Mark C. Lewis is the managing director of Deutsche Bank’s Global Carbon Markets desk. Here the Paris-based Englishman explores how carbon mitigation targets and Phase III of the European Union’s Emissions Trading Scheme will likely impact the power industry and influence utility investment decisions, as well as why national floor prices for carbon may be counter-productive. 

Mark C. Lewis, Deutsche Bank, France 

Mark C. Lewis, managing director of Deutsche Bank’s Global Carbon Markets desk
The European Union’s (EU) target to reduce carbon emissions by 20 per cent by 2020 will be easily met. Even before the recession, the target was likely to be hit because a large part of the burden for reducing emissions falls on the private sector, which faces significant fines – in the EU’s Emissions Trading Scheme (EU ETS) firms are fined €100/tonne ($125/tonne) – for exceeding carbon quota. The EU is also going to outperform Kyoto easily because of the recession.

That is why the European Commission published in May a paper setting out what it would take to move to a unilateral 30 per cent carbon reduction target by 2020. It is not yet formal policy, but the UK, France and Germany are all in favour, and the next meeting of the European Council in October will look carefully at this issue.

However, Deutsche Bank does not assume that the EU’s target to generate 20 per cent of electricity from renewable energy is realistic. It will not be met. It is very difficult to enforce compliance on sovereign governments, as there are no equivalent sanctions to EU ETS fines on EU member states to enforce the 20 per cent renewable generation by 2020 target.

For the power sector it means getting to 34 per cent of all electricity generated sourced from renewable energy by 2020, up from around 17 per cent now. In numerical terms, that means doubling from 600 TWh today, half of which is from large hydro, to 1200 TWh by 2020 – a massive challenge. Three-quarters of that extra 600 TWh will have to come from wind, and one-third of that will be offshore wind, which remains very expensive.

We believe that the EU will continue to add around 6 GW of renewables a year as it has done on average for the past ten years, rather than the annual 14 GW needed to hit the 2020 target.

Carbon mitigation requirement

When we factor in the extra renewable capacity coming onto the grid, the extra gains from energy efficiency we assume and the allowed offsets from outside Europe, we are left with what we call the ‘residual carbon abatement’ requirement. In other words, the target, on average, participants in the EU ETS need to meet to comply with.

With a carbon reduction requirement of 20 per cent by 2020, we think that the requirement is only 20 million tonnes per year. Two years ago, the requirement was closer to 100 million tonnes per year. Twenty million tonnes per year could be achieved simply by fuel switching from coal to gas. With a 30 per cent EU carbon reduction target, the requirement reaches near 100 million tonnes per year and a more long-term view of investment decisions in new plant is necessary.

THE EU ETS AND PLANT INVESTMENT OPTIONS

The point about carbon markets is that it does not matter what the carbon price is today; if a utility is going to build something that lasts for 40 years then it has to consider the price of carbon over a longer period. Contrary to what some believe, the carbon market has led to much hesitation about building new fossil fuel power stations, in particular coal fired plant. If we had not had the EU ETS, I believe we would have seen much more coal plant under construction.

Under Phase II of the EU ETS, the cap on emissions is set at 2.1 billion tonnes per year. The cap will be tightened under Phase III from 2013, so that by 2020 the limit will be just 1.72 billion tonnes per year. Carbon emissions in 2009 were 1.87 billion tonnes. We have had a tremendous contraction in EU ETS emissions as a result of the recession, falling by
370 million tonnes between 2007 and 2009.

However, there is a psychological expectation that the EU ETS will be a lot tighter under Phase III and the carbon price will rise. This is already having an effect on people’s willingness to invest in coal fired power stations. Does this mean the end of coal plant as an investment option? Well, we have already witnessed the end of coal fired power generation as an independent power producer (IPP) model, as it is very risky to put all of one’s eggs in one (coal) basket.

Is Coal out of the game?

A large utility like E.ON, RWE or even EDF could afford to build the odd coal fired power station, if it is to replace an old, inefficient coal plant, to maintain portfolio diversification and as a back-up for renewables.

But coal is basically out of the game as a new build choice with carbon prices above €30/tonne, except in specific circumstances. And if you believe that there will be an international climate change agreement in the next three to five years then utilities will have to be very wary about building new coal fired power stations.

A carbon price of €20/tonne raises the cost of gas fired generation by an extra €8 per MWh, or €15/MWh for coal. Assuming a long-term contract price for gas indexed to a crude oil price of $85/barrel, a coal price of €100/tonne, and capital construction costs for nuclear of €2.5–€3 million per MW, a carbon price of €20/tonne would mean the price of electricity would need to hit €70/MWh for both new gas and new coal plant investment to be economic. This compares to €68–€75/MWh for nuclear, €80–€90/MWh for onshore wind and €130–€160/MWh for offshore wind all on a 30-year, discounted cash flow basis.

Figure 1: Breakdown of generation costs with a carbon price of €20/tonne, crude oil at $85/barrel, using long-term contract pricing for gas, and coal at $100/tonne.

When the carbon price rises to €40/tonne, the price of electricity would need to hit €83/MWh for new coal plant investment to be economic. This compares to €75/MWh for gas with, of course, offshore wind and nuclear at the same levels as before. At a carbon price of €40/tonne but a crude oil price of $100/barrel, the price of electricity will need to be over €100/MWh for coal to be economic.

Over the next five years, onshore wind will be competitive with coal and gas even without a carbon price or direct/indirect subsidies. Onshore wind is viable at €80/MWh, not a million miles from where we are now and below the wholesale price of electricity we saw prior to the recession, but with offshore wind a lot of work needs to be done to make it commercially viable.

While coal plant remains relatively cheap to build and operate, with a price of €40/tonne, carbon makes up more than a third of the total costs of generating coal fired electricity. The carbon market has pushed out coal to the margins as a source of new build. It is out of the equation unless you can find CCS solutions. That is the future for coal.

The current price of carbon does not matter so much for CCS, because it is unlikely that much CCS plant will be connected to the grid until 2020. The industry needs confidence that the price will be at least €50/tonne in 2020 otherwise it may not be so willing to undertake the necessary investments.

Gas, gas and more gas?

New gas fired power stations are displacing old coal plants and to a lesser extent old gas plants. They are efficient, quick to build and are needed as baseload plant. Gas plant is the best all-rounder right now. It is the default choice for new build and it will remain so for some time to come.

Two years ago people were worried about natural gas supplies running out. Now everyone’s saying Europe’s drowning in gas. There may be some truth in that in the short term, but on a three-to-five year view I am personally very bullish on oil and, therefore, gas prices.

Figure 2: Breakdown of generation costs with a carbon price of €40/tonne, crude oil at $85/barrel, using long-term contract pricing for gas, and coal at $100/tonne.

I simply do not buy the argument that Europe will be swimming in gas for the next ten years. Shale gas will be environmentally and financially challenging to extract and it is far too early to say if it will be as bountiful as thought in some quarters.

By 2015, global daily production of crude oil will fall by 10 million barrels to 75 million barrels, and demand from China and India and the rest of Asia is outstripping falling usage in the western world. Furthermore, there is huge potential upside for Chinese demand for gas and redirection of Russian supplies from Europe to Asia.

Whether European electricity consumers want to be overly dependent on a commodity that is linked to rising oil prices and an oil industry, which, as we have been reminded recently in the Gulf of Mexico, is running into some very serious physical constraints, is a key question.

CARBON PRICE SET TO RISE

Deutsche Bank started investing in the carbon market in 2001, later establishing a Global Carbon Markets desk in 2005. We forecast the price of EU ETS carbon allowances to rise to around €25/tonne by 2012 with the current EU’s carbon reduction target of 20 per cent by 2020. If the Commission, as it has recently hinted, raises the target to 30 per cent by 2020, we expect the carbon price to rise to between €30–€35/tonne in 2012 and €48/tonne by 2020.

Upward pressure on carbon prices will come from an upswing in electricity demand and from European utilities, which will have to buy
100 per cent of their required carbon allowances under Phase III of the scheme commencing 2013.

Figure 3: Breakdown of generation costs with a carbon price of €40/tonne, crude oil at $100/barrel, using thermal-equivalent pricing for gas, and coal at $100/tonne.

RWE, the biggest emitter in the EU ETS, would have to buy between160 million and 170 million carbon permits a year under the 2013–2020 Phase III scheme, up from 60 million–70 million in Phase II. Poland and other recent entrants to the EU will get 80 per cent of their carbon allowances for free in 2013, tapering to zero by 2020.

Phase III allowances are not yet on sale, but RWE has already sold around ten per cent of its 2013 electricity output, so it and other utilities are hedging by buying Phase II permits. European utilities currently have a net deficit of 500 million tonnes of carbon allowances under
Phase II.

In stark contrast, industrial emitters like steel manufacturers have a large surplus because of the global recession, but are not yet selling. These factors could push up the price of carbon to €18–€20/tonne by the end of 2010. Had it not been for the recession, prices could well have been in excess of €30/tonne already.

Nuclear power and national carbon floor prices

Nuclear power is competitive with gas in terms of generation costs even without a carbon price, but the decommissioning liabilities are always an issue and it is always worth remembering that there is not a single nuclear power station on the planet that has not been built with some sort of direct or indirect government guarantee. Nuclear power plants may therefore require some additional incentives in order to compete with gas.

One possible way under discussion by the UK government is a national minimum price for carbon. In some ways a national floor price is a nice idea, but if it is done in only one jurisdiction then the cost of generating electricity from fossil fuels will rise, but there would not be any corresponding reduction in the overall cap on EU ETS emissions. In the end this will be counter-productive, as it would subsidize fossil fuelled generation in the rest of Europe.

How? Well, let’s say that the UK government offers a carbon floor price of €30/tonne for 2011 and the EU ETS price is €15/tonne. A coal fired generator may say, “I can’t afford to generate electricity from coal with a carbon price of €30/tonne, but I can at €15/tonne.”

The coal fired plant operator would then sell all the allowances it would have used to generate electricity from coal at carbon prices between €15–€30/tonne, or not buy the allowances in the first place, as it would be uneconomic to burn coal. The permits would then be sold to generators in the rest of Europe who would be able to generate more fossil fuelled power than otherwise allowed under the scheme.

Of course, utilities operating in the UK with a relatively low-carbon footprint are in favour of a floor price, but others would be less than pleased. But it would have a negative impact on the carbon price across Europe as a whole, as it effectively increases the number of allowances available to other generators. And a European-wide floor price is not going to happen.

At any rate, the UK might find that a national floor price is much trickier to implement than first thought. If the carbon price in the UK is being fixed above the market price in Europe, somebody has to pay the difference. In the current fiscal environment, the UK is not going to use public money to take allowances out of the system, so the burden would have to fall on consumers.

Future for carbon market

The EU ETS is a relatively inefficient market, but in terms of disincentivizing the building of new coal fired power stations it is doing its job.

This will be reinforced in the next two to three years as we approach Phase III. The future for the EU ETS is fairly robust but whether there will be a global carbon market is less certain.

Mexico’s Cancun will be the location for the next UN Climate Change Convention and expectations are a lot lower than they were for Copenhagen, so a global carbon market is clearly on the back burner. Much depends on the United States and whether they can implement a carbon market. Unfortunately, President Obama’s cap-and-trade plans are in limbo and it is difficult to imagine that it will on the statute book by Cancun, which takes place at the end of this year. In the longer term, however, I am more optimistic. But it may be close to 20 years to 30 years before there is a global carbon market where a tonne of carbon truly costs the same anywhere in the world, much like a barrel of oil.

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