the use of nuclear power fornon-electrical applications, such as process and district heat, and, in the longer term, nuclear energy could be deployed for hydrogen production (SAR II, 19.2.4).
5.2.5. Switching to Renewable Sources of Energy
Technological advances offer new opportunities and declining costs for energy from renewable sources. In the longer term, renewables can meet a major part of the world's demand for energy. Power systems, with the addition of fast-responding backup and storage units, can accommodate increasing amounts of intermittent generation (SAR II, SPM.184.108.40.206). Renewable sources of energy used sustainably have low or no GHG emissions. There are some emissions associated with the unsustainable use of biomass--for example, from reducing the amount of standing biomass and from decomposition of biomass associated with flooded reservoirs (SAR II, 19.2.5). If the development of biomass energy can be carried out in ways that effectively address concerns about other environmental issues (e.g., impacts on biodiversity) and competition with other land uses, biomass could make major contributions in both the electricity and fuels markets (SAR II, SPM.220.127.116.11). By and large, renewable sources of energy could offer substantial reductions of GHG emissions compared to the use of fossil fuels (SAR II, 19.2.5), provided their economic performance continues to improve and no siting problems arise.
The technical potential has been estimated at 14,000 TWhe/yr, of which 6,000-9,000 TWhe/yr are economically exploitable in the long run after considering social, environmental, geological, and cost factors (SAR II, 18.104.22.168). The market potential for reducing GHG emissions depends on which fossil fuel hydropower replaces. The long-term economic potential for replacing coal is 0.9-1.7 Gt C avoided annually (depending on technology and efficiency); for natural gas, the potential is 0.4-0.9 Gt C avoided annually.
The investment costs for hydro projects in 70 developing countries for the 1990s suggest that, on average, the cost of new hydroelectricity delivered to final use is 7.8¢/kWhe. The actual investment cost can be high, with financing likely to become a barrier due to the long amortization horizons involved (SAR II, 22.214.171.124). Replacing modern coal-fired electricity as presented in the SAR II (126.96.36.199) would result in average CO2 reduction costs of $120/t C avoided (assuming conventional coal electricity costs of 5¢/kWhe and emissions avoided of 230 g C/kWhe) (SAR II, 188.8.131.52).
Small-scale hydro can be regionally important especially where cost- effective. On the other hand, the construction phase of larger hydroelectric plants has social consequences and direct and indirect environmental impacts, such as water diversion, slope alteration, reservoir preparation, creation of infrastructure for the large workforce, or disturbing aquatic ecosystems, with adverse human health impacts. The social consequences include the relocation of people as well as a boom and bust effect on the local economy. The associated infrastructure stimulates regional economic development and also provides additional benefits for agriculture as a water reservoir (SAR II, 184.108.40.206).
Potential biomass energy supplies include municipal solid waste, industrial and agricultural residues, existing forests, and energy plantations (SAR II, 220.127.116.11.1).
Yields and costs of biomass energy depend on local conditions, such as land and biomass waste availability and production technology. Typically, the energy output-input ratio for high-quality food crops is low compared to the ratio for energy crops, which often exceeds the former ratio by a factor of 10. Biomass production cost estimates vary over a large range. On the basis of commercial experience in Brazil, an estimated 13 EJ/yr of biomass could be produced at an average cost for delivered woodchips of $1.7/GJ. Costs are higher in Annex I countries. For electricity generation in the Annex I countries, future biomass inputs are expected to cost around $2/GJ (SAR II, 18.104.22.168.1).
The mitigation cost range for biomass-derived energy forms such as electricity, heat, biogas, or transportation fuels not only depends on the biomass production cost but also on the economics of the specific fuel conversion technologies. Assuming biomass costs of $2/GJ and small-scale production, electricity can be generated for 10-15 ¢/kWhe. For lower cost biomass ($0.85/GJ), electricity can be generated for less than 10 ¢/kWh (SAR II, 22.214.171.124.2). On the basis of replacing coal with biomass, the mitigation costs would range between $200-400/t C avoided. A future biomass-integrated gasifier/gas turbine cycle with an expected efficiency of 40-45% and biomass costs of $2/GJ could produce electricity at costs comparable to coal and/or coal prices in the range of $1.4-1.7/GJ (SAR II, 126.96.36.199.2). In this case, the specific mitigation costs could well become negligible.
Advanced biofuels from woody feedstocks offer the potential of higher energy yields at lower costs and lower environmental impacts than most traditional biofuels. In addition to ethanol, methanol and hydrogen are promising biofuel candidates.
Modern biomass energy also offers the potential for generating income in rural areas. This income could allow developing-country farmers to modernize their farming techniques and reduce the need to expand output by bringing more marginal lands into production. In industrialized countries, biomass production on excess agricultural lands could allow governments eventually to phase out agricultural subsidies (SAR II, 188.8.131.52).
At present, advanced biomass conversion technologies as well as biomass plantations are in their infancy and require further RD&D to become technically mature and economically viable. Concerns about future food supplies have raised the issue that land will not be available for biomass production for energy in Africa and other non- Annex I countries (SAR II, 184.108.40.206.1). The potential competition for land use will depend on the degree to which agriculture can be modernized in these countries to achieve yields equivalent to those obtained in the Annex I countries, and whether intensified agricultural production will occur in an environmentally and economically acceptable way.
Intermittent wind power on a large grid can contribute an estimated 15-20% of annual electricity production without special arrangements for storage, backup, and load management (SAR II, 220.127.116.11.2, 18.104.22.168). In a fossil-dominated utility system, the mitigation effect of wind technologies corresponds to the reduction in fossil fuel use. The wind potential by 2020 is projected to range from 700-1,000 TWhe (SAR II, B.3.3.2); if utilized to replace fossil fuels and irrespective of costs, this translates into CO2 emission reductions of 0.1-0.2 Gt C/yr.
The present stock average cost of energy from wind power is approximately 10¢/kWh, although the range is wide. By 2005 to 2010, wind power may be competitive with fossil and nuclear power in more than small niche markets. For average new technology, investment costs of $1,200/kW and electricity production costs of 6¢/kWh have been estimated. Costs could be significantly lower for large wind farms. In the future, costs as low as 3.2¢/kWh have been calculated for favorable locations at a discount rate of 6% (SAR II, 22.214.171.124.3). In this case, the specific CO2 mitigation costs are negligible, if not zero or negative, where electricity from coal is more expensive. Countries with large numbers of operating wind turbines sometimes experience public resistance to such factors as the noise of turbines, the visual impact on the landscape, and the disturbance of wildlife (SAR II, 126.96.36.199.5).
188.8.131.52. Solar Energy
Direct conversion of sunlight to electricity and heat can be achieved by photovoltaic (PV) and solar thermal electric technologies. PV is already competitive as a stand-alone power source remote from electric utility grids. However, it has not been competitive in bulk electric grid-connected applications. Although module capital costs have decreased drastically over recent years, system capital costs are $7,000-10,000/kW; the corresponding electricity cost is 23- 33¢/kWh, even in areas of high insulation (2,400 kWh/m2/yr). However, the cost of PV systems is expected to improve significantly through RD&D, as well as with economies of scale. Because of its modularity, PV technology is a good candidate for cost-cutting through learning-by-doing, as well as technological innovation (SAR II, 184.108.40.206.1). Although PV devices emit no pollution in normal operation, some systems involve the use of toxic materials, which can pose risks in manufacture, use, and disposal.
By 2020 to 2025, the annual economic potential of solar energy in well-defined niche markets is assessed to be 16-22 EJ (SAR II, B.3.3.2). Realization of this potential will depend on the cost and performance improvements of solar electric technologies. If fully realized, irrespective of costs, the CO2 reduction could amount to 0.3-0.4 Gt C annually. A 50-MW power plant based on 1995 technology with installed costs of $2,300/kW would have generating costs of about 8-9¢/kWhe in areas with good insulation (SAR II, 220.127.116.11.1). The mitigation cost versus coal-fired electricity generation of approximately 5¢/kWh then would range from $130-170/t C avoided; compared to gas-fired electricity with similar costs, the range would be from $270-350/t C avoided. These costs do not account for energy system considerations such as storage requirements, or benefits of replacing more expensive peak electricity where the PV output is well-correlated with peak electrical demand.
Optimistic assessments of future PV costs indicate values as low as $700-800/kW by 2020-2030 and electricity costs of 2.2-4.4¢/kWh, depending on the level of insulation (SAR II, 18.104.22.168.1; Table 19-6). Ignoring energy system considerations, use of PV generation at these costs would reduce both generation costs and emissions relative to conventional coal technologies at today's costs. Other estimates of PV generation costs in 2030 are between 50 and 100% higher than these values, depending on whether or not there is accelerated RD&D.
Solar thermal-electric systems have the long-term potential to provide a significant fraction of the world's electricity and energy needs. This technology generates high-temperature heat, thus may realize conversion efficiencies of about 30% (SAR II, 22.214.171.124.2). Parabolic-trough technology has achieved significant cost reductions and current plants have energy costs of 9-13¢/kWh in the hybrid mode. Power towers have significantly lower projected energy costs of 4-6¢/kWh (SAR II, 126.96.36.199.2).
In addition to electricity production, solar thermal systems can provide high-temperature process heat, and central receivers can be used to process advanced fuels such as hydrogen and chemicals (SAR II, 188.8.131.52.2). Local solar thermal systems can provide heating and hot water for domestic, commercial, or industrial uses (SAR II, 184.108.40.206).
220.127.116.11. Geothermal and Ocean Energy
Electricity is generated from geothermal energy in 21 countries. The cost of electric generation from this source is estimated to be around 4¢/kWhe, and heat is generated at 2¢/kWhth. Direct use of geothermal water occurs in about 40 countries; 14 countries have an installed capacity of more than 100 MWth(SAR II, 18.104.22.168.1).
Various emissions are associated with geothermal energy, including CO2, hydrogen sulfide, and mercury. Advanced technologies are almost closed-loop and have very low emissions (SAR II, 22.214.171.124.1). The geothermal energy potential by 2020-2025 is estimated to be 4 EJ (SAR II, B.3.3.2). Hot dry rock and other non- hydrothermal reservoirs offer new supply resources. Despite its importance at the level of the local economy, the carbon reduction potential is small.
Although the total energy flux of tides, waves, and thermal and salinity gradients of the world's oceans is large, only a small fraction is likely to be exploited in the next 100 years (SAR II, 126.96.36.199.2).
In preparing these calculations of technical potential, it is assumed that 50% of the new installed energy conversion capacities in Annex I countries between 1990 and 2020 would employ the mitigation technologies described in this paper, irrespective of costs which would vary for different technologies. Six different mitigation technologies are considered: Replacing coal with natural gas, flue gas decarbonization for coal and natural gas, CO2 removal from coal, and replacement of coal and natural gas with nuclear power, or with biomass, respectively. This calculation does not attempt to present a comprehensive assessment of mitigation options in the energy sector. Only six examples are presented due to the limitations imposed by the IS92 scenarios. The mitigation potential of each individual technology option is based on a sensitivity analysis of the IS92a scenario and the range between IS92e and IS92c. Some of these mitigation options may be mutually exclusive and are not additive.
Each calculation includes a number of steps. First, new capacity additions between 1990 and 2020 in the IS92 scenarios are inferred; second, the profiles of new capacities that are to be partially replaced in Annex I countries by mitigation technologies are also inferred with the assumption that 50% of these capacities would consist of new technologies; third, the implied CO2 emissions reductions are determined for all three IS92 scenarios using technology characteristics from SAR II, Chapter 19, and emissions coefficients from SAR II, Chapter B; and finally, percentage emissions reductions are evaluated for each of the three scenarios.
The extent to which the technical potential can be achieved will depend on future cost reductions, the rate of development and implementation of new technologies, financing, and technology transfer, as well as measures to overcome a variety of non-technical barriers such as adverse environmental impacts, social acceptability, and other regional, sectoral, and country-specific conditions.
5.3. Measures for Reducing GHG Emissions in the Energy Supply Sector
Refer to Table 10 for examples of measures and technical options to mitigate GHG emissions in electricity generation.
5.3.1. Market-Based Programs
Market-based programs directly change the relative price of energy- related activities. In a perfectly competitive marketplace, under an emission tax or tradable quota scheme, emitters would reduce emissions up to the point where the marginal cost of control equals the emission tax rate or the equilibrium price of an emission quota. Both instruments would promote dynamic efficiency (cost minimization over the long term, when factors of production are variable and technological change may be stimulated), as each provides a continuous incentive for RD&D in emission abatement technologies to avoid the tax or quota purchases (SAR III, 11.5). As such, the costs of emission taxes are known, but the magnitude of emission reductions is uncertain. This situation reverses for emission quotas.
188.8.131.52. Phasing Out Permanent Subsidies
Permanent energy sector subsidies provide incorrect market signals to producers and consumers alike, and may lead to energy prices below actual cost; resource allocation is thus distorted and inherently suboptimal. Subsidies to established technologies create artificial market barriers to the entry of new technologies. For this reason, the adoption of marginal cost pricing and the minimization, if not elimination, of long-term, permanent subsidies that increase GHG emissions have been proposed as means for improving market entry opportunities for modern technologies with lower GHG emissions (SAR II, SPM.4.4). These subsidies absorb large amounts of capital, reducing the financing possibilities of investments in energy efficiency, RD&D in low CO2-emitting technologies, or other economic activities. Conventional energy technologies benefit from direct subsidies of more than $300 billion per year worldwide (SAR II, 19.4).
The argument for eliminating permanent subsidies, however, does not mean that some temporary, short-term subsidies could not be used as measures to support the market entry of GHG mitigating options such as renewables, nuclear power, or clean coal technologies. For example, price guarantees for independent producers utilizing low-carbon technologies would help reduce the economic risk of technologies that are not fully matured.
184.108.40.206. Full-Cost Pricing of Energy Services
The literature on full-cost pricing is controversial. No consensus exists on how to monetize the external (true social) costs of energy production and use (SAR III, SPM.6). If consensus were possible to attain, then the practice of full-cost pricing would contribute to a level playing field for all energy technologies. External costs include those costs usually not reflected in market prices in the absence of policies. Examples in the literature include morbidity, mortality, environmental damage, or the potential adverse consequences of the impacts of climate change, job opportunities, competitiveness, and other opportunity costs.
The inclusion of energy externalities would improve the competitiveness of low-emission energy uses (SAR II, 19.4). Because the external costs of existing and new technologies are unknown but are expected to vary greatly among countries and regions, unilateral national adoption of full-cost pricing may, in the short run, adversely affect international economic competitiveness. International agreements may be needed to overcome this competitiveness concern.
220.127.116.11. Tradable Emission Quotas and Permits
Other possible measures include setting emission quotas and issuing tradable emission permits. At the international level, fulfillment of quotas can enhance activities implemented jointly, which could simultaneously bring technology and finance to non-Annex I countries and to some Annex I countries undergoing economic transition, and help implement least-cost strategies internationally. 16
18.104.22.168. Financing Assistance
Capital shortage, especially in the developing world and some Annex I countries undergoing economic transition, is a major barrier to the implementation of GHG mitigation options. If a project has lower life- cycle costs and emissions but higher capital requirements than its alternative, it may not attract the necessary finance. In addition, energy supply technologies compete with other development needs for limited capital. However, many mitigation and other energy options could involve indigenous technology production, creating new local infrastructure and employment. Especially in rural areas, decentralized technologies may aid development goals (SAR II, 19.Executive Summary).
Even in the industrialized countries, the capital required for financing energy supply system-related GHG reduction may yield lower returns than other investment opportunities. Measures that make supply and conversion technologies more attractive in the market place would help resolve some of the financing difficulties by reducing risk, uncertainty, and upfront capital requirements. Other measures include accelerated depreciation, start-up loans, and concessional grants (SAR II, SPM.4.4).
5.3.2. Regulatory Measures
The conventional approach to environmental policy in many countries has used uniform standards (based on technology or performance) and direct government expenditures on projects that are designed to improve the environment. Like market-based incentives, the first of these strategies requires that polluters undertake pollution abatement activities; under the second strategy, the government itself expends resources on environmental quality. Both of these strategies figure prominently in current and proposed measures to address global climate change (SAR III, 11.4).
Standards and codes have the advantage that the effect on GHG
emissions can, in general, be assessed . The
disadvantage, however, is that the costs incurred are often unknown
and can be higher than market-based instruments. Under some
circumstances, however, a performance standard may provide
greater incentives but under other circumstances also lower
incentives for technological adoption than a marketable permit
system (SAR III, 11.4.1).
An example of a regulatory measure in the United States is the
Public Utilities Regulatory Policy Act (PURPA), enacted in 1978,
which required electric utilities to buy power from independent
producers at the long-term avoided cost and led to the creation of a
competitive, decentralized market. Small- to medium-scale
cogeneration fueled by natural gas and biomass became a popular
technology approach. PURPA is largely responsible for the
introduction of more than 10,000 MWe of renewable
electric capacity (SAR II, 19.4). According to some assessments, such
regulatory measures could lead to higher electricity costs.
5.3.3. Voluntary Agreements
An example of a regulatory measure in the United States is the Public Utilities Regulatory Policy Act (PURPA), enacted in 1978, which required electric utilities to buy power from independent producers at the long-term avoided cost and led to the creation of a competitive, decentralized market. Small- to medium-scale cogeneration fueled by natural gas and biomass became a popular technology approach. PURPA is largely responsible for the introduction of more than 10,000 MWe of renewable electric capacity (SAR II, 19.4). According to some assessments, such regulatory measures could lead to higher electricity costs.
5.3.3. Voluntary Agreements
Voluntary agreements generally refer to actions undertaken in the participants' self-interest and endorsed by a government with the objective of reducing GHG emissions. Such agreements are considered in many Annex I countries to constitute a flexible measure. The agreements can take on many different forms at both national and international levels, and can include target- and performance-based agreements, cooperative RD&D, general information exchange, and activities implemented jointly.
Forward-looking firms may take steps to control GHG emissions if they fear more costly mandatory controls in the absence of voluntary reductions. This could explain why some voluntary agreements for domestic energy management have arisen. The vast majority of GHG reductions from the actions announced or expanded through the U.S. Climate Change Action Plan, for example, come from voluntary initiatives aimed at increasing energy efficiency (SAR III, 11.4.3).
5.3.4. Research, Development, and Demonstration
High rates of innovation in the energy sector are a prerequisite for meeting the most ambitious GHG mitigation objectives and significantly lowering the costs of many technology options below present levels. The trend in recent years, however, has been one of declining investment in energy RD&D on the part of both the private sector and the public sector (see Table 11; SAR II, 19.4). Over the last decade, public-sector support for energy RD&D has declined absolutely by one-third, and by half a percentage of GDP (SAR II, 19.4). In the past, over half of government-supported RD&D in the International Energy Agency (IEA) member countries was allocated to nuclear energy and less than 10% was allocated for renewables. Together with energy conservation, more than 80% of RD&D is devoted to low- or zero-GHG emitting measures.
Although many energy sector mitigation options require further RD&D support, it is important to have a government strategy that does not attempt to pick individual technology winners. Fortunately, many of the promising technologies for reducing emissions, such as many renewable and other low- or zero-GHG emitting energy technologies, require relatively modest investments in RD&D. This is a reflection largely of the small scale and the modularity of these technologies (SAR II, 19.4). As a result, it should be feasible to support a diversified portfolio of options, even with limited resources for RD&D. It has been estimated that research and development of a range of renewable energy technologies would require on the order of $15-20 billion distributed over a couple of decades (SAR II, 19.4).
RD&D programs are necessary but not sufficient to establish new technologies in the marketplace. Commercial demonstration projects and programs located in realistic economic and organizational contexts to stimulate markets for new technologies also are needed. For a wide range of small-scale, modular technologies, such as most renewable energy technologies and fuel cells, energy production costs can be expected to decline with the cumulative volume of production, as a result of learning by doing.
5.3.5. Infrastructural Measures
22.214.171.124. Removal of Institutional Barriers
In some circumstances, the removal of institutional barriers can attract private-sector interest in advanced renewable technologies. Regulatory reform and deregulation (breaking-up of producer monopolies, transmission and distribution networks) have allowed small and independent power producers access to the grid and improved their competitiveness. Standardization of equipment to facilitate connection to the grid also would improve technology adoption. In the case of adoption of advanced renewable technologies, these measures can reduce GHG emissions.
126.96.36.199. Energy System Planning
Traditionally, the domain of energy sector industries has been the production and sale of kWhe, liters of gasoline, or tonnes of coal. The focus was on growth of demand for energy supplies and the efficient expansion of capital to meet that demand, not on the most efficient way to meet the growing and widening demand for energy services.
Some regulatory commissions are requiring energy sector industries to adopt a wider business concept, which extends to include the provision of energy services rather than the sale of energy units. Most importantly, end-use efficiency and technologies become an integral part of the energy industry capital allocation process. Energy planning would extend beyond the traditional energy sector boundaries and adopt a full energy system perspective.
However, the energy utility sectors in Annex I countries currently are undergoing privatization and deregulation. These changes may also provide opportunities for GHG mitigation, such as independent power production and CHP. These changes also mean that governments may have to modify the policy levers used to achieve environmental objectives. For example, demand-side management and integrated resource planning may need to be reexamined.
188.8.131.52. Local and Regional Environment Measures
Energy supply and end use lead to a number of local and regional environmental impacts. Local impacts include indoor and urban pollution. Regional impacts include acidification and possible land- use conflicts. Policies and measures for mitigating local and regional environmental impacts can affect and interact with policies for mitigating climate change. For example, more efficient conversion and end use of energy brings multiple benefits as it reduces environmental impacts on all scales. In contrast, other policies might involve complex tradeoffs. Some measures that improve regional environmental conditions may lead to higher GHG emissions; for example, flue gas scrubbers for the abatement of sulfur emissions from coal-fired power plants decrease the overall conversion efficiency, resulting in higher carbon emissions. Additionally, some GHGs may have adverse effects on local and regional air quality (e.g., small CHP might not include full de-SOx and de- NOx abatement equipment). Because the adverse regional impacts are more certain than the impacts of global climate change, action to combat this type of pollution is likely to occur in many parts of the world in the short to medium term.
Thus, integration of policies and measures is needed to reduce the overall environmental impacts at the national, regional, and local levels. In particular, policies and measures addressing local and regional environmental impacts should be assessed for their potential conflict with goals and policies for reduction of GHG emission.
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