ENERGY WATCH #1 - August 21, 2018
“A renaissance of natural gas in the EU-28 electricity sector looks unlikely.” That is the major conclusion of a technical paper published earlier this month by the SIPA Center for Energy Policy Studies of Columbia University in the U.S., which investigates the potential of future gas demand in Europe.
For EU energy policy this is clearly an important topic. Future gas demand is one of the great uncertainties in EU energy policy – and how it will develop is an important consideration for infrastructural investments.
You will recall that the European Commission on 19 August issued a press release proudly proclaiming that the EU “has co-financed or committed to co-finance LNG infrastructure projects worth over €638 million. In addition to the existing 150 billion cubic meters of spare capacity in the EU, the EU is supporting 14 LNG infrastructure projects, which will increase capacity by another 15 bcm by 2021, which could welcome imports of liquefied natural gas from the U.S., if the market conditions are right and prices competitive.”
At the same time, Gazprom is building new pipelines into Europe.
But do we need all this extra investment? The report from the researchers at Columbia makes that rather doubtful.
The report, which has compared costs between gas-fired power and renewable power under various scenarios (including a “robust” CO2 price) notes that “questions are now arising about whether Europe needs new investments in natural gas infrastructure or if those investments would become stranded assets.”
The authors – Tim Boersma, Tatiana Mitrova, Johana Typoltova, Anna Galkina and Fedor Veselov – seem to take the position that such investments continue to be necessary. “Suggesting that the EU does not need new investments risks underestimating the role—or the potential role—natural gas plays in various sectors of Europe’s energy economy, including industry, transportation, and commercial and residential usage”, they write.
But then when it comes to the real conclusions of the paper, a rather different picture emerges. Here are the main conclusions, as highlighted by the authors (emphasis added):
- A renaissance of natural gas in the EU-28 electricity sector looks unlikely [in all scenarios], with only modest room for fuel switching and growth—about 40 billion cubic meters (bcm) on a continental scale through 2030 (in 2017, European demand hovered around 483 bcm). Fuel prices, carbon prices, and interest rates will be critical factors in determining whether demand for natural gas increases or declines.
- In determining the impact of the price of carbon on European natural gas demand, the case of the United Kingdom offers some insight. Once the United Kingdom unilaterally installed its carbon price floor, natural gas did force coal out of power generation on an impressive scale. However, to allow for fuel switching, existing underutilized generation capacity must be available to use. If not, utilities face serious questions related to the cost of new generation capacity, anticipated fuel costs and cost curves, and time horizons. Importantly, recent data suggest that even though the carbon price floor did provide an incentive for incremental gas-fired power generation, soon thereafter, renewables, storage, and efficiency eroded some of the gains made by natural gas. This analysis suggests that there is moderate room for fuel switching similar to what happened in the United Kingdom.
- Increasing natural gas demand for electricity generation is most promising for southern Europe, chiefly because electricity demand in this part of the continent is still growing, although competition from renewables here is fierce. In a scenario with high carbon prices and high natural gas prices, by the end of the forecasting period, investments in renewables make more economic sense than natural gas in the southern part of the European Union. The costs of capital are likely going to be critically important in the coming years to determine whether investors turn to renewables or (in part) natural gas.
- Ultimately, the paper finds that new EU investments in gas infrastructure are probably necessary in parts of the European Union. New investments are less necessary in more mature parts of the continent relative to the less-developed parts of the continent, where gas demand has room for growth and/or single source dependency concerns trump basic economic considerations.
These conclusions speak for themselves. Purely on a cost comparison basis (assuming higher CO2 prices), gas will not be competitive in the end with renewables.
What I wonder about, shouldn’t there also be something like a methane price in addition to a CO-price? Or should calculations be made to include methane emissions in the CO2 emissions from fossil fuels? That would make gas even more expensive relative to renewables. It may also do away with part of the cost advantage gas has over coal with increasing CO2 prices.
Recently researchers from Colorado State University reported that methane emissions from the natural gas industry are significantly higher than has been assumed so far. Now researchers from consultancy TNO in the Netherlands have come to similar conclusions based on a completely different study and methodology.
The TNO researchers looked at methane emissions from cows and from gas installations in the northern Netherlands. They conclude that “natural gas production emits more methane than currently calculated”. How much exactly remains unclear. They only measured emissions for a week.
Up to now, official Dutch greenhouse gas emission figures had assumed gas production and transport was responsible for just 1.9% of total methane emissions. This now turns out to be 20%. The researchers do stress that the uncertainty around the figure is high.
Probably the main conclusion from the research should be that we though we knew how high methane emissions from the gas industry were in the Netherlands, now we know that we don’t know. More research is obviously needed.