Archive for March, 2011

The problem with two carbon prices

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Last week as the UK Budget was unveiled, the government announced, to nobody’s surprise, its intention to implement a UK carbon price floor for power generators. This mechanism would operate in tandem with the EU Emissions Trading System, effectively underpinning it for one sector within its existing coverage. The proposal will see a minimum price, delivered via a top-up payment mechanism against the prevailing carbon market, of £16 per tonne from 1/1/2013 rising to £30 per tonne by 2020. Of course if the EU-ETS price is high enough, and it may well be if a very different nuclear scenario plays out in the EU following Fukushima, then this policy measure will have no fiscal impact. But it will serve to support investments in the UK and deliver a degree of certainty to those making them. However, major power generation investments won’t even begin operation until 2017 at the earliest, which does bring into question why the UK needs a floor price in the near term.

In a scenario of lower EU-ETS prices, a UK floor price will have an impact right throughout the EU because of the reach of the Emissions Trading System. In the illustration below, abatement across the EU is shown as the sum of UK abatement and EU-26 abatement (i.e. the remaining member states). The horizontal axis is tonnes of CO2 reduced (R) and the vertical axis is the carbon price in €s. In the first chart we see that the reductions required to reach the EU 2020 target (RUK + REU-26) are delivered at a carbon price of just over €20 (as a hypothetical number). The pink area represents the UK abatement curve and the blue area is the EU-26 abatement curve, both shown in their simplest theoretical shape.

The second chart illustrates the effect on UK abatement of an imposed floor price which is higher than the price otherwise required to meet the EU target. Additional UK reductions take place, shown as ΔRUK. But, as shown in the third chart where the total EU reduction requirement for 2020 is unchanged, an equivalent amount of reductions are now no longer necessary in the EU given that they have been found in the UK, so there is a perfect offset. The overall EU carbon price falls as a result, although this is not felt by the UK consumer.

The net environmental impact of such a policy is zero because of the role of the EU-ETS and allowance trade. But the investment outcome in the UK is changed and the total cost of meeting the EU 2020 target rises as the cost of the extra carbon reductions in the UK is higher than the next best on offer in other parts of the EU. The UK consumer bears this additional cost. The slight fall in the EU carbon price, while giving a small benefit to EU (but non-UK) consumers, may also serve to undermine investor confidence in equally important power generation projects across the other 26 member states. This in turn may encourage other EU member states to implement their own support mechanisms, which in turn would further erode the effectiveness of the ETS.

An EU-ETS free of policy overlay can do the job that is needed across the EU, but it will take time. This is a forty year policy instrument and as such should be left to perform the role intended.

It was a curious time in Washington DC last week. While the House Energy and Natural Resources Committee voted against three amendments on the validity of climate change science and its potential future impact, some 400 other people were meeting close to the Capitol at the IETA (International Emissions Trading Association) Carbon Forum North America. The Forum attracted a wide range of participants from House and Senate staff, state government policy makers, senior industry representatives of Fortune 100 companies and lead representatives of US policy think tanks and NGOs. All focused on a single key issue, the need for a clear way forward with regards CO2 legislation in the United States.

While legislative clarity is needed but remains in limbo, the nation has nevertheless pledged, and the Administration continues to reiterate, its goal to reduce emissions by 17% by 2020 relative to 2005. This was the subject of one of my early posts in April 2009 and at that time it looked to be a formidable undertaking even with a clear policy framework in place. Yet as I noted just a few months ago, much has changed as a result of the global financial crisis and the expanding role of natural gas in the economy.

Recent (late February) greenhouse gas data released by the EPA for the calendar year 2009 shows the impact of the recession, but also offers some further insight into the pathway forward. Economy wide emissions have dropped sharply, with the carbon intensity of the power generation sector dropping even faster.

In addition, revised EPA regulations are expected to have a significant impact on coal fired power generation. A study released by The Brattle Group last December assessed the impact of emerging EPA regulations on air quality, water use and ash disposal and the choice of retrofit or retirement for older coal fired units. The key conclusion of the study is that up to 66 GW of coal capacity could close by 2020. Natural gas is a potential and probably likely replacement. Although new nuclear is now in planning, any further acceleration could well be delayed by the events in Fukushima over recent days. Renewables will play a role, but I have assumed that they fill the demand gap for electricity versus current levels – i.e. they do not contribute to an actual reduction in emissions.

In addition to the power sector, the auto sector is also changing. Biofuels are continuing to come into the mix, revised CAFE standards are having an impact and by 2020 some (small) part of the fleet will be electric. Higher oil prices will almost certainly have some impact on vehicle use. Assuming an on-the-road efficiency of 22 mpg today and incoming vehicles improving from 27 mpg now to 35 mpg in 2020, a theoretical drop in gasoline consumption of just over 10% is possible, even with a rise in the total number of vehicles as population increases.

Pulling all this together and assuming some rise in industrial CO2 as the economy recovers, but no rise in other sectors as efficiency improvements take hold, it is possible to build a case for a reduction in CO2 emissions of up to 14% by 2020 vs. 2005.

But to get to 17% with some certainty, two additional changes are necessary. A further 35 GW of coal fired generation needs to be replaced by natural gas and the carbon footprint of the biofuels coming into the gasoline pool needs to improve beyond the madates for advaced biofuels. Both of these need a carbon price.

While it was clear in Washington last week that a sharp political divide remains in terms of progress on this issue, it was also clear from the IETA meeting that those actually making the decisions on new generating capacity are assuming a carbon price anyway. This assumption alone may well see the additional 35 GW go and allow the US to at least come close to meeting its international obligation.

Energy impacts after Fukushima

It is hard to make any comment at all after the scenes of destruction that have been filling the airwaves since Friday. But as the immediate disaster starts to move into recovery, then rebuilding, the issue of energy supply in Japan will doubtless rise up the agenda. In a country with limited natural energy sources, security of supply has been the traditional energy source consideration, although more recently this has been augmented with greenhouse gas emission targets. In terms of primary energy demand for electricity production (see chart), data for 2008 from the IEA shows a 3+ way split – the key components being gas, coal and nuclear. Oil products (e.g. fuel oil) are a further important part, followed by much smaller contributions from renewables, waste, biomass and geothermal.

 The nuclear generated electricity comes from 55 operating nuclear plants (including those in Fukushima) for a total of about 51 GW of capacity. With rolling blackouts now underway on Tokyo as a result of the cluster of nuclear plants in the Fukushima area now out of action, it is clear that the grid is very dependent on nuclear power. In the short term all the other generating capacity will have to be maximized to make up for the loss of the Fukushima facilities. The load is likely to fall on coal, fuel oil and natural gas which will further stretch international supplies at a time of high energy prices and disruption to coal supply following the floods in Australia. With 10 GW in the Fukushima area now offline (or 20% of the national nuclear capacity), replacement with LNG would require some 8 million tonnes per annum against a global supply of about 230 million tonnes.

But in the longer term, what if Japan took the decision to phase out nuclear power? I am not proposing that it should or shouldn’t, but sometimes major events can have a profound impact on societal developments going forward. In terms of potential replacements, current technology points to coal and natural gas, although the latter has an advantage in terms of lower CO2 emissions.  Equally, a profound shock such as that experienced in Fukushima could be a catalyst for accelerating the development of solar PV and concentrated solar in Japan.

In 2008 Japan imported about 68 million tonnes of LNG, of which about two thirds was used for electricity production. In the same year electricity production from the nuclear power plants was about 10% less than that produced by natural gas, so replacing that with natural gas would require another 40 million tonnes of LNG imports per annum. By comparison, annual LNG production in Qatar, the world’s largest supplier, is some 80 million tonnes. As already noted, global production is now 230 million tonnes, but it is growing rapidly. For example, the Gorgon project in Australia which is now under construction will produce 15 million tonnes of LNG starting in 2014.

But the impact of Fukushima could be more profound. Arguably nuclear is undergoing something of a renaissance as nations grapple with the challenges of energy supply, diversity of supply and CO2 emissions. According to the World Nuclear Association there is currently more capacity proposed, planned, on order or under construction (609 GW) than is presently in operation (378 GW). Of this, 64 GW is actually under construction with 176 GW on order or planned. Reverting to coal, for example, even with modern efficient facilities, could result in an additional billion or more tonnes per annum of CO2 emissions by the end of this decade if 200 less nuclear plants were constructed than current expectations.

It is early days and emotions remain high, but balancing climate risk against nuclear risk looks certain to feature in the energy discussion for some time to come.

Tough choices for Australia

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By the time I left Australia on Wednesday evening the debate over a carbon price in the economy had reached what I can only describe as fever pitch. It dominated the daily headlines in almost every mainstream newspaper and in Federal parliament it dominated the debate, even resulting in numerous divisions of the House as censure motions were put to the floor. Doubtless there is much more to come and it is not hard to imagine that this one issue, that has at least in part contributed to the fall of two Prime Ministers and a Leader of the Opposition, has more surprises in store.

The choices for Australia are also quite limited and the clock is certainly ticking. For starters, much of the power generation capacity is coal and there are a number of ageing  coal fired power stations. These could probably run for several more years at relatively low cost but their best days are certainly behind them. From a big picture resource point of view the obvious replacement is natural gas, which will also deliver significant emission reductions, particularly given the low efficiency of the old brown coal facilities. But the abundant supplies of natural gas are in Western Australia whereas the demand if used for electricity is in the South East regions around Sydney and Melbourne. There is also the prospect for significant coal-bed methane supply in Queensland, but the infrastructure to take it South is currently lacking. In any case, this is being targeted for export as LNG.

 

Some are looking at the prospect of renewable energy, mainly concentrated solar (CSP) and wind. Those that are, also worry that immediately replacing coal with natural gas will push CSP off the agenda and lock in future, albeit much lower than present, emissions. Others believe that the way forward may be nuclear, particularly given the vast uranium reserves in Australia although I personally doubt that the social issue of going nuclear could be resolved any time soon, let alone the site selection and ultimately construction of nuclear power plants. Australia also has geothermal potential.

An uncertain but critical element of the mix is the role of land use and agriculture. Some argue that this represents the single biggest reduction opportunity and that it should be vigorously pursued, with a particular focus on soil carbon and land clearing. But there also remain issues with measurement and verification in this sector. Longevity of the reductions in a country that is regularly plagued by drought must also be considered.

Against this backdrop is the Australian commitment to reduce emissions by 5% by 2020 relative to a 2000 baseline. This corresponds to a near 30% reduction from today in under ten years. Those in the government tasked with planning the way forward see this being met through a number of measures, with a reduction in the use of coal for power generation being a key component. Other elements include changes in land use practices, reducing methane emissions from coal mines, changes in the transport sector and then a broad range of smaller reductions. Set against this is continued growth in the resource sector with its consequent rise in emissions. But the sums do not really add up, which means international offsets will probably have to play a role, either on a government to government basis (e.g. REDD in Indonesia) or through an emissions trading systems with emitters having access to international markets.

In the EU with its hundreds of GW of capacity and broad access to gas, renewables, nuclear and now even CCS (via the NER 300 demonstration programme support mechanism), operating in combination with the EU-ETS and the Renewables Energy Directive acting as the drivers of change, there is sufficient flexibility to meet the 2020 goals. But I discovered when visiting Canberra and talking with policy makers that the EU-ETS is looked upon as a failure by some which means that emissions trading faces an uphill battle before it even starts.

This all adds up to a set of difficult choices. Which policy framework is best suited to trigger the needed change in the power sector and can reductions be delivered in the available time? Given the relatively small size of the sector (~ 30 GW of coal generation capacity), is there a case for the government to simply intervene and set the outcome within narrow parameters or is a market signal sufficient to do the job and if the latter how is it best delivered? Should road transport be included with power generation and subjected to the same policy instrument (e.g. a carbon tax)?

 

Like almost every other country on the planet, the solution set is almost certainly multiple. Australia is going to have to diversify its energy matrix as it moves forward, not only to meet environmental targets but also to satisfy burgeoning demand. The policy story isn’t just about a carbon price, which is where the focus lies today, but about a broader range of  instruments, both market based in sectors such as power but also standards based to drive efficiency improvements (e.g. vehicles). What is very clear though is that the debate needs to reach clear resolution in the near future so that business can begin the task of responding. As was pointed out to me by one observer, this debate didn’t just start with Ross Garnaut in 2008, but has been ongoing for over a decade now.