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.

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© National Institute of Economic and Industry Research

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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.