Energy and Environment (NER 66)

National Economic Review

National Institute of Economic and Industry Research

No. 66               September 2011

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

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

National Institute of Economic and Industry Research

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

ISSN 0813-9474

Energy and environment

Graham Armstrong, NIEIR


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


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

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

Prospects for Cancun

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

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

Erik Haites, Margaree Consultants, Toronto, Ontario, Canada

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

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

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

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

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

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

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

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

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

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

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

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

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

Reduction of emissions from deforestation and forest degradation

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

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

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


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

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


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

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

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

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


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

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

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

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


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

New Zealand climate change policy

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

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

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

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

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

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

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

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

Businesses participate in the ETS in different ways.

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

Liable parties are required to:

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

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

Examples of emissions trading scheme participation

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

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

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

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

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

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

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

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

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

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

Table 1 E and E NER 66

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

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

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

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

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

United States climate change policy

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

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

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

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

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

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

Carbon markets

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

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

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

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

Australian developments


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

table 2 E and E NER 66

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

Business supporters of carbon pricing

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

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

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

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

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

Garnaut Climate Change Review update

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

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

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

The Review update should consider:

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

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


Victorian Climate Change White Paper,

July 2010

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

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


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

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

Clean energy

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


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


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

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

Also included are:

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


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


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


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

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

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

Coalition plans for energy and climate change include:

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

Energy and Environment (NER 60)

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

Energy and environment

Graham Armstrong, NIEIR


Graham Armstrong provides an update on the Kyoto Protocol before considering several related issues. These include the differing responses to greenhouse policy by the Australian States and Territories on the one hand and the Federal Government on the other, developments in this field in the European Union, an update of the New Zealand Kyoto Target, and carbon trading in Australia.

Kyoto Protocol update

  1. The Kyoto Protocol (KP) was developed in 1997 by two major groups of countries: Annex B and non-Annex B (see below for definitions). Since 1997 the countries party to the Agreement have met regularly as the Conference of the Parties (COP) to clarify and refine the Articles of the KP.
  2. Annex B countries comprise developed economies and economies in transition (mostly eastern European countries) who have made commitments to reduce greenhouse gas (GHG) emissions to the levels set out in Annex B of the Kyoto Protocol document. The specified levels are for the first commitment period, 2008-12, where emissions levels are compared with a 1990 base. Non-Annex B countries, loosely called developing economies, comprise all other countries signatory to the KP.
  3. Annex B countries were called on to ratify the KP, that is to be legally bound by their commitments in Annex B. When countries comprising 55 per cent of emissions covered by total Annex B emissions had ratified the treaty the KP came into force. This occurred on 16 February 2005 following ratification by the Russian Federation.


As of 1 July 2005, the percentage of Annex B emissions covered by ratifying countries had reached 61.6 per cent with 0.2 per cent of emissions from countries likely to ratify. The countries opposing ratification, the United States and Australia, comprise 38.2 per cent of emissions (USA 36.1 per cent, Australia 2.1 per cent).


  1. Australia and the United States continue to oppose ratification for two main reasons: potential damage to their economies and the non-inclusion in Annex B of major and rapidly growing emitters, particularly India and China.

It is important to note that:

  • projections by the Australian Greenhouse Office (AGO) continue to indicate Australia will meet its Kyoto target, but mainly through reduction of emissions from land clearing;
  • all Australian States and a significant number of USA States support KP ratification; and
  • close neighbours and trading partners of the United States and Australia, Canada and New Zealand, have ratified the KP and are implementing strategies to meet their Kyoto commitments.


  1. COP meetings and discussions in countries around the globe are increasingly looking towards policies and programs to address greenhouse (global warming climate change) in the post Kyoto period, that is beyond 2012. The two major issues are:


  • how to include Annex B ratifiers in Annex B and non-Annex B countries in a post 2012 agreement; and
  • what form post 2012 agreements should take.

Post-2012 global policy discussions dominated the COP-10 meeting in Montreal, Canada, in December 2005.


  1. The United States and Australia (depending on future government make-ups), and some major non-Annex B countries, are likely to oppose targets and timetables for the post 2012 era, whereas most Annex B ratifiers appear to favour continuation of the Kyoto Protocol targets and timetables approach. However, there is broad global agreement that major GHG emissions reductions (“deep-cuts”) will eventually be required.

The Asia-Pacific Partnership on Clean Development

The recently announced Asia-Pacific Partnership on Clean Development, although not viewed by partners as an alternative to Kyoto, will be a factor in future global policy discussions. An inaugural meeting of the group was held in Adelaide in March 2006. Current members of the Partnership are the United States, Australia, China, Japan, South Korea and India. Together they account for about half the world’s population, gross domestic product and greenhouse gas emissions. Of the countries only Japan is an Annex B Kyoto Protocol ratifier.

The primary aim of the Partnership, as set out in the group’s Vision Statement, is to achieve regional cooperation in developing and adopting cleaner (lower emission) energy technologies, including those based on coal, natural gas, nuclear (fission and fusion) and renewables, and technologies to capture and store GHG emissions.

Essentially the Partnership is a multi-lateral extension of existing clean technology agreements, for example that between Australia and India on clean coal. The main implication for States of the Partnership is that, in conjunction with the federal Low Emission Technology Fund, State development of low emission technologies could receive a further boost, depending on how the Commonwealth intends to act on progressing the aims of the Partnership.

Technology development, though essential for reducing global greenhouse gas emissions, does not alone lead to implementation of these technologies to actually reduce greenhouse gas emissions. Market signals complemented by market responsive regulations are a necessary adjunct to technology development. In this respect the plans and proposal outlined in Victoria’s Greenhouse Challenge for Energy (2004), and now being implemented, represent an exemplary integrated approach to future greenhouse policy development.

Thus, the Energy Technology Innovation Strategy (ETIS) and the earlier establishment of the Centre for Energy and Greenhouse Technology (CEGT), support for provision of market signals through development (with other jurisdictions) of an Emissions Trading System (ETS) and the development of Victorian Energy Efficiency and Renewable Energy Strategies (VEES and VRES), represent a balanced and responsible approach to the great challenges posed by global warming to global energy systems.

The Federal versus State/Territorial greenhouse policy positions


The Federal and the States/Territories have very different views on greenhouse policy. Thus, despite some cooperation in the areas of energy efficiency (the National Framework for Energy Efficiency (NFEE), Minimum Energy Performance Standards) and in technology development there is fundamentally a wide difference in approaches to greenhouse policy.


The Federal Government continues to oppose Kyoto Protocol ratification whereas the States/Territories, while recognising that Kyoto is just a first tentative step towards an integrated global policy, support ratification.

Emissions trading system (ETS)

The Federal Government continues to oppose the introduction of an ETS whereas the States/Territories are putting a major effort into designing an ETS appropriate to Australian circumstances. Consultations on the ETS design principles developed earlier in 2005 were held around the country over the September/November period. Efforts are now focussed on detailed proposals on the 10 design propositions set out in the Background Paper for Stakeholder Consultation dated 12 September 2005 ( trading). A Secretariat has been formed headed by Anthea Harris (formerly of Frontier Economy).

Design issues to be considered as a priority

Point of liability – and liability average (large and small final emitters, comprehensive coverage).

  • Cap – what range of caps should be analysed: level, timing, flexibility.
  • Allocation – the methods of allocation, permit duration and impacts on electricity prices of different designs, the basis for administrative allocation (“grandfathering”) and the role(s) of auctioning.
  • Offsets – definitions, sources, baseline issues, impacts on permit prices.
  • Treatment of energy intensive trade exposed sectors: definitions, treatment options and impacts of these options.
  • The roles of research, development, demonstration and commercialisation (R, D, D and C) in longer term greenhouse gas abatement and how an ETS can promote these roles.

Process issues to be considered as a priority

There are a number of other issues which should be addressed as a matter of priority which are essentially process related. These include:

  • the legal basis for a scheme – particularly in relation to the constitutionality of a State based scheme. There is no point in States designing a preferred model, without considering what form of scheme is constitutionally sound; and
  • reporting requirements.

Short, medium and longer term greenhouse policies

The Federal Government has virtually no short or medium term policies, seemingly content to assume current policies (or lack thereof) will attain Australia’s Kyoto target, that medium term (2012-20) policies such as an interim carbon signal are not required until global action post-2012 is decided on, and that in the longer term current technology development policies are adequate.

The States/Territories believe that integrated market based and regulatory policies are required for short, medium and longer terms to put us on a path for an orderly transition to a more stringent carbon constrained economy. That is, there is a belief that early action to place activities on a progressively carbon constrained economy is required.

Thus, for example, the States/Territories and the Federal Government’s seeming abandonment of MRET is poor policy and short sighed despite the federal government’s R, D, D and C support for renewables. And the States/Territories are moving on a more rigorous approach to energy efficiency improvement (EEI) and promotion of lower greenhouse gas intensive (GHGI) electricity production.

Developments in the European  Union (EU) ETS

The EU ETS which began on 1 January 2005, has been beset by start-up problems. Firstly, about half the EU countries have not finalised their National Allocation Plans and this has restricted EU ETS trading in emission allowances.

Secondly, allowance prices have been much higher than expected: up to E30/tonne (now down to about E20/tonne compared with an expected range of E10-15/tonne. Besides the partial market (should the commencement have been delayed until 2006 to allow for completion of all NAPS), the rise in oil prices has led to a significant rise in oil linked gas prices, leading to substitution of coal for gas in electricity generation. This resulted in a higher than expected demand for allowances (in a restricted market) with generators not better off paying for coal plus allowances rather than generating with high priced gas.

New Zealand Kyoto target update

Original estimates (2002) of New Zealand’s carbon trading status were that New Zealand would have a 30 Mt surplus of CO2 credits over 2008-12, worth about NZ$450 million. However, 2005 projections indicate a deficit of 36.2 Mt costing NZ$543 million due to rapid growth in energy (mainly transport), industrial process emissions, miscalculation of Kyoto forest sequestration credits and over-estimation of program (EEI, etc.) impacts.

The New Zealand carbon tax of NZ$15/t CO2e was estimated to cost the average household about NZ$4/week and raise about NZ$360 million a year. A review of the New Zealand Climate Change program in the fourth quarter 2005 resulted in termination of the proposed carbon tax and development of a new climate change policy is now underway.

The New Zealand experiences should indicate for Australia:

  • doubts on whether the Australian emission target will, in fact, be attained as the Federal Government continues to claim; and
  • the difficulties associated with climate change policy designs and impacts.

Carbon trading in Australia Current markets

Currently a range of initiatives, mandatory (M) and voluntary (V), most with a trading element, are reducing, or aim to reduce, greenhouse gas (GHG) emissions through greenhouse gas abatement. Certificates associated with these measures have a market value in 2005 totalling about $ 325 million. These measures are briefly outlined below.

1.             MRET (M)


MRET is currently a high cost route to GHGA, effectively sunsetted at about 6 Mt CO2e GHGA in 2010. Renewable energy certificates (RECs) from accredited renewable sources are now trading at about $30/MWh (about $ 25-35/t CO2e) from a range of renewable electricity sources.
The value of REC market in 2005 is about $100 million and about $285 million in 2010.


2.             New South Wales’ Greenhouse Abatement Scheme (GGAS) (M)

Recently extended to 2020, the Scheme requires electricity retailers to purchase their share (based on electricity sales of the estimated target market determined by regulations each year). NSW Greenhouse Abatement Certificates (NGACs), from a range of accredited renewable, fossil and energy efficiency improvement sources, are currently trading at about $14/t CO2e.

The value of the NGAC market in 2005 is estimated to be about $155 million and to be about $315 million in 2010.

3.             Queensland 13% Gas Scheme (M)

This measure is aimed at increasing the share of gas in the Queensland electricity generation mix and requires electricity retailers in Queensland to source 13 per cent of their electricity from gas (large loads over 750 GWh/year) are exempt (see Section 4.5 of this report for details). The Scheme which commenced on 1 January 2005 is implemented through tradable accredited Greenhouse Electricity certificates (GECs) which are currently trading at about $15/MWh.

The value of the GEC market in 2005 is estimated at about $70 million and in 2010 about $60 million (GEC price expected to drop despite increased volumes).


4.             Green Power (V)

Green Power involves the voluntary payment of a premium for electricity to cover the retailer costs of acquiring Green Power RECs which cannot be used for acquitting MRET liabilities.

The value of the Green Power market in 2005 is estimated to be about $15 million and perhaps some increase to $20 million in 2010.

5.             Greenhouse Friendly Certificates (V)

GFCs which accredit GHGA from eligible sources (including flaring of methane at landfill gas sites) are voluntarily purchased by companies to offset their greenhouse gas emissions from their activities. Currently there is a very limited market for GFCs which are trading at about $4/t CO2e.

The estimated GFC market value in 2005 is <$5 million and in 2010 to be about $10 million.

6.             Greenhouse Abatement Certificates (GACs) (V)

This market, which is just commencing, is the voluntary purchase of GHGA accredited certificates by entities to offset GHG emissions from their activities. The GACs differ from GFCs because of the wider range of eligible sources and their generally more stringent eligibility (additionality) criteria.

The rationales for purchasing GACs vary from “green image” to “contingent liabilities” and “learning by doing” in advance of a mandatory emissions trading system (ETS) introduction. Use of renewables for production of thermal energy (process heat, water heating), which are not eligible under MRET, GGAS or GP can be eligible to produce GACs.

The estimated value of the GAC market in 2005 is <$1 million and in 2010 possibly $ 10 million plus, as interest in GACs increases.

Total estimated value of the above “carbon” markets in 2005 is about $280 million.

Some companies, such as Energy Developments Ltd (EDL), are significant players in this market (EDL Annual Report indicates about $20 million of accredited certificates in 2004).

Future carbon markets

  • Current markets, in absence of new measures, could build to about $700 million in 2010.
  • The 31 October 2005 announcement by Victorian Premier Bracks of a Victorian Renewable Energy Obligation (VREO) to sustain the renewable electricity in Victoria is faced with collapse as a result of a static MRET. The VREO target is 10 per cent of electricity end-use consumption by 2010. Compared with an MRET only policy this would require about another 2,500 GWh of Victorian RE by 2010. At $35/MWh VREO (higher cost than MRET RECs) this “carbon” market would be worth about $90 million in 2010. VREO details are currently being considered.
  • Main potential future measure is an Emissions Trading System (ETS) now commencing operation in the EU, Norway and proposed for Canada to meet their ratified Kyoto Protocol commitments.
  • ETS elements: tradable carbon emission permits to attain a specified greenhouse target (information available on
  • Federal Government remains opposed to ETS but supported by States/Territories who are now designing a national “made in Australia” ETS.
  • Ten design propositions/issues including:
  • method of allocating permits (auction, AA, hybrid);
  • target: now looking at beyond Kyoto (2012) period and approach to GHGA (greenhouse versus economic uncertainty);
  • point of permit liability (who must hold and acquit permits) – some stationary energy sector possibilities set out in Figure 2.1; and
  • means of addressing adverse economic impacts on certain economic sectors.

ETS permit prices, economic impacts and size of the permit market will depend on the specific design of the ETS: potentially $3 billion total value of permits (at $10/t CO2e) in 2010.

Table 1 E and E NER 60

The concept of Australian Greenhouse Gas Abatement Program (GAP)

Currently in the absence of an emissions trading system (ETS) there is no national carbon signal initiative. As indicated above, there is a range of State programs encouraging greenhouse gas abatement (GHGA) that mainly focus on renewable electricity (gas electricity in Queensland and New South Wales).

MRET and Green Power are high cost GHGA routes and no program covers the range of GHGA opportunities, thus not encouraging least cost GHGA. For example, except for domestic solar hot water (SHW) under MRET production of thermal energy from renewables (for example, production of biogas from renewable wastes avoiding landfill and displacing fossil fuels), although often relatively low cost, is not eligible under any programs.

What is suggested here, in advance of an ETS, is a national GAP implemented through tradable certificates and based on new projects with a greenhouse gas intensity of <0.3t/CO2e and not viable under market conditions (that is, the projects would be additional, beyond BAU, as under the Kyoto Protocol Clean Development Mechanism rules). Energy efficiency improvement (EEI) projects would also be eligible, albeit raising difficult baseline/additionality issues.

More work is required on the GAP concept, but it is one worthy of consideration, perhaps initially on a voluntary basis (there are niche market opportunities) and later to replace existing programs.

Potential GAP features

  • Energy sources, including production of thermal energy from thermal sources, with a GHGI lower than 0.2-0.3t CO2e/MWh would be eligible for tradable abatement certificates.
  • Would be a greenhouse gas abatement measure (NOT a renewable electricity scheme) implemented through tradable GACs not RECs.
  • Between 0 and 0.2t CO2e/MWh GHGIs which fossil fuel technologies would qualify?
  • fuel cells: 0.4+?;
  • cogeneration: probably not but depending on how GHGI estimated (electricity, heat) could qualify at 0.25;
  • other? Geosequestration with CCGTs and possibly coal, hybrid RE/fossil technologies for example biogas/gas electricity generation;
  • energy efficiency: difficult baseline issues.
  • Would eligible sources be restricted to emerging technologies? If so, how would emerging technologies be defined? Additionality test?

Definitions of Large Final Emitters (LFEs) and Small Final Emitters (SFEs):

  • data sources on energy use (sources) and emissions (levels) (ABARE, AGO) and decision, following analysis, of SFEs, LFEs. LFEs in Canada emit >8,000t CO2e (about 0.16 PJ of gas emits 8,000t CO2e);
  • treatment of fugitive emissions.

Decisions required for these emissions on acquittal points (upstream, downstream) and/or alternative policies: analysis and recommendations being prepared by Vic. ETS Technical Group (DPI, DSE, DOI).

Suggest an 0.3 upper limit

  • All renewable energy applications would qualify, not just renewable electricity as in MRET, GGAS, GP: thermal applications of renewable energy would qualify.
  • However, given MRET and VREO would renewable electricity qualify?
  • Should a portfolio approach be adopted?
  • Could be badged as a greenhouse abatement program (GAP) OR low emission technology application (LETA) program.
  • Implemented through gas and electricity retailers and certificates. Target?
  • Project cost of certificates? Up to $20/t CO2e if renewable electricity excluded. If used portfolio approach, different prices for each portfolio would emerge.


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


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.


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

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


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


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 ( 

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).