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. 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

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ISSN 0813-9474

Income tax zone rebates

 Dr Ian Manning, Deputy Executive Director, NIEIR

Abstract

 

Remote area zone rebates or allowances have been a feature of Australian income tax since 1945 and the social security system since 1984. In 2009, the Henry report on the tax system recommended that they should be reviewed, but no action has been taken. Zone rebates accord with each of the major purposes of the tax system. The first of these is the promotion of economic efficiency and economic development, chiefly by supporting the costs of infrastructure provision in remote areas and so assisting the pastoral and mining industries, where there is a case for compensation for the incidental effects of macroeconomic policy on these industries, and also assisting tourism, defence and indigenous development. The second major purpose of the tax system is the ability to pay principle; in this case, compensation for lower real incomes due to higher outback prices. Third is the benefit principle; that is, recognition of the higher cost of access to essential services from outback areas. As the Henry review expected, there is also a case for a review of zone boundaries, of the residence requirements and, in particular, of the rates, which have not been indexed since 1993. This paper presents the case for a review.

This paper was prepared for the Shires of Bulloo, Murweh, Paroo and Quilpie, the Maranoa Regional Council and Regional Development Australia, Darling Downs South West region. It is printed with permission.

Introduction

 For 68 years the income tax has included provisions to reduce the tax that would otherwise be payable by residents of remote areas. The major report into the tax system prepared by the Australian Treasury in 2009 (Australia’s Future Tax System: Report to the Treasurer or, informally, ‘the Henry review’) refers to these provisions as the ‘zone tax offset’. The report admits that it does not examine the zone offset in any detail but its basic attitude is clear from the wording of its Recommendation 6:

To remove complexity and ensure government assistance is properly targeted, concessional offsets should be removed, rationalised or replaced by outlays. … The zone tax offset should be reviewed. If it is to be retained, it should be based on contemporary measures of remoteness.”

Such a review has yet to materialise. The remote area tax rebate continues to be offered at rates that were last adjusted in 1993 and, therefore, have been significantly eroded by inflation. As of September 2011, all classes of zone rebate were worth around 62 per cent of their value in 1993 (adjusted by the consumer price index for Darwin). Longer term comparisons are more difficult because of changing consumption patterns, rising incomes and the switch from tax deductions to rebates. Updating using the consumer price index, the current zone A rebate is worth approximately 70 per cent of the value of the zone A rebate to a single worker on average earnings in 1948, but in relation to average weekly earnings the current zone A rebate is worth only a quarter of its value in 1948.

Given the recent lack of indexation, it appears that the remote area rebate is fated to fade away. This paper outlines the case for retaining and updating it.

History of income tax concessions for remote areas

In its present form, the Australian income tax dates from the Second World War. To pay for the war, the Commonwealth increased its rates of income tax considerably and incorporated the various state income taxes into its own tax. When the fighting ended the enhanced income tax continued to be collected, largely to pay for post-war investments in national development and also to enhance the social security system. In line with contemporary practice, the tax featured a schedule of rising marginal rates.

At the time, Australia was experiencing full employment and both businesses and governments resorted to paying ‘district and regional allowances’ to attract workers to remote and tropical jobs, many of which were considered of high priority for national development reasons. Much of the benefit of these supplements was clawed back by the Commonwealth through its marginal tax rates: at the time, the top marginal rate was over 75 per cent, although the marginal rate for a typical worker was around 18 per cent. In 1945 zone allowances were introduced in the form of deductions from taxable income for taxpayers resident in regions where workers commonly received district or regional allowances to compensate them for ‘disabilities of uncongenial climatic conditions, isolation or relatively high cost of living’.

Zone allowances were made available to all taxpayers who spent at least 6 months of the tax year living in a zone, not merely those who received district or regional allowances.

Two zones were defined. Zone A comprised the Australian tropics apart from the Queensland east coast south of Cape Tribulation, and zone B included the Queensland coast from Cape Tribulation south to Sarina plus the following: a belt of inland Queensland adjacent to zone A; the far west of New South Wales; the far north of South Australia; the Western Australian goldfields and the west of Tasmania. From the beginning, and to this day, zone A attracted a greater allowance than zone B.

In 1955 the zone A boundary was extended south to the 26th parallel. From 1958 zone allowances were complemented by loadings on the deductions for dependants, which had long been a feature of the tax system. In 1975 the zone allowance was converted to a rebate. The additional allowances for dependants were also converted to rebates and zone residents became entitled to percentage additions to their basic dependent rebates. When rebates for children were merged into Family Allowance payments they remained as an element in the zone rebate system.

The Public Inquiry into Income Tax Zone Allowances was conducted in 1981. Zone dependant rebates were increased as a result of this inquiry. A second important change was the creation of special areas, defined as places within zone A or B located more than 250 km by the shortest practicable surface route from the nearest town with more than 2,500 people as of 1981. The rebate in the special zone has been set at 3.47 times the zone A rebate.

Finally, in 1984 remote area allowances were introduced as supplements to all the major income-support social security payments. Remote area allowances are available to pensioners and some beneficiaries who are permanent residents of tax zone A and special tax zones located within zone B. They are not available in the non-special parts of zone B. The allowances are paid at the same rate without distinction between the special zones and the rest of zone A. Although not part of the income tax system, these allowances are an obvious complement to the income tax zone rebate. Taken together, they mean that the Commonwealth provides income allowances for nearly all permanent remote area residents.

The Cox Inquiry

The 1981 Cox Inquiry is the only review of the system to date and, therefore, is worth considering in detail. The four members of the Public Inquiry into Income Tax Zone Allowances called for submissions and arranged public consultations. After going through this process they found that their views diverged. As a result, the team of four members produced three reports with different recommendations. The main report was signed by the chairman (P. E. Cox) and S. G. W. Burston and, with reservations, by the other two members. G. Slater prepared a minority report with alternative recommendations and A. M. Kerr added a statement in which he endorsed some recommendations and varied others. However, the Cox Inquiry was unanimous in recommending that zone allowances should continue; the differences between its members concerned the geography of eligibility and the rates of allowance.

It is likely that in any future review much the same arguments will be considered and similar divergences will emerge. We will accordingly base our discussion of the purpose of the rebates on the points raised in 1981. We will also ask whether conditions have changed so as to affect the relevance of the arguments, keeping in mind two obvious differences since 1981:

  • that the real value of the rebates has declined through failure to index them; and
  • that the income tax rebates are now complemented by social security entitlements.

There have also been various other more subtle changes since 1981 and, indeed, since 1945.

Incidence of zone rebates

Serious discussion of remote area rebates is only possible if we know who they benefit. As compared with a situation where rebates are not available, do they benefit employees, granting them higher disposable incomes, or do they benefit employers, allowing them to reduce cash pay rates?

When remote area allowances were introduced in 1945 it was assumed that they were essentially a benefit to employers who would be able to attract labour with lower remote area loadings than would have been required in the absence of the tax allowance. However, much recent discussion of the equity of zone rebates assumes that they have no effect on pay rates and, therefore, the rebate benefits the employee. It is hard to make a definitive judgement since the answer depends on an unobservable variable: What would remote area wage rates be in the absence of the zone rebate?

Tentative answers are as follows:

  1. Where the rebate is large (as it was, in relation to wage rates, when the provision was first introduced), it is hard to argue that it will not affect at least some wage rates. When this happens at least some of the benefit will accrue to employers, who may increase the level of remote area employment in response. Per contra, when the rebate is small (as it is now, in relation to wage rates) it is less likely to be taken into account in wage negotiations.
  2. Where wage rates are fixed by centralised wage-setting authorities without regard for geographic area, it is more likely that the benefit will accrue to employees. When wage rates are set by ‘the market’, it is more likely that the rebate will be taken into account in setting wage rates and, therefore, will accrue to employers.

Given the erosion of the value of the rebate in relation to wage rates, one would expect a trend towards its benefiting employees rather than employers. However, the trend away from centralised wage determination to bargained rates has increased the chances that the rebate will benefit employers. These two trends cancel out, and the best that can be said is that the incidence of the rebate is likely to vary with circumstances. By contrast, the remote area allowance in social security unambiguously increases the income of its recipients.

Decentralisation and industry development

The Second World War was a shock to Australia’s sense of security. One reaction to this shock was to seek to raise the national population and in particular to populate the north: those vast regions with population densities way below those not so far away in Asia. It was also believed that there were significant unutilised resources in the north and that exploitation of these resources would be of national benefit. Tax incentives were an obvious element in policies to populate and develop the north.

‘Develop the north’

In 1945 it was commonly believed that one of the hindrances to populating and developing the north was the ‘uncongenial climate’. For decades up until the Second World War most tropical countries were under the control of the European powers as colonies. In these countries the colonialists managed and the natives worked. The racial division of labour in the tropical colonies meant that the idea that people eligible to be citizens of White Australia could do all the work necessary to develop tropical Australia was still somewhat novel. Populating the north would be a great national experiment and there was a sense that the nation as a whole should participate in the experiment by providing cash rewards to people who went north.

The Australian population doubled during the 37 years separating the original provision of zone allowances and the Cox Committee’s hearings in 1981, but not in the pattern envisaged by those who sought to populate the north: the growth was based on manufacturing and much of it occurred in the cities, reflecting deliberate policies of industry development. The committee held its hearings at a time when Australia was debating government involvement in industry development, particularly tariffs. Tariff cuts were a cause célèbre in remote areas where it was argued that abandoning protection would provide a major stimulus to local export industries, including pastoral production and mining. It was even argued that, in the absence of tariff cuts, zone rebates were justified as compensation for the costs of protection. Three decades on, tariffs have been cut, the mining and pastoral industries continue their cycle of boom and bust (currently boom) and the argument for zone rebates as compensation for tariffs has disappeared. The Australian population has grown by a further 50 per cent, still mainly in the major cities and their immediate surrounds but with one significant change: Darwin has moved from backwater status to become a vibrant if small city.

During the post-war period the cry to develop the north became muted. The memory of recent conflict faded and various high-profile investments to develop the north struck economic trouble (e.g. Humpty Doo rice and the Ord River Dam). At the same time, Australians became less anxious about their capacity to survive and work in the tropics, although to this day Australian tourists avoid the north and centre during the hot and wet seasons. Despite these subsiding anxieties, the Cox Inquiry took the idea of compensation for an uncongenial climate seriously. The committee observed that no place in Australia has a completely congenial climate: everywhere there are episodes when it is too hot or too cold or too wet or too dry. However, some places are less comfortable than others. According to a meteorological discomfort index, which emphasises heat and humidity, the most uncongenial region extends eastwards from Kununurra. Even in this area it is now possible (at an expense) to create congenial indoor, car-driving and plant-operating conditions through air conditioning. If air conditioning is the answer, there is no need for compensation for uncongenial climate but there may be a case for compensation for the cost of air conditioning and, for that matter, for the cost of heating in cold places.

Interest in population geography did not disappear when the metropolitan electorates forgot about populating the north, but was replaced by the promotion of decentralisation, which meant moving jobs out of the capital cities to reduce congestion costs. This argument for decentralisation was, however, irrelevant to zone rebates since it was not necessary to move more than a moderate distance from the capital cities to avoid congestion; indeed, longer moves into the remote regions tended to increase transport costs.

Although decentralisation provided no more than weak support for zone rebates, there was still the argument that it was in the national interest to encourage the development of remote area resources. Whereas this argument was important in 1945, the Cox Inquiry gave it relatively little attention. All members of the inquiry, despite their divergences in other respects, seem to have been persuaded that resource development would be better pursued by other means. They provided very little discussion of what these other means might be, although in the 1980s there was a rising body of opinion that held that development should be left to the private sector. The Cox Inquiry concluded that zone rebates were justified on ‘horizontal equity’ but not industry development grounds. The equity arguments will be considered below, after the economic development arguments are reconsidered.

Structure of the outback economy

Discussion of the economic development argument for zone rebates not only requires assumptions about incidence (employee or employer?) but a definition of the remote areas. It would be possible to adopt current tax definitions (i.e. zone A, zone B and the special zone), but, as the Henry report points out, these zones are in need of review. Remote areas can be conceptualised in two main ways:

  • as regions of low population density that either lack urban centres or have few and isolated towns; or
  • as regions with limited agricultural resources apart (perhaps) from small irrigated oases.

The two concepts are related, with the low population density the result of the limited resource base. For the purpose of this discussion the remote area, or outback, will be defined as country where there is no, or very little, arable or forest land. By this definition Victoria, Tasmania and the Australian Capital Territory do not contain any remote areas. In Western Australia, South Australia and New South Wales the remote areas comprise all country outback of the wheat-sheep belt and in Queensland all country west of the Maranoa, the Peak Downs and the Tablelands back of Cairns. All of the Northern Territory is remote except Darwin and its immediate surrounds. To avoid confusion with ‘remote Australia’ as defined by the Australian Bureau of Statistics (ABS), we will refer to this area as the outback.

Although the outback lacks arable land and, hence, has few farmers, it is by no means lacking in pastoral and mineral resources. This is reflected in the industry distribution of the approximately 150,000 jobs (1.6 per cent of the national total) that were located in the outback in 2001 (Table 1).

 Table 1   Outback employment by industry, 2006

 Capture

 Three industries were overrepresented in outback employment: mining (including associated manufacturing such as smelting and equipment repair), the pastoral industry (plus fishing, hunting and a few meatworks) and tourism (in so far as this can be separated from the more general accommodation and transport industries). Defence and general government service employment was present at slightly above national average rates, while all other employment was underrepresented in relation to the national average. In particular, the outback generates few jobs in finance, information, professional and scientific services.

Arguments for assistance to outback economic development

Several strands of argument for assistance to outback economic development can be distinguished. Two of the arguments are familiar from the history of zone rebates:

  • the strategic and moral argument that Australia wishes to occupy, and be seen to occupy, its whole national territory, and to take such measures as are necessary to defend it; and
  • the argument that resources should be developed.


The question is whether, given the range of policies available, zone rebates are an efficient means towards achieving these ends. In addition, a new argument has arisen. In 1945 and even in 1981 the proponents of developing the north tended to overlook the fact that much of remote Australia was already occupied by indigenous people, admittedly at low density but including regions where a century of efforts to develop profitable settler enterprises had failed. Over the past 30 years indigenous occupation has been recognised by the award of native title over significant parts of remote Australia to traditional owners. Social and environmental changes mean that these owners and their families can no longer live on their traditional lands as hunter-gatherers. Although some remote indigenous communities have an assured economic base, many of them depend on a mixture of Centrelink payments and government employment. It is beyond the scope of this paper to enter into the current vigorous debate about the economic future of these communities but it is fair to ask whether zone rebates have a role in generating ‘real jobs’ for them.

The economic development argument for zone rebates resolves into the judgement that it is desirable to develop remote areas more rapidly than would take place under ‘hands off’ policies and that zone rebates make sense as a component of the resulting economic development policies.

If the benefit of zone rebates goes to the employee, they may be interpreted as an incentive to employees to undertake remote area work. If the benefit of zone rebates goes to the employer, they may be interpreted as an incentive to employers to create remote area jobs. Although the discussion could be cast in terms of either interpretation, the present discussion will assume that the benefit of the rebates goes to employers and reduces the cost of remote area labour. It is, in effect, a wage subsidy.

At this point it must be conceded that the effectiveness of wage subsidies in generating remote area employment and economic development is likely to vary across the outback and also between remote area industries. However, outback areas have several features in common:

  1. Their industry structure is thin. Typically, they have only one or two economic base industries plus support services.
  2. Their  economic  base  industries  are  typically trade-exposed;   indeed,   most   are   export industries directly dependent on overseas markets.

 These characteristics leave the remote areas subject to several market failures:

  1. Along with other tradable industries, they are exposed to overvaluation of the exchange rate. Australia’s chronic balance of payments deficit provides evidence that the exchange rate is, on average, overvalued and that, to correct this, trade-exposed (particularly export) industries should be encouraged vis-à-vis trade-sheltered industries. This applies to trade-exposed industries generally but is crucial in the remote areas due to their dependence on such industries.
  2. Not only is the exchange rate overvalued but it fluctuates unpredictably. In addition to the price fluctuations generated by international markets, the trade-exposed industries are further exposed to price fluctuations generated by movements in the exchange rate. Current policy is to welcome these movements for their contribution to short-term macroeconomic management but they have the serious side-effect of increasing the level of risk borne by long-lived investment in the trade-exposed industries. Much of the investment required by outback industries is long-lived, consisting as it does of property improvements and transport infrastructure. Once again, there is a case for policies to ameliorate this side-effect.
  3. This industry structure and low population density mean that the remote areas depend more heavily than others on government provision of infrastructure. For example, telecommunications are commercially highly profitable in high-density areas but not so in low-density areas.

These arguments will surface in various forms as we discuss the major outback industries. As shown in the discussion above, mining now dominates the outback export industries. However, it remains that pastoral production is the classic, and most widespread, outback export industry. We will consider it first.

 

Pastoral production

From first settlement the pastoral industries (wool and beef) were seen as the economic mainstay of the outback, as they still are in western New South Wales,Western Queensland, northern South Australia and much of the Northern Territory. Judged by employment, they dominate the economic base of shires such as Central Darling (New South Wales), Barcoo and Boulia (Queensland). In such shires pastoral production may be augmented by hunting (e.g. feral goats and kangaroos). Some of the coastal outback supports a fishing industry, which, like hunting, is run by small businesses.

When considering the importance of sheep and cattle in the outback it is important to remember that pastoral production also occurs elsewhere, including in the wheat/sheep belt and hilly pastoral areas such as New England and the Monaro. Is it reasonable to argue for zone rebates for the remote part of the pastoral industry while denying them to the same industry operating in closer-settled regions?

Managing a high-risk industry

Government policy towards the remote area pastoral industry is discussed in a companion article that deals with the position in South West Queensland. The experience in South West Queensland and, indeed, in the pastoral industry as a whole is that the industry is high risk as the succession of good and bad seasons interacts with fluctuating commodity prices and the risk-increasing effects of fluctuating exchange rates. For the best part of two centuries the pastoral industry has proved its resilience, not only to price fluctuations but to the sequence of good and bad seasons. Resilience involves prudent accumulation of reserves during the good times and maintenance of capacity during the bad: it is hard to take advantage of the next in the capricious series of booms without productive capacity in place.

Reserves can be accumulated in different ways. One way is through cash and off-property investments but another is by making improvements to property. The pastoral industry has traditionally used a combination of off-property and on-property investment to employ funds generated in the upswings of the seasonal and commodity cycles. Similarly, the maintenance phase can be financed by running down investments (and in dire necessity incurring debt) and by postponing on-property investment, but preferably in a way that does not threaten capacity.

At the regional level, these business strategies can be complemented by government action. When the pastoral industry is in a boom phase, the government can help to release local resources to participate in the boom by restricting itself to maintenance. When the pastoral industry is in a maintenance phase, it is appropriate for governments to attempt to take up the slack, investing in infrastructure as a contribution to readiness for the next boom. It is, of course, as difficult for governments as for businesses to make the necessary financial arrangements, exercising discipline during booms and countering despondency during periods of slack activity, but this is no excuse for not trying.

In this discussion it has been assumed that fluctuating commodity prices are inevitable. It has often been pointed out that steady capacity utilisation would be less wasteful than the current alternation between the costs of overcapacity production and the costs of underutilised capacity. While steady prices sufficient to generate a moderate rate of profit minimise costs, there is no known way to achieve this steadiness in commodity markets. The chief lesson from Australia’s long and sorry history of government schemes to stabilise 0agricultural markets is that intervention at the industry level is hazardous, to say the least, and that governments are best restricted to general countercyclical policy, including the maintenance of infrastructure and its extension during times when activity levels require support.

Case for remote area wage subsidies in the pastoral industry

Against this background, can a case be made for zone rebates to assist the remote area pastoral industry? Because the rebates have to be financed, it may be assumed that they (slightly) increase tax rates in non-remote areas and, therefore (slightly), reduce employment in these areas. Can a case be made for this?

We have already noted an argument on these lines: the claim, in 1981, that zone rebates compensated for the effect of tariffs on remote area industry costs. This argument has lapsed with the cuts in tariffs, and in any case it drew a long bow. However, it can still be argued that pastoral employment in remote areas should be encouraged through zone rebates, as follows:

  1. Remote areas depend on trade-exposed industries subject to volatile international prices. These industries are important for balance of payments reasons. Price volatility coupled with a finance sector that is unable to provide insurance against medium-term price fluctuations creates risks which, if not managed, will result in these industries having less capacity (and the non-tradable industries having more capacity) than desirable in the overall long-run allocation of resources. It is neither possible nor desirable that the price volatility should be removed. In lieu of removal of price volatility, other ways should be sought to ensure that capacity is maintained, particularly in downturns.
  2. The prohibition of direct industry-specific subsidies by World Trade Organisation rules means that indirect industry support measures are relevant. Possible indirect support includes skills training, subsidies to research and market development, government provision of infrastructure and wage subsidies available on a regional rather than an industry basis.
  3. The advantages of wage subsidies on a regional basis are stronger than they appear prima facie, in that such subsidies assist the maintenance and development of regional infrastructure (defined broadly to include support services) on which the pastoral industry depends.
  4. The case for regional wage subsidies is strongest in the remote areas, due to their high level of risk. Not only are the seasons more variable than in the closer-settled regions but the thin industry structure means that there is little flexibility to turn to alternative sources of income when the pastoral industry is suffering from a downturn.
  5. The case for wage subsidies is strongest when the industry is in maintenance phase but can be made generally, in that wage subsidies compensate across the trade cycle for the higher than average (and partly artificial) risks, which otherwise result in the pastoral industries attracting less investment than is economically efficient.

 

The market failure case for wage subsidies in remote areas where the pastoral industry provides the economic base therefore rests on these areas being much more dependent on a trade-exposed industry subject to volatile prices than the rest of the country. In addition, the residents as a whole contribute, through their social networks and support services, to the productive capacity of the pastoral export industry.

Providing wage subsidies to all outback employers, rather than just to the trade-exposed pastoral industry, strengthens the capacity of the region as a whole to support export production while avoiding interference with the market allocation of resources within the remote areas and interfering no more than marginally with the allocation of resources between the remote and non-remote areas. The capacity of local and state governments to maintain infrastructure and the capacity of local service suppliers (e.g. retail, equipment maintenance and social facilities) are enhanced along with the capacity of pastoralists to maintain their properties

 Mineral resource exploitation

Although the pastoral industry is the classic outback activity, the mining industry is currently very active in several outback regions.

Mineral resource exploitation and the pastoral industry: Similarities and differences

The mineral resource industry covers mining broadly defined to include production of metal ores, energy minerals and non-metallic minerals plus mineral exploration, services to mining and related manufacturing activities, such as ore beneficiation and heavy equipment repair carried out close to mine sites. This industry has several characteristics in common with the pastoral industry:

  • many of its operations, to the extent of a quarter of total industry employment, are in the outback as defined for this paper;
  • the industry is trade-exposed and has to cope with the vagaries of international commodity markets and the Australian dollar exchange rate; and
  • like the outback pastoral industry, the mining industry has the choice of making do with the levels of infrastructure provided by the Commonwealth, state and local governments, or providing its own.

Despite the likenesses there are major differences. First, most parts of the mineral resource industry are capital intensive and wages are a minor proportion of costs. Therefore, wage subsidies are unlikely to affect the location or level of industry activity. However, they may affect resource allocation decisions within the industry, particularly resource allocation to labour-intensive industry activities, such as site remediation.

Second, the exploitation of mineral resources is extractive whereas pastoral production is sustainable provided overstocking is avoided. The extractive nature of the mining industry is reflected in different financial arrangements: miners have to pay royalties to the state governments. The high profitability of the mining industry during the current boom has generated debate as to whether the states and territories are levying sufficient royalties to compensate future generations for the sale of the resource (see discussion in the companion article). Those who argue that the industry is being subsidised through low royalty payments are likely to argue that it should not receive any further benefits from wage subsidies.

Third, the exposure of the mining industry to fluctuating exchange rates is limited by the fact that the industry is largely overseas-owned, which means that its capital transactions are carried out in overseas currency rather than Australian dollars. This reduces risk and reduces the cogency of the argument for compensation for uninsurable risk.

Fourth, the financial strength of the large overseas-owned corporations which dominate mining lessens the case for wage subsidies.

Fifth, mining industry employment is concentrated in a small number of major outback centres. The four Pilbara shires plus Kalgoorlie and Mount Isa together account for nearly half of total outback mineral resource employment. These workers have access to reasonable urban facilities, which lessens the case for wage subsidies to ease recruitment.

Finally, as noted in the companion article, the mining industry has adopted a completely different employment strategy to the other remote area industries, one which may further reduce the case for wage subsidies. Many of the firms in the industry have adopted a policy of high wages, low expenditure on workforce development and low job security. A major element in this strategy is fly-in fly-out and the question raised is whether wage subsidies should apply to fly-in fly-out workers.

We will first consider fly-in fly-out and then return to the more general case.

Fly-in fly-out

Currently, whether a fly-in fly-out worker can claim a zone rebate depends on the 6-month rule. A claim can be made if the worker spends more than 6 months worth of nights in the zone during 2 successive financial years. It is not unknown for employment contracts to be drawn up with an eye to satisfying this requirement. It would be a simple matter to withdraw eligibility from fly-in fly-out workers by extending the residence requirement to (say) 10 months in each year or, alternatively, to reduce the residence period so as to include visiting professional personnel who stay for shorter periods.

The decision here depends on conceptualisation. If the wage subsidy is simply a wage subsidy to industries that are under-investing due to uninsurable risks arising from price and exchange rate volatility, it would be appropriate to extend it to all persons employed in such industries, whether in remote areas or no. If, however, the wage subsidy is a form of compensation to those who employ the residents of communities that are heavily dependent on the risk-exposed export industries and that contribute to the prosperity of those regions, it is not appropriate to extend the subsidy to fly-in fly-out workers. Looked at this way, fly-in fly-out workers should be seen as belonging to the labour markets of their region of primary residence. It is argued in the companion article that the mineral exploitation industry, with exceptions, has not been highly committed to regional development, and when it is committed to such development, it is likely to develop a resident workforce that would be eligible for remote area rebates under a 10-month rule.

A second argument for excluding fly-in fly-out workers from wage subsidies was also reviewed in the companion article: fly-in fly-out is perceived as imposing unnecessary costs on workers’ families. If this is the case, the least the Commonwealth can do is to refrain from subsidising it. Exclusion of fly-in fly-out workers while continuing to support resident employment provides employers with an incentive to the latter.

It should also be noted that, in so far as fly-in fly-out workers spend their incomes in their places of permanent residence and not in the remote regions, arguments for compensation for high living costs or for high costs of access to public services do not apply to them.

Finally, the extent to which remote area employers resort to fly-in fly-out is also influenced by fringe benefits tax. A review of this tax is beyond the scope of this article but would have to be incorporated into any considered review of the zone rebates.

Exploration and infrastructure

Mineral production sites (i.e. mines, quarries, oil and gas wells and processing facilities) generally have specialised infrastructure requirements that are, rightly, provided by the industry. However, one crucial part of the mineral industries depends more heavily on general infrastructure: mineral exploration. This is also a high-risk part of the industry because many mineral explorers find nothing. This risk is magnified financially since it arises well in advance of any resulting revenue.

Approximately 8,000 people are employed in mineral exploration nationally, which is a little over 10 per cent of the workforce employed in mining broadly defined. Of these, around 1,500 work in the outback and a further 900 or so work at no fixed address. Even if we add these numbers together, mineral exploration is responsible for less than 2 per cent of outback employment and many of these workers are likely to be flying-in and flying-out. Employment in mineral exploration is spread across the continent, with concentrations in the capital cities (particularly Perth) and the mining provinces.

Where mineral explorers are engaged in proving up and extending deposits that are already in production they may rely on purpose-built industry infrastructure, but where they are seeking new deposits far and wide they rely on the transport, supply and support facilities that happen to be in place. Support to the providers of these facilities, whether by wage subsidies or otherwise, assists mineral exploration, leading to a case for wage subsidies to infrastructure provision useful to mineral exploration.

The case for wage subsidies to the outback mining industry in general is less strong than for the pastoral industry, particularly in boom times such as the present, but is likely to become stronger when it becomes a question of maintaining capacity during a slump and when the industry is providing infrastructure of general benefit. Wage subsidies also reduce the cost of remediation, thus encouraging the industry to take this responsibility seriously. There is also a case for wages subsidies to outback resident workers as a way of lessening the advantages of fly-in fly-out to employers.

 Defence

Four significant defence complexes are located within the current tax zones A and B, at Cairns (Queensland), Townsville (Queensland), Darwin/Berrimah (Northern Territory) and Katherine (Northern Territory). In total, these installations account for 13 per cent of persons employed in the defence of Australia (compared with 16 per cent Canberra). However, only about 1,250 defence personnel are employed in the outback as defined in this paper and they constitute less than 1 per cent of total outback employment.

It may be argued that the Commonwealth does not need to provide itself with wage subsidies in order to employ its own employees: it could equally well charge full taxes and use the proceeds to raise employee wages. On this argument there is no need for zone rebates for Commonwealth employees, including defence personnel. However, zone rebates are only a wage subsidy if their eventual incidence benefits the employer; technically, they are a tax rebate claimed by employees. Therefore, It would be administratively inconvenient to deny them to Commonwealth employees while allowing them for other income recipients.

It is more important to note that the effectiveness of defence personnel depends not so much on the location of their bases as on the ease with which they can access the areas that they are to defend. Access is mainly by road, although also by air and sea. Local and state governments have substantial responsibility for roads and airstrips in remote areas. There are no explicit Commonwealth payments that recognise the defence importance of these assets, although this is partly taken into account in Commonwealth grants for roads and other local government expenditures. Wage subsidies assist in equalising costs so that similar amounts of grants yield similar amounts of road maintenance. The main defence argument for outback wage subsidies is thus an argument for infrastructure subsidies.

Tourism

A number of Australia’s major tourist attractions lie in remote regions, along with a considerable further number of potential attractions. Remote locations that have developed significant trade over the past three decades include Kakadu, Uluru, Broome and Shark Bay. Many less well-known remote locations have also developed tourism as part of their economic base.

Governments have acknowledged the importance of tourism as an economic activity through regulation to maintain standards and assistance with publicity. They also provide the transport infrastructure that underpins tourism. Remote area transport infrastructure is undergoing steady improvement, which has generated additional tourism activity. However, there are plenty of opportunities to develop the industry further.

The current high Australian dollar is proving that tourism is a trade-exposed industry with a claim on outback wage subsidies not dissimilar to that of the pastoral industry. Like defence, it depends on transport infrastructure, not to speak of basic social infrastructure. In this way, it generates an argument for wage subsidies to the provision of outback infrastructure broadly defined.

Lands in traditional ownership

Much effort has been expended over many decades to find an economic base for communities living on traditional lands, including experiments with agriculture, silviculture, pastoral production, tourism and mining. In some places these experiments have succeeded but, scattered across remote Australia, there remain many indigenous communities that depend on welfare payments and, hence, on remote area social security allowances.

Wage subsidies assist the states, local governments and non-profit agencies in provision of welfare-oriented employment (including health services and education). They also assist with the provision of physical infrastructure, including the transport and communication facilities without which there is little hope that ‘real jobs’ will become available. For example, it is sometimes argued that real jobs could arise in land conservation, including from such measures as the recent Carbon Farming Initiative. These developments will require local transport between communities and the places to be conserved, not to speak of transport facilities for tourists to come and admire conservation areas.

Service employment

The industries discussed so far (i.e. the outback export or economic base industries) account for roughly one-third of outback employment (Table 1). The remaining two-thirds comprises employment in various service industries, including transport, trade, education, health services and government services. In discussing the outback export industries, the importance of these service industries has been emphasised: the economic viability of outback export industries (including defence) depends on infrastructure; that is, on the adequacy of the services provided by the service industries. As a general rule these industries are labour intensive (particularly health and education) and stand to benefit from wage subsidies. Indeed, much of the economic case for outback wage subsidies rests on their contribution to infrastructure provision and the indirect contribution this makes to the export industries.

Contribution of zone rebates to outback development

It is argued above that zone rebates have a place in encouraging outback economic development and by this means underwriting the effective occupancy of the Australian continent, both by indigenous communities and by the general population. In particular, wage subsidies are helpful in two ways:

  • by assisting with the provision of infrastructure in the broad sense, so benefiting the economic base industries of the outback and enabling them to fulfil their role in utilising the resources of the outback to the national benefit; and
  • by countering high levels of uninsurable risk in the major outback export industries.

Additional benefits arise because the assistance to infrastructure helps with defence and will potentially contribute to the self-improvement of the remote indigenous communities.

Higher Education Contribution Scheme

We have so far considered zone allowances as primarily an income tax provision. However, the provision could be extended to the Higher EducationContribution Scheme (HECS). HECS has many virtues as a means of financing higher education. It is essentially a tax measure since it relies on income tax assessments to recoup loans, thus avoiding many of the problems of private-sector student loan schemes, although with the corresponding disadvantage that repayment can be avoided by emigration.

An incentive to young professionals to work in remote areas could be provided by the Commonwealth forgoing HECS repayments which would otherwise have been exacted from residents of remote areas.

Costs of living

We now turn to the equity arguments for zone rebates considered by the Cox Inquiry.

Remote area rebates have frequently been defended as compensation for higher costs of living in remote areas. This is most easily argued if one takes the view that the benefit goes to employees: the concession then goes to increase the taxpayer’s disposable income to compensate for higher prices. However, in a free labour market it is likely that price compensation has already been included in the wage package and that the benefit of the rebate goes to employers. In this case, the rebate (partly) compensates employers for the higher costs of labour hire in the remote regions, where these costs relate to the higher cost of living.

The Cox Inquiry took the simple approach. If the taxpayer rather than the employer benefits from the rebate, it is arguably fair that income received should be adjusted for geographic price differentials. Comparing two people on the same cash wage, the one who has to pay higher prices has the lower ability to pay taxes. However, as always, there is a contrary argument. If geographic differentials reflect different costs in service provision or different land costs, they have a function in providing incentives to the efficient location of economic activity. Compensation will blunt the incentives. A taxpayer who objects to the higher prices charged in the remote areas has the option of shifting elsewhere and the incentive argument says that this is exactly what he or she should do; the taxpayer should not be granted a concession. In this conflict of values the Cox Inquiry inclined towards the ‘real income’ or ‘horizontal equalisation’ view. Essentially they argued that the incentive effects were less important than the inequity of depressing the standard of living of outback employees.

It is one thing to claim that the cost of living is higher in remote areas than in some reference area, say the metropolitan areas. It is quite another to give this monetary expression. The following observations are more or less agreed:

  1. Transport costs add to the price of widely-distributed consumer goods in remote regions.
  2. In small remote towns there are further additions due to diseconomies of small scale, including less than truckload shipments and/or high warehousing costs for larger shipments. Consumers can avoid these costs only at the considerable expense of driving to a larger town.
  3. Remote area consumers are further disadvantaged by the limited range of goods and services on offer.
  4. Housing cost differentials are more complicated; in general, the unimproved value of the underlying land is less than in metropolitan areas but the costs of construction are greater.
  5. Construction costs are particularly high in small towns that lack resident tradespeople, since transport and accommodation costs have to be met.

The Cox Inquiry noted that the ABS had, in the late 1970s, prepared an experimental index of relative retail prices for food across Australia’s major metropolitan areas and a large selection of country towns. Where a weighted average of prices in the eight capital cities was set at 100 this index yielded values of 110 in Cunnamulla and Charleville, the only two centres assessed in South West Queensland. It was only in the Pilbara that larger and smaller centres could be compared, with an index value of 115 in Port Hedland and 136 in Marble Bar. Judging by this differential, Thargomindah would probably turn in a value around 125. The index was experimental and was not continued, but the differentials thus documented accord with current anecdotal experience in South West Queensland: not only for food but for consumer prices generally. The main exception is housing costs, which depend on the balance of supply and demand in each town.

A fundamental feature of price indices is that they cover the same ‘basket of goods and services’ for each comparison. This is a bold assumption over time (new commodities are constantly entering consumers’ shopping trolleys and old items exiting) and it is an even bolder assumption when comparing places. Consumers in remote areas have different opportunities to those in the metropolitan areas: less choice, perhaps, but also some choices that are not available in metropolitan areas (a rodeo perhaps). Again, restricted choice itself has benefits: there is no need to agonise over choice and perhaps there is more time for simple entertainment, like yarning over a beer or playing participant sport. Some remote area residents have rejected the rat race; they don’t have to keep up with the Joneses and consider that they pay less for a better life than they would have had in the cities. More generally, people confronted with different price patterns adjust to those patterns; they buy more of what is relatively cheap and don’t agonise over what is relatively expensive or not available. The resulting difficulties of measurement are known in economics as the ‘index number problem’, which means that comparisons apply to ‘typical’ people and not to those who have taken particular advantage of the opportunities available in different places or at different times. When metropolitan and remote areas are compared, the result regarding a ‘typical person’ is robust: the cost of living is, indeed, higher in remote areas.

Even so, the difficulties of measuring cost of living differentials and the lack of up-to-date evidence have caused people to appeal to an alternative differential (i.e. differences in access to government services) as a way of quantifying outback disadvantage. This does not mean that the cost of living argument has lost its force; rather, it has been supplemented with a related argument pointing in the same direction.

Isolation and services

In 1945 zone allowances were, in part, justified as compensation for isolation. This is a somewhat slippery concept. In so far as it was desirable to compensate for isolation so that it would be easier to recruit labour to the developmental task in the remote regions, the argument collapses back to populating the north, decentralisation and the exploitation of remote resources already discussed. However, the argument can take another tack: zone rebates can be seen as (possibly token) compensation for the reduced range of government services available to the residents of remote regions and/or as partial compensation for the transport and telecommunications costs occasioned in accessing essential services. Here the appeal is to another of the classic principles of taxation, the benefit principle, which argues that taxes should be related to the value of benefits received. Remote area residents receive less benefit and, therefore, should pay less. Alternatively, the private (mainly transport) costs of accessing government services are greater and there should be compensation for this. Those who make this argument tend to assume that taxpayers receive the benefit of the rebate, but like cost compensation the argument can also be applied when the benefit is assumed to go to employers. The rebate then compensates employers for the extra wages they have to pay so that their employees can access services.

In 1981 it was argued that zone rebates were an unfair way of compensating for service access costs because they were available only to taxpayers and not to people who fell below the tax threshold. This argument is no longer valid. The provision of remote area allowances to social security recipients in 1984 means that most remote area residents now gain compensation.

Remote area residents have two main ways of dealing with the problems of service access. These are:

  1. Bundling trips: Visits to service outlets, other than emergency visits, can be bundled together and satisfied in a single ‘trip to town’.
  2. Accepting a more limited range of choice and a concentration on the quality of local facilities. Thus, metropolitan residents who disapprove of the education provided in their local high school send their children somewhere else. Residents of towns that are not large enough to support multiple schools are much more likely to campaign for an improvement in standards in their local school.

By contrast with the lack of recent work on cost of living differences, two studies on geographic differences in service provision have been published since the Cox Inquiry.

In 1997 the Commonwealth Department of Health and Aged Care commissioned the National Key Centre for Social Applications of GIS to develop an accessibility/remoteness index for Australia. There are two main inputs to this calculation:

  • a list of urban centres classified into five population groups, 1,000–5,000, 5,000–18,000, 18,000–48,000, 48,000–250,000 and >250,000; and
  • a matrix of road distances.

For each ‘populated locality’ in Australia, road distances are calculated to the nearest urban centre in each of the five groups. This distance is divided by the average all-Australia distance for the category. The five scores thus obtained are added and used to define five ‘remoteness area classes’. (That there are five scores and five classes is coincidental: the researchers could have varied either number.) The remoteness area classes vary from ‘major city’ through ‘inner regional’, ‘outer regional’ and ‘remote’ to ‘very remote’. (Note the peculiar use of ‘regional’ in this nomenclature to mean neither metropolitan nor remote.) The ABS has adopted this index as a means of classifying the remoteness of localities throughout Australia.

The fundamental assumption underlying the remoteness index is that service availability depends on town size and that increments in service availability occur at the five population thresholds used in the classification. Using the same general methodology, a different size classification would yield different patterns. Similarly, different weights could be awarded to the size categories. Work by NIEIR for the Farm Institute provides a check on these assumptions, since this work did not take urban centre size as a proxy for service availability but instead plotted actual locations of service delivery and estimated the distances residents would have to travel to visit the nearest outlet for a standard list of services, mainly in the education, health and welfare fields. For some services, the second-nearest and third-nearest (and so on) facilities were included at reduced weight, to allow a modicum of choice. Not surprisingly, in view of the major differences between services provided in the heavily and sparsely populated regions, both the ABS and NIEIR studies supported two conclusions:

  1. The accessibility of services differs systematically between rural locations (defined as all settlements of less than a thousand population) and urban locations. (The ABS has been understandably reluctant to publish remoteness indicators for other than very small geographic areas because the typical larger area, say a local government area, contains a range of locations that often have significant differences in accessibility to services).
  2. The accessibility of services also differs systematically with distance from the major metropolitan areas. This differential is particularly marked if emphasis is placed on choice of service outlets; for example, only the metropolitan areas have multiple universities.

 The NIEIR study distinguished between widespread and centralised services. The former are available locally in most country towns complete with a choice of service providers where this is appropriate (it is not appropriate, for example, for police services), while centralised services are provided mainly in the metropolitan areas and not in the country. Centralised services include tertiary education and specialised health services, and also, surprisingly, secondary education, which is available in the typical country town but with very limited choice.

Judged by employment, centralised services account for roughly one-third of the public services provided in Australia. Because of their metropolitan concentration, they account for the way in which service accessibility declines with distance from the main cities. However, even if attention is confined to the widespread services and the micro-variation between towns and the countryside is averaged out, the NIEIR service accessibility index generates patterns that largely accord with the ABS remoteness index. According to the ABS the ‘very remote’ area comprises: the Australian north coast from Shark Bay nearly to Cooktown, except around Darwin; the coast of the Great Australian Bight; and all the country between these two coasts except for the immediate surrounds of Alice Springs and Mount Isa, which are merely ‘remote’. In South West Queensland all places west of Mitchell are considered ‘very remote’, while the ‘remote’ area is a strip between the ‘very remote’ area and a line running from roughly Dirrinbandi to Miles.

The NIEIR study helps to place these patterns in context. According to this study a typical journey from a residence to the nearest outlet of a widespread service (or nearest several outlets in the case of services like GPs where choice is important) will take more or less the following times:

  • 12 minutes in Brisbane;
  • approximately 12 minutes in Dalby but more like 40 minutes in the rural parts of Western Downs;
  • just under 2 hours in Roma (due to restricted choice in some services) and over 2 hours in the rest of Maranoa;
  • just under 3 hours in Charleville (again, mainly due to restricted local choice) and over 3 hours in the rest of Murweh and in Paroo; and
  • nearly 5 hours for residents of Quilpie and Bulloo Shires.

These estimates can be roughly translated into dollar costs. Without imputing any cost to residents’ time, the typical metropolitan service access trip costs around $3. It costs less in towns like Bundaberg due to less congestion and lower car parking costs. At the other end of the distribution, the typical remote area trip costs around $50. As already pointed out, remote area residents manage these accessibility costs by restricting choice, by bundling trips and simply by doing without (e.g. by forgoing education).

To a large extent the superior accessibility of essential services in the metropolitan areas and provincial cities is due to the inexorable logic of economies of scale. An approach that emphasises economic efficiency narrowly defined would leave it at that: services are cheaper to provide in large centres and if citizens want good services they should shift to these centres. (Never mind if the shift causes congestion and increases land costs.) However, the Queensland Government endeavours to guarantee equality of service access to all its citizens, if necessary by bearing transport costs and also by upholding service standards in remote areas to overcome the need for choice and duplication.

Given this policy, is there any need for zone rebates and the complementary social security allowances as contributions towards service access costs? Whatever the good intentions of the state governments, remote area residents bear significant service access costs that have to be met from their own pockets. The zone rebates can be interpreted as a contribution towards basic mobility (e.g. car ownership, assumed by service providers). In addition, accessibility costs for essential services can be taken as proxy for accessibility disadvantages more generally – those which we have already considered as cost of living disadvantages or, more broadly, the costs of a minimum level of engagement with society as a whole – those costs which, in the broad social welfare literature, are called the costs of belonging.

The Cox Inquiry argued that poor service accessibility and high costs of living together provided an equity argument for zone allowances. At the very least, accessibility calculations help to identify the affected areas and the size of the disability. Given that the prime purpose of social security is to provide minimum

incomes to people who have no other income source, equity arguments apply particularly strongly to the recipients of remote area allowances, but also apply to income earners in general.

Zone boundaries

When the system was inaugurated in 1945, the then Treasurer, Mr Chifley, said that the zone boundaries took into account latitude, rainfall, distance from centres of population, density of population, predominant industries, rail and road services and the cost of food and groceries. Unfortunately, the exact criteria used in the demarcation (if there were any) have been lost.

The only general change to date in the zone boundaries occurred in 1955 when the boundary of zone A was extended south to the 26th parallel, so conveniently including the whole of the Northern Territory within zone A. As noted above, special zones were introduced in 1981.

A comparison of the current zone map with the ABS remoteness/accessibility index broadly mapped, and similarly with the NIEIR/Farm Institute service accessibility index, shows several major divergences. We consider first the zone A/zone B differential:

  1. Although Darwin is somewhat disadvantaged (according to the ABS it ranks as ‘outer regional’) its level of remoteness is well short of that in the typical zone A location. It might be added that Darwin has now developed a broad industry structure and is no longer dependent on the prosperity of a limited number of export industries exposed to fluctuating world prices.
  2. Similar considerations apply to the Queensland coast between Mackay and Cairns, which is included in zone B despite ‘outer regional’ status.
  3. There is essentially no difference in remoteness between zone A and B locations either side of the 26th parallel. No remoteness gradient runs along this line, nor is there any noticeable difference in industry composition either side (although it is roughly the northern limit for sheep).
  4. Apart from Darwin and the Queensland coast, zones A and B taken together are remarkably similar to ‘very remote Australia’ as defined by the ABS and confirmed by NIEIR. This applies whether remoteness is defined in terms of distance from services, distances from towns or thin industry structure arising from a lack of arable land.

By contrast, apart from Mount Isa, Alice Springs, Kalgoorlie and Esperance, the special zones are not recognisable in the ABS remoteness map, nor are they to be found in the NIEIR calculations. For example, in Queensland, Charleville and Longreach are each responsible for large circles in which residents are not entitled to special zone allowances, but in both instances the typical trip to access a widespread service from within the town is rated at around 2 hours and from within the excluded circle is closer to 3 hours. Among the isolated centres in Queensland, only Mount Isa is large enough, and has a sufficient range of services, to produce a significant improvement in accessibility. This suggests two conclusions:

  1. A town population of 2,500 is too low to produce significant improvements in accessibility in an otherwise remote area. Judging by the populations of Alice Springs, Mount Isa and Kalgoorlie, the cut-off appears to be more like 15,000.
  2. The radius of 250 road km is too long. Accessibility drops rapidly with distance from urban centres.

 

There is a strong case for redefining the zones to take these findings into account. The exclusion of Darwin, Mackay, Townsville and Cairns and the adjacent coast, plus an extension of the eligibility period from 6 to 10 months, would go a long way towards financing the redrawing of zone boundaries. An outback zone could be based on ‘very remote’ Australia as defined by the ABS. A new fringe outback zone could serve as a transition area and also accommodate towns of 15,000 plus population which would otherwise be located within the outback zone. The special zones would be abolished. It is suggested that the rebate for the outback zone would be the current special zone rebate, updated, while the rebate for the marginally outback zone would be the current zone A rebate, updated. The social security remote area allowance would be available to permanent residents of the outback zone and possibly, at reduced rates, to permanent residents of the marginal outback.

Value of the allowance/rebate

When introduced the zone A allowance was set at £40 but in 1947 it was increased to £120, a considerable concession at a time when workers were typically paid around £500 a year (average earnings per railway employee were £477 in 1948–1949). In conjunction with the schedule of marginal rates, this increased disposable incomes by 3 to 4 per cent compared with charging the full income tax to workers in zone A. The zone A deduction was indexed sporadically and in 1958–1959, after an increase, produced increases in disposable income of the order of 6 per cent for workers on average weekly earnings. The additional deductions for dependants meant that the proportion was broadly similar for taxpayers with and without dependants. From 1959, however, there was a pronounced reluctance to index the allowances, later rebates, for inflation.

The Cox Inquiry failed to produce any indexation of the rebates but its recommendations to raise the loading for dependants and introduce special zones were implemented. As a result, in the 1981–1982 tax year zone rebates produced the following increases in real incomes (calculated, for convenience, on the assumption that the allowance benefits the taxpayer rather than the employer).

  1. For a taxpayer on average weekly earnings living in zone A, an increase in disposable income of approximately 1.8 per cent. Due to the dependant allowances, this increase was roughly the same for all levels of dependants.
  2. For a taxpayer on the minimum wage living in zone A, an increase in disposable income of approximately 2.7 per cent. Increases for taxpayers with dependants were somewhat less because they ran out of tax to offset the rebate against.
  3. For a taxpayer on average weekly earnings living in a special zone: an increase in disposable income of 6.3 per cent (9.4 per cent for a taxpayer on the minimum wage).

The two dissenting members of the Cox Committee would both have made more generous allowances available:

  1. Mr Kerr, a rebate sufficient to raise the disposable incomes of taxpayers earning average weekly earnings in the special zone by 12.6 per cent (18.8 per cent if on the minimum wage); and
  2. Mr Slater, a rebate sufficient to raise the disposable incomes of taxpayers earning average weekly earnings in a revised zone A by 16.8 per cent (22.2 per cent if on the minimum wage).

The rebates were increased in 1984, 1985, 1992 and 1993, but since then the zone A rebate has remained at $338 plus a 50-per cent loading on dependant rebates. Due to growth in earnings and lack of indexation of the rebate, its value has now been eroded to an increase of 0.8 per cent in the disposable income of a zone A resident without dependants receiving average weekly earnings. The value of the rebate for a taxpayer without dependants working in the special zone now stands at an increase in disposable income of 2.7 per cent.

The value of the remote area allowance for social security recipients stood in 2011 at an increase of 2.6 per cent in the disposable income of a single pensioner and 3 per cent in the disposable income of a couple.

The real value of zone rebates has been falling since

1993, which accords with Treasury’s preference for removing concessional tax offsets. Indeed, the failure to review the zone rebate might indicate satisfaction with the current non-indexed benefit: from Treasury’s point of view there is a risk that a review will defend the rebate and recommend that it be raised. The present paper has shown that there are, indeed, strong arguments for retaining and increasing the rebate.

Conclusion

It is 4 years since the release of the Henry Report into Australian taxation and its recommendation that remote area tax offsets be reviewed. The review has not taken place and, in the meantime, zone rebates continue to decline in real value.

There remain three arguments for the continuation and updating of zone rebates, including the related social security remote area allowances.

First, support is necessary for remote area economic development. Zone rebates provide partial compensation for the reduction in the competitiveness of remote area export industries, which has occurred as an unintended side-effect of the market-determination of the exchange rate coupled with heavy reliance on monetary policy to counter inflation. Zone rebates also assist in the provision of local infrastructure and support services in the remote areas. This infrastructure is important for the export industries, for defence and for the future of remote indigenous communities. (In discussions of public finance, this is essentially an economic efficiency argument.)

Second, compensation may be justified by the higher prices of necessities in remote areas, particularly food. This is especially important for social security recipients. (In discussions of public finance, this is essentially an ability-to-pay argument.)

Finally, partial compensation may be granted for the costs of accessing government services from remote areas. Although the primary responsibility here lies with service providers, the zone rebates recognise that remote area residents bear a share of these costs. (In discussions of public finance, this is essentially a benefit principle argument.)

This article provides a preliminary discussion of each of these topics and shows that zone rebates can be justified by arguments invoking each of the major principles of taxation. Following through from these arguments, the present paper also suggests that the zones should be updated and the levels of rebate revised. Zone rebates have not been reviewed for three decades. This article has shown that there is a strong case for updating the rebates, subject to a review of eligibility. It is time that the review recommended in the Henry report took place.

 

 

 

 

 

 

 

References

Australian Bureau of Statistics (2001), ‘ABS Views on Remoteness’, cat 1244.0, Australian Bureau of Statistics, Canberra.

Australian Bureau of Statistics (2001), ‘Outcomes of ABS Views on Remoteness Consultation, Australia’, Australian Bureau of Statistics, Canberra.

Australian   Bureau   of   Statistics   (2003),   ‘ASGC Remoteness Classification: Purpose and Use’, Census Paper  No.  03/01,  Australian  Bureau  of  Statistics, Canberra.

Henry et al. (2009), ‘Australia’s Future Tax System: Report to the Treasurer’, December, CanPrint Communications, Canberra.

Hicks, P. (2001), ‘History of the Zone Rebate’, research note no 28, Department of the Parliamentary Library Commonwealth Parliamentary Library.

National Institute of Economic and Industry Research (2009), ‘A Comparison of the Accessibility of Essential Services in Urban and Regional Australia’, report for the Australian Farm Institute.

Public Inquiry into Income Tax Zone Allowances (P. E. Cox, Chairman) (1981), Report, Commonwealth Parliamentary Paper No. 149, Australian Government Publishing Service, Canberra.

 

Demand Side Management in California

National Economic Review

National Institute of Economic and Industry Research

No. 60               December 2006

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: Dr A. Scott Lowson

© 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 Institute.

ISSN 0813-9474

Demand side management in California: current and proposed measures

Graham Armstrong, NIEIR

Abstract

Although definitions vary, demand side management (DSM), demand management (DM) and demand response (DR) measures generally encompass energy efficient improvement, load shifting and peak load control. Over the past five years, increasing peak load demands and regional supply shortfalls (due to one or a combination of inadequate inter-connections, generator capacity, unexpected summer load peaks) have focused DSM/DR/DM efforts on peak load control of air conditioning equipment.

In Australia air conditioning loads are increasing at a rate of about 50 per cent above overall load growth. Although there has been increasing interest over the past five years in DSM to address this peak load growth, there have been few actions beyond analysis and discussion of the issue. Peak load growth has been met by supply augmentation.

On the other hand in California, where electricity prices soared and supply shortfalls were experienced in 2000, a range of measures has been introduced.1 Today, California is almost certainly the jurisdiction with the most comprehensive array of DSM/DM/DR measures. These measures are mainly designed (often with overall government direction by the State’s Government) and delivered by energy utilities operating in the State.

Graham Armstrong believes that the United States experiences with measures for addressing peak loads are useful when considering the situation in Victoria and Australia in general – with the important qualification that policy design must be based on our particular circumstances and provides a preliminary program design for consideration and analysis.

Introduction

California can in some ways be viewed as a stand-alone nation state which has the fifth largest economy in the world. The Californian electricity demand requires a capacity of nearly 55,000 MW (about 25 per cent imported): this compares with total Australian generation capacity of about 50,000 MW (Victoria 8,000 MW). 2 Accordingly, California is a very significant global entity in the energy field.

California – A Nation State

  • Population of 34 million in 2002, 41 million by 2010.
  • 5th largest economy in the world.
  • 5th largest consumer of energy in the world.
  • 2nd largest consumer of gasoline and diesel – only the total United States uses more.
  • Lowest US per capita electricity consumption.
  • 1.5 per cent of world’s greenhouse gas emissions but low per capita emissions.

Source:   California Climate Change Programs: An Overview, Conference of the Producers, The Hague, 12 May 2003 presented by James D. Boyd, Californian Energy Commission.

In 2004 the State electricity usage was about 265,000 gigawatt hours of electricity per year. Consumption is growing at 2 per cent annually. Over the 1994-2004 period, between 29 per cent and 42 per cent of California’s in-state generation used natural gas. Another 10 -20 per cent was provided by hydroelectric power that is subject to significant annual variations. Almost one third of California’s entire in-state generation base is over 40 years old. California’s transmission system is also ageing. While in-state generation resources provide the majority (average annual of about 75 per cent) of California’s power, California is part of a larger system that includes all of western North America. Fifteen to thirty per cent of state-wide electricity demand is imported from sources outside State borders.

Peak electricity demands occur on hot summer days. California’s highest peak demand was 52,863 megawatts which occurred on 10 July 2002. On average peak demand is growing at about 2.4 per cent per year, requiring the equivalent of about three new 400 MW peaking power plants per year. Residential and commercial air conditioning represent at least 30 per cent of summer peak electricity loads.

California’s demand for natural gas also is increasing. Currently the State uses 2 trillion cubic feet (2,100 PJ, Victoria approximately 250 PJ) of natural gas per year. Historically the primary use of this fuel was for space heating in homes and businesses. Electricity generation’s dependence on relatively clean burning natural gas now means that California’s annual natural gas use by power plants is expected to increase. Overall, natural gas use is growing by 1.6 per cent per year. Eighty five per cent of natural gas consumed in California is supplied by pipelines from sources outside the State.

Californian initiatives in DSM/DR/DM have evolved in three fairly distinct phases over the past 30 years.

In the first phase, extending from the mid 1970s to around 1990, the emphasis, led by utilities such as Pacific General Electric (PGE), was on energy efficiency in an integrated resource planning (IRP) framework, in which the costs of reducing energy demand were compared with the costs of expanding supply. In this phase measures focused on energy efficiency with some attention to load control.

In the second phase, extending into the 1990s, less attention was paid to DM/DSM/DR as supply pressures (costs, levels) eased: a situation common around the world. Environmental concerns increased, particularly urban air quality and greenhouse, but more attention was paid to transport rather than stationary energy. DSM funding, focused on energy efficiency improvement (EEI) varied considerably in the period as regulatory wrangles remained unresolved.

The third phase, commencing in 2000, was precipitated by the electricity supply disruption and soaring wholesale prices. Since then DSM/DR/DM measures (both voluntary and the use of incentives) have been vigorously pursued with substantial public spending. The 2001 summer peak, weather and growth adjusted, was 10 per cent below the 2000 peak. The immediate response to the 2000 events was to install emergency peaking plants and to engage in a publicity campaign and incentive measures (lower tariffs for reducing demand below the previous year) to curtail demands. Rebates for the purchase of higher efficiency products were also tried to curb power consumption in 2000-01, but this approach was judged to be relatively ineffective as take-up was low and wholesale electricity prices fluctuated from one hour to the next, but retail prices did not.

Program funding has mainly been based on a combination of State funds provided on measured energy savings and utility funding, but in 2000 -01 the Californian Energy Commission (CEC) was appropriated an additional $ 380 million from special taxpayer funds for a range of DSM programs.

Recent developments

Although rebates continue, the policy focus has shifted to the potential use of time-of-use (interval) meters, which could be used with time -of-use (t-o-u) pricing (dynamic pricing in Californian terms, which includes consideration of real time pricing, RTP, covering price changes as wholesale prices change).

Backed by data from the t-o-u meters, rates can be adjusted according to several market variables, including demand, supply, wholesale prices and individual use. The State, with the major utilities, conducted a test to gauge customer response to variable pricing. About 2,500 small scale users across the State were given t-o-u meters and put on different pricing plans. In one plan, consumers were charged 13 cents a kilowatt hour for most hours except for 2:00 p.m. to 7:00 p.m. on weekdays, when the price went to 25 cents. On a few occasions the price was increased to 66 cents a kilowatt hour to mimic a period of special system needs. Evaluation indicated the program reduced peak demand by about 13 per cent.3

Results of the evaluation of 2003 programs is presented on www.energy.ca.gov.

Test results and results from general use of t-o-u might be quite different. Some customers might adjust their use to realise cost savings, while others might ignore the pricing changes. However, utilities, the Californian Energy Commission (CEC) and the Californian Public Utilities Commission (CPUC) are confident that, on the basis of the t-o-u pilots, this approach is effective.As a result, three major Californian utilities – PGE, Southern California Edison (SCE) and San Diego Gas and Electric (SDGE) are planning to replace conventional gas and electricity meters with up to 15 million t-o-u meters at a cost of around US$6 billion, beginning in 2006. The t-o-u meter expense will be offset to an unknown extent (depends on implementation policies and responses to them), by reduced peak usage: rate increases as a result of the meter rollout is expected by PGE to be small. In the period before t-o-u metering can make an impact, the California Energy Commission (CFC) estimates, that a 1 in 10 summer could result in a Southern Californian region shortfall of capacity of 2,000 MW (3.3 per cent) below demand by September 2005. Normal weather would not result in a shortfall and reserves would be adequate.As a response to the potential shortfall situation, the Californian Public Utilities Commission (CPUC) approved SCE’s request to implement additional energy efficiency programs aimed at reducing peak demand by 36 MW: insignificant compared to the potential shortfall. The decision orders SCE to expand four energy efficiency programs to immediately and significantly reduce peak demand – from residential customers and small, medium and large businesses.7

The programs:

  •  expand residential customers’ options for “instant rebates” – which are done at the point of sale – and are currently only available for compact fluorescent light purchases. The expanded program will include pool pumps and motors, refrigerators, air conditioners and whole house fans;
  • give  small  businesses  “no-cost”  lighting retrofits.  SCE    estimates    reaching approximately 10,000 customers through this effort; and
  •  allow larger business customers to apply for incentives of up to 100 per cent of the cost of the project on lighting retrofits.

Review of the Californian situation indicates that:

  • despite a range of in-place DSM/DR/DM programs the Californian system is still susceptible to disruptions;
  • t-o-u pricing may still some time off; and
  • the supply system is not being expanded at a sufficient rate to meet increasing demands.

 

The Californian Energy Commission (CEC) Integrated Energy Report8

This report, which is prepared every two years, with an update each alternative year, reports on the status of the State’s energy system and makes recommendations for action where it is deemed necessary.

Key issues identified in the 2004 Update are as follows:

  • implementation of the Energy Action Plan’s loading order strategy;
  • improved transmission planning is required to address inadequate transmission as it presents a significant barrier to accessing renewable energy sources critical to diversifying fuel sources;
  • reliability issues with ageing power plants;
  • the need for accelerated renewable energy developments; and
  • the need for acceleration of demand response programs that signal the actual price of electricity to customers in peak periods.

In the demand response area, the primary focus of this report, the 2004 Update calls for electrical utilities to aggressively implement the 2007 State-wide goal of reducing peak demand by 5 per cent. The 2004 Update appears to rely essentially on “dynamic pricing” (implemented through tariffs using t-o-u, interval meters) to meet this target.

Given the interval metering rollout schedule, likely rollout delays and uncertainty regarding peak tariffs and their impacts, it would seem that attention to other peak demand reduction and supply security are required if the target is to be attained. Thus, despite the 2000-01 disruptions actions to avoid a repeat the Californian system continues to be vulnerable to high (1 in 10) summer peaks.

The lesson for Victoria (and Australia generally) is that even after actual and significant supply disruptions, the implementation of preventive actions lags the requirements. Victoria/Australia has different circumstances: the private sector is responding on the supply side (but the Basslink delay reminds us of supply side reliance fallibility). BUT after five years of discussion, etc. little DSM to address peak loads has been implemented.9 (Would a serious disruption help?)

The 2004 Update, reviews progress on 2003 recommendations. In the DR/DSM/DM area:

(i)                        significant progress is reported on increasing energy efficiency funding and evaluation and monitoring of energy efficiency programs;

(ii)                       improved efforts are needed is reported on maximising energy efficiency of existing buildings; and

(iii)                     improvement is needed on rapid deployment of advanced (t-o-u, interval) meters and implementation of dynamic pricing tariffs.

In the case of (i) the Energy Commission recommended that the State10:

  • “Ramp up public funding for cost effective energy efficiency programs above current levels to achieve at least an additional 1,700 MW of peak electricity demand reduction and 6,000 gigawatts (GWh) of electricity savings by 2008.
  • Standardise and increase the evaluation and monitoring of energy efficiency programs to ensure that savings and benefits are being delivered. (Importance to be noted in VEES development.)

The State has made significant progress in this area, with the CPUC’s recent decision to adopt more aggressive goals for the investor owned utilities (IOUs) than the 2003 Energy Report recommended. These new goals, based on collaborative staff work between the Energy Commission and CPUC, require peak electricity demand reductions of 2,205 MW by 2008, exceeding the 2003 Energy Report goal by 505 MW, and energy consumption reductions of 10,489 GWh by 2008, exceeding the 2003 Energy Report goal by 4,489 GWh. These new goals will require approximately $522 million in annual funding by 2008 compared to the annual spending level of $348 million for 2004 and 2005.” And in the Executive Summary of the Update11 it is stated that “As recently as the 2000-01 electricity crisis, Californians embraced energy efficiency and demand response programs, reducing State demand by approximately 6,000 MW, more than 10 per cent of peak demand.”

In both cases (the 2003 Energy Report goals and the reductions to 2000-01) no evaluations are provided. This detracts from the credibility of the program results (see an outline of recent evaluation policies below). The Californian energy agencies (CPUC, etc.) proposed in a 2003 Energy Action Plan, in the energy conservation and resource efficiency area, that:

“California should decrease its per capita electricity use through increased energy conservation and efficiency measures. This would minimise the need for new generation, reduce emissions of toxic and criteria pollutants and greenhouse gases, avoid environmental concerns, improve energy reliability and contribute to price stability. Optimising conservation and resource efficiency will include the following specific actions:

  1. Implement a voluntary dynamic pricing system to reduce peak demand by as much as 1,500 to 2,000 megawatts by 2007.12
  2. Improve new and remodelled building efficiency by 5 per cent.13
  3. Improve air conditioner efficiency by 10 per cent above federally mandated standards.14
  4. Make every new state building a model of energy efficiency.
  5. Create customer incentives for aggressive energy demand reduction.
  6. Provide utilities with demand response and energy efficiency investment rewards comparable to the return on investment in new power and transmission projects.
  7. Increase local government conservation and energy efficiency programs.
  8. Incorporate, as appropriate per Public Resources Code section 25402, distributed generation or renewable technologies into energy efficiency standards for new building construction.
  9. Encourage companies that invest in energy conservation and resource efficiency to register with the State’s Climate Change Registry.”

The Decision builds upon Decision (D.) 04-09-060 and D.05-01-055 and an 21 April 2005 Decision 05-04-05, establishing the goals, policies and administrative framework to guide future energy efficiency programs funded by the ratepayers of the four largest investor-owned utilities (IOUs): Pacific Gas and Electric Company (PGE), San Diego Gas & Electric Company (SDGE), Southern California Edison Company (SCE) and Southern California Gas Company (SoCalGas).

D.04- 09- 060 established aggressive energy savings goals to reflect the critical importance of reducing energy use per capita in California. For the three electric IOUs, these goals reflected an expectation that energy efficiency efforts in their combined service territories should capture on the order of 70 per cent of the economic potential and 90 per cent of the maximum achievable potential for electric energy savings, based on the most recent studies of that potential. If successful, these efforts are projected to meet 55 to 59 per cent of the IOUs incremental electric energy needs between 2004 and 2013. On the natural gas side, adopted savings goals represent a 116 per cent increase in expected savings over the next decade, relative to the status quo. A three year cycle for updating savings goals, in concert with a three year program planning and funding cycle for energy efficiency (“program cycle”) was established and load reductions were included in savings goals.

In addition, an administrative structure for evaluation, verification and measurement (EM&V) was established to create a clear separation between “those who do” (the Program Administrators and program implementers) and “those who evaluate” the program or portfolio performance. (Victorian EES to note!) In particular, for program year (PY) 2006 and beyond, the Californian Energy Division will assume the management and contracting responsibilities for all EM&V studies that will be used to:

(i)                 measure and verify energy and peak load savings for individual programs, groups of programs and at the portfolio level;

(ii)                generate the data for savings estimates and cost effectiveness inputs;

(iii)              measure and evaluate the achievements of energy efficiency program, groups of programs and/or the portfolio in terms of the “performance basis” established under Commission-adopted EM&V protocols; and

(iv)               evaluate whether programs or portfolio goals are met.

The budget for EM&V was set, as a guideline, at 8 per cent of total energy efficiency program funds. (Note the significant resources that could be available for program evaluation at this level of funding.)15

Case study: Sempra Energy Inc/San Diego Gas and Electric (SDGE)16

Sempra/SDGE, serving a region in capacity constrained Southern California, operates a range of DSM programs, covering:

  • reduction of load during peak periods;
  • dynamic pricing; and
  • energy efficiency.

The utility claims over the past ten years to have cumulatively saved 1.9 million MWh, reduced peak load by 409 MW and provided cost savings to customers of over US$200 million.

2004-05 energy efficiency programs

Residential sector

Description of market segment:

Includes single family homes, condominiums, multi-family units, mobile homes and multi-family common areas.

The utility territory mainly has moderate coastal climate with high density housing and sparsely populated rural high desert and desert climates.

Provides electric service provision to approximately 1.2 million households.

Residential sub-segments:

  • single family customers;
  • multi-family customers; and
  • hard to reach.

Further segmented by end-use – air conditioners, all-electric homes.

Statewide residential rebates

Target market

All residential customers residing in SDGE’s service territory living in dwellings of 4 units or less, including condominiums and mobile homes.

 

Measures – rebates for:

  • Appliances;
  • Building shell – insulation;
  • Building shell – windows;
  • HVAC – air conditioning systems;
  • HVAC – controls;
  • HVAC – Ventilation systems;
  • Lighting – comprehensive products; and
  • Water heating – systems.

Industrial and commercial sectors

Commercial/industrial market segment includes over 138,000 electric meters and close to 30,000 gas meters.

Approximately 20 per cent of market consists of “large” customers – monthly kW demand above 500 kW.

Remaining 80 per cent of market consists of small and medium sized business with monthly demand of 500 kW or less.

  • Majority of the customer segment are considered “Hard-To-Reach”: rent or lease space; where English is the second language; businesses have less than ten employees; are outside urban San Diego, and annual electric demand is less than 20 kW or annual gas consumption is less than 10,000 therms, or both.
  • Almost 90 per cent of small and medium sized business customers have a monthly demand under 20 kW.

Industries are varied, including food service, property management, manufacturing, lodging, grocers and food growers.

Programs in these sectors include:

  • rebates for high efficiency HVAC systems and electric motor: delivered through system/product distributors;
  • provision of energy audits;
  • education and training programs for contractors, retailers, manufacturers;
  • building operator training and certification;
  • standard performance contract development and dissemination; and
  • incentives to participate in savings by design targeted at building owners and design teams to achieve “better than code” performance.

More information on the Sempra/SDGE program is set out in overheads from the utility’s Energy Efficiency Programs, Public Workshop, 3 March 2005. Although these programs are not targeted at peak load control, which will be addressed through t-o-u metering and tariffs, the SDGE’s comprehensive DSM measures that are summarised above:

  • can have a significant impact on peak loads; and
  • are well ahead of anything being implemented by Australian utilities.

It might be argued that the southern Californian situation has brought about such action and that program evaluation detail is lacking, but the SDGE programs (current and planned) indicate an innovative attach on energy efficiency improvement and peak load control that appears to be accepted by the government and its agencies.

Other USA state measures

A 2004 paper, Demand Response in the United States, prepared by the Wedgemere Group for the New Zealand Energy Efficiency and Conservation Authority (EECA) outlines DR/DSM/DM programs in a range of USA states17 and Ontario, Canada.

The outlines are a useful summary of these initiatives (websites are provided). TOU meters, coupled with dynamic pricing, is strongly supported in the EECA paper based mainly on the results of pilot programs in the USA: an average 0.3 demand elasticity is reported (for example, a 30 per cent demand reduction for a 100 per cent increase in price).

Program packages to address peak loads are not critiqued. Attachment B of the EECA report outlines reasons why new direct load control programs were not proposed in California.

The reasons provided are:

(i)                 the load impacts from these programs are already well understood;

(ii)               they limit customer choice: the utility determines the end-use (usually AC) and response level and does not allow customer overrides;

(iii)             they limit peak reduction potential to the chosen end-use load;

(iv)              they are inequitable because they offer a reward to owners of AC units, but not to non-owners; and

(v)                they are expensive because customers are paid even when the program is not used.

However, the possibilities for designing innovative load control programs in combination with t-o-u dynamic pricing and EEI programs are not considered in the EECA paper. This detracts from the usefulness of the paper from a policy perspective in the Victorian/Australian context.

Briefly, the reasons for rejecting direct load control are critiqued as follows.

(i)                 Load impacts from the earlier direct control may be well understood but are not for new designs of direct load control programs.

(ii)               More innovative designs can allow customer overrides: but if overridden full peak pricing would apply.

(iii)             They could be extended to other than A/C peak loads but A/C load is the load which is overwhelmingly weather dependent.

(iv)              They can be designed to reward non-A/C owners with lower rates than all A/C owners: that is, A/C owners taking direct load control would still pay more than non-A/C owners, but less than A/C owners not taking direct load control.

(v)                In combination with t-o-u meters, there is no reason why customers taking direct load control need not be paid when the program is not used.

Concluding comments

The United States experiences with measures for addressing peak loads are useful for analysis and consideration in the Australian/Victorian situation.

However, policy design here must be based on our particular circumstances.

Preliminary program designs for consideration and analysis (modelling, etc.) are set out in Attachment A.

Attachment A:

Scenarios for long run projections of Victorian peak demands

Introduction

This paper outlines potential measures for addressing summer peak load demands and suggests three scenarios for analysis of these measures.

For given weather patterns, population, income, economic trends, and consumer preferences, peak electricity demands will be driven by:

  • overall electricity prices (peak prices are considered separately), which rise to some extent as new plants are commissioned, but significant price increases will be mainly due to greenhouse (carbon price/permit) policies;
  • efficiencies of air conditioning units;
  • peak pricing policies; and
  • building trends.

Over the past five years, when it has been very evident that summer peak demands were increasing rapidly, the “non-policy” has been to build low capacity peaking plants or inter-connections. There has been virtually no policy directed at peak load control. This brief paper suggests how peak load control might be addressed. The study focuses on scenarios of policies to reduce (from BAU) peak demands in the residential sector: commercial and industrial sector analysis of peak demands requires separate analysis.

Three scenarios, two of which progressively reduce peak demands below BAU, are presented below for the 2005-50 period.

Under the BAU scenario electrical energy summer peak demand will continue to grow as population and incomes increase in each scenario. Income growth and consumer choice may translate into increases in average dwelling size, cooling of a greater proportion of space volume (whole house rather than one or two rooms), longer hours of operation and perhaps lower summer space temperatures. In the projections presented, these economic and social factors are held constant: further scenario development work would be required to assess their impacts.

Potential peak reducing policies

Emissions trading (carbon pricing)

Although the Federal Government continues to oppose the introduction of an emissions trading system for the pricing of carbon and trading of emission permits, States and Territories are continuing to work on the design of an ETS appropriate for Australia.

Action by the States/Territories and the possibility of a change in federal policy, suggests a carbon/permit price of $5/t CO2e by 2010 in a mild policy scenario and a price of $20/t CO2e by 2010 in a stringent policy scenario.

In the study these prices are assumed to remain over the 2010 to 2020 period, but increase to $10/t CO2e and $30/t CO2e respectively over 2020-2050 as the global greenhouse policy regime becomes more stringent, offset to some extent by technology advances which constrain the emissions permit price.

No explicit carbon pricing is included in the BAU scenario.

Peak load pricing and direct load control

In Victoria the installation of interval meters in all buildings will not be completed until about 2020. By 2013 only about one third of households will be fitted with interval meters (GWA, p.2918). Accordingly, unless there is a roll-out schedule change, universal time of use (TOU)/peak pricing in Victoria will not be possible until 2020.

There are several alternatives for direct control (for example through radio waves) of air conditioner loads and several trials are underway (New South Wales, South Australia, Western Australia) and a Ministerial Council on Energy (MCE) Committee is addressing the options. Work in this area commenced in 2000, but to date progress on developing policies and measures has been very slow.

Minimum energy performance standards (MEPS)

Levels for three phase air conditioning units were raised in 2004 and MEPS for single phase units introduced in 2004 are due to be raised in 2006 and 2007, with the final stage to match 2004 world’s best regulatory (not economic) practice in 2007. An indication of the impact of these MEPS changes is provided by GWA 2004, Table 4, p.23 and in the accompanying text.

There will be a rated performance improvement for the least efficiency split system units permitted to be marketed in Australia from April 2006. This improvement will be about 2 per cent for <4 kW and 5 per cent for >4 kW units compared with the average units sold in mid- 2004. Of current models available, about 10 per cent of <4 kW and 17 per cent of >4 kW would meet the proposed 2006 standard (GWA, 2004).

It is estimated (GWA, 2004) that the sales weighted efficiency for single phase units will then be 13-14 per cent higher, compared with 2004, than it would have been without the new 2006 MEPS.

World best practice for air conditioners is led by Taiwan and South Korea. The Australian MEPS lag the use of regulatory world best practice. As indicated above, MEPS applies, as the name implies, to the minimum acceptable rating (1- star) when the most efficient units (5-6 stars) are up to 40 per cent more efficient. The impact of higher air conditioning unit efficiencies on peak demands is debatable. Wilkenfeld, in a recent paper (GWA, 2004) claims, “where operation is intermittent and/or limited to one space, it is more likely that an increase in efficiency will lead to somewhat cooler internal conditions but have little effect on peak load”. (p.4, GWA 2004)

Why cooler internal conditions would result is not explained. In any case, this type of limited, intermittent situation is likely to become less important over time. MEPS levels could be raised by 2008 (or at least by 2010 -12) and/or greater efforts made to promote higher efficiency (5-star and higher) units.

Building trends: stock, sizes, retrofits and standards

The energy efficiency of buildings is increasing due to increased awareness of the net economic and environmental benefits achievable by improving the thermal efficiency of building envelopes and systems. Stock increases form a standard part of NIEIR’s projection methodology, but judgments on thermal efficiency trends must be made on the basis of policy and underlying trends.
In the case of new buildings, the Building Code of Australia (BCA) is moving to higher levels of thermal efficiency. From the early 1990s to 2004 there was only a slow and moderate increase in the thermal efficiency of new buildings. For example, in Victoria the 1992 thermal efficiency standard for new residences of about a 2 star rating had only increased to an average of about 2.7 by 2003. However, in 2004 a 4 star rating was mandated and on 1 July 2005 a 5 star rating will become mandatory. And work is being undertaken on a 6 star rating which is being achieved in a small proportion of homes.

Similarly, in the commercial sector movement to a 5 star rating for new buildings is likely (but not certain) in 2006. In the existing buildings area, retrofits are achieving higher thermal efficiency but the trend has not been quantified. Offsetting these trends, which reduce peak demands for a given stock, is an increase in building size (new or through refurbishment). Again, this trend has not been quantified.

No peak load pricing or direct load control is assumed in the BAU scenario. Faced with this uncertainty the following scenarios are suggested by NIEIR.

Scenarios for analysis of summer peak demands

Business-as-usual (BAU)

Over the past eight years, peak electricity demands have been increasing at about 4.0 per cent per year and are projected to increase at 2.6 per cent per year based on a 10 per cent POE through to 2015.

Although interval metering continues to be rolled out throughout the NEM, differential peak electricity pricing and specific load control measures are not introduced in this scenario. MEPS are held at 2004 levels in this scenario.

A 5 star requirement for new residences over the entire projection period (30 per cent net reduction in space cooling requirement compared with pre- 2005 new residences). No net increase in building size. No explicit carbon price is assumed in the BAU scenario.

Mild policy intervention

In this scenario the following new policy measures are introduced.

  1. An emissions trading system (ETS) is introduced in 2010 which results in a permit price of $5/t CO2e over 2010-2020 and an average electricity price increase of $6.5/MWh in Victoria over 2010-2020 (GHC4E), compared with 2005 levels. Over 2020-50 as the permit prices increase to $10/t CO2, average electricity prices increase by $10/MWh ($10/t CO2) as Victoria’s electricity greenhouse gas intensity reduces to an average of 1.0t CO2/MWh compared with 1.3t CO2/MWh over 2005-20).
  2. Air conditioner MEPS are accelerated resulting in an average 15 per cent increase in efficiency of new air conditioner units sold from 2008. (This means in effect, for example, that a previously rated 2 MW unit becomes a 1.7 MW unit from 2008 to 2020 compared with 2004.) This can be modelled by reducing the 2008 on growth in temperature dependent demands by 15 per cent.

By 2050 efficiencies are assumed to improve by 35 per cent (compared to 2004 levels).

(i)                 Peak pricing policies increase summer (October-April) peak prices by 30 per cent over 2005-20.

Customers are offered a lower price increase of 10 per cent if they agree to direct load control achieved through fitting devices to AC units which enable central control of AC units (for example through radio waves). Thirty per cent of customers accept this offer by 2020. Over 2020-50 peak prices increase by 50 per cent and customers are offered a lower price increase of 20 per cent if they agree to direct load control: 50 per cent of customers accept this offer by 2050.

(ii)               A 5 star requirement (30 per cent net reduction) for new residences from 2005-20 and 6-stars (40 per cent net reduction) from 2020 to 2050. No net increase in building size.

Stringent policy intervention

In this scenario the following policy measures are introduced.

  1. An ETS in 2010 results in a permit price of $20/t CO2e and an average electricity price increase in Victoria of $26/MWh over 2010-2020. Over 2020-2050 the average price increase is $40/MWh from a permit price of $40/t CO2e.
  2. Air conditioner MEPS are accelerated resulting in a 30 per cent increase of new air conditioner units sold from 2008 to 2020. (This means in effect that a previously rated 2 MW unit becomes a 1.4 MW unit.)

Over 2020-2050 average efficiencies of new air conditioner units increase by 50 per cent compared with 2004 levels.

  • Peak pricing policies increase summer peak prices by 50 per cent over 2005-2020.

Customers are offered a lower price increase of 20 per cent if they agree to direct load control as in 2. above. Fifty per cent of customers accept this offer.

Over 2020-2050 peak prices increase by 80 per cent and customers are offered a lower price increase of 30 per cent if they agree to direct load control: 75 per cent accept this offer.

5 stars for new residences over 2005-10, 6 stars over 2010-2020 and 7 stars (50 per cent net reduction from 2004 new residences) over 2020-30. No net increase in building size.

Note that in the latter two scenarios customer behavioural attitudes (for example in temperature control) to air conditioning is assumed to be similar to those in the BAU scenario. Behavioural changes scenarios could be introduced into the analysis but would require considerably more resources than proposed above.

Demand side management in California: current and proposed measures

Footnotes:

1        See Armstrong, G., California South: Coming to a Network Near You?, National Economic Review, No. 50, February 2002, for a review of the electricity situation which spawned many of these measures. 

2        Bob Thorkelson, Executive Director, Californian Energy Commission (CEC), Statement to Californian Senate Energy Utilities and Communications Committee, April 2005. 

3        Wall Street Journal, Rebecca Smith, 11 May 2005. 

4        The CPUC regulates the older so-called investor-owned-utilities (IOUs). Newer utilities are referred to as private utilities. In addition, there are municipally-owned utilities. 

5        Joint press release, 11 May 2005. 

6        CPUC press release, 5 May 2005 (www.cpuc.ca.gov). 

7        Thorkelson, op. cit. 

8        Californian Energy Commission, Integrated Energy Report, November 2004 update. 

9        Energy Australia time-of-use meter implementation 

Energy Australia announced in June 2005 that it will offer Sydney, Central Coast and Hunter Valley residents lower cost electricity in shoulder and off-peak prices via new “smart” power meters. The meters will allow Energy Australia to introduce different rates at different times. Lower prices will be offered in the morning and overnight, with customers able to reduce power bills by choosing the pricing period in which they use appliances such as dishwashers and air conditioners. 

The three tiered pricing structure will mean peak prices are charged between 2:00 and 8:00 p.m., “shoulder” prices from 7:00 a.m. to 2:00 p.m. and 8:00 p.m. to 10:00 p.m., and off-peak prices from 10:00 p.m. to 7:00 a.m. 

The new system will be phased in gradually, with new residential homes, those upgrading their electricity installation and big users with annual bills in excess of $4,000 the first to be offered the new meters. Existing customers can convert to the new meters if they pay for installation. According to Energy Australia, prices will be 70 per cent higher in the peak period than current prices, 20 per cent cheaper in the shoulder period and 60 per cent cheaper during off-peak times. 

The company claims a family with a $900 bill could save $100 by changing 5 per cent of their peak electricity usage to off-peak and another 5 per cent to the shoulder times. An audit of Energy Australia customers has found changing operating times for pool pumps, washing machines, dryers and dishwashers could have a marked impact on bills.

10      2004 Update, p.54.

11      Ibid, p. xiii. 

12      California continues to actively evaluate and implement such pricing systems under a CPUC rule-making (R.02-06-001) edict. 

13      The Energy Commission’s new building standards, to be adopted in 2006, when combined with training and enforcement, are expected to reduce energy needs in new buildings by approximately 5 per cent. 

14      New federal appliance standards will increase air conditioner efficiency by approximately 20 per cent by 2007. However, if California were granted a waiver from federal standards, by 2007 the CEC estimates that California air conditioner efficiency could increase by another 10 per cent. 

15      Interim Opinion: Updated Policy Rules for Post-2005 Energy Efficiency and Threshold Issues Related to Evaluation, Measurement and Verification of Energy Efficiency Programs, Decision 05-04-051, 21 April 2005. 

16      Summary of Sempra Energy/SDGE presentation, Energy Efficiency Programs, Public Workshop, 3 March 2005. 

17      The paper regards Demand Response (DR) as only applying to peak load reduction measures, including distributed generation (DG), but including EEI in only a long term sense. This definition is not universally accepted. 

18      A National Demand Management Strategy for Small Air Conditioners, for the National Appliance and Equipment Energy Efficiency Committee (NAEEC) and the Australian Greenhouse Office (AGO), November 2004 (GWA 2004).