The EUETS stands alone in not managing price – time to change?

The EUETS stands alone in currently excluding any element of price management from its basic design.  In this respect it can learn from other schemes.

The current debate on whether the backload the sale of EU allowances is in many ways a distraction from the more important issue of structural reform.  The Commission’s review of the EUETS published last year mentioned price management as an option for structural reform (Option f in the document)ⁱ.  I have previously talked about the way in which carbon pricing lies on a spectrum between pure emissions trading and pure taxes (27th March 2013), and looked at the role of floor prices in emissions trading schemes (2nd May 2013).  In the context of the current debate on EUETS reform it seems worth further emphasising how exceptional the EUETS is in not already including some element of price management in its design.

Every other carbon pricing scheme in the world contains some element of price management or fixed pricing, or (for those schemes still being designed) seems likely to put something in place, with the only possible exception I am aware of being Kazahkstan.  The measures that have been introduced or are being considered – floors, ceilings, market interventions, and carbon taxes – are summarised in the table at the end of this post.

There are many reasons why governments may wish to introduce such mechanisms.  They may be concerned about the economic damage of very high prices, or that low prices will fail to stimulate the necessary long-term investment, or that they do not wish to see the price fall below the range plausible estimates of the likely cost of the damage due to additional emissions.  In any case, pervasive uncertainties in advance about both the effects of climate change and the cost of mitigation imply that simultaneous attention to both prices and quantities is appropriate.  (A review of the reasons for this will need to await another post, but it is a well-established principle.)

There will of course be political challenges in negotiating the form and level of any price thresholds in the EUETS, with some eastern European member states likely to favour lower values than some in western Europe.  But whatever form and level of price containment in the EUETS proves achievable, the presence of such mechanisms in every other scheme in the world surely at least warrants a close look at how such mechanisms might benefit the EUETS.

The EUETS was a pioneering scheme, and other schemes have learnt much from it.  Now other schemes are up and running, and the EUETS can learn from them in return.  And one of the things it can learn is that price containment mechanisms are an appropriate component of emissions trading schemes.

Adam Whitmore – 25^th June 2013

Scheme	Price floor	Price Ceiling	Notes
California,	$10 + 5% p.a. real escalation auction floor	$40/45/50 + 5% p.a. real. Reserve tranche volume increasing over time.	The floor appeared to influence the first auction and some future tranches
Quebec	C$10 + 5% p.a. real escalation, auction floor	c$40/45/50 + 5% p.a. real	Linked to California as part of the WCI
RGGI	c. $2 constant real, auction floor price	Increased offsets at price thresholds.  Moving to Cost Containment Reserve, at $4 in 2014 rising to $10 by 2017, 2.5% p.a. nominal  increase thereafter	The floor has been effective in sustaining prices despite chronic oversupply
Alberta	No	$15/tonne buyout price, may rise to $30-40/tonne following review	A hybrid baseline and credit scheme and tax
British Columbia	Carbon tax fixed at C$30		May adopt emissions trading in future as part of WCI, but does not appear likely at present.
Australia (pre EU link)	A$15 + escalation (abolished with EU link)	$20 above EU price, rising annually	Fixed price of A$23 rising at 5% nominal p.a. for first three years
New Zealand	No	Price ceiling at NZ$25	Effective ceiling lower due to 2 for 1 surrender provisions
Prospective schemes
China pilot schemes	Likely to have some kind of price management through buying/selling of allowances, perhaps in a “central carbon bank” type model
South Korea	Understood to be examining a wide variety of options, including a review committee with powers to implement measures such as increased supply and price floors
South Africa	Carbon tax at Rand120/tonne

 

[i] The State of the European Carbon Market in 2012 Com (2012) 652 final, Brussels 14.11.2012 http://ec.europa.eu/clima/policies/ets/reform/docs/com_2012_652_en.pdf

Will carbon pricing in China be regional or national?

Regional differences are already an important feature of carbon pricing in China.  These differences seem unlikely to stop the emergence of carbon pricing across the country, but prices and scheme designs may continue to vary between regions for many years.  Something may emerge with characteristics between the complete integration of the EUETS and the diversity of provincial schemes in Canada.

Policy developments in China, the world’s largest greenhouse gas emitter, are critical to global prospects for limiting climate change.  The trial emission trading schemes being implemented in seven provinces and cities, accounting for around a quarter of the economy, are, taken together, by far the world’s largest carbon pricing system, after the EUETS.  However wealth and economic structure are very different across China.  The seven trial schemes are in the richer eastern and central parts of the country, with as yet nothing equivalent in poorer provinces.  This raises the question of whether economic diversity will be a barrier to establishing national carbon pricing in China.

A unified emissions trading scheme might prove possible despite differences in wealth.  The chart below compares the percentage variation in GDP per capita across the twenty-seven countries in the EU with the thirty-one provinces in China in 2030 (see note below chart for details).   The variation between rich and poor countries in the EU is substantial. The three richest countries (Denmark, Sweden and the Netherlands) have per capita incomes around 4.8 times those of the three poorest (Bulgaria, Romania and Poland).  The range of incomes among China’s provinces is slightly smaller, with the three richest provinces, the cities of Tianjin, Shanghai and Beijing, having incomes around 4.5 times those of the three poorest (Gansu, Yunnan and Guizhou).  However the variation in the middle of the income range is greater in China.  Thus, very broadly, the variation in incomes across China is comparable to that across the EU.  As it has been possible to establish and maintain a unified emissions trading scheme across the EU with its diversity of income then it may be possible to establish something similar in China.

The countries/provinces are arranged in order of increasing GDP per capita.  The horizontal axis shows the cumulative proportion of the population in countries/provinces with GDP per capita below a certain level, relative to the national mean per capita GDP (population weighted average across provinces/countries).  The vertical axis shows the relative GDP per capita of countries/provinces.  The blue arrows indicate the positions of the Chinese provinces with trial ETSs.  Data sources are World Bank and China NBS Database.  Data for China is for 31 provinces (taken to include the 22 provinces – Taiwan being excluded – 5 autonomous regions and 4 municipalities). Hong Kong and Macau are excluded.  Data for the EU is for the 27 Members States.  Data is for 2011 in both cases. 

Furthermore, emissions trading creates the potential for transfers of wealth from richer to poorer provinces.  If richer provinces in China have more demanding emissions caps they may buy in allowances from the less prosperous provinces, transferring funds in the process.  Such differences in stringency may to some extent resemble the EU’s burden sharing agreements.  Wealth transfer may stimulate further economic integration and convergence, especially if there is also a transfer of administrative infrastructure and capabilities to less developed provinces as part of the process of building a national scheme.

These considerations lend credibility to a scenario in which there is a single national scheme with uniform prices, but different stringencies of cap in different provinces, and perhaps different allocations of allowances to industry and other sectors across different provinces.  Coverage of sectors and facilities may also vary between provinces.

Nevertheless, even in the EU diversity of economic circumstances is proving an obstacle to reform of the EUETS, with poorer countries in eastern Europe more resistant to reform than more prosperous countries in western Europe.  China’s provinces remain economically diverse and politically distinct, and this may form a barrier to establishing a national trading scheme.  A scenario in which there are separate regional schemes, each having its own rules and prices, with prices generally lower in poorer regions, seems at least as plausible as a fully national scheme, and perhaps more so.  There might be some linkage and trading between schemes, perhaps in the form of offsets, but this might not be enough to fully equalise prices.  Over time schemes might converge, and perhaps eventually merge, but this may take many years.  (Alternatively, differing regional carbon taxes might be introduced.)

Canada is the clearest example of distinct regional pricing in a single country.  Despite total 2011 emissions in Canada being only about 6% of China’s, Canada has three separate provincial carbon pricing schemes (British Columbia, Alberta and Quebec), with other provinces currently considering what, if anything, they might implement.   Any unification of these schemes seems a distant prospect.   Although British Columbia is, like Quebec, a member of the Western Climate Initiative it does not currently appear to be moving towards introduction of an ETS.

Among the barriers to unification of carbon pricing are the different economic structures and resource bases of Canadian provinces, for example hydropower rich Quebec contrasting with fossil fuel rich Alberta.  Similarly, differences in the economies and resource endowment of provinces across China may create persistent barriers to full integration of emissions trading schemes, although there may be greater commonality of design than between the Canadian carbon pricing schemes, which are notably diverse in their approaches to pricing.

Whichever model it chooses it seems clear that China is pursuing carbon pricing as an important component of its emissions reductions programme.  Carbon pricing will surely spread across the country.  And there may well be much in common between regional schemes, and increasing linkage.  But although a national price may emerge in the next few years it also appears possible that pricing could remain diverse for many years to come.

Adam Whitmore  –  17^th June 2013   

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CCS is making progress – but not much in power generation

There is now sufficient experience of CCS around the world to begin to see what makes early projects happen.  Most projects capture from natural gas processing or other industrial processes, with little progress in the power sector.

Many projections show CCS as a major future contributor to decarbonisation.  But, as described in my last post, energy technologies take a long time to reach scale, and CCS has to date developed less rapidly than many were hoping a few years ago.  However with around eighteen large-scale projects now either operational or under construction patterns have begun to emerge that indicate which factors make for a successful project [i].

Use of captured CO₂ for Enhanced Oil Recovery (EOR) is common across projects of various types, being a feature of two thirds of projects.  When injected into oil reservoirs each tonne of CO₂ can enable the production of (typically) two or three additional barrels of oil, making the CO₂ a valuable commodity rather than a waste product.  While the carbon capture project is unlikely to be able to capture all of this value (much of it flowing to the owner of the oil field), the revenue can be substantial.  For example, the price paid for CO₂ in some Canadian projects is understood to be $60/tonne or more.  This greatly enhances the economics of a project relative to incurring a cost for transport and storage, which in the absence of oil revenue is likely to be at least $20/tonne.

The most widespread application of CCS technology to date, with eight projects out of the eighteen and over 60% of annual volume captured, has been for natural gas processing, where CO₂ needs to be removed to meet the specifications required by the pipeline network.  There is a wide range of projects, including onshore processing where the CO₂ is used for EOR, such as at the Val Verde project in the USA, offshore processing where CO₂ is injected into saline formations, for example the Sleipner and Snohvit projects in the Norwegian North Sea, and the Gorgon project under construction in Australia, where CO₂ will be captured from a LNG liquefaction facility.

There are other projects where a relatively pure stream of CO₂ is produced as part of an industrial process, avoiding much of the capture costs associated with dilute CO₂ streams.  These include capture from electric arc furnaces at steel mills, such as at the ESI project in Abu Dhabi, and capture from steam methane reformers (SMRs), such as an Air Products plant that has just begun operating in Texas.  Other industrial projects include Shell’s Quest oil upgrader in Alberta and the Enid fertiliser plant in Oklahoma.  With substantial natural gas processing facilities, industrial facilities and onshore oil fields suitable for EOR, North America has been the main location for all types of CCS projects to date, around two thirds being in Canada or the USA.

However the contribution of CCS to decarbonising the power sector and other combustion remains minimal.  There are only two full-scale (greater than 100MW capacity) power projects under construction. The largest of these, the Kemper County project in Mississippi, has relatively high emissions (estimated to be greater than those of a CCGT per MWh) due to its use of lignite and a relatively low capture rate.  The other is the Boundary Dam project in Saskatchewan where construction is nearing completion and commissioning is due to start later this year.

CCS projects are dominated by natural gas processing and industry with relatively little capture from the power sector …

Source:  Global CCS Institute

Whichever of the CCS technologies a power project uses – pre-combustion, post-combustion or oxyfuel – a chemicals plant needs to be added to the power plant, and this is inevitably expensive.  The large additional capital and operating expenditures required for a capture system, combined with the loss of efficiency due to the energy required to run the capture process, including the electricity required to compress the CO₂ ready for transport, add greatly to the cost of power.  According to a recent study sponsored by the UK government, power generation with CCS has a cost of around £161/MWh at present, about three times the cost of power from conventional fossil fuels [ii].  The study suggests that this could potentially be reduced to around £100/MWh by the early 2020s, although this may prove a somewhat optimistic estimate.  Meanwhile, the Kemper County plant is reportedly suffering cost over-runs.

The large additional cost of power from CCS means that it needs types and levels of enabling support similar to other early stage power generation technologies. The power sector projects that are under construction both have favourable financial arrangements.  The Boundary Dam project is being developed by the province-owned utility, Saskpower. This means that the additional costs of CCS can be covered through government-backed financing and through the ability to pass on costs to electricity users.  The Kemper County project is allowed to recover its costs from the local rate base from the start of construction, greatly improving the financial attractiveness of the project.  Both projects also benefit from sales of CO₂ for EOR.

Financial support is likely to take the form of some combination of a premium price for the power, capital grants, loan guarantees and other source of low cost capital, and perhaps support for provision of common infrastructure, including pipelines and sinks.  A substantial per MW or per MWh contribution is needed, and the relatively large scale of CCS projects means that finance needs to come in large blocks, with large amounts of support for each project.  Building projects will be necessary to enable “learning by doing” to bring the cost down substantially, but learning times are long due to long design and construction periods.

So far putting the necessary support in place has proved daunting for most governments, and public opposition has also hampered progress in some jurisdictions.  Europe has made little progress, and in the USA the potential to reduce emissions much more cheaply by switching from gas to coal seems likely to lead to limited prospects for CCS power projects in the short to medium term.  However there is increasing interest in CCS in China, and it is possible that, as with so much else, development in China will prove crucial to the global picture over time.  The strength of interest in CCS may in turn depend on progress with developing shale gas in China.

Achieving scale sufficient to capture a large proportion of the world’s combustion emissions from the power sector or elsewhere will in any case be an enormous task.  CO₂ is 27% carbon.  Fossil fuels are more typically 75-80% carbon [iii] by mass.  From this, a simple mass balance implies that the capture, transport and storage to dispose of the CO₂ must handle about three times the mass of the production and transport of the fossil fuels burnt.

Many new CCS projects are likely to continue to be outside the power sector, especially where there is potential for EOR, and this will make important contributions, for example to knowledge of reservoir management and in some cases to the scale of pipeline networks.  It remains important that some power sector projects are undertaken at scale, as implementing widespread CCS on power plants, especially on gas, remains an option that will probably need to be exercised in the coming decades.  However realising power projects with CCS will continue to be a difficult and, very likely, slow process.

Adam Whitmore  3^rd June 2013

Thanks to Dave Mirkin of 2CO for providing valuable input for this post.

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[i] See the 2012 Annual Report from the GCCSI and January update.

http://www.globalccsinstitute.com/publications/global-status-ccs-2012

http://cdn.globalccsinstitute.com/sites/default/files/publications/85741/global-status-ccs-january-2013-update.pdf I have added the Abu Dhabi ESI project to the total as I understand it has now progressed to the construction phase.  A similar project is understood to be planned in Saudi Arabia, but is excluded due to lack of firm information.

[ii] https://www.gov.uk/government/publications/ccs-cost-reduction-task-force-final-report

[iii] This is a typical number.  Natural gas has a carbon content about this level.  The carbon content of oil is higher, coal varies depending on quality.  The essential point that the waste disposal must handle much greater mass than the fuel supply remains unaffected.