Review of EDD weather standards for Victorian gas forecasting

 

The Effective Degree Day (EDD) index was developed to capture the combined impact of temperature, wind and sunshine on Victorian gas demand. edd long term trend

Gas consumption due to short term weather variations is often removed prior to forecasting gas demand. This is partly achieved by developing weather standards that represent conditions under temperatures, for example, that are neither warmer nor cooler than expected. 

Weather standards for Victorian gas forecasting are typically developed using the Effective Degree Day index.

The Australian Energy Market Operator (AEMO), and previously VENCorp, have reviewed the EDD index and EDD standards every two to three years since 2000 with the latest completed in 2012.

The 2016 NIEIR Review of EDD Standards for Victorian Gas Forecasting report follows on from these reviews with a particular focus on the development of new weather standards for annual gas consumption and peak day to inform the Gas Access Arrangement Review (GAAR) over the 2018 to 2022 period.

 

This report covers:

  • background to weather normalisation and how the EDD index is formulated;
  • the development of new annual EDD standards under alternative methodologies;
  • the development of new 1-in-2 and 1-in-20 peak day EDD standards under alternative methodologies;
  • The impact of climate change on annual and peak day weather standards;
  • The correction applied to temperature to account for the change in location of the official Melbourne weather station from the CBD to Olympic Park in 2015 and;
  • monthly standards are also estimated for gas consumption and peak day.

 

Download the NIEIR Review of EDD weather standards for Victorian gas forecasting report:

Full Report    (26 pages | PDF | 1,328 kb)

Tables   (XLSX | 87 kb)

Australia’s Climate Change Policy: An Overview

The termination of carbon pricing in Australia is occurring at a time when moves towards carbon pricing and more stringent climate change policies are appearing around the world, for example in China and the United States. The international Panel on Climate Change 2013-2014 reports cover the science, effects on ecosystems, the economy and population and policies to combat climate change.  Overall the IPCC sees substantial net costs of climate change and the need for urgent action.

In Australia carbon pricing is planned to be replaced by a Direct Action Plan (DAP) at the Federal level. The DAP will mainly subsidise greenhouse gas abatement (GHGA) delivered by an Emissions Reduction Fund (ERF) through bidding for GHGA though a reverse auction (lowest bids win). The ERF will be funded by tax payers so, in fact it is a form of carbon tax.

The ERF is the central element of the Coalition Government’s Direct Action Plan (DAP) to meet the target reducing greenhouse has (GHG) emissions by 5 per cent below 2000 levels by 2020.

The ERF will help reduce Australia’s greenhouse gas emissions while delivering valuable co-benefits to Australian businesses, households and the environment. The ERF will operate alongside existing programs that are already working to offset Australia’s emissions growth such as the Renewable Energy Target and energy efficiency standards on appliances, equipment and buildings.

The overriding objective of the Emissions Reduction Fund (ERF) will be to reduce emissions at lowest cost over the period to 2020, and make a contribution towards Australia’s 2020 emissions reduction target of five percent below 2000 levels by 2020.

The Government set out a commitment to the Emissions Reduction Fund of $300 million, $500 million and $750 million – a total of $1.55 billion over 3 years with total funding capped at $2.55 billion. These funds will be allocated flexibly over time according to the profile of projects contracted under the ERF.

Businesses, community organizations, local councils and other members of the community can undertake activities and offer to sell, at auction, the resulting emissions reductions to the Government. Winning bids will be paid for out of the ERF.

Emissions reductions will be verified and credited according to approved methods. These methods will ensure that emissions reductions are genuine. Emissions reduction methods will set out rules for estimating emissions reductions from different activities. To let a wide range of businesses participate in Emissions Reduction Fund, a menu of emissions reduction methods will be available. This will let businesses choose the method that best suits their specific projects.

Some emissions reduction activities such as re-vegetation and household and commercial energy efficiency may often be smaller scale actions that are most cost-effectively implemented through aggregation. There are many businesses and organisations that are well placed to aggregate the emissions reductions resulting from these activities. The design of the Emissions Reduction Fund will encourage business models that aggregate emissions reductions.

Concerns

  • Lack of an explicit carbon pricing signal which we regard as an essential element of the internalisation of greenhouse gas emissions.
  • Additionality, that is, what projects would have been undertaken in the absence of the ERF
  • Attribution, that is, what amount of the project greenhouse gas abatement (GHGA) could be attributed to other programs such as Renewable Energy Target (RET, now under review) and State White Certificate Programs (VEET, ESS and REES)
  • The potential credit costs under the ERF, that is, what are the ‘likely’ bid costs under the ERF auction. No estimates have yet been provided.

The ERF is based on the erroneous assumption that an externality (global warming) need not be priced, in this case by pricing carbon dioxide equivalent (C02e) emissions. Externality pricing is fundamental to addressing externalities. Although pricing will, in most cases and certainly in the global warming case, require complementary actions as under the previous Government’s Climate Change Policy package. That is, carbon pricing alone is necessary but not sufficient to reach climate change targets.

The 2020 GHG emissions target may be achieved through economic and other policy circumstances. However, the more aggressive targets required from the overwhelmingly accepted climate science will not be achieved without some form of carbon pricing (carbon tax, emissions trading system) at the core of climate change policy.

Apart from the core carbon pricing issue, concerns with the ERF- design include:

  • The costs of achieving GHGA through the ERF
  • The limited ERF budget for the period to 2020
  • Additionality and attribution of GHGA from ERF projects
  • Safeguarding of emissions growth outside the DAP/ERF

The outcomes emanating from these concerns will become evident over the next 12 months. We will be reporting on and critiquing the DAP/ERF developments as they evolve.

Energy and Environment (NER 67)

National Economic Review

National Institute of Economic and Industry Research

No. 67               November 2012

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

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

Editor: Kylie Moreland

© National Institute of Economic and Industry Research

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

ISSN 0813-9474

Energy and environment

Graham Armstrong, Consultant, NIEIR

Abstract

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

Introduction

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

Durban

Outcomes of Durban

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

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

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

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

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

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

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

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

The Durban Agreement: A deal to negotiate a deal

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

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

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

Box 1 E and E NER 67

The Durban Agreement

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

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

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

Perspectives and opinions

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

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

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

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

‘had  all  the  elements  that  we  were  looking  for’

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

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

Effectiveness of Durban

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

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

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

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

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

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

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

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

The USA

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

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

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

The European Union

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

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

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

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

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

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

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

Australian developments

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

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

Clean Technology Investment Program

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

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

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

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

International permits and the floor price for permits

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

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

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

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

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

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

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

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

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

2,000 × 8.76 × 0.9 × 1.5 × 103

t = 23,652,000 t.

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

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

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

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

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

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

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

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

September 2012 update

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

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

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

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

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

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

Issues

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

September 2012 status of Australian climate change policies

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

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

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

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

2020 emissions, targets and greenhouse gas abatement sources

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

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

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

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

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

Liable parties

Generators

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

Other liable parties

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

Permit suppliers

Carbon Farming Initiative

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

Government

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

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

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

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

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

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

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

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

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

Liable parties

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

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

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

Lowy Institute Poll, 2012

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

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

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

Polls: 1 July 2012 on

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

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

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

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

References

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Energy and Environment (NER 66)

National Economic Review

National Institute of Economic and Industry Research

No. 66               September 2011

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

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

National Institute of Economic and Industry Research

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

ISSN 0813-9474

Energy and environment

Graham Armstrong, NIEIR

Abstract

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

Introduction

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

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

Prospects for Cancun

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

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

Erik Haites, Margaree Consultants, Toronto, Ontario, Canada

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

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

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

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

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

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

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

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

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

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

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

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

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

Reduction of emissions from deforestation and forest degradation

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

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

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

Concerns

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

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

Brazil

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

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

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

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

Indonesia

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

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

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

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

Africa

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

New Zealand climate change policy

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

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

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

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

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

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

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

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

Businesses participate in the ETS in different ways.

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

Liable parties are required to:

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

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

Examples of emissions trading scheme participation

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

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

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

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

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

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

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

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

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

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

Table 1 E and E NER 66

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

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

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

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

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

United States climate change policy

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

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

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

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

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

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

Carbon markets

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

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

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

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

Australian developments

Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

table 2 E and E NER 66

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

Business supporters of carbon pricing

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

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

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

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

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

Garnaut Climate Change Review update

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

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

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

The Review update should consider:

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

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

 

Victorian Climate Change White Paper,

July 2010

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

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

Targets

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

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

Clean energy

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

Solar

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

Homes

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

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

Also included are:

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

Business

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

Transport

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

Government

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

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

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

Coalition plans for energy and climate change include:

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

Energy and the Environment (NER 63)

National Economic Review

National Institute of Economic and Industry Research

No. 63               March 2010

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

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

© National Institute of Economic and Industry Research

(Australian Farm Institute for the first article)

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

ISSN 0813-9474

Energy and environment

Graham Armstrong, Consultant, NIEIR

Abstract

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

Introduction

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

Climate change policy options: Senate requests for further modelling

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

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

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

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

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

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

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

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

Carbon pollution reduction scheme: 4 May revisions

2011–2012

Fixing a $10/t CO2e price will:

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

2012–2013 on

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

Carbon pollution reduction scheme: 24 November adjustments

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

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

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

NIEIR’s current CO2e price scenarios

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

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

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

Table 1 E and E NER 63

 Table 2 E and E NER 63

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

Table 3 E and E NER 63

Sources of emission reductions

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

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

Impacts of the two scenarios on energy prices

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

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

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

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

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

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

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

Peak and off-peak electricity prices

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

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

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

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

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

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

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

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

Opposition modelling, emissions trading scheme design suggestions

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

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

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

Table 4 E and E NER 63

United States climate legislation progress

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

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

China: Climate change action developments

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

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

Chinese initiatives

Chinese initiatives include the following:

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

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

Japan’s commitment

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

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

Russian situation

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

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

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

Indian position

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

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

Global emissions market

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

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

 

Canada

Canada’s greenhouse gas emissions keep on rising

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

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

Alberta (Canada)

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

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

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

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

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

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

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

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

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

The Chicago and Montreal Carbon Exchanges

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

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

Montreal Carbon Exchange activity

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

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

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

 

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

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

Greenhouse gas emission costs and benefits of the program

New York Times study concluded the following:

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

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

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

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

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

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

Abstract

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

Introduction

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.

Kyoto

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 (www.cabinet.nsw.gov.au/greenhouse/emissions 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 www.iea.org.).
  • 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

Abstract

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

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

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

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

Introduction

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

California – A Nation State

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

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

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

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

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

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

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

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

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

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

Recent developments

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

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

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

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

The programs:

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

Review of the Californian situation indicates that:

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

 

The Californian Energy Commission (CEC) Integrated Energy Report8

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

Key issues identified in the 2004 Update are as follows:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2004-05 energy efficiency programs

Residential sector

Description of market segment:

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

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

Provides electric service provision to approximately 1.2 million households.

Residential sub-segments:

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

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

Statewide residential rebates

Target market

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

 

Measures – rebates for:

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

Industrial and commercial sectors

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

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

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

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

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

Programs in these sectors include:

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

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

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

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

Other USA state measures

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

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

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

The reasons provided are:

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

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

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

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

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

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

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

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

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

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

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

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

Concluding comments

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

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

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

Attachment A:

Scenarios for long run projections of Victorian peak demands

Introduction

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

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

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

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

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

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

Potential peak reducing policies

Emissions trading (carbon pricing)

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

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

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

No explicit carbon pricing is included in the BAU scenario.

Peak load pricing and direct load control

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

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

Minimum energy performance standards (MEPS)

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

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

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

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

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

Building trends: stock, sizes, retrofits and standards

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

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

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

Scenarios for analysis of summer peak demands

Business-as-usual (BAU)

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

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

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

Mild policy intervention

In this scenario the following new policy measures are introduced.

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

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

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

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

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

Stringent policy intervention

In this scenario the following policy measures are introduced.

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

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

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

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

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

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

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

Demand side management in California: current and proposed measures

Footnotes:

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

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

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

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

5        Joint press release, 11 May 2005. 

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

7        Thorkelson, op. cit. 

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

9        Energy Australia time-of-use meter implementation 

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

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

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

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

10      2004 Update, p.54.

11      Ibid, p. xiii. 

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

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

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

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

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

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

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