Air-Source heat pump water heaters in Australia and New Zealand

National Economic Review
National Institute of Economic and Industry Research
No. 68   October 2013

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board. The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.

Editor: Kylie Moreland

©  National Institute of Economic and Industry Research

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ISSN 0813-9474

Air-source heat pump water heaters in Australia and New Zealand
Graham Armstrong, Consultant, NIEIR

Abstract
This paper is based on a study prepared and presented by Graham Armstrong to the Air Source Heat Pump Water Heater Asia (ASHPasia) Forum in Shanghai, China on 17 November 2012. This study draws on two main information and data sources: the National Institute of Economic and Industry Research and Saturn Corporate Resources database for projects undertaken for a range of Australian electricity and gas distributors (low voltage wires and metering responsibilities) and retailers (customer billing, energy end-use advice and liabilities under government end-use programs); and a study for the Australian and New Zealand Governments’ E3 Equipment Energy Efficiency joint initiative entitled ‘Product Profile: Heat Pump Water Heaters, Air-source Heat Pump Water Heaters in Australia and New Zealand’ (June 2012; E3 report, available at www.energyrating.gov.au). An outline of E3 programs is provided in the Appendix.

Introduction
Although similar in many ways (e.g. having mild climates very suitable for air-source heat pumps), Australia and New Zealand have quite different energy supply and demand characteristics. Australian electricity generation is greenhouse gas intensive (GHGI), averaging approximately 1 t CO2e/MWh, and is predominantly based on coal.1 Australia has substantial gas production (approximately 50 per cent exported as LNG) and reserves (i.e. conventional, mainly offshore and onshore; coal seam methane; and shale (no production as yet)). Renewables account for approximately 10 per cent of electricity generation. Water heating is increasingly based on gas (48 per cent), with 45 per cent electricity (declining), and growing contributions from a low base (5 per cent) of solar hot water (SHW) and air-source heat pump hot water (HPHW) systems. Regional variations are significant. There is a national policy to phase out electric resistance water heating because, on average, it is GHGI. A carbon tax was implemented in July 2012 at A$23/t CO2e, which will be replaced by an emissions trading system (ETS) in 2015–2016.

New Zealand electricity generation has low greenhouse gas intensity, averaging approximately 0.15 t CO2e/MWh, and is predominantly based on renewables (hydro-electricity, geothermal and wind). New Zealand has limited gas production and reserves. Water heating is dominated by electricity (80 per cent). Natural gas contributes 16 per cent and SHW 1.4 per cent. An ETS is in place.

The above summary of the two national energy systems indicates that the drive for low end-use GHGI water heating is far greater in Australia. However, the wide availability of reasonably priced gas has meant that, without incentives, low GHGI SHW and HPHW systems are not competitive with gas in reticulated gas areas. Liquefied petroleum gas/propane is also widely available but is relatively expensive.

In Figure 1, data on average annual mean temperatures in Australia (annual) indicate favourable conditions for air-source HPHW systems. The efficiency of heat pumps, measured as the coefficient of performance (COP), depends on the temperature differences between the medium to be heated (i.e. water or air) and the desired service (i.e. hot water or warm or cool air) delivery temperature. The smaller the seasonal difference, the higher the COP.

In New Zealand, the low GHGI of electricity does not raise climate change concerns for electric resistance water heating. In both Australia and New Zealand, residential water heating economics can be attractive for SHW and HPHW systems replacing ERHW units when incentives to install SHW and HPHW units are available.

In Australia, replacement of a typical ERHW unit using 4 MWh annually with a heat pump with an average COP of 2.2 provides a saving of 2.4 MWh per year. Under the average current tariff for water heating using the two systems, the annual savings would be approximately A$350 when a HPHW heater replaces an ERHW unit. In New Zealand, the savings would be approximately NZ$600 per year (E3 report (Australian and New Zealand Governments, 2012)). Note, however, that the savings depend on the tariffs ($/MWh) applied to the ERHW units and the heat pump. In Australia, domestic electric water heaters are typically storage heaters using off-peak (22:00 to 07:00 hours) electricity, at approximately A$150/MWh.

In Australia, a heat pump system producing hot water on demand would use electricity at an average price of approximately A$230/MWh, thus reducing the efficiency advantages of a HPHW system. Most HPHW systems installed in Australia are off-peak storage units and seldom require non-off-peak boosting. Smart (interval) meters are being installed in Australia but, as yet, time-of-use tariffs are not mandated.

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The residential water heating market: Current and potential
In 2011, there were approximately 8,602,000 residences in Australia (see Table 1). By comparison, there were approximately 1,730,000 residences in New Zealand.

Water heating proportions by state/territory are presented in Table 2. Gas dominates in Victoria and is also the major energy source for water heating in South Australia and Western Australia. In all states, solar penetration increased markedly over the 2009–2011 period, albeit from a small base. SHW systems (and HPHW) are subsidised under the Federal Renewable Electricity Target (RET) and state initiatives, and were, until 1 July 2012, under the Federal Renewable Energy Bonus Scheme. SHW and HPHW are also encouraged in new homes in Victoria (SHW or plumbed water tank must be installed), New South Wales (under the Building Sustainability Index (BASIX)) and South Australia. SHW and heat pump hot water installation rates peaked in 2009 but then dropped as households preferred to invest in photovoltaic (PV) rather than SHW/HPHW installations. HPHW heating is not reported separately by the Australian Bureau of Statistics (2011).

In terms of the residential water heater market in Australia, there are approximately 800,000 units installed annually: 650,000 are replacement systems and 150,000 are for new residences. In 2011, there were approximately 70,000 residential SHW installations and approximately 15,000 residential HPHW installations.

Average annual energy use for water heating and potential heat pump hot water savings

There are variations in annual energy use for water heating in Australia by region and household structure and characteristics. Electric resistance heating produces the highest level of GHG emissions and running costs are high. At approximately $150/MWh ($42/GJ) off-peak and using 4 MW per year, the annual cost is $600. For gas, consumers pay approximately $20/GJ. Using 25 GJ per year, an average household pays $500. Hence, for electricity and gas, a 60-per cent reduction in use when a HPHW unit replaces an electric resistance (ERHW) or a gas water heater saves the household $360 and $300 per year, respectively.

If a 10-year payback were acceptable to consumers, the maximum capital cost for HPHW units would be approximately $3,600 for electricity (ERHW unit) and $3,000 for gas (GHW) replacement (undiscounted, with no energy price increases).

In November 2012, Chromagen was offering (in Victoria) a Midean HPHW unit of 280-L capacity for $2,300 (total subsidies approximately $2,000; i.e. without the subsidies the cost would be approximately $4,300). At this price, capital payback from savings is approximately 6.4 years in non-gas areas for this replacement, which assumes the ERHW system replacement is relatively new. However, at ERHW or GHW unit end-of-life, the economics for an HPHW unit are much better. In this case, when the ERHW or GHW unit fails (end-of-life), the choice is between an HPHW unit and a new unit of the same type that has failed (i.e. like-for-like replacement). In this situation, the real cost of an HPHW unit for the householder (consumer) is the difference in cost between the HPHW and conventional units. These costs vary but are approximately $1,000 for an HPHW unit versus a new ERHW unit, and $800 for an HPHW unit versus a new GHW unit. At a cost for the HPHW unit of $2,300 (as in the case above), the paybacks would be: 2.8 years for an HPHW unit replacing an ERHW unit and, when the new HPHW unit is displaced (early in life or later (or end) in life (average non-HPHW unit is approximately 12 years)), 2.7 years for an HPHW unit replacing a GHW unit. These paybacks should be attractive for most householders. As indicated above, paybacks will vary. Paybacks will depend on:

  • if end-of-life, price differential between non-HPHW units and HPHW units;
  • gross costs of HPHW units (e.g. $4,000) net of subsidy cost (e.g. $2,000);
  • efficiency of hot water units (HPHW, ERHW and GHW) (for HPHW units COPs will be higher in warmer regions);
  • electricity and gas prices (vary by region);
  • hot water usage per year (lower hot water usage reduces HPHW attractiveness; reverse for higher hot water usage); and
  • life and maintenance costs of units.

Given, as indicated above, the attractive paybacks of HPHW units in Australia, why do HPHW units not have a higher market share (now approximately 2 per cent)? One of the main reasons is that although the cost of an HPHW unit is not much greater than the cost of a conventional unit and paybacks are good, many householders will purchase equipment on a first (capital) cost basis and ignore operating CO2 advantages of HPHW units. Second, there are concerns about the reliability and life of HPHW units. Third, there is very limited promotion of the benefits of HPHW unit technology and, finally, the tendency for like-for-like replacement, particularly at end-of-life situations when replacement with an HPHW unit, might take 1 to 2 weeks (hot water is seen as an essential service and delay in restoration of the hot water service is very inconvenient). These issues need to be addressed by the air-source HPHW industry (manufacturers and retailers) in Australia. For example, at end-of-life, a temporary hot water unit could be immediately supplied and used until a new HPHW unit is installed.

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Residential sector gas and electricity prices
Electricity and gas prices have a significant influence on water heating economics and, thus, the consumer choice of water heating systems. Australian retail electricity prices have risen significantly in real terms over the past 5 years due mainly to increases in distribution (‘poles and wires’) costs. Costs of ‘green’ policies passed on to consumers, and since 1 July 2012 carbon pricing, have also contributed to residential electricity price increases. The estimated breakdown of retail electricity and gas prices (variable energy, not including fixed supply charges) in 2011 in Victoria (typical of other States/Territories) is presented in Table 3.

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Carbon (CO2 equivalent) pricing impacts
Carbon pricing increases the prices of electricity and gas according to the carbon dioxide equivalent (CO2e) price, the CO2e content of fuels used to produce electricity and the CO2e content of end-use combusted gas. In end-use markets energy users will respond to increased energy prices by reducing energy demand, particularly in the longer term when energy using equipment can be changed. Carbon pricing also changes the generation mix required to balance demand and supply towards gas and renewables.

The Australian CO2e price is $23/t from 2012–2013 to 2014–2015 (see Figure 2). Then, as the ETS phase is linked to the European Union (EU) scheme, the estimated price falls to $15/t by 2015–2016, rising linearly to $18/t in 2020 and $22/t in 2025.

For electricity, at $23 to $27/t CO2e, the pass-through (CO2e price impact on wholesale electricity price) is approximately 85 per cent, resulting in an electricity price rise of $21 to $24/MWh plus goods and service tax (GST), or, at current price levels, approximately a 9-per cent increase in retail price. At higher CO2e prices the pass-through percentage decreases, and increases at lower CO2e prices.

CO2e content of end-use gas varies by state. For example, the CO2e content is 0.057t CO2e/GJ in Victoria and 0.71t CO2e/GJ in South Australia. At $23/t CO2e, the price rise in Victoria is $1.3/GJ plus GST, or a 9-per cent rise in retail prices.

The demand response, that is, the price elasticity of demand for electricity, is estimated to be approximately −0.3 in the long run. High real price increases such as the ones that have occurred in Australia over recent years could engender a short-run response close to the long-run elasticity, or even greater.

From an electricity demand viewpoint, the focus of electricity retailers on CO2e pricing impacts will be on CO2e pricing increasing electricity prices and reducing demand compared with no carbon pricing, and on gas prices rising. Accordingly, gas versus electricity competition may not be significantly affected.

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If the current Federal Coalition removes the carbon tax, electricity and gas prices could still rise as a result of Coalition climate change policies. The impact, however, is indeterminate at this time.

National Institute of Economic and Industry Research projections of residential electricity prices are presented in Table 4, together with a breakdown of price components in Victoria. These prices include fixed supply charges. Off-peak (22:00–07:00 hours) rates, mainly applying to water heating, are $100 to $120/MWh below peak rates (tariffs). Each retailer offers a range of tariffs (available on their websites). The above tariffs are the average of the most common peak tariffs. Tariffs may fall due to carbon price changes and as ‘green’ policies, and responses to them, change.

Gas prices have, where gas is available, made the fuel very competitive for water heating. In Victoria, where over 90 per cent of residences have access to natural gas, 66 per cent of residences used natural gas for water heating in 2011.

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As indicated in Tables 4 and 5, gas prices are low compared with electricity prices. However, higher efficiency electrical equipment, such as heat pumps (with efficiencies of 200 to 300 per cent), can offset the lower cost of gas (gas efficiencies are 65 to 95 per cent).

Note that electricity and gas prices post-2013 are difficult to predict mainly because of carbon pricing uncertainty.

Performance of heat pump hot water units
Heat pump water heater performance depends on several factors, including: the location and climate where it is installed; the heating efficiency or COP of the system under standard conditions; the heat loss of the storage tank; the quantity of hot water drawn off each day; the quantity, the duration and the time of day of each draw; the time interval between draws; the thermostat and control strategy settings; and whether the heat pump can run at any time or whether it is constrained from running at certain times due to electricity tariff structures, for example, lower off-peak rates. These factors contribute significantly to the competitiveness of HPHW systems with alternative water heating systems.

Most relevant standards for performance are AS/NZS 5125: 2010 Heat Pump Water Heaters (product performance assessment) and AS/NZS 4692.1: 2005 Electric Water Heaters (energy consumption, performance and general requirements).

Independent laboratory testing in 2010 and 2011 of heat pump water heaters of the most common models sold in Australia and New Zealand using AS/NZS 5125 generally gave similar results to the tests undertaken by manufacturers. Testing raised some concerns about heat pump water heaters that had very slow heat up times, particularly in colder temperatures. Key concerns raised as a result of testing include low energy efficiency in cold ambient temperatures in some models and slow reheat times, especially in cold ambient temperatures in certain models. In addition, many models had higher noise levels than expected.

While physical test results were largely consistent, the modelled performance estimates using AS/NZS 4234 were often inconsistent with manufacturer-modelled results. This divergence appears to be a result of: a lack of clarity in some definitions in the standards; inconsistencies between instructions and how the model actually operated; and the small, medium and large load categories in AS/NZS4234, which can result in step changes in calculated displaced energy if a product is only marginally below the requirements of a particular load category.

Testing of heat pump hot water units
The Australian and New Zealand standards that relate to the design, construction and performance of HPHW units are listed in Appendix 1 of the E3 report (Australian and New Zealand Governments, 2012).  The greenhouse gas performance of HPHW units in Australia depends on energy used and energy GHGI. These factors vary by region and over time. For example, in Victoria, with a cooler climate compared to other regions of Australia, there is high electricity GHGI and gas is widely availability and low in cost. For a HPHW system, average electricity use is 1.6 MWh/year, with GHGI of 1.3 t CO2e/MWh, resulting in 2.08 t CO2e/year. In contrast, a new high efficiency GHW system uses 20 GJ/year, with GHGI of 0.06 t CO2e/GJ, resulting in 1.20t CO2e/year. There is a clear advantage to gas unless GHGI reduces significantly and/or HPHW COP increases significantly.

In Queensland, the climate is warmer and there is lower electricity GHGI, and limited availability and higher costs of gas. For a HPHW unit, the average electricity use is 1.2 MWh/year, with GHGI of electricity of 0.90t CO2e/MWh, resulting in 1.08t CO2e/year. A new high efficiency GHW unit uses 18 GJ/year, with GHGI of 0.06t CO2e/GJ, resulting in 1.08t CO2e/year. For an ERHW unit, the average electricity use is 3.5 MWh/year, with a GHGI of electricity of 0.9 t CO2e/MWh, resulting in 3.15t CO2e/year. There is a clear advantage to HPHW compared to ERHW, the dominant hot water source in Queensland. In gas (limited) areas, there is similar greenhouse performance for HPHW and GHW units.

Suppliers of heat pump water heaters in Australia and New Zealand
There are 18 brands and approximately 80 separate models of HPHW systems registered with the Australian Clean Energy Regulator (CER) (see Table 6). (There may be other models that are not CER registered.) The GWA Group and Rheem Australia share approximately 60 per cent of total sales. As is evident from Table 6, China has a significant role in the manufacture and assembly of HPHW units. As noted above, Chromagen is offering Midean HPHW units at prices that are attracting sales, particularly in non-gas areas.

Regulations and policy initiatives applying to heat pumps
Mandatory energy efficiency regulations
Mandatory energy efficiency regulations do not apply to HPHW units in either Australia or New Zealand. In both countries, storage heat tanks, if a component of heat pumps, are exempt from standing tank heat loss provisions if resistance heating provides less than 50 per cent of annual energy supplied.

Building codes
Australian states and territories (except Tasmania and the Northern Territory) have rules that restrict the use of GHGI water heaters in detached houses, semi-detached houses and townhouses. This has virtually eliminated ERHW systems in new homes. In New South Wales, the BASIX energy rating system contributed to an increase in the HPHW share of the New South Wales water heater market. The New Zealand Building Code specifies maximum heat losses for all types of water heaters up to 700-L capacity.

In existing buildings, South Australia and Queensland have regulations restricting the replacement of ERHW systems. In 2010, the national Ministerial Council on Energy agreed to phase out GHGI water heaters for existing homes except Tasmania (mainly a hydro system). When the policy is implemented, water heater replacement in detached houses, semi-detached house and townhouses will be by heat pumps, SHW, gas or wood-fired water heaters.

The Australian Federal Renewable Electricity Target
Under the Australian Federal RET policy, the use of renewable energy for electricity generation and hot water production is provided with incentives delivered through electricity retailers (sellers of electricity to end-users). A target for renewable energy as a percentage of total electricity consumption (with some exemptions) has been set for 2020: now approximately 25 per cent. The retailers are liable for acquisition of renewable energy in proportion to their share of total electricity sales. The RET is divided into two parts:

  1. small renewable energy systems (SRES), which cover small-scale renewables, including PVs, and other small (up to 100 kW) generators and displacement technologies (SHW and heat pump units); and
  2. the large renewable energy target (LRET), which covers large-scale renewables.

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There is no maximum target (cap) for SRES. In contrast, 41,000 GWh by 2020 has been set as an LRET, with the target increasing gradually from 12,500 GWh in 2011. In recent years (2009 to 2012), SRES has been dominated by PV. In 2011, approximately 15,000 heat pumps and 70,000 SHW units were installed under SRES out of a total residential water heater market of approximately 800,000 for new and existing residences. The heat pump installations have declined from approximately 65,000 units in 2009 when state rebates (see Table 7) were very generous for heat pumps, resulting in a virtually zero price for heat pumps.

The SRES is delivered through Small Scale Technology Certificates (STCs) created following SRES regulations. In the regulations the number of STCs is specified for each type of equipment installed. When eligible equipment, such as a heat pump, is installed, STCs can be created and sold to retailers. At a price of $30 to $40 per STC, the price of HPHW systems can be reduced by approximately $900 to $1,200 per unit. Each electricity retailer must purchase and deliver to the SRES regulator (Clean Energy Regulator) STCs in proportion to their share of the end-use electricity market.

Since 2008, households  have preferred to put their ‘solar dollars’ into PV systems, mainly because of greater PV incentives under RET and state/territory feed-in-tariffs, and reductions in state/territorial incentives for heat pumps and SHW.

Rebates and subsidies
Federal rebates
Up to 1 July 2012, the Federal Government provided rebates to replace ERHW systems with SHW or HPHW units. The progress of the rebate over 2009–2012 is shown in Table 7: 250,000 water heater installations were covered by the program.

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New South Wales

From 2007 to 2011, 48,000 rebates were paid for HPHW units under a state program that terminated in June 2011. Rebate levels varied from $300 to $1,200 per unit.

Victoria

Under Victoria’s Energy Efficiency Target, a ‘white certificate’ program, HPHW units are eligible for subsidies to replace ERHW units. In addition, until March 2013, direct subsidies for HPHW and SHW units were available from Sustainability Victoria.

South Australia

Since 2002, low income households have been eligible for incentives to install SHW, HPHW and GHW units in new and existing residences. Incentives will end in June 2013. Approximately 1,200 HPHW units will be installed under the program.

Queensland

Since 2010, rebates up to $1,000 have been offered for SHW or HPHW units (heat pump take-up unknown).

Australian Capital Territory

The Australian Capital Territory (ACT) offers $500 for replacement of heat pump units to replace ERHW units. Heat pump take-up is not known.

New Zealand

Over 2009–2012, rebates of $575 to $1,000 were offered for installation of heat pump water heating units. Take-up data is not available.

Heat pump installations
Apart from the SRES element of the federal RET, incentives to install HPHW units have been significantly reduced since 2009 in Australia. As a result, HPHW installations appear to have dropped from approximately 80,000 in 2009 to fewer than 20,000 in 2011, partly due to reduced incentives and partly due to consumer preference for PV installations.

In New Zealand, installations are very low, perhaps 500 per year because of relatively low electricity prices and low climate change concerns associated with low GHGI electricity.

In the future, heat pump installations will depend on several factors, including HPHW performance (coefficient of performance); electricity and gas prices; subsidy/rebates for heat pump installations; promotion of HPHW units by suppliers to enhance consumer acceptance of the units; and regulation of water heating technologies.

There was a close correlation between the total level of federal and New South Wales rebates and installations up to 2011 (see Figure 3). New South Wales and Queensland installations accounted for the majority of HPHW installations to 2011 due to incentive levels, favourable climatic conditions and the limited availability of natural gas (see Figure 4).

New South Wales and Queensland have 76 per cent of the Australian stock of heat pump water heaters, even though they have 52 per cent of the total number of Australian dwellings. The higher rate of HPHW unit installations in these states is due to a number of factors. First, a lower share of households in these states have access to reticulated natural gas than in Victoria, South Australia and Western Australia, and, as a result, there is less competition from gas in the low greenhouse emissions water heater market. Second, there were favourable financial incentives (especially in New South Wales) over 2008–2010. Third, New South Wales benefitted from the effects of the BASIX requirements for new dwellings. Finally, large populations live in climate zones where HPHW units perform well. Final data for 2011 and 2012 are not yet available, but installations have declined in these years as the availability of rebates has declined, even though SRES has continued.

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In Australia, HPHW sales are forecast to increase, with current policies, from approximately 20,000 per year in 2011 to approximately 40,000 by 2030 (E3 report (Australian and New Zealand Governments, 2012). However, if the phase-out of ERHW system policy is fully implemented, sales of HPHW units could reach approximately 100,000 per year by 2020 for new heat pumps and heat pump replacement use. Sales increase factors besides the planned electric resistance phase-out are consumer acceptance of HPHW units (which could be enhanced by supplier promotion), increases in heat pump efficiency, a decrease in the price of units, an increase in electricity price and the introduction of favourable tariffs for HPHW units.

In New Zealand, approximately 350 HPHW units were sold in 2009 and 400 in 2010, with an expected 500 in 2012 (E3 report). The much lower New Zealand numbers are due to fewer residences (1.7 million versus 8 million in Australia), fewer climate change concerns, less favourable electricity prices, and overall less favourable air-source heat pump operating conditions.

Policy options to improve heat pump water heater performance
A range of studies, performance testing and comparison with global experience indicate that the market penetration of heat pump water heaters in Australia and New Zealand could be significantly improved.

Potential policy initiatives include improved information on heat pump benefits and costs, enhanced unit testing, improved publicity, better appliance performance labelling, Minimum Energy Performance Standards (MEPS), and research and development for units to ensure unit specific suitability for Australian and New Zealand conditions.

The E3 study (Australian and New Zealand Governments, 2012, pp. 36–37) proposes the following strategies for consideration by stakeholders:

  1. Establish a system of mandatory product testing and registration, based on AS/NZS 5125, as well as noise testing to ISO 3741. As heat pump water heater suppliers already conduct physical tests to AS/NZS 5125 and governments already maintain registers of other appliances, the additional costs should be relatively minor in comparison with the potential public benefits.
  2. Introduce MEPS and functional performance requirements, including addressing cold temperature performance and noise issues, with proposed notification of the requirements no later than mid-2013 and requirements to take effect by mid-2014. There are likely to be significant benefits from ensuring that all models are fit-for-purpose and achieve MEPS.
  3. Enable public access to the registered data, with models identified. This will provide potential purchasers, competing suppliers and regulators with an overview of the range of products and performance levels on the market.
  4. Develop energy labelling standards, either as a mandatory requirement or initially for voluntary use by suppliers.
  5. Develop a roadmap of potential future increases in minimum performance criteria and associated measures such as labelling.

From the author’s perspective, what is also needed is promotion of the costs and benefits of HPHW units. In Australia this is almost totally lacking.

Heat pumps in the residential sector for space heating and cooling
Based on heat pump technology, reverse cycle air conditioners (RACs) are increasingly used for space cooling and heating in the Australian residential sector. Space cooling penetration is now applied in the majority of Australian residences (see Table 8) mainly through the use of RACs. In the states/territories (New South Wales, Victoria, Tasmania and South Australia) where there is a significant heating load, RACs are increasingly being used for space heating, particularly in non-gas areas.

Except in Western Australia and the Northern Territory, new air conditioner sales are virtually all reverse air cycle (RAC) units, which can be used for heating and cooling. In hot, dry regions, evaporative air conditioners are very effective and space heating requirements are low.

In gas areas, the high efficiency of RACs (COPs of 3.5 to 4.5) virtually offsets the lower price of natural gas. With gas at A$16/GJ and electricity at $250/MWh, gas space heating costs per year are A$750/year and RAC space heating costs are A$794/year.

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Conclusions of heat pump hot water review in Australia and New Zealand
The following can be concluded after reviewing the use of HPHW in Australia and New Zealand. First, there is significantly more potential for HPHW in Australia compared with New Zealand. Second, in Australia, climate conditions and the policy environment are favourable to HPHW. Third, HPHW incentives, although reducing in Australia, continue to provide attractive payback returns to HPHW units. Fourth, payback returns and greenhouse performance vary regionally: potential for HPHW units is greater in New South Wales, Queensland, South Australia and Western Australia. Finally, greater HPHW market penetration requires monitoring and reporting of HPHW performance combined with enhanced promotion of the reliability and benefits of the technology and addressing the end-of-life, like-for-like issue.

The Australian and New Zealand MEPS initiative is an early (1999) and major element of national energy efficiency improvement (EEI) and climate change policies. MEPS was originally developed under the National Appliance and Equipment Energy Efficiency Program (NAEEP).

Minimum Energy Performance Standards now form part of and are developed under the Equipment Energy Efficiency (E3) Program, a joint Australian and New Zealand initiative. Energy labelling (part of E3) was introduced into both Victoria and New South Wales in the late 1980s, and the first MEPS were introduced in Australia in 1999. They now cover a range of residential, commercial and industrial appliances and equipment. Once introduced, MEPS levels are regularly updated and new energy using appliances and equipment continues to be added. In addition to this, the energy rating algorithms used for appliances are updated from time to time and made more stringent, so the labelling scheme continues to encourage the marketing of high-efficiency appliances.

The MEPS set a regulated minimum energy performance standard for appliances and equipment covered by the program. That is, MEPS prevent (subject to compliance) low energy performance units from entering the Australian market and, therefore, contribute to savings in consumer operating costs and reducing generation requirements. It is illegal to sell products which do not meet the required MEPS levels. Mandatory energy rating labels give an indication of energy performance (higher stars = higher efficiency). Some appliances (refrigerators/freezers, air conditioners and televisions) are subjected to both MEPS and mandatory energy labelling. In general, where both MEPS and energy labelling apply to an appliance, the sales weighted star rating of products sold exceeds the MEPS levels by a significant margin.

In 2007, a total of 5 appliance categories were subjected to mandatory labelling, and 9 appliance categories were subjected to MEPS. By the end of 2010, 7 appliance categories were subjected to mandatory labelling (plus 2 voluntary levels) and 16 appliance categories were subjected to MEPS. In 2009, MEPS were introduced for chiller towers, close controlled (computer room) air conditioners, external power supplies, set top boxes, self-ballasted compact fluorescent lamps and incandescent lamps. Both MEPS and energy labelling have been introduced for televisions.

The implementation of MEPS and energy labelling is coordinated through a joint Commonwealth, state and territory government E3 committee.

Given the long MEPS history and the regular updates and additions, the determination of the additional impact of the MEPS on energy use and greenhouse gas emissions is complex. It is very difficult to estimate how energy performance for each group of appliances would have changed in the absence of MEPS, and this becomes more difficult as the time elapsed since the introduction of a MEPS increases. Due to MEPS in countries to which export appliances to Australia, there may be improvements in performance not related Australian regulatory change.

George Wilkenfeld and Associates (GWA), the MEPS impact consultant to the E3 program, provided the GHGA MEPS national and state impacts to 2025 in a 2009 report. In the report’s analysis, GWA attempted to estimate the beyond business-as-usual (BAU, no MEPS) impact of MEPS. That is, the estimated impacts did consider EEIs, which would have arisen if the MEPS had not been implemented. The estimates also considered the impact beyond BAU of new MEPS initiatives scheduled to be implemented over the 2009, 2010 and 2011 period (the next MEPS triennium).

The resulting GWA estimates do not include adjustments related to estimates of rebound, non-compliance with MEPS and deterioration of appliance and equipment over time. These factors could reduce these estimates. However, the GWA estimates also assume that carbon pricing would be introduced but in 2011.

Estimates by GWA of E3 program savings in the National Electricity Market (annual) over 2000–2022, from a 1999 efficiency base for new appliances and equipment, are presented in Table 9. The estimates are additional in that they assume that without MEPS and labelling new appliances and equipment efficiencies would have been ‘frozen’ (i.e. fixed) at 1999 levels. On this basis and given the extensive range of appliances and equipment the MEPS apply to, the estimated savings are substantial.

Electricity savings in Australia from E3 programs from 2000 to 2009 were estimated by GWA for E3 to be approximately 6,750 GWh and from 2009 to 2022 increasing by approximately 26,500 GWh.

References

Australian Bureau of Statistics (2011), ‘Environmental Issues: Energy Use and Conservation’, Cat. No. 4602, March, Australian Bureau of Statistics, Canberra.

Australian and New Zealand Governments (2012), ‘A study for the Australian and New Zealand Governments’ E3 Equipment Energy Efficiency Joint Initiative: The study entitled Product Profile: Heat Pump Water Heaters, Air-source Heat Pump Water Heaters in Australia and New Zealand, June 2012 (E3 report – available at www.energyrating.gov.au).

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National Economic Review

National Institute of Economic and Industry Research

No. 67               November 2012

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.

Editor: Kylie Moreland

© National Institute of Economic and Industry Research

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ISSN 0813-9474

Energy and environment

Graham Armstrong, Consultant, NIEIR

Abstract

This paper first reviews the United Nations Framework Convention on Climate Change Conference of the Parties in Durban (COP-17) and discusses the global and Australian developments during the months leading up to COP-18 in Doha, Qatar in November–December 2012. The legislation progress and climate action developments of Brazil, South Africa, India, China, the USA, the European Union and Australia are reviewed. Although the Durban climate talks were able to maintain momentum in the global climate effort, it remains to be seen whether the Durban Agreement will in fact be a ‘historic breakthrough’ or a deferment of ambitious climate action into the future. Second, the paper reviews Australian climate change policy developments up to 12 September 2012.

Introduction

Since the Durban Conference of the Parties of the United Nations Framework Convention on Climate Change Conference (COP-17) in December 2011, there has been little comment on global climate change policy. In Australia, comments and debate have focused almost exclusively on the Clean Energy Futures Act (CEFA), particularly the perceived negative effects of carbon pricing. Globally, more countries and regions have developed (e.g. British Columbia in Canada, some US states and China), or are developing, carbon pricing (e.g. through taxes or emission trading schemes (ETS)) (e.g. South Korea) and complementary initiatives (e.g. renewable energy, energy efficiency improvement (EEI), forestation and agriculture and transport fuel). A review of COP-17 Durban and events leading up to COP-18, Doha, Qatar are outlined in what follows.

Durban

Outcomes of Durban

Despite the disappointment that annual negotiations on a post-2012 regime have not resulted in an overall global climate agreement with quantified objectives for, at least, major greenhouse gas (GHG) emitters, there have been several positive developments. For instance, there are agreements on adaptation, the Green Climate Fund and the Technology Mechanism. With the Durban Platform, the division between developed and developing countries in terms of differentiated responsibilities has become less strict. Moreover, the focus seems to have shifted from quantified commitments (what) towards how pathways for low emission development can be realised.

Negotiating a climate policy package with quantified targets for countries (such as tried in Kyoto) is very complex. Countries negotiate within an intergovernmental setting without an overarching authority so that no country can be committed to sign a deal that it does not want. Consequently, negotiations become a game to form a coalition, the size of which is determined by the countries for which the benefits of joining the coalition are higher than the costs. As climate change is a global issue, the coalition needs to be global, so that for all countries the benefits are higher than the costs.

Negotiations have become so complex that an ambitious package with strict emission reduction commitments is likely to drive up costs. This is especially the case with many low emission technologies still being early on their learning curves with much R&D to be done, followed by deployment in the market and diffusion to commercial application. In this respect, the current financial market turbulence, with reduced availability of private and public financing, does not work in favour of new efficient technologies.

Moreover, as the Kyoto Protocol has shown, costs of quantified national commitments are difficult to predict and become an endogenous economic parameter.

Practice has shown that once a country realises that it cannot comply with the target, it can withdraw from the agreement (e.g. Canada stepped out of the Kyoto Protocol). This is especially the case if other countries are in a similar position and are willing to join the move.

On the benefit side, there is a challenge to make countries aware that ambitious climate actions could also support sustainable development objectives. There is always a risk that climate policy-making resembles the prisoner’s dilemma: if a country does not undertake actions but the others do, then it benefits from the others; if the country fears that it is the only one taking strong actions, then it will be reluctant to do so. In both cases, an individual country, in an uncoordinated setting, has an incentive not to act. The challenge, therefore, is to find ways to support countries in maximising climate and development benefits against given resources, irrespective of what other countries do.

How have the recent climate negotiations managed to address this challenge? After Durban, media headlines were not spectacular. There was a general feeling that there had been an agreement not to agree now. Durban did not provide hard figures. Canada avoided penalty by stepping out of the Kyoto Protocol. The week after Durban, this action was emphasised.

However, Copenhagen, Cancun and Durban have delivered important results, with the establishment of a framework for adaptation, through the Green Climate Fund and the Technology Mechanism, as well as provisions such as low carbon development strategies and the Technology Needs Assessments. Although not enough yet for the ‘Green Industrial Revolution’ that United Nations Framework Convention on Climate Change (UNFCCC) Executive Secretary Figueres desires, these mechanisms and provisions could considerably contribute to required system changes in countries for climate and development, backed by international capacity support, with financial, technology and knowledge transfer. All these steps are modest, but they do reflect progress.

The Durban Agreement: A deal to negotiate a deal

‘We have made history’, said UN climate negotiation chair Maite Nkoana-Mashabane when gavelling the longest negotiation session in the history of the two decades of climate negotiations to a close. However, considerable uncertainty remains as to the effectiveness of the Durban Agreement to realise sufficient climate change mitigation. This review investigates the main elements of the Durban Agreement (these are briefly summarised in Box 1) and the perspectives of several negotiating Parties, analyses the Durban outcome, and looks forward to Qatar (COP-18).

After the failure of Copenhagen (2009) and the only modest success of Cancun (2010), expectations for Durban to realise a comprehensive, legally binding agreement were not high. As such, the negotiations were essentially preoccupied with two main objectives:

  • to maintain momentum in the process to realise an agreement that incorporates all main emitting Parties (especially the USA and the BASIC countries, Brazil, South Africa, India and China); and
  • to revitalise the Kyoto Protocol through the establishment of a second commitment period and, as such, prevent the creation of a commitment gap.

Box 1 E and E NER 67

The Durban Agreement

The outcome of the Durban negotiation round, which ran from 28 November until 11 December (2 days longer than scheduled) is the Durban Agreement. One of the main components of the Durban Agreement is the establishment of a second commitment period of the Kyoto Protocol (UNFCCC, 2011a). Within this second commitment period (which is scheduled to start in 2013 and end in either 2017 or 2020 (to be decided upon at COP-18)), the aim is to ensure aggregated emissions by Parties included in Annex I are reduced by at least 25– 40 per cent below 1990 levels by 2020 (IISD, 2011). To realise this aim, it is the intention to convert the Cancun Agreement pledges for emission reductions into quantified emission limitation or reduction objectives (QELRO), information on which was to be submitted by the Parties to the Ad-hoc Working Group–Kyoto Protocol (AWG-KP) by 1 May 2012. An important unresolved issue in this regard is the implication of carry-over of assigned amount units (AAUs (abatement credits)) from the first to the second commitment period on the scale of emission reductions to be achieved (IISD, 2011). In addition, to eliminate the ‘ambition gap’ between the pledged reductions and the above emission reductions goals, the AWG-KP decision emphasizes the relevance of the 2013–2015 review of pledges.

Furthermore, the Durban Agreement outlines a negotiation process that is to result in a ‘protocol, or legal instrument, or agreed outcome with legal force’ that covers all negotiating Parties (UNFCCC, 2011b) and is to come into effect and be implemented from 2020. As such, the Ad Hoc Working Group on a Durban Platform for Enhanced Action (AWG-DP) is to complete its work no later than 2015. An important consideration in the process will be to raise the level of ambition in terms of emission reductions. This consideration will be informed by the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report, the 2013–2015 review and the work of the subsidiary bodies.

The Durban Agreement also allows for the completion of the design of the Green Climate Fund and designates the World Bank as the interim trustee. With these developments, the Fund should be operational in 2012 (UNFCCC, 2011c). The aim of the Fund will be ‘to promote the paradigm shift towards low-emission and climate-resilient development pathways’ by providing balanced support for developing countries between mitigation and adaptation efforts in the context of  sustainable development. With the aim of making the Technology Mechanism fully operational in 2012, the negotiations also focused on the two components of the Mechanism: the Technology Executive Committee (TEC) and the Climate Technology Centre and Network. The Durban Agreement contains a decision on the modalities and procedures of the TEC policy-making body (UNFCCC, 2011d). The TEC has had its first meeting and has developed a rolling work-plan for 2012–2013. This is an important step towards the operationalisation of the Technology Mechanism with the objective of enhancing action on technology development and transfer to support action on mitigation and adaptation. Besides financial support, support for technological development is seen as a major component of an effective climate action strategy.

Perspectives and opinions

The Durban Agreement was heralded by most negotiating Parties as a positive development towards a global climate policy regime.

The process established under the AWG-DP mirrors the call for a ‘roadmap for climate action’ made by the European Union (EU) prior to Durban. The EU posited that, for it to be persuaded into a second commitment period of the Kyoto Protocol, a pathway to universal action was a prerequisite. Therefore, it is not surprising that the EU sees the Durban Agreement as a ‘historic breakthrough’ document capable of finally realizing a global and ambitious climate policy regime (Ebels, 2011).

An important development in the international negotiations was the alignment of the small island states and least developed countries with the position of the EU (Vidal and Harvey, 2011a). This coalition allowed for a stronger negotiation position to confront the other Parties. In addition, the African countries were determined to prevent the burial of the Kyoto Protocol on African soil (IISD, 2011).

Because the USA has consistently called for symmetry between developing countries (especially China and India) and the developed countries in terms of climate policy actions, it eventually supported the proposed roadmap of the EU (Vidal and Harvey, 2011b). As such, the USA is satisfied with the Durban Agreement as it ascribes to a legal document in 2020. The US climate envoy Todd Stern stated that the Agreement:

‘had  all  the  elements  that  we  were  looking  for’

(EurActiv, 2011a; U.S. Department of State, 2011).

With a large number of Parties backing the EU proposal, attention turned to India and China. Early on in the negotiation process, China signalled some flexibility to participate in a climate regime with legal force (Conway-Smith, 2011). In return for support for the roadmap process, the EU offered to commit to a second period of the Kyoto Protocol. The formulation of what form of legal status the 2020 agreement would entail, without any current clarity of what the specifics of the deal are going to be, encountered fierce resistance, especially by India (Vidal and Harvey, 2011c). As such, the realization that the BASIC countries have agreed to a commitment with legal force ‘applicable to all Parties’ is a substantial deviation from their original negotiation position and, therefore, a major concession.

Effectiveness of Durban

With the establishment of the AWG-DP and the agreement on a second commitment period for the Kyoto Protocol, the multilateral process seems to have been revitalised. However, several aspects of the Durban Agreement allow for critical analysis. Importantly, Canada, Russia and Japan will not participate in the second commitment period of the Kyoto Protocol (Euractiv, 2011b). This signals the dwindling political importance of the Kyoto Protocol. Furthermore, the second commitment period of the Kyoto Protocol is still to be inscribed with new QELRO and amendments, and the length of commitment is still to be decided. Therefore, ‘commitment’ is limited. As such, all the second commitment period appears to achieve for now is to realise continuity for climate action.

In addition, due to persistent pressure provided by the USA, India and China, the Durban Agreement specifically incorporates the year 2020 for implementation of a new climate regime (Lynas, 2011). As such, this formulation appears to exclude the option for earlier implementation even if political agreement has been achieved. The wording of the AWG-DP aim to realise a ‘protocol, or legal instrument, or agreed outcome with legal force’ is sufficiently ambiguous to allow for multiple interpretations. In fact, when one considers the considerable negotiation effort invested in this formulation, it is not at all clear whether the different Parties have a similar understanding of what is to come into effect in 2020.

These two aspects are significant because they separate mitigation ambition and the legal nature of targets until 2020 (Lynas 2011). The voluntary Copenhagen process, dubbed pledge-and-review, will be the only system in which all Parties participate until 2020. Critics point to the fact that the pledged emission reductions made so far are insufficient to limit temperature increase to 2°C (CAT 2011). Moreover, while the Durban Agreement notes that ‘the process shall raise the level of ambition’, it does not provide methods to actually do so. This limits the potential of the Agreement.

The participation by all Parties in a legal climate regime signals the end of the Kyoto Protocol dichotomy of Annex I Parties and non-Annex I Parties. As such, it appears Durban will allow for the reformulation of the meaning of the Convention principle of ‘common but differentiated responsibilities’ into a spectrum of climate action in light of country-specific development. This could turn out to be one of the main achievements of Durban as this dichotomy was one of the principal obstacles for global agreement on climate action throughout the history of the negotiations on climate change.

Durban Agreement: A historic breakthrough or a deferment of ambitious climate action?

The long timeline involved with the established process raises doubt as to the commitment of negotiating Parties to undertake climate action. This doubt is further substantiated by the history and dynamics of the climate negotiations, which clearly outline the trade-offs made between participation, compliance and stringency. The negotiation process as it is currently formulated postpones multilateral action outside of the Kyoto Protocol to 2020.

In the meantime, climate action will need to be initiated unilaterally through the voluntary pledge-and-review approach, which, in its current form, offers no effective approach to climate change. This realisation not only stems from the notion that current pledges and actions are insufficient to realise the emission trajectory required to limit climate change to 2°C, but also finds a basis in the notion that voluntary commitments have a historically inadequate performance record both inside and outside the climate change negotiations. Moreover, because the pledge-and-review approach does not provide incentives for ambitious action, the level of commitment is unlikely to become sufficient after Durban.

The 2013–2015 review, the Fifth Assessment Report by the IPCC, and the work of the subsidiary bodies are to provide means to reduce this gap in ambition over the next couple of years. As such, while the Durban climate talks were able to maintain momentum in the global climate effort, it remains to be seen whether the Durban Agreement will, in fact, be a ‘historic breakthrough’ or a deferment of ambitious climate action into the future.

The USA

The US administration has proposed CO2e emission limits for new electricity generators at 454 kg CO2e/MWh. Unless carbon capture and storage (CCS) can be applied commercially, this effectively restricts new generators to combined cycle gas turbines (CCGT) or renewables. The rules do, however, allow new coal-fired plants to exceed the cap for 10 years provided they subsequently make up the difference by installing effective pollution controls: essentially declaring that CCS may be viable 10 years after a new coal generator is built.

Low gas prices and lower demands for electricity have favoured gas generation, kept electricity prices low and made coal generation less competitive. Continuation of these trends means that the proposed GHG inventory (GHGI) (tCO2e/MWh) rules would not have a significant impact.

Under the US Clean Air Act, with Supreme Court affirmation, the GHG emissions are a threat to ‘public health and welfare’ and GHGI rules will have to be developed for existing generators.

The European Union

European Union Allowance Unit (EUA) CO2 prices continued at low levels through the first half of 2012, at €6–9/t (A$7.5–11.25), well below the Australian CEFA prediction of A$29/t in 2015–2016 and the Australian floor price of A$15/t (see discussion below).

The  UK  Government  has  proposed  a  floor  price  of €30/t (A$38) in 2009 prices, well above the current EUA price. UK programs and regulations mean that, effectively, in the UK CO2e prices are in the A$25–30/t range. The EU is examining the possibility of reducing permit caps to provide a stimulus to attain higher EUA prices.

Current EU emissions are well below the current cap for the 11,000 liable companies, due mainly to economic conditions: hence, the EUA price drop from approximately €30 in 2008 to today’s levels of <€10/t.

Sales of permits to raise revenue for green energy projects and new EEI initiatives will add to EUA oversupply, which could reach 8.45 × 106 available permits in 2020 against a planned 2020 cap of 1.8 × 106 permits.

In December 2011, an EU committee proposed three possible strategies:

  • withhold (set aside) a tranche of permits from the market;
  • withhold 1.4 billion permits; or
  • tighten the cap.

Tightening the cap, the most effective solution (although by how much is hard to determine), would be strongly resisted by heavy emitters, such as Poland, and would reduce EU investor confidence. Cap reduction would have to be spread among EU states, which might not be easy depending on the size and timing of the cap reduction. Improving economic conditions could ease the cap reduction problems. A gradual reduction could be monitored to gauge the economic impact, which could be quite modest as the market adjusted to emission reductions by developing lower than expected cost abatement actions.

Australian developments

On 1 July 2012, the start of the fixed carbon price period commenced. As it approached, support for the carbon package dropped to below 40 per cent. Negative comments from some industry groups and the Federal Opposition continue to dominate media coverage of the legislation. Positive aspects of the package, such as compensation, early mover advantages, transition to an ETS, grants for EEI in the industrial sector and movement by other countries and jurisdictions, do not receive nearly as much publicity. Surveillance of the international press on climate change policies reveals, overall, a quite different story: one that is much more positive.

A particular aspect of the debate is the A$23/t CO2 starting price on 1 July 2012: it is above other specific CO2e prices (except in British Columbia in Canada), while the EUA price continues to be <€10/t. However, in other jurisdictions, regulatory policies have a price impact, and while probably <A$20/t, are pushing the global economy towards a lower GHGI level compared with business as usual (BAU). In the UK, the EUA prices and regulatory policies and initiatives have pushed the effective CO2 price above A$25/t.

Clean Technology Investment Program

Further details of the Clean Technology Investment Program (CTIP) were released in April 2012. Under the program, A$800 million is allocated for general manufacturers and another A$200 million for food and beverage processors and metal foundry and forging firms. For firms with turnovers of <A$100 million, 1:1 grants will be available for funding of <A$500,000. For grants from A$500,000 to A$10 million, applicants will be required to contribute A$2 for every A$1 from government. For grants of +A$10 million, a contribution of A$3 for every A$1 from government will be required (co-investment).

The total expenditure (private plus government) for EEI is likely to be well below the potential for economic EEI investment over the next 20 years. However, the CTIP is an appropriate initiative that could stimulate further EEI investment.

The CTIP application process, based on previous requirements, may be overly administratively burdensome for small and medium sized enterprises (SMEs) where no employee is dedicated to the grant application process. This does, however, create an opportunity for firms, such as Energetics, that specialise in EEI to work with SMEs on CTIP applications (also VEET in Victoria).

The CEFA programs (CTIP and the Clean Energy Finance Corporation (CEFC)) require statements on Australian participation in applications in an effort to ‘maximise’ Australian content of programs (not a mandatory percentage as in Ontario, Canada).

International permits and the floor price for permits

A floor permit price of A$15/t was proposed in the ETS phase of the CEFA. Up to 50 per cent of a firm’s liability under the CEFA was to be accessible from eligible international permits under the Clean Development Mechanism certified emission reductions (CERs) and joint implementation (JI) emission reduction units. Several politicians, industry groups and analysts proposed removing the floor price and letting the market (domestic and international) determine the price. Note that at a CO2e price below A$20/t CO2e, the impact on BAU emissions is likely to be negligible.

A ‘surrender tax’ on international permits was proposed if international permit prices continued to be below A$15/t. For example, if a permit were purchased at A$12/t, a A$3/t levy would be imposed to arrive at the A$15/t floor price.

In the ETS phase it seemed there would be two permit markets:

  • The international permit market with prices set in those markets: up to 50 per cent of the ETS cap permits could come from this source.
  • The domestic permit market for the balance of the ETS cap permits liability (which could be 100 per cent of the ETS cap if the international price were above the domestic price). Several politicians, industry groups and analysts called for a lower or no floor price, but this approach was rejected by the government. At CO2e prices below A$20/t, our analysis indicates that there will be price impacts but little impact on GHG abatement (GHGA).

Caps for the post-fixed carbon price will not be set until 2014. The caps set will depend on:

  • the 2020 target (now 5 per cent below 2000 levels by 2020);
  • progress towards the target by 2014; and
  • the schedule decided on for annual progress towards the target.

To meet the current 2020 target, modelling in 2011 estimated that approximately 160 Mt CO2e/a would need to be removed from trend GHG emissions. By 2014, the carbon tax and associated programs might have reduced this GHGA to 140 Mt CO2e/a, but the 2012–2014 GHGA impact is quite uncertain and could be very low. Assuming 50 per cent of the 140 Mt came from international permits at A$15/t (price could be much higher by 2020), 20 Mt would need to come from domestic GHGA over 2014–2020. The first cap period would presumably be for 2015–2016, the first ETS year after the fixed price years of 2012–2013, 2013–2014 and 2014–2015. Over the 2015–2016 to 2019–2020 period, domestic GHGA could come from the following.

  1. Closure of 2,000 MW of GHGI coal capacity and replacement with CCGT capacity (but not likely to be viable at under A$40/t CO2e).

With a 90-per cent capacity factor (CF) brown coal closure (2,000 MW) and a GHGI of 1.5 t CO2e/MWh, annual saving would be:

2,000 × 8.76 × 0.9 × 1.5 × 103

t = 23,652,000 t.

Replaced by 2,000 MW of CCGT at 90 per cent CF and a GHGI of 0.4 t CO2e/MWh:

2,000 × 8.76 × 0.4 × 103 = 6,307,200 t.

There is a net saving of 17,344,000 t per annum.

To save 70 Mt/a would require approximately 10,000 MW of coal of higher (>1.2 t CO2e/MWh) coal capacity to be displaced by CCGT requiring a CO2e price of A$40–50/t depending on relative coal and gas prices. A total of 45 Mt CO2 from displacing approximately 6,000 MW of higher GHGI coal might be feasible at approximately A$50/t CO2e.

  1. The Carbon Farming Initiative (CFI) might deliver 10 Mt CO2e at <A$25/t CO2e but levels and prices are quite uncertain.
  2.  Enhanced EEI might deliver 10 Mt CO2e at <A$0/t CO2e (value of discounted energy savings less investment cost).
  3. Renewables (above the renewable energy target (RET), which is included in BAU) at A$50– 150/t CO2e, approximately 5 Mt CO2e might be possible but unlikely given current trends and policies.

The above very preliminary estimates indicate that the target could be reached with international permits at an average cost of approximately (price × per cent contribution of GHGA required by 2021):

15 × 0.5 (international) + 50 × 0.32 (fossil generation) + 20 × 0.07 (CFI) + 0 × 0.07 (EEI) +   100 × 0.04 (renewables) = A$(7.5 + 16 + 1.4 +  0 + 4) = A$28.5/t CO2e (This is not the market permit price. It is the average GHGA price paid by liable parties.)

The above example indicates a potential path for achieving a 2020 target. Emissions would be reduced (50 per cent overseas and 50 per cent in Australia). However, how would the permit market evolve?

September 2012 update

As outlined above, the permit floor price of A$15/t CO2e in the ETS period was criticised as:

  • being too high and unnecessary in some industry analysts; and
  • being too low to bring about structural change toward low emission technologies by others.

In early August, it was reported in the media that changes were in the offing to limit further (from 50 per cent of liabilities) the proportion of international permits that could be acquired by liable parties. In the early years of the ETS (2015–2016) it has become more likely that international permits could be available at prices >A$5–10/t CO2, necessitating an administratively cumbersome surrender ‘tax’ top-up to A$15 from the price actually paid by liable parties.

On 28 August, the Federal Government announced major climate change policy changes. These changes are:

  • removal of the floor price of A$15/t CO2e, which was to operate over 2015–2016 to 2018– 2019, the first 3 years of the ETS phase;
  • linking of the ETS phase directly to the EU market (initially one-way, Australia buying 1 g EEAAs, but two-way by 2018), resulting in EU permit prices being the same as Australian prices; and
  • limiting access to CDM CERs and JI emission reduction units (ERUs) to 12.5 per cent of a liable entity’s liabilities (previously 50 per cent).

The Treasury modelling estimate of a A$29/t price in 2015–2016 was retained.

Issues

  1. Price of EU permits post 2014–2015. Current estimates are approximately A$12 in 2015 and A$20 in 2020. However, these estimates depend on:
  • EU growth with the current EU scheme; and
  • any changes to the EU scheme (e.g. cap tightening and deferring permit auctions) that (several proposed) that would have the effect of increasing the EU permit price.
  1. Approach taken for the proposed auctioning of domestic permits to ensure that the 2020 target of a 5-per cent reduction on 2000 emissions by 2020 is achieved. This would not become evident until liable parties began buying ERUs and EU AAUs to cover their liabilities.
  2. At permit/CO2e prices below approximately A$20/t, there would be negligible domestic GHGA from price responses by consumers and generators, although GHGA from complementary policies would continue. Limited domestic GHGA over 2015–2020 is likely to result in higher GHGA action costs, if desired, post-2020.

September 2012 status of Australian climate change policies

The 2020 target remains at 5 per cent below 2000 levels, requiring 159 Mt CO2e of abatement by 2020 according to the Treasure 2011 modelling in the Strong Growth, Low Pollution (SGLP) report (Australian Government, Treasury). In 2009–2010, emissions were 578 Mt CO2e and in the Treasury modelling, the 2020 BAU (i.e. no CEF Act policies) was 679 Mt CO2e.

At a carbon price of A$29/t CO2e by 2020, domestic emissions were estimated in the SGLP report to be 621 Mt CO2e (i.e. 58 Mt CO2e below BAU without carbon pricing), but approximately 12 per cent above 2000 levels of 550 Mt CO2e. This gives a 2020 target of approximately 520 Mt CO2e, 159 Mt CO2e below 2020 BAU emissions of 679 Mt CO2e. With domestic emission reductions of 58 Mt CO2e, 101 Mt CO2e would come from international permits.

Now with CEF Act policies in place with lower projected electricity growth rates, 2020 emissions are likely to be much less, perhaps by around 60 Mt CO2e. This would reduce the abatement task to meet the 2020 target to approximately 100 Mt CO2e.

Given the policy change to restrict JI and CDM Kyoto credits to 12.5 per cent of liabilities, the linking with the EU and the availability of EU permits (EU assigned abatement units (EUAAs)) for acquitting liabilities, and the reduction in the abatement task, where will permits for the attainment of the 2020 target now come from?

2020 emissions, targets and greenhouse gas abatement sources

  1. 2020  emissions  under  BAU  (i.e.  without  the CEFA) will now be approximately 620 Mt CO2e, as against 679 Mt CO2e in the Treasury 2011 SGLP, due to slower growth in emissions and responses to the carbon tax and CEF Act complementary measures.
  2. Attainment of the 2020 target (5 per cent below 2000 emissions by 2020) would then require abatement of approximately 100 Mt CO2e (620 – 520), compared with 159 Mt CO2e in 2011 SGLP. (Note: levels in the SGLP are not entirely consistent with respect to 2000 levels, projected 2020 levels and the abatement task required.)
  3. At 100 Mt CO2e  abatement required 12.5 per cent (12.5 Mt CO2e ) could come from Kyoto (CDM and JI) credits at <$10/t Mt CO2e , perhaps <$5/t CO2e .
  4. Some of the other 87.5 Mt CO2e (100 – 12.5) could possibly come from purchase of EU permits (EUAAUs) and from Australian CFI permits if the prices were below domestic auctioned permit prices. EUAAUs are permits to emit CO2. Currently, a surplus of EUAAUs are available due to issuance being greater than requirements, mainly due to low economic growth causing emissions to be lower than anticipated. Available permits do not result in emissions abatement unless their price is high enough to induce a switch from a higher GHGI source to a lower GHGI source. Thus, purchase of EUAs may or may not result in GHGA. Given the foreseeable surplus amount of EU permits, GHGA from purchase of these permits is likely to be negligible. Abatement to attain a given target must be sought elsewhere.
  5. Other abatement could come from additional carbon price response and complementary measures (e.g. CTIP, CEFC and CFI).

However, note that under the CEF Act, closure of 2,000 MW of high GHG intensive generators was proposed, entailing negotiation of closure with the generator owners. Prime targets for closure were Hazelwood, Yallourn and Morwell brown coal operators in Victoria, Playford B (low grade black coal) in South Australia and Collinsville (black coal) in Queensland. However, on 3 September the government announced the failure of negotiations due to unacceptably high closure dollar demands (>A$2 billion expected cost) by the generation companies. With lower than previously expected permit prices in the ETS phase, the economics of operating high GHGI plants have improved, hence their asset values.

The closure would have saved up to 23 Mt CO2e per year out of the required reduction to meet the 2020 target of a now estimated 100 to 120 Mt CO2e (lower than the previously estimated 160 Mt CO2e due to lower electricity and gas demands and impacts of complementary policies). The government claims that the closure abandonment will not affect target attainment. Why? Because of lower target attainment requirements or lower costs of other GHGA opportunities?

This failure to close the 2,000 MW of highest GHFI generators, together with compensation for carbon pricing to high GHGI generators and lower CO2e prices, makes it much less likely that significant gas generation will replace coal generation.

  1. On 1 September, the government announced that 40 million permits would be auctioned in 2013– 2014 at a projected price of $15/t CO2e. If the EU AAU price is <$15/t CO2e, why would liable parties bid $15/t CO2e at the auction for up to 40 million permits unless EU AAU access was restricted (not apparent)?
  2. How then will the target be attained? Presumably, by monitoring and frequently announcing progress towards the 2020 target and, if necessary, taking further GHGA action (e.g. by subsidising the new gas base load) to attain the target.
  3. Liable parties will continue to buy permits from CDM, JI and the EU to meet their liabilities unless domestic permit auctioning results in prices for domestic permits <EU AAU prices. If prices are less than the EU AAU prices, domestic permits can be sold into the EU market when two-way linking is established.
  4. In conclusion, to attain the 2020 target under the new permit availability arrangements, target GHGA must be continuously estimated and announced, and progress toward the target continuously monitored and announced. This is necessary to limit 2020 emissions to approximately 520 Mt CO2e. With the current (September 2012) polices, it seems very unlikely that the 2020 target will be attained.

Liable parties

Generators

Fossil generators would have to purchase permits to cover their liable emissions from accredited suppliers (see below).

Other liable parties

Other liable parties would attempt to reduce their emissions at a cost below the expected permit price by changing production characteristics and improving energy efficiency (assisted by CEFA programs). The resulting (balance of) liable emissions would be purchased in the permit market(s).

Permit suppliers

Carbon Farming Initiative

Accredited CFI units (Australian carbon units (ACUs)) can be sold directly to liable parties. If non-liable party EEI ‘suppliers’ could reduce their emissions impact through EEI and the use of renewables, they could become, for example, accredited suppliers of permits.

Government

Permits will be auctioned on the basis of the cap for each year. Liable parties will bid for these auctioned permits on the basis of requirements and marginal costs of internally reducing their emissions and purchasing international permits (depending on price and CFI AEUs).

Potential evolution of greenhouse gas emissions, greenhouse gas abatement and carbon prices over 2012–2013 to 2020–2021

In regards to estimated target emissions, does the target refer to total emissions or to liable emissions (liable emissions are approximately 65 per cent of total emissions)? Some emission reductions will come from non-liable sectors, such as agriculture.

In 2012–2013 to 2015–2016 there will be some impact of the fixed CO2e price, with the impact depending on the elasticity of demand for covered fuels, particularly electricity. Complementary measures and economic conditions (e.g. closures and household formation) will also have an impact. Note that the now expected carbon price impact will be less than the total of other price increasing impacts (e.g. fuel prices, network costs and green program costs) and not enough to significantly shift generation merit order. CEFA complementary measures are unlikely to have a significant impact until around 2015. These impacts will depend on the 2013 election results.

Overall, it is now expected that there will only be a small departure from BAU trends over this period.

The impacts of the CEFA over 2015–2016 to 2020– 2021 will depend on:

  • the CO2e permit prices over this period and the expected prices beyond this period;
  • economic conditions; and
  • the impacts of complementary measures.

Changes to the CEFA (likely under the Opposition and global pressure) would change the emission path and policy impacts.

Preliminary analysis suggests that under the CEFA, as it stands, the target (2020) could be reached if actual and expected average permit prices exceed approximately A$30/t; that is, until a combination of complementary measures and CO2e prices induce a significant (6,000–8,000 MW) shift from coal to CCGT generation. No other domestic actions appear likely to fill the target gap if this change does not eventuate.

Liable parties

In April 2012, the Clean Energy Regulator released a list of 280 liable parties: more will be added later. This is preliminary and well below the estimated 500 liable parties estimated in the CEFA analysis. A particular liable party issue is the liability of landfill sites operated mainly by municipalities. Although the minimum liable party emissions limit is 25,000 tCO2e, because landfills emit methane (×21 global warming potential) many sites, seemingly small, could become liable parties. Reduction of emissions is possible through collection of methane (from anaerobic digestion of organic wastes) and combustion to produce electricity (eligible under RET) and heat. This is practiced widely overseas (some with Australian technology) and at some landfill sites in Australia.

Accordingly, the ‘problem’ could be resolved with best practice waste management, such as at Nanaimo in British Columbia, Canada.

In June 2012, BHPB said it would not be in favour of rescinding carbon pricing but would attempt to make it ‘more optimal’ (not explained). Over 2006–2017, BHPB has a target of holding emissions constant despite a large increase in production from the company’s range of operations.

Lowy Institute Poll, 2012

The Lowy Institute’s 2012 Poll, an opinion survey of 1,005 Australian adults in March–April 2012 on a range of issues reported the following on climate change:

  • 63 per cent are against the Clean Energy Futures Act (carbon pricing elements);
  • 45 per cent are strongly against the Act (53 per cent of men and 36 per cent women);
  • 35 per cent are in favour of carbon pricing;
  • 52 per cent oppose the legislation as it will result in job losses;
  • 38 per cent say it is not necessary to act on climate change before other countries (were they told some countries were acting?);
  • 57 per cent are in favour of the Coalition removing the ETS (39 per cent with a degree) but 39 per cent against this action;
  • 36 per cent support more aggressive action on climate change (in 2006, 68 per cent were in favour);
  • 45 per cent support global warming being addressed but in a gradual and low cost way (increase of 5 per cent from 2011); support for this option is 56 per cent for the 18–29 year age group;
  • 7 per cent say they are less concerned since the climate change debate began in Australia; and
  • 18 per cent are not sure global warming is a problem and reject any steps that would have an economic cost.

The poll is not good news for the government and its partners (e.g. the Greens) but will opinions change once carbon pricing is introduced on 1 July? We await the next 6–12 months with great interest.

Polls: 1 July 2012 on

A Fairfax poll on 1 and 2 July indicated that 62 per cent of those surveyed opposed the carbon tax (up from 57 per cent in April/May) and 33 per cent were in favour. Fifty-three per cent said they would be worse off under carbon pricing despite substantial compensation. The message on the advantages of carbon pricing and the compensation was, at that time, not getting through.

In the same week, a poll by ANU’s Crawford School of Public Policy found that 40 per cent of liable companies, carbon financiers and carbon analysts (53 per cent of emitters) believed the carbon pricing would be repealed by 2016. However, only 21 per cent of those surveyed thought there would not be a scheme in 2020. Seventy per cent believed that the 5 per cent below 2000 emissions by 2020 would still be in place in 2015. Twenty-five per cent thought that the target would become more ambitious. Seventy per cent of emitters surveyed had already cut emissions; 84 per cent said they expected to make cuts over the next 3 years.

A report by The Economist found that 75 per cent of senior executives polled expected the scheme to survive, but only 33 per cent believed carbon pricing advantages would outweigh the longer-term risks of the scheme. Hence, a significant proportion of business does not believe Abbott!

A Fairfax/Nielsen poll in late July 2012 indicated that the percentage of those who thought they would be worse off under a carbon taxed dropped to 38 per cent from 51 per cent in late June 2012, with 52 per cent believing they were no worse off (37 per cent in late June and 54 per cent in late August). However, in August–September 2012 electricity and gas bills will be arriving to ‘remind’ people of the carbon tax impact, even though this will be responsible for only part of the price increase incorporated into the bills

References

Australian Government, Treasury (2011), ‘Strong Growth Low Pollution: Modelling a Carbon Price’. Available from: http://carbonpricemodelling.treasury.gov.au/carbonpric emodelling/content/report.asp.

CAT (Climate Action Tracker) (2011), ‘Climate Action Tracker: Durban Agreements a Step towards a Global Agreement but Risk of Exceeding 3°C Remains’. Available from: http://climateactiontracker.org/news/116/Durban-Agreements-a-step-towards-a-global-agreement-but-risk-of-exceeding-3C-warmingremainsscientists.html.

Conway-Smith, E. (2011), ‘China is Surprise Good Guy at Durban Climate Conference’, Globalpost, 6 December 2011. Available from: http://www.globalpost.com/dispatch/news/regions/afric a/south-africa/111205/china-surprise-good-guy-at-durban-climate-conferenc.

Ebels, P. (2011), ‘EU Claims Climate Victory but Global Warming Goes On’, EUobserver, 12 December 2011. Available from: http://euobserver.com/885/114590.

EU (2011), European Commission Press Release: Durban Must Deliver a Roadmap for Climate Action by All Major Economies. Available from: http://europa.eu/rapid/pressReleasesAction.do?referenc e=IP/11/1436&format=HTML&aged=0&language=EN &guiLanguage=en.

EurActiv (2011a), ‘UN Climate Talks Wrap 2020 Global Pact’, EurActiv, 12 December 2011. Available from: http://www.euractiv.com/climate-environment/un-climate-talks-wrap-2020-globa-news-509607.

EurActiv (2011b), ‘Canada Becomes First Country to Quit Kyoto Protocol’, EurActiv, 13 December 2011. Available from: http://www.euractiv.com/climate-environment/canada-country-quit-kyoto-protoc-news-509686.

U.S. Department of State (2011), United Nations Climate Change Conference in Durban, South Africa. Available from: http://www.state.gov/r/pa/prs/ps/2011/12/178699.htm.

IISD (International Institute for Sustainable Development) (2011), ‘Summary of the Durban Climate Change Conference’, 28 November–11 December 2011, Earth Negotiations Bulletin, vol. 12. IIISD, New York, NY. Available from: http://www.iisd.ca/download/pdf/enb12534e.pdf.

Lynas (2011), ‘The Verdict on Durban – A Major Step Forward but Not for Ten Years’. Available from: http://www.marklynas.org/2011/12/the-verdict-on-durban-a-major-step-forward-but-not-for-ten-years.

UNFCCC (United Nations Framework Convention on Climate Change) (2011a), Decision CMP.7: Outcome of the Work of the Ad Hoc Working Group on Further Commitments for Annex I Parties under the Kyoto Protocol at its Sixteenth Session. Available from: http://unfccc.int/2860.php.

UNFCCC (United Nations Framework Convention on Climate Change) (2011b), Decision CP. 17 Establishment of an Ad Hoc Working Group on the Durban Platform for Enhanced Action. Available from: http://unfccc.int/2860.php.

UNFCCC (United Nations Framework Convention on Climate Change) (2011c), Decision CP. 17: Launching of the Green Climate Fund. Available from: http://unfccc.int/2860.php.

UNFCCC (United Nations Framework Convention on Climate Change) (2011d), Decision CP. 17: Technology Executive Committee – Modalities and Procedures. Available from: http://unfccc.int/2860.php.

Vidal, J. and F. Harvey (2011a), African Nations Move Closer to EU Position at Durban, EurActiv, 9 December 2011. Available from: http://www.euractiv.com/climate-environment/african-nations-move-closer-eu-p-news-509568.

Vidal, J. and F. Harvey (2011b), ‘Durban Climate Talks See US Back EU Proposal’, Guardian, 8 December 2011. Available from: http://www.guardian.co.uk/environment/2011/dec/08/d urban-climate-talks-us-backs-europe.

Vidal, J. and F. Harvey (2011c), ‘Durban Climate Deal Struck after Tense All Night Session’. Guardian, 11 December 2011. Available from: http://www.guardian.co.uk/environment/2011/dec/11/d urban-climate-deal-struck.

Energy and Environment (NER 66)

National Economic Review

National Institute of Economic and Industry Research

No. 66               September 2011

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.
Editor: Kylie Moreland

National Institute of Economic and Industry Research

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the relevant Institute.

ISSN 0813-9474

Energy and environment

Graham Armstrong, NIEIR

Abstract

This paper reviews the global and Australian developments during the months leading to the Conference of the Parties of the United Nations Framework Convention on Climate Change Conference in Cancun, Mexico (COP-16) in December 2010. The legislation progress and climate action developments of Brazil, Indonesia, Africa, New Zealand, the United States and Australia are reviewed.

Introduction

In the year following the Conference of the Parties of the United Nations Framework Convention on Climate Change (UNFCC) Conference in Copenhagen (COP-15) and the associated disappointments, a range of UNFCC subsidiary bodies and non-UNFCC organisations met to advance global negotiations leading up to COP-16, Mexico.

Some progress has been made in relation to the major issues, including: the future of the Kyoto Protocol, the positions of China and India, the status policy after the mid-term elections, the financing of reduction of emissions from deforestation and forest degradation (REDD), the prospective roles of regulations, carbon taxes and emissions trading systems, the 2020 and beyond targets, the adaptation strategies and the outlook for abatement technologies.

Prospects for Cancun

As this paper was being finalised (1 December 2010) there had been very little discussion on COP-16, Cancun, Mexico, particularly compared to the lead up to Copenhagen the previous year.

On a recent (August–September 2010) trip, Graham Armstrong held discussions with two respected climate change observers on the prospects for Cancun.

Erik Haites, Margaree Consultants, Toronto, Ontario, Canada

Erik is an economist with a long-established (30 years) consultancy based in Toronto. Over the past 15 years, Erik has been involved in climate change policy at both national and international levels. Erik is a principal advisor to the UNFCC and the Intergovernmental Panel on Climate Change and, as such, is in an excellent position to comment on global climate change policy trends.

Approaching COP-16 in Cancun, Mexico in December 2010, Erik sees the global institutional structure for addressing climate change developing along some promising lines. Erik recognises the divergent views of the groups involved: the Organization of the Petroleum Exporting Countries, the Small Island States, Africa, China, Brazil, Russia, India, China, the United States and the European Union (EU).

Erik believes that despite much pessimism over Copenhagen and the potential outcomes from Cancun, there are drivers for some progress at Cancun:

  • There will be a desire, overall, not to have two successive COP failures.
  • Actions, agreements and negotiations outside the UNFCC, for example in China, sub-national progress in North America and Australia, and developments on energy efficiency improvement (EEI) and renewables, are progressing greenhouse gas abatement (GHGA) and there is a trend towards concensus on the need for and forms of a global agreement.
  • There is growing acceptance, albeit grudging by the EU, and others, that there will need to be a differentiated approach to obtain ‘approval’ from the United States.

Perhaps Erik is too optimistic, as indeed he must be as an advisor to the UNFCC/IPCC, but he is deeply involved with the global process and, accordingly, his views are very important.

Erik emphatically believes that China has the most progressive and aggressive climate change policies, despite the general view that China’s growth in emissions is out of control. He views Chinese policies, for trade and overall environmental disruption concern reasons, as having a significant impact on reducing emissions growth in China and globally.

On overall energy policy and trends Erik believes that, in line with the 2010 International Energy Agency (IEA) World Energy Outlook:

  • energy use is stable or declining in the OECD;
  • energy security is of major concern in most parts of the world;
  • China/India energy use will continue to grow, although not as rapidly as GDP;
  • excess supply capacity is exerting downward pressure on energy prices; and
  • energy infrastructure requirements are increasing in the United States (declining market) due to ageing assets compared, on an energy use basis (i.e. investment compared with energy use), with China (an expanding market), where infrastructure is overall of a newer vintage.

On technologies, Erik sees carbon capture and storage (CCS) and nuclear costs as increasing in real terms compared with solar, for which costs are declining in real terms.

Rod Janssen, Energy/Climate Change Consultant to the European Union, Brussels and to the European Council for an Energy Efficient Economy

Rod is a Canadian who worked for the Federal Energy Department in Ottawa and for the IEA. Since 1982 he has been an independent consultant. He is now based in Paris.

Rod recently acted as rapporteur for the European Capacity Building Initiative (ECBI) funded by Sweden to encourage dialogue and action on climate change action in developed and developing (e.g. African) countries. At an ECBI meeting in Oxford, UK in early September, Rod’s general impression was that no agreement was likely in Cancun in December 2010 or even in South Africa in 2011. Rod believes that an agreement might not be reached until 2020! He sees the United States as the major problem due to the lack of concensus in relation to political action. However, the United States Environmental Protection Agency (EPA) CO2 regulations starting with power stations might provide some progress. In contrast to the United States, China has taken considerable climate change GHGA action even though China is wary of political action at a global level.

The EU is becoming more aggressive in relation to coal phase-out, renewables and aviation, but has been slower to act on EEI. There has been increased emphasis on energy security (gas from Russia), and on CCS and renewables.

Reduction of emissions from deforestation and forest degradation

One positive outcome of the COP-15, Copenhagen in December 2009 was the pledge by some wealthier countries to provide US$4–5 billion by 2012 for REDD in developing countries. Much more support will be needed for a significant REDD result, but beyond 2012 the funding mechanism is uncertain. Currently, forest carbon credits are not accepted in the EU emissions trading scheme (ETS), but this is likely to change as REDD develops stringent, credible and audited credits.

The Informal Working Group on Interim Financing for REDD estimates that a REDD investment of US$100 billion by 2025 could cut deforestation by 25 per cent: this is the equivalent of 3 million ha of forest saved and 7 Gt of carbon emission reductions a year, approximately 17 per cent of total global emissions. The estimated cost was US$2.4/tonne of CO2e.

However,  Indonesia’s  National  Council  on  Climate Change puts the opportunity cost of foregoing oil palm plantations at US$30/tonne of CO2e, still a relatively low cost. For example, CCS is probably not viable at under US$75–115/tonne of CO2e.

Concerns

Avoided deforestation might not be permanent, particularly where there is a risk of climate-induced forest dieback.

In addition, REDD funds will inevitably go to the most ‘avid’ deforesters, such as Indonesia, which might create an incentive for other countries to engage in deforestation. Hence, REDD will have to be applied on a large comprehensive scale, even if the payments vary.

Brazil

Brazil has been developing REDD for 2 years and has received US$1 billion in funding from Norway. The payment formula favours Brazil’s Amazon states with higher deforestation rates. However, a state’s record on meeting REDD commitments is also taken into account when determining payments.

In Brazil, REDD faces substantial challenges, including, for example, forest title issues. Unowned forests are unprotected, leading to Brazilian grileiros (land grabbers) turning rainforest into pasture.

In the Brazil State of Para in 2009, 20 ranches were identified as operating on illegally cleared land, and selling meat to well-known retailers, such as Wal-Mart and Carrefour. The ranchers were fined US$1.2 billion in total and the retailers were threatened with fines, unless they were able to verify legal supply chains.

As a result, abattoirs in the region only deal with legal suppliers. Greenpeace has also acted on a report on Amazon beef and deforestation, linking beef and leather from the region with companies such as Adidas, Nike, Toyota, Gucci and Kraft. Many of these companies have agreed to work with Greenpeace, thus putting pressure on developing countries’ to adopt developed world standards in the supply chain, and thereby raising the prospects for an effective REDD program to reduce global emissions.

Indonesia

Even where governments own a forest, the degradation results can be similar. An estimated 63 per cent of Indonesia’s West Kalimantan national parks were illegally cleared by loggers between 1985 and 1990.
Unclear ownership is a barrier to the effective land use planning necessary for REDD. For example, in Indonesia, palm oil can be produced on degraded land (40 million ha available) rather than on forested land. Between 1990 and 2005, Indonesia planted over 3 million ha of oil palms, with over half of it on freshly cleared land.

When forests are on peat deposits, the problems are substantial as peat land can store over 5,000t CO2e/ha and, when drained for cultivation, greenhouse gases are emitted for over 20 years.

Indonesia’s peat area plantations contribute less than 1 per cent of GDP but nearly 20 per cent of emissions. With Indonesia planning to double the area for oil palms, emissions could increase greatly, but this provides a REDD opportunity through palm oil expansion on degraded land. A 2-year moratorium on commercial deforestation resulted in US$1 billion in funding from Norway for REDD in Indonesia.

Corruption also poses a threat to REDD success. Indonesia’s forest ministry, claiming control of over 75 per cent of the country’s area, is suspect. In the 1990s, over US$5 billion disappeared from the national reforestation fund: saving trees is not a priority at the national or state level.

Africa

In Africa, the problems are even greater. National forest is virtually non-existent, land titles are vague and corruption rife. However, aerial surveillance can help and REDD payments tied to improvement in practices can provide an incentive to improve performance. REDD dollars can be partly provided for improved land use control and inventory programs, and to encouraging local forest management. Overall, the prospects for REDD are not encouraging, but there are some grounds for optimism for REDD to contribute to reducing global CO2e emissions.

New Zealand climate change policy

On 1 July 2010, the New Zealand Government introduced an ETS. The ETS is expected to cost New Zealand households an average A$2.45/week. This cost will be derived from of an increase in petrol prices of A$0.025/litre and an increase in average electricity prices of 5 per cent.

A major reason for introducing an ETS was concern that without it New Zealand could have been subject to trade sanctions, a concern that appears to be absent from the Australian climate change debate. Revenue from the ETS will be used for reforestation.

The ETS covers emissions from six greenhouse gases: CO2, CH4, N2O, HFCs, PFC and SF6. The ETS will eventually incorporate all sectors of the economy, and, by 2015, all greenhouse gases will be included. The ETS is internationally linked and conforms to current climate change rules. Self-assessments will be undertaken for monitoring, reporting and verifying emissions produced by liable parties.

During a transition phase between 1 July 2010 and 31 December 2012, liable parties will be able to buy emission permits from the government for a fixed price of NZ$25/t CO2e. Also in this period, parties in the energy, industrial and liquid fossil fuel sectors will only have to surrender one emission unit for every 2 tonnes of emissions they produce, effectively halving the costs. Parties can surrender international permits, such as Clean Development Mechanism (CDM) carbon emission reductions (CERs) and EU assigned amount units. The ETS will eventually cover the following sectors: forestry, transport fuels, electricity generation, industrial processes, synthetic gases, agriculture and waste. Forests planted after 1989 can produce emission units for CO2 stored or removed from the atmosphere.

Most participants are required to meet their obligations under the scheme by surrendering emission units. Surrendering a unit means it cannot be used again: for example, it cannot be also given to another participant.

Some participants, such as those with forests planted after 1989, are able to earn emission units for carbon dioxide stored or removed from the atmosphere by their activities.

The liable party is not necessarily the business at the actual point where emissions are produced. For example, a coal producer would be required to surrender units for the coal it sells, even though the actual emissions will occur when the coal is burned.

Alongside those who are required to participate in the scheme and those who can opt in, other people may also hold and trade emission units. These parties are commonly referred to as ‘secondary market traders’.

Businesses participate in the ETS in different ways.

  • Some have a legal obligation to acquire and surrender emission units to cover their direct greenhouse gas emissions or the emissions associated with their products. These participants are generally ‘upstream’ operators: for example, transport fuel producers or importers of products.
  • Some have the choice to apply to opt into the scheme if they carry out a relevant GHGA activity.
  • Some receive free emission units that can be used to meet their own obligations or to sell to other firms: for example, landowners with forests planted before 1990.
  • Some do not have to take part in the ETS, but can trade emission units in the same way that stockbrokers or real estate agents trade in their respective markets. These are secondary market traders. They may have specialist expertise in linking those who can reduce their emissions and have spare emission units with those wishing to buy these units.

Liable parties are required to:

  • monitor, record and report activities that produce or remove greenhouse gas emissions; and
  • surrender to the government emission units to cover emissions associated with their activities each year.

Secondary market traders, such as brokers, can also hold and trade emission units, but do not have to monitor and report emissions and are not required to surrender emission units. They can hold and trade emission units to take advantage of opportunities in the financial market.

Examples of emissions trading scheme participation

  • Firm A is an oil company. It needs to buy emission units to cover the greenhouse gas emissions it is responsible for.
  • Firm B is a large forestry company that receives emission units for land it is planting in forests. It is also cutting down some trees, leading to emissions for which it has to surrender emission units. Initially, Firm B has a shortfall of units,
  •  Firm C is a major industrial user of electricity for which it has to surrender emission units. To help Firm C adapt to these higher costs, the government gives Firm C a free allocation of emission units, which Firm C can sell to offset its increased electricity costs.

Under the ETS, Firm A and Firm B can both buy Firm C’s units in the short term to cover their emissions.

Because it now has to pay higher energy prices, Firm C finds it has lower costs if it invests in energy efficiency.

Over time, as its forest matures, Firm B has spare units available and can sell them to Firm A.

Some participants will be eligible to receive a free allocation of emission units from the government to cover some of their emissions.

The New Zealand Emission Unit Register (NZEUR) will record:

  • who holds emission units and the number of units that they hold;
  • transfers of emission units between holders both within the NZEUR and between international unit registers; and
  • emission units surrendered by participants to meet their obligations under the ETS.

As with a share registry, the NZEUR does not record information about the price or financial value of emission unit trades, nor does it provide a mechanism for exchanging cash for units traded.

Sectors will be introduced to the ETS gradually over a period of 7 years, starting in 2008.

The transport fuels, electricity production, industrial processes and waste sectors are able to start voluntarily reporting their greenhouse gas emissions 2 years before their obligations to surrender emission units begin, and are required to report their emissions 1 year before. Those in the agriculture sector can voluntarily report emissions 4 years before their obligations to surrender emission units begin and are required to do so 3 years before.

Table 1 E and E NER 66

 The Ministry of Economic Development manages the day-to-day running of the ETS. It is the main compliance and enforcement agency. It also runs the NZEUR.

The  Ministry  for  the  Environment  administers  the Climate Change Response Act, which established the ETS. It is also responsible for developing emission unit allocation plans and regulations under the Act, except for those relating to the forestry sector, which are managed by the Ministry of Agriculture and Forestry.

The ETS will be reviewed once during each international commitment period: the review must be completed 12 months before the end of each period. The review will consider impacts of the ETS on the economy, how it links with other trading schemes, and any social, economic and environmental impacts, such as the effects on biodiversity. The review will be conducted by an independent panel of experts.

Penalties will be imposed on liable parties for incomplete and incorrect emissions data or if all required permits are not surrendered, at a rate of NZ$30/t CO2e plus a requirement to acquire and surrender liability permits.

Progress of the New Zealand ETS should be closely followed in Australia.

United States climate change policy

The United States Administration has abandoned efforts to limit United States greenhouse gas emissions through a cap and trade ETS. Instead, at this stage, the 27 July Energy Bill only includes measures such as subsidies for home insulation and natural gas vehicles due to the seeming impossible task of gaining Senate approval for the comprehensive Bill passed in the House last year.

Like Abbott in Australia, Republicans and some Democrats view carbon pricing as detrimental to the economy, especially when economic recovery is weak. In addition, representatives from coal states are concerned about the impact of carbon pricing on their constituents. Polling indicates low levels of belief in the seriousness of the impacts of global warming.

However, despite the demise at this time of a United States ETS, there has not been complete United States inaction on climate change. Under the Clean Air Act, the United States Supreme Court has ruled that regulations could be applied to greenhouse gas emissions and, therefore, that the United States EPA could decide on their public health impacts.

The EPA has determined that there are considerable negative public health impacts of greenhouse gas emissions and is now working on regulations to apply to large stationary emissions sources, such as generation plants. Such regulations will include the introduction of minimum efficiency standards, and the use of renewable/green technologies will be promoted.

In addition, agencies, at the government’s discretion, can set fuel efficiency and appliance standards. Again, states are developing measures to restrain greenhouse gas emissions: for example, north-eastern states have a cap and trade ETS in place for power stations. The World Resources Institute has studied the potential for emission reductions using the existing federal and state regulations and has concluded that emission reductions of 13 per cent below 2000 levels could be achieved by 2020 (below the 17 per cent reduction pledged at Copenhagen).

However, indications are that United States action over the next 5–10 years will fall far short of 2009 expectations, unless international pressure is applied through sanctions and/or competitiveness in domestic and global markets. Inaction is likely over the next 2 years as a result of Republican Party (members of which are mainly opposed to climate change policies) success in the November 2010 mid-term elections. One surprising climate change outcome of the elections was the rejection of the referendum proposal in California to defer the state climate change action plan until the state economy recorded 3 per cent annual growth.

Carbon markets

Under the CDM, destruction of HFC-23 can be eligible for CERs, which are tradeable in the EU ETS. HFC-23 has a global warming potential 14,800 times that of CO2. HFC-23 is produced as a by-product of HFC-22 manufacture, an ozone depleting refrigerant. HFC-22 is banned in developed countries but will not be banned in developing countries until 2030.

Wind and solar energy and other low greenhouse gas intensive projects are eligible to create CERs under the CDM, but destroying HFC-23 is much lower cost for the creation of CERs and has, therefore, become the main source of CDM credits. In the EU ETS in 2009, 55 per cent of CERs came from HFC-23 destruction, representing approximately US$700 million in credits. HFC-23 production/destruction is limited to HFC-22 plants operating in 2000–2004 so as to avoid setting up HFC-22 plants to produce HFC-23 credits.

Clean Development Mechanism Watch, monitoring the offsets market, has found that some plants reduced their HFC-22 production during periods in which they were ineligible for CERs and increased production when they became eligible. Since the CDM Watch report by the CDM Executive Board, eight HFC projects have been placed under review and the HFC-23 methodology is being reassessed. As a result, the supply of CERs from this source is likely to decline, putting upward pressure on CER prices, possibly from €15 in August 2010 to €25 by January 2011.

Increased price pressure could result from any CDM Board decision to retroactively invalidate some HFC-23 credits, causing entities responsible for invalid CER issuance liable for replacing those CERs.

Australian developments

Overview

Before the 21 August 2010 federal election, neither the Australian Labor Party (ALP) nor the Coalition planned to introduce carbon pricing, the Coalition with no carbon pricing plan (but with policies that would have a price impact: see Energy Working Paper, August 2010) and the ALP with no price before 2013 and some incentives (particularly for renewables). However, both parties aimed to reduce 2000 emissions by 5 per cent by 2020.

The Greens, with a 25–40 per cent below 2000 emissions by 2020 target, wanted immediate introduction of carbon pricing at around A$20–25/t CO2e.

In the aftermath of the election, the support of two Independents and a Green enabled the ALP to form government, but in the Senate, the Greens will hold the balance of power after 1 July 2011. The Greens’ electoral success put early carbon pricing back on the agenda and the two Independents supporting the ALP, together with the Greens, want increased support for renewables and EEI. A further climate change policy ‘twist’ was the release of the Victorian Climate Change White Paper in late July 2010 (see below).

Two ‘round table’ consultative/advisory bodies were set up, one comprising business and one non-government organisation, reporting to nominated Ministers to consider options: a limited ETS, a carbon tax and incentives/regulations.

Post-election, several senior business leaders came out in support of carbon pricing, while other business identities (e.g. mining industry) continued to oppose carbon pricing.

In  another  development,  the  Prime  Minister’s  (then Rudd) Task Force (TF) on Energy Efficiency released the TF’s report, which strongly supported a major energy efficiency effort. The TF also released a study (commissioned by the TF) on design, costs and benefits of a National Energy Efficiency Obligation Scheme. Thus, since the election, the Australian Climate Change debate has been reinvigorated and carbon pricing is firmly back on the policy agenda.

Whether it will be introduced, and its timing, depends on support in the House of Representatives (and the Senate before 1 July 2011) from the ALP, Independents and possibly some dissident Coalition members. Support from some powerful business interests (e.g. BHPB, AGL and Origin Energy) and a majority of community support suggests to us that carbon pricing will be introduced in 2012 (the consultative committees are not due to report until the end of 2011). Accordingly, NIEIR is building carbon pricing into modelling, commencing with $10/t CO2e in 2012 (revenue raising, minimal GHGA impact) rising to approximately $45/t CO2e in 2015–2020.

A CO2e tax/price of <$20/t CO2e would have a low price response impact, but would raise revenue that could be applied to GHGA incentives.

National Institute of Economic and Industry Research analysis indicates that a price of at least $30/t CO2e is needed before there will be significant incentives to shift towards gas for base load generation. The prospect of such a price would remove much of the uncertainty surrounding electricity generation investment, a major reason for business support for early introduction of carbon pricing.

Removal of this uncertainty is urgently required as although electricity demands are, overall, increasing slowly (<2 per cent per year) and spare capacity remains, by 2015 there could be significant electricity supply security concerns.

Grattan Institute study on emissions trading scheme/Carbon Pollution Reduction Scheme free permit compensation

In a study released in April 2010, the Grattan Institute argued that Australia would gain from letting its aluminium smelters and oil refineries close rather than providing them with free carbon permits under an ETS. The study argues that free permits undermine emission reduction, which is the purpose of an ETS. Issuance of free permits to these industries would remove the incentive for them to shift to lower emission operations.

Regarding job losses through industry relocation, the study states that a carbon price would leave most emissions intensive sectors relatively healthy. Where there were noticeable negative effects, permits should only be issued if a closure would not noticeably reduce greenhouse gas emissions. The money saved by not issuing free permits could be spent on support for communities affected by plant closures.

The study, ‘Restructuring the Australian Economy to Emit Less Carbon’, is based on A$35/t CO2e. Some assistance would be justified to prevent steel and cement production shifting to countries that did not penalise carbon, but this would be best done by rebating the carbon cost on exports and imposing tariffs on competing imports. This would be allowable under World Trade Organization rules, provided imports were treated the same as local production.

In the study, it was estimated that free permits would have an average cost of A$59,000/employee, highest for aluminium at A$161,000/employee and A$103,344/employee for LNG (see Table 2). At a price of A$35/t CO2e, the study found that there would be little impact on the profitability of the Australian LNG industry, as Australia has fewer establishment and operating risks for developers and customers. With respect to aluminium, the study argues that higher Australian electricity costs without carbon pricing is still directing investment towards lower electricity price locations (such as Qatar) with or without carbon pricing.

table 2 E and E NER 66

The ETS (Carbon Pollution Reduction Scheme) legislation did not eventuate and the policy debate appears to have moved away from carbon pricing compensation (although it is likely to reappear with any carbon pricing) and towards, at least initially, a carbon tax, regulation and incentives.

Business supporters of carbon pricing

Given the advantages of carbon pricing to gas industry players such as Origin Energy, AGL and Santos, their support is not surprising. However, the support by BHPB’s Marius Kloppers changed the balance of industry support for carbon pricing because of the potential impact on BHPB’s investment in a range of commodity sectors. On 20 September 2010, the Australian Financial Review put the impact on BHPB’s net present value at 21 per cent, assuming a carbon price of A$25/t CO2e in 2012 rising to A$50/t CO2e in 2019. Note also that the Business Council of Australia acknowledges that it is inevitable that implementing some form of ETS is the lowest cost way to cut carbon emissions.

In September, AGL analysts indicated that the cost of a delay until 2013 in regulatory uncertainty is A$2.1 billion a year to 2020. The rationale is that wholesale electricity prices would be 13 per cent higher ($8.6/MWh) in 2020 than if certainty on carbon pricing were delivered in 2010.

Energy Supply Association of Australia data indicates that the generation sector’s forecast of capital expenditure over 2010–15 has fallen by more than 50 per cent, from A$18 billion in 2007 to A$8.2 billion, due mainly to uncertainty on climate change policy. For example, TRU Energy has A$3 billion in gas fired power in Victoria and New South Wales on hold and Origin cannot, in this situation, commit to upgrading Mortlake from essentially a gas peaking plant to a combined cycle gas turbine base load plant.

Any plant, coal or gas, requires more than 5 years from decision to commissioning, and risk of power shortages is increasing as investment decisions are not taken. AGL suggests consideration of an ETS for generation, whereas BHPB suggests a combination of carbon tax, land-use measures and a limited ETS.

A recent (August 2010) survey of 1,000 members by the Australian Chamber of Commerce indicated 75 per cent believed policy should focus on renewable energy and EEI rather than placing a direct price on carbon.

Garnaut Climate Change Review update

In October 2010, Greg Combet, the Minister for Climate Change and Energy Efficiency, commissioned Garnaut to update significant elements of his 2008 Garnaut Climate Change Review (the 2008 Review), and to report on the update by 31 May 2011.

The review update will update elements of the Climate Change Review:

  • where significant changes have occurred, or the sum of expert knowledge has increased, since the original analysis of the 2008 Review was undertaken; and
  • where these changes or improvements in expert knowledge could have significant implications for the key findings and recommendations of the 2008 Review, such that they should be updated.

The Review update should consider:

  • international developments in climate change mitigation efforts;
  • developments in climate change science and understanding of climate change impacts;
  • previous proposals to develop a carbon price in Australia and the ensuing public debate;
  • domestic and international emissions trends;
  • changes in low emissions technology costs and availability;
  • the potential for abatement within the land sector; and
  • developments in the Australian electricity market.

Throughout the Review update, consultation with key stakeholders will be required to understand views and inform analysis. A series of publicly released papers is to be prepared between November 2010 and March 2011. A final report is to be presented to the Government by 31 May 2011. The Report will embody the independent judgments of its author.

 

Victorian Climate Change White Paper,

July 2010

The Victorian Climate Change White Paper, ‘Taking Action for Victoria’s Future’, while not detailing how plan proposals are to be implemented, goes further than any other Australian Government in drawing up a climate change strategy. A White Paper Implementation Plan is due to be released before 2011. The Paper outlines 10 Action areas (see Table 3).

Note that following the Victorian 27 November election the future of the Climate Change Policy is very uncertain.

Targets

From 2008, emissions of 122 Mt CO2e to a 2020 BAU of approximately 130 Mt CO2e, the White Paper proposes a target of 20 per cent below 2020 BAU emissions by 2020: a reduction from BAU of 34 Mt CO2e, or 24 Mt CO2e below 2000 emissions.

This is a significant challenge. In August 2010, NIEIR projected an average 1.25 per cent increase per year for electricity (GWh) over 2010–2020 (without considering the potential White Paper impacts).

Clean energy

There is a commitment to reduce greenhouse gas emissions from brown coal generation by up to 4 Mt CO2e/year, a cumulative saving of 28 Mt CO2e by 2020. This is generally seen as closing 25 per cent of Hazelwood capacity. Financing and compensation are significant implementation issues. There is an emissions target level of 0.8t CO2e/MWh for any new brown coal plant. This compares with 0.8t CO2e/MWh for new black coal stations and 0.4t CO2e/MWh for gas CCGTs.

Solar

The target for large-scale solar (+100 MW) is approximately 5 per cent of electricity supply by 2020 (approximately 2,500 GWh), derived from 5–10 large-scale plants. This target will be supported by a Large-scale Solar Feed-in-tariff (FIT). The tariff might also be available for other low emission technologies, such as geothermal energy. A Medium-scale Solar Working Group has been established, and FIT could also be available for medium-scale plants. There will be funding of A$5 million provide for up to 10 solar energy hubs, generating approximately 8.6 MW of community-based solar power.

Homes

From May 2011, a 6-star standard will be required for new homes (as per a Council of Australian Government’s decision).

The goal is to improve the energy efficiency of existing housing stock to an average 5-star equivalent energy rating by 2020.

Also included are:

  • a doubling of the Victorian Energy Efficiency Target (VEET) and expansion of VEET activities;
  • a comprehensive household retrofit program;
  • extended solar hot water rebate scheme;
  • mandatory disclosure of residence energy performance on sale and lease, in 2011; and
  • promotion of Green Power (GP), aiming to increase GP homes from 300,000 to 500,000.

Business

Goals for Victorian business include VEET expansion to small and medium enterprises. The government will encourage energy efficiency in businesses though the Climate Tech Strategy and the Clean Business Fund. The Environment and Resource Efficiency Plan is to be expanded.

Transport

Transport initiatives include an electric vehicle program. The government has committed to improving fuel efficiency in the Government fleet to reduce emissions by 20 per cent emissions by 2015. They will purchase 2,000 Camry hybrids.

Government

Additional 20 per cent in EEI in all government buildings and facilities by 2018:

  • further $100 million in Greener Government Building Program;
  • study installation of 50 MW of cogeneration in Victoria’s existing hospitals (36 MW at present);
  • increase Green Power commitment to 35 per cent by 2015 and 50 per cent by 2020 (said to be equivalent to output of 100 MW of wind); and
  • support for local government initiatives.

Overall, the Victorian Climate Change Strategy is impressive (although relatively weak on initiatives in the business sectors, both commercial and industrial), but success will depend on effective implementation plans and the monitoring, review and evaluation of initiatives as they proceed.

Coalition plans for energy and climate change include:

  • review of Smart Metering: (impacts, costs, in-house display);
  • review of wind farm guidelines;
  • $1 billion Regional Growth Fund, including a $100 million natural gas distribution expansion;
  • review of brown coal phase-out and transition strategy (road map) for the Latrobe Valley;
  • ‘apparent’ support for carbon pricing and natural gas replacement of brown coal generation;
  • support for cogeneration, tri-generation and standby generation;
  • support for consideration by VCEC of gross FIT design, including tariff PV policies and low emission sources and expansion of size limit;
  • support for CCS, algae research and doubling of ETIS for low emission R, D, D and C;
  • support for 5 per cent solar generation by 2020, doubling of VEET (to SMEs) but review of VEET compliance; and
  • review of VCEC of barriers to distributed energy (renewables, cogeneration/tri-generation).

Energy and the Environment (NER 63)

National Economic Review

National Institute of Economic and Industry Research

No. 63               March 2010

The National Economic Review is published four times each year under the auspices of the Institute’s Academic Board.

The Review contains articles on economic and social issues relevant to Australia. While the Institute endeavours to provide reliable forecasts and believes material published in the Review is accurate it will not be liable for any claim by any party acting on such information.
Editor: Kylie Moreland

© National Institute of Economic and Industry Research

(Australian Farm Institute for the first article)

This journal is subject to copyright. Apart from such purposes as study, research, criticism or review as provided by the Copyright Act no part may be reproduced without the consent in writing of the relevant Institute.

ISSN 0813-9474

Energy and environment

Graham Armstrong, Consultant, NIEIR

Abstract

This paper reviews the global and Australian developments during the months leading to the Copenhagen COP-15 commencing 7 December 2009. As of 20 November it seemed unlikely that a consensus on emissions caps and the role of developing countries (non-Annex B) would be reached. Cuts below 1990 emissions are being sought from developed nations, as well as a slowing of emissions growth by non-Annex B nations. The investment costs to reduce emissions levels below 1990 levels will be huge. In addition, to achieve these reductions more stringent policies are required. The legislation progress and climate action developments of Australia, the USA, China, Japan, Russia, India and Canada are reviewed in the present paper.

Introduction

The 6 months prior to Copenhagen COP-15 saw considerable activity on climate change policies both internationally and in Australia. As this chapter was being finalised, the fate of the Australian carbon pollution reduction scheme (CPRS) was undecided. Set out below are reviews of the global and Australian developments.

Climate change policy options: Senate requests for further modelling

On 22 June 2009, the Senate Select Committee on Climate Policy released a report. The first recommendation was that Treasury be directed to do more modelling of the effects of the CPRS, including considering transition costs, effects on jobs and the environment and effects on regional Australia, allowing for the deterioration in the Australian economy.

The committee recommended Treasury be directed to model five policy alternatives:

  1. a ‘baseline-and-credit’ scheme;
  2. an ‘emissions intensity’ model;
  3. a carbon tax;
  4. a consumption-based carbon tax; and
  5. the McKibbin approach.

Options 1–3 and 5 target Australia’s production of emissions, including those exports that do not affect Australia’s emissions imports. Option 4 targets spending on emissions (embodied and use emissions consumption) and would apply to local spending, including imports and excluding exports. All options involve pricing carbon, whether applied to production or consumption. Another recommendation was that a CPRS-40 (cap of 40 per cent below 2000 emissions in 2020) be modelled.

The Treasury modelling report stated on page 84 that: ‘Emissions allocations based on production are likely to result in higher welfare costs for Australia than allocations based on consumption’. This implies that a consumption-based policy is lower cost than a production-based emissions trading scheme (ETS).

In a draft report open for comment, Climate Strategies provides climate policy modelling results for selected emissions intensive trade exposed industries (cement, steel and aluminium) operating in the European Union (EU). The modelling evaluates ‘carbon leakage’ under six policy options for dealing with trade exposed industries:

  1. full border adjustment (BA full), roughly equivalent to a consumption base;
  2. BA import (BA only for imports);
  3. BA direct (adjustment of exports and imports but only for direct emissions);
  4. BA EU average (adjustment for imports based on the EU emissions average);
  5. BA import direct; and
  6. full auction of permits.

The first five of these options are more or less comprehensive versions of the consumption -based carbon tax identified as option 4 by the Senate select committee. The sixth option is a particular variant of a production-based approach: a pure ETS. For cement, steel and aluminium, the first option, BA full (closest to a consumption-based carbon tax), delivers the lowest carbon leakage. The sixth option (full auction of permits to producers) generates the highest carbon leakage. A consumption-based ETS/tax would reduce the carbon leakage reason for not acting now on climate change.

Carbon pollution reduction scheme: 4 May revisions

2011–2012

Fixing a $10/t CO2e price will:

  • raise revenue (approximately $400 million);
  • not change generator merit order as brown coal generators with <$5/MWh short-run marginal cost (SRMC) and with greenhouse gas intensity at 1.2–1.5t CO2e/MWh would have SRMC increased by $12–15/MWh, to $17–20/MWh. Black coal $8–15/MWh SRMC would have SRMC and 0.8–1.0t CO2e/MWh increased by $8–10/MWh, to $16–25/MWh (lowest in Millmerran and Kogan Creek, Queensland, and Victoria protected due to transmission costs); and
  • have very low impact on electricity use due to low demand elasticity.

2012–2013 on

From 2012–1213, a $46/t CO2e cap will rise at 5 per cent plus inflation until 2020. New forest plantations can generate permits from July 2010.

Carbon pollution reduction scheme: 24 November adjustments

After prolonged negotiations with the opposition, the Federal Government announced several adjustments to the CPRS, outlined in Table 1. As the present paper was finalised, many details were not available.

The net budgetary impact over 10 years was estimated to be $769 million due to, it was stated, accounting procedures and a lower permit (CO2e) price (reason not stated: probably exchange rate assumption changes). Why the permit price would be lower was not explained, but the lower price reduced compensation to households by $916 million. Lower permit prices are probably due to higher exchange rate assumptions and, hence, lower Australian dollar prices of international credit purchases.

The total CPRS assistance package to industry to 2020 now amounts to approximately $120 billion. Whether CPRS-5 will be attained through a mix of domestic actions and purchase of international credits or through external balance effects is yet to be determined.

NIEIR’s current CO2e price scenarios

Following the Garnaut Review paper in June 2008, the Green Paper of the Federal Government in July 2008, the White Paper in November 2008, the 4 May 2009 revisions to the CPRS, and our analysis over the past year of likely Australian climate change policies, a CO2e pricing schedule was developed (see Table 2).

As emphasised above, analysis and projections have to be developed in the absence of emissions caps announcements, and detailed design announcements of an ETS (CPRS). The ‘base’ scenario is considered to be the most likely at this time (November 2009). A lower CO2e cost projection is considered very unlikely (P < 0.2), but a higher CO2e cost projection is a possibility (P = 0.3) post-2020.

In the base CO2e price scenario (essentially under CPRS-5) a higher cap is set and in the ‘high’ CO2e price (essentially CPRS-25) scenario a lower cap is set. The prices actually resulting over the period will depend on caps finally set, actual CPRS design, coal and gas prices, renewables costs, emission reduction technology developments and effectiveness of energy efficiency improvement (EEI) policies.

Table 1 E and E NER 63

 Table 2 E and E NER 63

Emission caps and reductions from business as usual (BAU) to 2020 are presented in Table 3.

Table 3 E and E NER 63

Sources of emission reductions

Domestic actions would largely fall on the stationary energy sector but international permit purchases could limit the domestic actions required, depending on the relative costs of international permits and the costs of domestic greenhouse gas abatement (GHGA).

The base scenario results in lower GHGA permit prices and electricity price impacts, and the high scenario produces higher GHGA, permit prices and electricity prices. We regard these two scenarios as covering the likely range of permit prices to emerge over the next 25–30 years. However, very stringent targets, for example the 40 per cent emissions reduction below 1990 levels by 2035 suggested at Bali COP 13 in December 2007 and Garnaut’s ‘necessary’ cap of a 90 per cent reduction by 2050, could see permit prices rise to much higher levels. In practice, in any scenario there could be significant volatility in CO2e prices as the system adjusts to the CPRS.

Impacts of the two scenarios on energy prices

In the electricity generation area there is relatively good data on generation SRMCs and long-run marginal costs (LRMCs) . Thus, it is reasonably straightforward to estimate the impact on SRMCs and LRMCs of permit price, the main caveat being future gas and black coal prices. There is less reliable data on the costs of reducing emissions from generators (e.g. via carbon capture and storage) and from emissions in other greenhouse (National Greenhouse Gas Inventory) sectors where abatement could contribute to attainment of a given cap. Over time, generator energy efficiencies will improve and reduce the impact of CO2e pricing on new generation entering the market. Accordingly, it is difficult to predict the permit price that would produce the abatement required to attain a given cap (EEI and generator mix responses) and to estimate the impact of permit prices on electricity prices.

In addition, demand responses to increased energy prices and to complementary measures that contribute to GHGA will reduce the permit price required to attain a given cap. In the EU ETS, and proposed by the Australian state/territories work on an ETS as well as the White Paper and Garnaut, complementary measures to cover EEI, renewable energy (RE) targets and support for R&D, demonstration and commercialisation are seen as desirable. Federally, there appears to be some ambivalence on EEI and RE complementary measures. Effective EEI measures such as minimum performance standards, rebates and targeted business sector programs can provide significant GHGA at lower costs per tonne of CO2e than can be delivered by reducing greenhouse gas (GHG) emissions from fossil electricity generation.

Higher mandated renewable electricity targets, although delivering relatively high cost abatement (>$30/t CO2e), reduce the contribution from fossil generators of delivering a national greenhouse gas abatement target from an ETS because this RE GHGA contributes to the cap outside the ETS. The mandated contribution from RE increases electricity prices until CO2e inclusive fossil generation costs rise to RE cost levels.

For NEMMCO and Transgrid in April 2008, NIEIR estimated impacts of an ETS on generators in the inter-connected NEM regions based on ACIL-Tasman (for NEMMCO, 2007) SRMC estimates and NIEIR LRM/AC estimates. For Western Australia the resulting electricity prices are likely to be similar as the generation mix (black coal and gas) is broadly similar to that in the NEM. In the Northern Territory, which has a gas-based system, the impact will be lower. Again, we emphasise that without details of the final ETS design and modelling of these details, it is only possible to develop broad estimates of future electricity prices under an ETS.

Note that the estimates for existing and new gas plants depend on the price at which gas can be sourced (there are low and high views on future gas prices) . In addition, for new gas plants the capital costs are escalating as demand for gas turbines increases globally. New coal plants are also subject to cost (capital and operating) pressures but not to the same extent as new gas plants.

Note also that coverage of fugitive emissions as proposed in the CPRS increases the fuel costs for gas and black coal generators and for gas use in water heating. That is, the sent out costs of gas and black coal generators increase relative to brown coal generators (very low upstream emissions) because of the carbon cost of transport of the fuels to generators and the fugitives (methane, CO2) from production and processing. In New South Wales, these indirect (Scope 3) emissions for large users of gas (generators etc.) are 0.013t CO2e/GJ and for coal depend on the actual coal source, but average approximately 0.009t CO2e/GJ. In New South Wales for gas each $10/t CO2e would add approximately $0.13/GJ to the price of gas, for a CCGT would add approximately $0.80/MWh and for ‘gassy’ black coal approximately $0.85/MWh.

If these emissions are covered in the CPRS design (as proposed) they would raise the costs of gas and black coal generators if, as expected, the fuel price impacts were passed on in fuel prices purchased by the generators.

Peak and off-peak electricity prices

Currently, in most regions, off-peak electricity (10.00 pm to 7.00 am) is met by coal plants. The exceptions are the Northern Territory and, to some extent, South Australia and Western Australia (in Tasmania, with Basslink in place, hydro water is conserved for peak operation and off-peak power is mainly imported from Victoria).

Under the CPRS, as permit prices rise, a level (approximately $30/t CO2e) will be reached where only very efficient coal plants (Millmerran and Kogan Creek) can compete with gas plants in off-peak periods. Gas plants will have to operate at higher capacity factors and coal plants at lower capacity factors at the projected permit prices required for the emissions cap to be attained. To maximise net revenues, coal plants will run in periods where pool prices are higher.

Demands in peak and off-peak periods will be met at a price where the marginal bidder, whose bid is necessary to meet demand, has an SRMC (including CO2e costs) lower than the spot price (in addition, some off-peak power is, and will continue to be, met by intermittent generators). Currently, peak electricity (i.e. outside off-peak) may be broken down into several periods (e.g. intermediate/shoulder, daily peak and summer peak). Currently, demands in these periods are met by a combination of coal, gas and renewables. In high peak periods (mainly on hot summer days), the marginal generators (those providing the last MWhs required to meet demands) are generally open cycle gas turbines (OCGTs) with perhaps some scheduled hydro generators.

Under the CPRS, OCGTs will still be (with hydro where/when available) the high peak suppliers because of their quick-start capabilities (coal generators cannot respond to rapid demand increases). When the spot price exceeds the CO 2e price adjusted SRMC of these generators, bids will reflect the prices these OCGTs need to cover their long- run average costs (LRACs) at their anticipated capacity factors.

The conclusion of the above discussion is that electricity prices in each period will rise to at least the level at which the marginal generator required to meet demand will cover that generator’s SRMCs. The marginal generators will, over time, have to meet their LRACs by operating in periods where the price of SRMCs gives them enough net revenues to enable their capital as well as operating costs to be covered. However, their capital costs will depend on their asset values: the lower the asset value, the lower will be the excess net revenues over SRMCs to service the asset value (capital costs). Asset values will drop if these excess (over SRMCs) net revenues are insufficient to service current asset capitalisation. Asset values may drop towards zero, at which point if revenues cannot cover SRMCs the plant will cease operation.

Average wholesale percentage price increases for CPRS-5, CPRS-15 and CPRS-25 estimated in the Treasury modelling are presented in Table 4. Higher wholesale electricity prices flow into the retail prices that are faced by households. In the initial years of emission pricing, average Australian electricity prices faced by households increase by 20 per cent for the CPRS-5 scenario and 38 per cent for the Garnaut-25.

The effect on households is muted by rising real incomes over time.

It is very important to note that underlying ($0/t CO2e) average retail prices have risen by approximately 25 per cent over the past 5 years (2004–2009), through increases in wholesale prices and through higher network charges. Similar, probably higher, underlying price increases are likely over the next 5 years, mainly due to higher network charges as networks are refurbished, augmented and extended. Currently, average residential prices (peak) in Victoria are approximately $180/MWh and in the absence of a CPRS could reach $230/MWh or higher by 2020 (2009 dollars). CPRS-5 would increase this price to approximately $275/MWh; off-peak prices would be approximately $185/MWh ($80/MWh in 2009).

Opposition modelling, emissions trading scheme design suggestions

The Coalition opposition commissioned Frontier Economics to model suggested CPRS amendments. Among these, the main amendments were as follows:

  • fugitive emissions from coal mining be excluded;
  • permanently excluding the agricultural sector from the CPRS but allowing the sector to create and trade accredited offsets;
  • reducing emissions through improved soil management, better grazing practices, increased forestry planting and maintenance and use of technologies such as biochar;
  • making power generators only liable for emissions that exceed an industry benchmark, rather than all their emissions (marginal CO2e tax); and
  • trade exposed industries to receive permits for all their emissions provided they conform to world’s best practice.

The Greens proposed (October 2009) a program of $22 billion to EEI retrofit all Australian residences (an approximate average of $2,750/house) and to limit purchases of international credits to 25 per cent of required emission reductions.

Table 4 E and E NER 63

United States climate legislation progress

A Senate Bill (Boxer–Kerry), the Clean Energy Jobs and American Power Act, is similar to the Waxman– Markey Bill: it calls for a 20 per cent reduction on 2006 emissions by 2020, which translates into a 7.3 per cent reduction below 1990 by 2020 (similar to CPRS-5 targets/caps). Seventeen per cent below 2005 (Obama/Boxer/Kerry) would be approximately 5 per cent below 1990 levels by 2020.

There are three main steps that remain to be taken before climate change legislation in the United States comes into force. First, the Senate will have to agree on the ‘Climate Bill’. Second, once approved, the Senate version of the text must be reconciled with the version that passed the House of Representatives. Third, the bill needs to be signed by the President.

China: Climate change action developments

Chinese emissions continue to increase significantly as economic growth continues, electricity generation based on coal soars, emitting industries continue to expand and personal consumption increases rapidly. However, there is also substantial action on GHG emission reductions through investments in EEI, RE and replacement of other greenhouse gases such as hydrofluorocarbons.

In China’s 2008–2009 stimulus package of A$650 billion, approximately 40 per cent was dedicated to sustainable initiatives. In the United States stimulus of A$850 billion, 12 per cent was allocated to such initiatives; of the Australian A$27 billion, 9 per cent; and the South Korea A$45 billion, 80 per cent.

Chinese initiatives

Chinese initiatives include the following:

  • solar water heaters: 50 per cent of global production, 65 per cent of installations;
  • photovoltaics: 40 per cent of global supply;
  • energy efficiency: energy intensity down 60 per cent since 1980, and a further reduction of 20 per cent by 2010; 240 million tonnes of coal equivalent reduction by 2010;
  • new building standard: 50 per cent savings compared to current standard;
  • subsidies to photovoltaic (PV) production;
  • installation of 25 MW of solar PV in 2008; 100 MW since 2000;
  • 6,000 MW of wind installed by 2008; 3,000 MW in 2007 increasing by over 40 per cent per year (doubled in 2008 to 12,200 MW) and could reach 100,000 MW by 2020; and
  • 15 per cent renewable electricity target by 2020.

China went to the Copenhagen conference with an offer of a significant (40 per cent) intensity (tCO2e/GDP) reduction by 2020.

Japan’s commitment

Japan’s Prime Minister, Yukio Hatoyama, pledged to cut GHG emissions by 25 per cent below 1990 levels by 2020. However, this proposal is contingent on similar ambitious goals by other major emitters. In 2008, emissions were 16 per cent above Kyoto targets for 2008–2012. Major initiatives to attain the Japanese target are an ETS and a feed-in-tariff for production of electricity from renewables. It is not clear what the domestic/international offset balance for emission reductions would be in meeting the target.

Japan’s largest business association, Keidanren, opposes cuts of greater than 6 per cent by 2020.

Russian situation

In 2007, Russia’s actual emissions were almost 34 per cent lower than in 1990. Since Kyoto, many experts have expressed concerns about these surpluses flooding the international carbon market, thereby lowering carbon prices.

It will be interesting to see what Russia’s position will be in a post-2012 climate regime. Russia has the legal right under the Kyoto Protocol to use its surplus assigned amount built up during 2008–2012 for complying with follow-up commitments after 2012 (conservatively assuming that Russia’s emissions will remain constant at 2007 levels, a tradeable surplus of well over 1 billion assigned amount units could emerge).

Russia has officially announced a 10–15 per cent emission reduction target compared to 1990 levels to be achieved by 2020. According to a study by Anna Korppoo and Thomas Spencer (The Dead Souls: How to Deal with the Russian Surplus?, 2009), this target ‘neither reflect[s] the country’s efficiency potential, nor modelled trends’. Korppoo and Spencer argue that Russia could commit to a target of approximately –30 per cent below 1990 levels by 2020.

Indian position

The Indian Government stated on 29 November 2009 that it would not commit to binding emission cuts, but would sign onto a deviation from BAU. India has taken significant steps towards increased penetration of renewables and EEI. Over the past 10 years there has been an average of 8–9 per cent economic growth, with only 3.8–3.9 per cent growth in energy use.

China, Brazil, India and South Africa agreed to a draft statement on climate change for COP-15 as a basis for negotiations. India might follow China in setting an energy intensity reduction target without jeopardising a 7–8 per cent growth continuance.

Global emissions market

In 2008, it is estimated that the global emissions market was worth approximately US$126 billion, of which approximately US$92 billion was trading in EU abatement allowances. Clean Development Mechanism (CDM) certified emission reduction (CER) credits were valued at US$26 billion, five times 2007 levels. European utilities are the most significant players in the market. They also use derivatives as an instrument to hedge against energy prices.

Credit prices dropped in 2008 and 2009 as the economy declined, reducing CO2 emissions, thus reducing the demand for allowances. EU abatement allowance prices in the third quarter of 2009 were €13– 15/t CO2e (A$21–24/t CO2e). CDM CER prices were slightly lower.

 

Canada

Canada’s greenhouse gas emissions keep on rising

Canada’s National Inventory Report for 2007 emissions was filed with the UN on 17 April 2009 in compliance with its reporting obligations under the Kyoto Protocol. The report shows that there has been a 4 per cent increase in GHG emissions in Canada since 2006 and more than a 26 per cent increase since 1990. This increase makes Canada the G8 nation with the most significant rise in GHG emissions. Under the Kyoto Protocol, Canada pledged to reduce emissions to 6 per cent below 1990 levels. This latest report confirms that as of 2007, Canada was 33.8 per cent above its international commitment. The report indicates that transportation and energy production are primarily responsible for the rise in emissions as these sources account for approximately 143 million tonnes of the 155 million tonne increase since 1990.

On 18 November 2009, the Canadian Government declared that it would not announce new climate change policies until 2010.

Alberta (Canada)

Alberta’s Climate Change and Emissions Management Act and its associated Specified Gas Emitters Regulation set province-wide emissions reduction goals and provide the framework and regulatory enactment authority for the regulations that set out the details of Alberta’s emissions reduction and trading regime.

Alberta has set targets based on emissions intensity (emissions reductions per unit of output) . Its legislative regime requires mandatory reporting for all releases of specified gas (the term used to define GHGs and their global warming potentials) from facilities that emit more than 100,000 tonnes of GHGs per year (referred to as Large Final Emitters). There are approximately 106 Large Final Emitters in the province. By sector, these Large Final Emitters are power plants (45 per cent), oil sands (21 per cent), heavy oil (7 per cent), gas plants (7 per cent), chemicals (6 per cent) and other (14 per cent).

Large Final Emitters were required to apply for the establishment of a ‘baseline emissions intensity’ by 31 December 2007. The baseline is calculated based on the ratio of total annual emissions to production. A Large Final Emitter must not exceed 88 per cent of its baseline emissions intensity (i.e. 12 per cent below the facility-specific baseline). Reduction amounts are currently static, but more stringent targets are contemplated in the future. The regime contemplates that all new facilities will be subject to gradual reductions from the fourth year of operation, reducing emissions by 2 per cent per year until a 10 per cent reduction is achieved. Those found to be out of compliance may be subject to a $200/tonne fine. Other penalties for contravention of specified sections of the regulation could result in penalties of up to $ 50,000 in the case of an individual and $ 500,000 in the case of a corporation (e.g. failure to submit the required compliance report: s.11). Emitters can also be subject to administrative penalties.

If they are unable to make the mandated reductions on-site, Alberta’s system allows regulated entities to buy credits from other regulated entities, to purchase offset credits or to make a payment into the technology fund. Payment into the technology fund is currently set at $15/tonne of CO2e. Offset project assurance occurs after offset credits are created. Offset credits do not have to be pre-approved before they are used; however, they must be verified by a third party and the reduction must:

  • occur in Alberta;
  • not otherwise be required by law;
  • have a project start date not earlier than 1 January 2002;
  • be real and demonstrable; and
  • be quantifiable and measurable.

Alberta offset projects use government approved protocols to establish the scientific basis for the ultimate assertion that GHGs have been reduced or removed as a result of the project. In Alberta there are currently 24 approved protocols and approximately 14 more are in the review process.

Verified offsets (‘emissions offsets’) can be registered with the Alberta Emission Offset Registry and sold to Large Final Emitters in Alberta. Offset owners may also choose to register and sell their emissions offsets inter-provincially and internationally. In such cases, trading occurs through bilateral contracts outside the Alberta Emission Offset Registry. The Alberta system does not allow offsets from any source outside of Alberta. Large Final Emitters that emit less than their allocation can trade their emissions performance credits or bank them for future use.

Payment into the technology fund was a popular method of compliance in the first round of the program, ensuring that the price of carbon would not move much higher than $15/tonne. In the first compliance period, 1.5 million emissions offsets were created and over 2.6 million tonnes worth of payments into the technology fund were made. In 2007, 1 million emission performance credits were created, but only 250,000 were used for compliance purposes. In 2008, 1.9 million tonnes of emission performance credits were generated and 1.3 million of those were banked for future use. 2008 also saw 5.47 million tonnes worth of payments deposited into the technology fund and 3.4 million offset credits generated, 2.7 million of which were used for compliance purposes.

There have been over 5 million offset credits created under the Alberta system. Alberta emitters have spent more than $155 million on technology fund credits and offsets. The program saw 32 per cent of compliance attained by real intensity reductions in 2007 and 38 per cent in 2008.

The Chicago and Montreal Carbon Exchanges

With respect to emission reductions, the Chicago Carbon Exchange (CCX) is a self-contained voluntary regulatory scheme and trading system. Credits can be created on the CCX, in much the same way as in a government regulated system. On the one hand, a company may become a member of the exchange and agree to reduce its carbon emissions, thereby becoming a sort of voluntary regulated entity. On the other hand, a company may create a reduction project, the reductions from which, once they have been verified by a verifier that is approved by the CCX, may be registered on the exchange and traded. In short, the CCX acts as its own regulatory framework and determines the reduction requirements for its members as well as the validation criterion for reduction projects that are entitled to register credits on the exchange. The market for which the CCX is a platform is a voluntary market, in that the participants are not bound by law to reduce their emissions.

The Montreal Carbon Exchange (MCX) for its part is not a platform for a voluntary market but rather a market for forward contracts for delivery of ‘Canadian compliance units’ that will be created in a future regulated market to be put in place by the Canadian Federal Government. As such, the MCX is reliant on the coming into force of an eventual federal GHG emissions trading scheme in Canada. The MCX does not determine reduction requirements for any of its members, develop criteria for the validation of emission reductions or do anything other than function as a trading platform and clearing house for the contracts described above. The trading unit is a contract for future delivery of 100 ‘Canada Carbon Dioxide Equivalent Units’. Each such unit will be an entitlement to emit 1 ton of CO2 equivalent in the system to be defined by the government of Canada. The contracts will expire quarterly and the first expiration date is June 2011. Currently, the rules of the MCX provide for the physical settlement of the contracts with an alternative delivery procedure being available to the parties on an ad hoc basis.

Montreal Carbon Exchange activity

Although the exchange opened on 2 May 2008, the level of activity has been negligible. Exchange representatives attribute this to the federal government’s failure to deliver key elements to its offset system promised in mid-2008. This failure, along with the federal government’s non-committal attitude toward the execution of its proposed GHG regulatory scheme has depressed activity on the CCX market due to the uncertainty that the underlying element of the forward contracts will be available for delivery on the contract expiration dates.

The trading volume for the first quarter of 2009 for the four contracts that are currently traded is very low. Until such time as the federal government begins to create more certainty with respect to the timing of the coming into force of GHG regulation in Canada, there is little reason to expect any significant pick-up in the transaction volumes handled by the MCX.

The MCX must now contemplate what it will do in the event that nobody comes to the party in June 2011. In February 2009, the MCX sent out a survey to market participants asking them to give their view on different courses of action that could be adopted by the MCX in the event that the federal framework for GHG emissions trading is not in place by June 2011.

 

United States Cash for Clunkers Program: Greenhouse gas emission and other impacts

This program, part of the United States’ stimulus package, cost approximately $3 billion and concluded in September 2009. Approximately 700,000 rebates were used to purchase new cars in July and August, adding 0.3–0.4 per cent to GDP in the third quarter of 2009.

Greenhouse gas emission costs and benefits of the program

New York Times study concluded the following:

On average, USA cars are driven 12,000 miles per year, according to government statistics. Considering that the traded-in clunkers had an average fuel economy of 15.8 m.p.g. while the new ones deliver 24.9 m.p.g., a swap saved some 278 gallons of gas per year – which would have released almost 2.8 tonnes of carbon dioxide when burned.

Assuming the clunkers would have been driven four more years, the $4,200 average rebate removed 11.2 tonnes of carbon from the atmosphere, at a cost of some $375 per tonne. If they would have been driven five years the carbon savings cost $300 per tonne. And if drivers drive their sleek new wheels more than they drove their old clunkers, the cost of removing carbon from the atmosphere will be even higher.

To put this in perspective, an allowance to emit a tonne of CO2 costs about US$20 on the European Climate Exchange. The Congressional Budget Office estimated that a tonne of carbon would be valued at US$28 under the cap-and-trade program in the clean energy bill passed by the House in June.

The program might have been more efficient with modifications, like a smaller rebate. But even if the new cars bought under the program had zero emissions, the price of removing the clunkers’ carbon dioxide from the atmosphere would have been nearly $140 per tonne.

However, the New York Times analysis ignores two other major benefits of the program: air quality improvement and safety health benefits. Analysis of the similar British Columbia ‘Scrap it’ program concluded that air quality improvement benefits from removing older vehicles from the roads in Vancouver (the major city in British Columbia) could justify the program there. In addition, the health cost reductions by replacing older vehicles with much safer (e.g. ESP, ABS and air bags) new vehicles, would together with the CO2e and air quality index reduction benefits, make the program very attractive from a social cost–benefit viewpoint. Analysis of a similar program that could be adopted in Australia is required.