February 13, 2018
ENERGY WATCH #1 by Karel Beckman
The oil industry’s 20-year window of opportunity
February 13, 2018
ExxonMobil has, under pressure from shareholders and lawsuits, for the first time published an analysis of how the company believes it can adapt to a 2-degree Celsius energy scenario. The company’s Energy & Carbon Summary, published – very instructively – alongside its annual Outlook for Energy, shows how global energy demand and supply is likely to evolve in a 2-degree scenario, and how this will impact is oil and gas reserves.
This is no small thing. As the company itself acknowledges in the Energy & Carbon Summary: “the main driver of intrinsic value of an integrated oil company’s upstream operations is its proved reserves”. In other words, this is what the oil industry is all about.
The trillion-dollar question is of course whether these reserves can still be produced in a 2-degrees scenario, or whether they will become “stranded”. In the latter case, it would imply that the company’s stock market valuation – which is largely based on its reserves – would be overvalued. Hence the notion of a “carbon bubble”.
At first sight the outcome of the Energy & Carbon Summary, published on 2 February, seems fairly reassuring for investors, and for the oil industry in general. Under the 2-degree scenario, oil demand will decrease about 0.4% per year, but gas demand will increase by 0.9% per year. Companies like ExxonMobil and Shell hold roughly half of their reserves in oil and half in gas.
Hence, although the outlook for oil is surely rather alarming (demand would decline from 95 million barrels per day in 2016 to about 78 million barrels per day in 2040), on the whole the picture does not look too bad.
What the report does not mention however – what no press report has mentioned, as far as I was able to tell – is: what will happen after 2040?
2040 is only 22 years from now. Doesn’t ExxonMobil care what happens after that? There is no indication anywhere that it does.
The point is highly relevant: if you follow the trend lines in ExxonMobil’s report – e.g. for the spread of electric vehicles (EVs), the growth of renewables, the decline of oil – beyond 2040, you see that the window for the conventional oil industry is closing fast.
So what are some of the key projections in ExxonMobil’s 2-degree scenario?
Actually, the company has not made its own projections. It has analyzed a number of existing 2-degree scenarios, as shown in the following chart:
Exxon then simply takes the average of these scenarios and concludes that:
- Oil demand is projected on average to decline by about 0.4 percent per year
- Natural gas demand is expected on average to increase about 0.9 percent per year
- The outlook for coal is the most negative, with diverse projections showing an average decline of about 2.4 percent per year, or about a 50 percent decline by 2040
- The projected growth rates for renewable energies and nuclear are between 4 and 4.5 percent per year for non-bioenergy (e.g., hydro, wind, solar) and bioenergy, and about 3 percent per year for nuclear
- Energy demand increases 0.5 percent a year
These are only averages of course (some scenarios sees oil demand dropping 1.7 percent a year and natural gas 0.8 percent per year) – and again, they only reach until 2040.
Based on these numbers, ExxonMobil concludes that there is no reason to fear that it can produce the overwhelming majority its current proven reserves: “We believe our reserves face little risk”.
Incidentally, ExxonMobil has some 20 billion oil-equivalent barrels (oil+gas) in proven reserves and 71 billion in non-proved resources. That’s quite a lot: the U.S. as a whole has 48 billion barrels in proven oil reserves.
The company also notes that substantial investment is still needed to produce all this oil and gas. In other words, they can continue to do business as usual. Until 2040, that is.
Now all of this of course is based on the various 2-degree scenarios that researchers have drawn up. In ExxonMobil’s annual Outlook for Energy, also published on 2 February, the company shows what it regards as the most likely energy future, based on current economic trends and existing climate policies. In other words, in this scenario, the world warms more than 2 degrees, even though Exxon does not indicate exactly by how much.
This gives an altogether different picture:
As can be seen in this chart, oil demand in Exxon’s “normal” Outlook for Energy shows healthy growth of 0.7 percent per year, and gas 1.3 percent.
However, this is not yet the whole story. A bit confusingly, the Outlook for Energy also contains a number of “sensitivity analyses”, which show what could happen if certain assumptions turned out to be true.
They are quite interesting. Take for example the following chart, which assumes that “the global light-duty vehicle fleet is 100% electric by 2040”:
As you can see, a massive uptake of EVs leads to a quite rapid decline of oil demand by 2040. Of course, it is unlikely that all light-duty cars will be electric in 2040. Then again, note that in this picture, zero EV penetration is assumed in commercial transportation. And, to repeat once more, it does not look beyond 2040, when the effects of EV penetration are likely to really start kicking in.
A similar story can be told for another key sensitivity: the demand for natural gas in electricity generation (the most important use of gas).
This gives the following picture:
In this analysis, natural gas demand does take a hit, although a fairly small one. However, to my mind, it looks quite unrealistic. If wind and solar achieved 50% penetration (and in practice it could be a lot higher), surely gas demand in the power sector would be hit a lot more? And why assume that nuclear would be replaced by gas, rather than vice versa – since nuclear is after all CO2-free?
As to how ExxonMobil’s Outlook for Energy compares with the 2-degree scenarios in terms of CO2-emissions, this is shown here:
Note that the “baseline scenarios” at the top are business-as-usual scenarios that assume no “policy evolution” beyond 2010.
What is clearly visualized in this picture is that Exxon’s Outlook for Energy runs only to 2040. And you can see what happens after 2040 in the 2-degree scenarios: steep drops in CO2 emissions – presumably based on steep drops in fossil fuel use.
Not that ExxonMobil is not doing anything to prepare itself for a lower-carbon future. It is pursuing certain alternative activities.
However, unlike its main European competitors – BP, Shell, Total, Statoil – it does not invest in solar and wind or in electric vehicles or electric charging. Instead, it mainly pursues three kinds of alternative energies:
- Researching breakthroughs that make CCS technology more economic for power generation and industrial applications
- Developing process intensification technologies to reduce energy requirements of manufacturing facilities
- Progressing advanced biofuels for commercial transportation and petrochemicals
The problem with all three of these activities is that they show very little concrete results so far. For example, ExxonMobil has been investing in producing oil from algae, but there is nothing to indicate that this is likely to become very successful.
At this moment, it seems that 20 years is all that ExxonMobil has…
As a footnote, I should add that on 6 February, the Energy Information Administration (EIA), the U.S. government’s energy think tank, has come out with its Annual Energy Outlook. As always, the energy future presented in this report is very much of the business-as-usual variety.
The EIA stresses that its outlook is not a “prediction of what will happen”, but a “modeled projection of what may happen given certain assumptions and methodologies”.
As Inside Climate News notes, if the EIA’s projection – which extends to 2050 – were to come true, “the U.S. alone would burn through much of the world’s carbon budget”.
In fact, “The carbon footprint of the United States will barely go down at all for the foreseeable future and will be slightly higher in 2050 than it is now.”
And this is the case even while “starting in 2022, practically all additional electricity generation capacity would come either from natural gas or wind and solar. Coal would flatten out, but not disappear, and the boom in gas and oil would continue, turning the U.S. into a net exporter of energy.”
ENERGY WATCH #2 by Karel Beckman
100% renewable energy revisited: the window could close even quicker
February 13, 2018
If ExxonMobil’s 2-degree scenario provides at least reassurance to the oil industry for the next 20 years, there are other scenarios going round that should be a lot more worrisome for oil companies.
In particular, Stanford Professor Mark Jacobson has become famous for his 100% renewable energy roadmaps.
In August last year, Jacobson published a study showing for 139 countries around the world how they could move to 100% renewable energy by 2050. Mind you, that’s 100% renewable ENERGY, not just electricity, so for the transport and heating sector as well. Not only that: it’s also 100% RENEWABLE energy, i.e. no nuclear – and not even bio-energy.
You can read more about it here in this article by Cleantechnica correspondent Steve Hanley. The roadmap is summarized in this chart:
But Jacobson’s study drew a lot of criticism. A good account of the debate can be found here on Energy Post in an article by Joshua D. Rhodes of the University of Texas.
As Rhodes pointed out, critics questioned for example how quickly technologies, including underground thermal energy storage, phase change materials to store solar thermal energy, and hydrogen as a usable fuel, can mature and be used at large scale. Other critiques focused on assumptions around how flexible the demand for energy can be – a key consideration when dealing with variable sun and wind power. “Then there’s the amount of electric transmission power infrastructure needed, the costs of all the capital required, the pace of investment needed and land use issues”, Rhodes wrote.
He said that “some criticisms are probably fair. I tend to be bullish on the potential of technology to advance rapidly, but having worked in residential energy use, and energy retrofits in particular, I find the amount of geothermal energy storage retrofits for heating and air-conditioning in buildings Jacobson assumed hard to fathom.”
Nevertheless, Jacobson’s study did put out a challenge to those who, like ExxonMobil, tend to discount the possibility of a speedy and thorough energy transition. After all, does it really matter whether the 100% is really reached in 2050, as long as the path is travelled?
However that may be, Jacobson has now, together with researchers from the University of California at Berkely and Aalborg University in Denmark produced a new study which updates and expands his earlier analysis. It has been published in the journal Renewable Energy.
The new study again claims that 100% renewables by 2050 is possible “at a comparable cost, even slightly cheaper, than business as usual (fossil fuels), and at just one-quarter of the cost if you dial in savings from avoided fossil fuel damage to the environment and health”, as Giles Parkinson summarizes it on his website Reneweconomy.
“Based on these results, I can more confidently state that there is no technical or economic barrier to transitioning the entire world to 100 percent clean renewable energy with a stable electric grid at low cost,” Jacobson said. “This solution would go a long way toward eliminating global warming and the 4-7 million air pollution-related deaths that occur worldwide each year, while also providing energy security.”
As Parkinson notes, “The modelling assumes a phenomenal amount of wind, solar and other technologies to be built over the next few decades – some 18,000GW of wind, 10,000GW of rooftop PV, 16,000GW of utility-scale PV, and 2,850GW of solar thermal.”
The latest paper addresses some of the criticisms raised last year, notably those that said that Jacobson’s scenarios were too much centred on a single scenario and that it relied too much on adding turbines to existing hydroelectric dams.
“That’s why the new paper present different scenarios, including ones with no added hydropower turbines and no storage in water, ice, or rocks”, notes Parkinson.
“Our main result is that there are multiple solutions to the problem,” Jacobson says. “This is important because the greatest barrier to the large-scale implementation of clean renewable energy is people’s perception that it’s too hard to keep the lights on with random wind and solar output.”
According to Parkinson, “The new study matches supply and demand in 30-second increments for five years (2050-2054) to account for the variability in wind and solar power as well as the variability in demand over hours and seasons.”
“The average contribution from wind and solar totals more than 90 per cent in the main scenarios, with storage in hydro, batteries, hydrogen, and solar thermal, and considerable amount of demand flexibility in transport (charging and discharging) and industrial uses.”
“The fact that no blackouts occurred under three different scenarios suggests that many possible solutions to grid stability with 100 percent wind, water and solar power are possible,” the report says.
“That, it notes, is a conclusion that contradicts previous claims that the grid cannot stay stable with such high penetrations of just renewables.”
If Jacobson and colleagues are right that 100% renewable can be achieved in thirty years’ time, the question then becomes how this could be done. They note that it will require “coordination across political boundaries”.
“Ideally, you’d have cooperation in deciding where you’re going to put the wind farms, where you’re going to put the solar panels, where you’re going to put the battery storage”, said Jacobson. “The whole system is most efficient when it is planned ahead of time as opposed to done one piece at a time.”
Such global political agreement is hard to imagine of course. Hence, Jacobson is “working on smaller road maps to help individual communities, many of which have already committed to achieving 100% renewable energy.”
But in the end the most valuable part of Jacobson’s work may be in the fact that he is opening up in people’s minds the real possibility of a 100% renewable energy system that looks radically different from ExxonMobil’s Outlook for Energy or the EIA’s Annual Energy Outlook.
ENERGY WATCH #3 by Karel Beckman
In fact, it is closing quicker: solar, storage displacing fossil fuels faster than ever
February 13, 2018
“How Tesla’s big battery is bringing Australia’s gas cartel to heel”, is the intriguing title of a recent article by Giles Parkinson, editor of the Australian website Reneweconomy, published in the British Guardian newspaper.
It is a hugely instructive an entertaining story that Parkinson has to tell.
You have heard of Tesla’s 100MW/129MWh battery presumably: it was commissioned by the government of South Australia to back up the state’s rapidly increasing wind and solar power capacity. Tesla built it at record speed in 100 days’ time (Elon Musk had promised he would give it away for free if it wasn’t on time).
The project is part of a bigger story in Australia that is also relevant to Europe and America: the struggle going on between the federal government, which tends to be anti-renewables and lukewarm on climate policy, and the South Australian government, which wants to be leading in the energy transition. In other words, similar to California versus Washington DC (or the European Commission/Germany versus Poland).
The anti-renewables forces, backed by Murdoch-owned media, routinely blame renewables for blackouts that are in reality more often caused by grid failures or failing coal and gas fired power stations as well as a general failure to modernize the electricity system. (See e.g. this article on Energy Post.)
What they don’t usually mention is the way in which the conventional generators are gaming the system to profit from power shortages. But now the Tesla battery appears to be putting an end to this lucrative game.
Parkinson explains how it works: the Australian Energy Market Operator often calls for generators in South Australia to provide network services known as FCAS, or frequency control and ancillary services. Usually, that provides a big bonanza to the big generators: they bid in at prices of between $11,500 and $14,000/MW, sometimes “charging up to $7 million a day for a service that normally comes at one-tenth of the price”. This happened 10 times in the past twelve months.
However, on the most recent occasion, on 14 January, “the market price did not go into orbit and the credit must go to the newly installed Tesla big battery and the neighbouring Hornsdale windfarm”, writes Parkinson. The price stayed down (after a short spike) to $270/MW.
Ed McManus, the CEO of Meridian Australia and Powershop Australia, which operates the Mt Millar windfarm in South Australia, says the Tesla big battery is already having a “phenomenal” impact.
“If you look at FCAS … the costs traditionally in South Australia have been high …. and our costs in the last couple of years have gone from low five-figures annually to low six-figures annually. It’s a hell of a jump,” McManus said. “That plays into the thinking of new players looking to come in to South Australia to challenge the incumbents. FCAS charges are on their minds.”
“It’s a little early to tell, but it looks like from preliminary data that the Tesla big battery is having an impact on FCAS costs, bringing them down … that is a very, very significant development for generation investment and generation competition in South Australia,” McManus said.
According to Parkinson, “There is no doubt that the actions of the Tesla big battery in the FCAS market will please the state government, which signed a contract with Tesla to address just this issue. And it may be able to repeat the dose with the newly announced 250MW “virtual power plant”, also to be built by Tesla. If it can keep a lid on FCAS prices like it did in January, then it will likely pay back the cost of the battery in a single year from this service alone, let alone the value of its trading in the wholesale market, and the value of its emergency backup capabilities.”
Parkinson adds that this is “just another string in the bow of the Tesla big battery, following its devastatingly fast response to trips of major coal-fired generators … , its ability to go to capacity from a standing start in milliseconds, and its smoothing of wind output and trading in the wholesale market.”
What this means is that the combination of variable renewable energy with storage is spelling big trouble for incumbent power plant operators. They have already been hit by the renewables revolution in recent years, now the addition of storage is likely to hit them even worse, by taking away some of their most lucrative options of making money.
In the U.S. the same thing in happening, with gas peaker plants quickly becoming obsolete as solar-plus-storage is increasingly being embraced by utilities.
“I don’t think we’re going to be building many traditional gas peaker plants five years from now”, said Andrew Oliver, Chief Technology Officer of Renewable Energy Systems Americas (RES), “the world’s largest independent renewable energy company”, in an interview with Bloomberg New Energy Finance.
Oliver notes that “The business of energy storage is growing surprisingly fast as battery systems get cheaper and utilities and other businesses find new ways to use them.”
RES has a 12 GW portfolio in onshore and offshore wind, solar, storage and transmission in Canada, Australia, the U.S. and various European countries, including Turkey.
With regard to the future of energy storage, according to Oliver, “There’s two very hot areas right now. The first one is solar-plus-storage, the second is peaker plant replacement. Nearly every solar independent power producer is adding an energy storage option to their plans. In certain markets, they can get a capacity payment and it certainly provides a hedge to the people writing the PPAs [power purchase agreements], usually the utility, against future lower wholesale pricing as that penetration of solar increases on the grid.”
Oliver sees the market growing extremely fast: “We see the number of RFPs [requests for proposals, i.e. tenders] continue to accelerate from both utilities and IPPs. It’s hard to imagine this is going to slow down. It’s phenomenal growth. I was in the wind industry and I saw that grow rapidly, and this is like wind on steroids, almost…. The growth rate of the marketplace has surprised me. A few years ago, a 10-megawatt project was huge. Now we’re seeing utilities wanting 30-megawatt, 50-megawatt, 100-megawatt projects just a couple of years later. The number of opportunities we’re seeing — New York announcing 1.5 gigawatts of storage, California with all its procurements — continues to grow.”
The interview offers some interesting inside looks into the complexity of the storage sector. Thus, for example, Oliver notes that “Finding the optimal cost solution is really quite impractical without throwing a massive amount of computing power at the problem — AC-coupled systems versus DC-coupled, the ratio of DC panels to the AC grid connections, the orientation of the panels, trackers or fixed-tilt, the ratio of storage to solar, the number of hours of storage, and then the overbuild strategy — lithium-ion technology degrades over time and so how much extra do you need to build to get to the end of your power purchase agreement.”
So, after 26% growth last year, with 99 GW of solar PV installed across the world, there is every reason to believe that the market will continue to grow.
GTM Research’s new Global Solar Data Hub predicts that in 2018 106 GW of solar PV will be built.
Greentech Media also identified 10 trends that it believes will shape the global solar market this year. These include the following:
- Global solar tenders continue to proliferate
GTM Research counts 53 national markets where a tendering or auction scheme is currently in place, up from 32 in the second half of 2016. Furthermore, there are an additional 29 national markets where a tendering or auction scheme has been discussed or planned.
- The global market is diversifying, but large countries still dominate
- PV continues to compete with (and beat) coal and natural gas
According to GTM Research’s Global Solar Demand Monitor, recent bids are pushing average PPA tariffs past the cost-competitive range with coal and gas.“It is important to note that nearly all global low-bid projects have long lead times and are still unbuilt and unproven,” said GTM Research Solar Analyst Ben Attia. “Three to five years is an eternity in the solar space. It remains to be seen how market and country-level risks will erode the tendered pipelines.”
- A bumpy road for module supply
Looking toward 2018, GTM Research is forecasting supply-demand tightness in the first half of 2018 and an oversupplied environment in the second half. This means there is risk that prices will increase in the first half of the year and depreciate rapidly in the final six months.
- Balance-of-system costs will be an important cost-reduction driver
In 2018, balance-of-system costs will account for the largest share of utility-scale PV project costs. GTM Research Solar Analyst Rishab Shrestha notes that efficiency improvements, higher-wattage modules, and 1,500-volt systems will provide BOS cost savings, in addition to hardware cost reductions, helping solar to compete against other sources of generation in markets around the globe.
- S. residential solar pricing is the highest in the world
Despite falling prices globally, residential solar system pricing is higher in the U.S. than in any other major Organisation for Economic Co-Operation and Development (OECD) solar market.
- Storage continues to be integrated into solar projects
ENERGY WATCH #4 by Karel Beckman
Why are electricity prices so high for UK industry? No, it’s not climate policy
February 13, 2018
Just as there is a debate in Australia over power failures, and in the U.S. over fossil fuels, so there has been a long-running debate in the U.K. about the (presumably) high electricity prices that the industrial sector is confronted with.
Conservatives often claim that the UK’s carbon floor price or renewables subsidies are responsible for that. Just recently, the University of Oxford’s well-known energy expert Dieter Helm delivered a report for the government, the “Cost of Energy Review”, which, as Carbon Brief reports, “was supposed to clear a path to the government’s manifesto pledge of having the “lowest energy costs in Europe, both for households and business”.
Helm concluded that renewable energy subsidies should bear a large part of the blame for the high electricity costs.
Carbon Brief notes moreover that the Conservative Party’s manifesto was co-authored by Nick Timothy, a former policy adviser to prime minister Theresa May, who has “continued to attack climate change policy, arguing it is “impos[ing] higher energy costs and lower industrial output”.
However, not everyone agrees with Helm and Timothy’s assessment. Thus,”the government’s independent Committee on Climate Change (CCC) said that wholesale costs and network charges were to blame for higher industrial electricity prices, rather than climate policy. It said last year:
“Differences in low-carbon policies cannot explain the difference in electricity prices, which stem primarily from higher wholesale and network costs…It is not clear why these costs are higher in the UK than in many comparable countries.”
Now a new report has come out, co-written by professor Michael Grubb of University College London, which backs up the conclusions of the CCC.
Grubb and his colleagues found that “continental industrial power prices are often lower than those in the UK because of better links between neighbouring electricity grids, “activist” industrial policy and reliance on old generating capacity that is nearing the end of its life.”
The report “confirms that climate policy costs are not the decisive factor.” Grub tells Carbon Brief: “It’s kind of nonsense, the idea that it’s driven by carbon-related policies.”
It is worth looking at Grubb’s report in a bit more detail, since it offers many interesting findings for other European countries as well. Grubb compared price movements in the UK with Italy, Germany and France in particular.
Here some of his conclusions, as reported by Carbon Brief:
“Since 2000, UK industrial electricity prices have more than doubled. Most of this was due to rising international fossil fuel prices before 2008, when the UK passed its Climate Change Act.”
“The UK is highly exposed to wholesale gas prices, the report notes, since the liberalised market of the 1990s led to the “dash for gas” and increased reliance on the fuel.”
“After 2012, UK industrial electricity prices started to diverge from the EU average. A particularly large spike in euro-denominated UK power prices, around 2015, was due to the strength of the pound, whereas sterling-denominated prices held steady.”
“This exchange-rate effect harmed the competitiveness of UK industry by raising its cost base relative to overseas firms … The pound has since fallen back to levels seen in 2010 or 2011.”
“Other factors driving the divergence with other EU countries include the UK’s exposure to gas, …, with prices peaking in 2013, well after a peak in coal prices. Like the UK, Italy is also reliant on and exposed to gas.”
“In contrast, France gets most of its electricity from nuclear plants built in the 1970s and 80s, while German electricity prices tend to be set by coal.”
“UK prices after 2012 were also driven by rising investment in the electricity sector, after a lack of investment during the 2000s, and the carbon price floor, the UK’s unilateral top-up carbon tax. Note that while this contributed to a growing gap between UK and EU average prices after 2012, it cannot explain this difference and some industrial firms are compensated for the cost.”
“For the average industrial user in the UK, prices in 2016 were 35% above the level in 2008 and a similar amount above the EU average, which was relatively static over that period, the report says.”
“With maximum compensation, UK users in 2016 faced lower prices than in Germany or Italy, while they remained slightly above those in France.”
“Note that other countries make greater use of exemptions, instead of compensation. This makes the UK look worse than it actually is, in the pre-compensation figures published by Eurostat, which can, therefore, be “quite misleading”, Grubb says. The UK is now moving towards exemptions.”
“Eligibility for compensation is complex, writes Carbon Brief, “and varies between different schemes and countries, but the broad outlines are determined by EU-wide state aid rules. In principle, firms that face competition from overseas and with high electricity costs as a share of their outgoings can get compensation.”
“Eligible firms got 85% compensation for carbon price costs during 2013-15, falling to 80% in 2016-18 and 75% in 2019-20. This includes indirect costs passed through by electricity suppliers. In the UK, some firms also get 85% compensation for the costs of renewable subsidies, while some German firms also get a discount at similar levels.”
“The report divides policy costs into two sections. First, it shows that taxes and levies – including support for renewables – cannot explain higher prices in the UK. In fact, UK industrial electricity faces lower taxes and levies than in Germany or Italy.”
“Carbon pricing – the second part of policy – is listed under “energy and supply” in the report. Here, policy is once again unable to explain lower costs on the continent. Even if the UK’s carbon price floor were set to zero, costs would be higher than in France or Germany.”
“If policy costs cannot explain the higher industrial electricity prices for uncompensated UK firms, then what other explanations can there be?”, asks Carbon Brief.
The UCL report “shows that network costs are actually almost equal across the four countries it looked at. Instead, it is the way these costs are shared between consumers that differs. In the UK, costs are shared relatively equally between domestic, business and industrial users whereas in Germany, France and Italy industry is cross-subsidised by smaller consumers.”
“This is one example of what the report calls a more “activist” approach to industrial policy on the continent. Another example is the French “Exeltium” consortium, a large group of industrial firms that negotiated a cheaper fixed-price, long-term electricity supply contract with French utility EDF. This sort of arrangement would be “incompatible” with the UK’s historic approach to promoting competition between industries, the report notes.”
“Besides these factors, it is in wholesale electricity prices where the largest and most obvious differences lie. These can be explained by the makeup of countries’ electricity mix and the past policy and investment decisions they stem from.”
“Germany is more reliant on coal, for which prices fell sooner after 2012 than for gas. Part of its fleet uses lignite, a low-quality high-emissions coal that is cheap. In contrast, the UK and Italy are reliant on international gas markets.”
“Germany has also benefited from the merit-order effect, whereby renewables cut wholesale prices by pushing the most expensive generators out of the system…. This cut German wholesale prices by €14-16 per megawatt hour (MWh) in 2016, the report says, with a similar saving in Italy, against a lower €7/MWh effect in the UK.”
“For France, the wholesale price is low because it relies on nuclear plants built decades ago. The country also benefits, as does Germany, from being closely connected to the grids of neighbouring countries, whereas the UK and Italy are less integrated.”
“This explains one of the report’s recommendations, which is that the UK should continue to expand its interconnection capacity as planned, despite planning to leave the EU. This should help prices converge between the UK and the continent, as long as the UK maintains access to the EU’s internal energy market. (This remains a big if).
“The other key recommendation of the report is for the UK to unlock investment in renewables, since this is now the cheapest way to generate electricity. New onshore windfarms, for example, could deliver electricity below current UK wholesale prices, if industry were to embrace them.”
“The government should also consider a more ambitious reform, whereby standardised power purchase agreements for renewables are bought and sold by industrial users in a “green power pool” that shares the system costs of backing up variable wind output. Firms buying into this pool could get reduced rates by offering flexible demand to match variable supply. They would also avoid paying the rising carbon price, which would only be applied to trades on the wholesale electricity market.”
“Finally, the government could facilitate industry directly buying cheaper continental electricity via interconnectors, similar to systems already in place in Italy and California.”
There is, however, a silver lining for UK industry, notes the report. Germany will have to start phasing out is old coal power industry and France will be faced with the high costs of closing, or extending the life of its old nuclear power stations.
Not that Labour leader Jeremy Corbyn wants to wait for that. In a speech on 10 February, he called for the nationalization of the energy sector “to deliver the transition to a low-carbon economy and help prevent climate change”.
It’s a prospect Brussels would no doubt have tried to block. With Brexit, it becomes a real possibility.