Energy security is judged to be high in the UK – the lights will stay on

A recent Ofgem report prepared for the government suggested there was a high risk of a shortage of UK electricity capacity as early as 2015 under certain conditions, and with it the possibility of blackouts. However, a new index suggests that the UK is one of the most energy secure countries in the world.

The Ofgem report cited the possibility of lower electricity capacity margins in 2015 in light of older coal and oil power stations coming offline under the European Union (EU) Large Combustion Plant Directive. However, in a recent article "The lights will stay on in the UK" Datamonitor expressed the opinion that the actual likelihood of blackouts is slim. The possibility of such an outcome has simply been exaggerated by the media and those with an interest in receiving rapid approval for capacity construction in the short term.

The low risk of electricity blackouts is reinforced by impartial analysis from outside of Europe. An offshoot of sorts from the US Energy Security Risk Index, the first edition of the International Index of Energy Security Risk ranks 25 developed and emerging countries according to 28 metrics. The quantitative index - which covers 1980-2010 and focuses on larger energy users - was put together by the US Chamber of Commerce Institute for 21st Century Energy.

In general, countries with large energy resource bases and efficient economies enjoy the greatest comparative energy security in the index. Metrics included the resources available for a wide range of fuel supplies, the amount of fuel imports, environmental emissions, energy intensity, price volatility, consumption levels, reliability of generation, and geopolitical risk to name a few.

The index underlines the fact that energy policies matter greatly, as they influence energy efficiency, technology development, and how resources are built or used. Despite its shortcomings - for example, each metric was assigned a weight aligned with that in the US index - it does provide insight into the opportunities and options that a government must consider to maintain or increase its energy security.

Anyone having read the press of late may be surprised to see that the UK was ranked the second most energy secure country in the whole group, making it the most secure European nation. Not only does the UK have a relatively stable political environment, but its high score (and thus low energy security risk) is due to the fact that it still has relatively high quantities of oil, gas, and to a lesser extent coal relative to its EU neighbors. Only Norway has more crude oil than the UK, and only Norway and the Netherlands have more gas.

                                Source: International Index of Energy security risk 2012

However, year-on-year change shows that the UK's security risk has been increasing since the early 2000s, at a rate comparable with the rate change of the Organisation for Economic Co-operation and Development average.

This higher risk in the UK is due to the larger amount of fuel imports, especially oil and natural gas. Future risks will stem from even higher expected import levels. In particular, gas imports will be a source of insecurity if the UK turns to gas-fired electricity generation as a backup source should new nuclear investment fail.

Even so, there is little cause for concern. On the basis of natural resources, the UK should remain one of the most secure countries if it can exploit new and existing oil and gas fields in the North Sea and its reserves of shale gas. The new brown field tax allowance approved by the government in September 2012 to encourage investment in older oil and gas fields in the North Sea indicates that the government has no qualms about maintaining energy security through hydrocarbon-based energy.

Looking at it from a resource viewpoint, lights in the UK will stay on. While Datamonitor acknowledges the danger of a simplistic resource-based view of energy security, it also points out that policy decisions - influenced by public opinion on prices, carbon emissions, and perceptions of safety - are just as important in understanding the UK's real energy security now and in the future.

Written by Yasmin Valji

Analyst in Datamonitor's Energy team

Follow Yasmin on Twitter: @YasminV_DMEN

Please leave comments or questions below. The author will respond to you as soon as possible.

Will the lights will stay on in the UK?

Reductions in high-carbon generation capacity in the United Kingdom raises power shortage concerns.

Ofgem’s first annual electricity capacity assessment report to the government has drawn attention to a high risk of a shortage of UK electricity capacity as early as 2015. In accordance with the EU large combustion plant directive (LCPD) 12 GW of coal and oil-fired capacity will come offline after reaching the allowed 20,000 hours of operation. In fact these coal plants have been operating for more hours than anticipated due to the relative cheapness of coal compared to gas, and, in theory, should close before the expected deadline of December 31, 2015. 

Ofgem’s chart shows the extent to which coal and oil capacity coming offline is expected to be replaced by gas, biomass and onshore wind. 

Contrary to alarmist reports of possible country-wide black outs Ofgem states that the capacity margin will simply be lower (14% to 4% in 2015/2016 in the base case). This means that the risk of some disconnections will be higher, up from near zero now, if demand happened to outstrip supply in the event of several factors happening at once. 

One of these factors is extreme winter weather: Ofgem’s estimated base case already assumes peak winter demand under normal winter weather. Another factor is if gas supplies from Norway completely dried up, say in the middle of winter, or if LNG imports were limited, or if an accident happened in one of the UK’s nuclear plants. Such things are clearly perilous to model, and Ofgem has sensibly refrained from quantifying some risks that would simply skew the results. 

That said, Ofgem’s estimates of capacity margins do acknowledge large uncertainty. The estimates consider sensitivities around mothballed gas fired plants coming back on line and imports from the continent. In a high scenario, the capacity margin would be about 9% in 2015/2016, however in a low case (full exports to the continent and no new gas builds or old gas plants in operation) the margin would be almost zero. So, if winter demand was unexpectedly high AND the price differential in Europe was such that the UK was exporting at full throttle to the continent, then some of the lights would go out. 

This is very unlikely in Ofgem’s estimates. In the base case scenario, the chance of disconnection of some customers is approximately 1 in 12 years. Even then, demand side measures (including disconnecting industrial customers first) would mean that there would be “little or no impact on (residential) customers”. 

While any blackouts are indeed very unlikely, what is more likely is a higher reliance on imported gas, which could translate into higher electricity prices. Although slightly more palatable than allowing Britons to walk around with candles, the policy response to the issues of securing and cost effectiveness will be keenly awaited in the upcoming Energy Bill.

Written by Yasmin Valji
Analyst in Datamonitor's Energy Team
Follow Yasmin on Twitter: @YasminV_DMEN

Comments and questions are welcome on this article. Please leave them in the box provided and the author will respond as soon as possible.

Germany shifts to coal to tackle its installed capacity shortfall

Angela Merkel shut down eight of Germany's 17 nuclear plants in 2011 in response to the Fukushima nuclear disaster, removing some 10% of Germany's installed capacity. It is not surprising that in light of this shortfall and the delays seen in grid investment, Germany must turn to coal- and gas-fired capacity.

In October Germany added coal-fired capacity to its generation mix, with Vattenfall increasing coal-fired capacity at the Boxberg R Plant in the state of Saxony by 675MW. However, this is tiny compared with the 12,696MW of nuclear capacity that is required to shut down by 2022.

Germany's Energiewende "energy switch" calls for a phase out of nuclear by 2022, using renewables to replace the lost capacity. New coal capacity in Germany is therefore surprising given the government's enthusiasm for pursuing low-carbon generation.  However, this change raises massive challenges with consequences for the country's energy security and the profits of its utility companies.  

Essentially, Germany is faced with the challenge of connecting the dots between the source of generation power - in particular from renewable offshore wind farms in the north of the country - to where electricity is demanded, such as to factories and businesses in the south and east.

The lines to join the dots - high voltage transmission lines, to be precise - are running behind schedule. Germany has 72 projects that have already started or should have started, representing some 5,400km of lines. A portion of these lines has been delayed due to public objections as well as bureaucratic delays, and a further 600km of lines that the four network companies (TenneT, Ampiron, 50Hertz, and TransnetBW) have agreed is necessary faces potential delay due to public consultation.

The lack of grid connectivity due to legal barriers is starting to dissuade investors. This has been seen most recently in Dong Energy’s decision to stop development of its offshore Borkum riffgrund 2 wind farm due to TenneT TSO delaying a contract for grid connection to Germany’s onshore grid.

Clearly, more gas and coal plants will need to be added to meet demand. Germany's network development plan forecasts almost the same amount of hard coal in 2023 as now, and only about 2% less brown coal compared with 2012. The main replacement of the lost nuclear capacity will be from solar and wind - but even if these are built, the lines still need to be there.

Coal's low cost is driving other countries to pursue this  generation. The UK looks set to burn up its quota of coal-fired generation capacity before 2015; meanwhile,

Datamonitor notes that countries on Europe's periphery that are exempt from European Union low carbon regulations are also pragmatic about adding coal to their mix. For example, Turkey is adding new coal-fired generation capacity. In August 2012 the state coal authority TKI opened a tender for the construction and operation of two coal fields, which is just the second of a line of tenders that will contribute to the new 17-18 GW of coal capacity desired by the government for 2023.

Written by Yasmin Valji

Analyst in Datamonitor's Energy Team

Follow Yasmin on Twitter: @YasminV_DMEN

Comments or questions are welcome on this article. Please leave these in the box provided and the author will respond to you as soon as possible. 

Strike price for nuclear still in negotiation - Energy and Climate Change Committee evidence session

The UK parliament’s Energy and Climate Change Committee heard evidence yesterday from representatives of the nuclear industry on the challenges of building new nuclear capacity in the UK.

A twitter message following the session was a pithy yet fairly accurate description of the bargaining relationship between EDF and the government: “How much is it?” EDF: “How much have you got?”

Indeed, EDF is currently negotiating with the government over the long term return on investment it will receive for the electricity generated from its planned new nuclear reactors at Hinkley Point (Somerset) and at Sizewell (East Anglia).

At the heart of the negotiations is the strike price, a guaranteed price per MWh of electricity generated that would be received by EDF. In the contracts for differences (CfDs) context, this means that if the price in the market falls below the strike price, then EDF would be paid the difference. 

The government is in a delicate position in its negotiations with EDF - it intends to have 16GW of new nuclear power in the UK by 2025. Without this there is a grave danger of failing to meet its EU agreed carbon reduction goals. However, the French utility is the sole company – under the name of its jointly owned subsidiary with Centrica, Lake Acquisitions – that intends to invest in the two sites, each with a capacity of 1.6GW. 

EDF’s CEO Vincent de Rivaz firmly refuted the Committee’s insinuation that EDF had inflated its expected costs to build the plants. Instead, he insisted that the ‘perverse incentive’ was not to inflate costs, but rather to have a transparent cost discovery process to show that nuclear energy is a competitive form of generation.

But over and above the price put on the table, Monsieur de Rivaz put it quite simply: EDF’s investment decision depends on the CfD price. Without this, there is no clarity, and EDF is relying on the government to be serious and provide such clarity. This is an issue of primary importance, as the ultimate cost to UK consumers will depend on the strike price for different types of low carbon technology agreed on in the forthcoming electricity market reform bill.  

At the evidence session the strike price for nuclear was repeatedly compared with the expected and desired long term cost for off shore wind at £100/MWh – as offshore wind would be the main renewable alternative in the absence of nuclear. Despite uncertainties as to what offshore wind will cost in the vicinity of 2020-2025, it was clear that nuclear is, and will be expected to be, competitive with respects to offshore wind, and its strike price may be capped at £100/MWh. 

Written by Yasmin Valji

Analyst, Datamonitor Energy & Utilities

Follow Yasmin on twitter: @YasminV_DMEN

Comments or questions on blog posts are welcome and the author will respond to you as soon as possible.

The ebbs and flows of UK power investment

The arrivals and departures of foreign investor interest in the UK’s nuclear industry are starting to resemble St Pancras International on a Friday evening. Three comings-and-goings are of note.

Firstly, the equivocation of the potential Chinese investors in the Horizon project (China Guangdong Nuclear Power Group and China's State Nuclear Power Technology Corp), who proved hesitant to the point of opting out of their respective international consortia. The Horizon project, being sold by RWE and E.ON, represents two new nuclear reactors comprising a total of 6 GW of new generation capacity for the United Kingdom. 

Secondly, the Russian state nuclear operator Rosatom was also rumoured to have registered interest in the Horizon bid. Altough it was not present among the final bids on September, 28, it has nevertheless stated that it is still considering investing in nuclear in the UK, either in Horizon or by taking a stake in EDF’s share of the Lake Acquisitions project, which includes a new nuclear station at Hinkley Point in Somerset. Rosatom’s interest is pan-European, as it is currently a bidder in a contract to expand the Temelin Czech nuclear power plant along with Westinghouse.

Lastly, there is also uncertainty surrounding NuGen, the nuclear company owned by Iberdrola and GDF SUEZ, which plans to build up to 3.6 GW of new capacity in the north west of England.  While there are rumours of Iberdrola’s intentions to withdraw from the NuGen partnership, the Iberdrola chairman Ignacio Galán confirmed last week at the Scottish Low Carbon Investment Conference the company’s commitment to the UK and investing in electric power transmission and onshore and offshore renewable energy. The nature of the conference may have precluded him from explicitly referencing the company’s commitment to NuGen, however his speech will no doubt allay the NuGen withdrawal rumours. 

These demonstrations of investor uncertainty should be of concern to the government. In addition to comments like the one made by Mr Galan in his speech regarding regulatory issues that needed to be addressed (including the electricity market reform) in order to create a favourable investment atmosphere for investors, two letters were sent to the Secretary of State for Energy and Climate Change, Ed Davey. The letters called for a clear 2030 decarbonisation target and expressed fears over the potential damage that would be done to the UK’s reputation as a country with low political risk if a long-term, stable policy framework is not put in place. 

One of the letters is from a group of seven key players in the UK energy industry, including Siemens, Alstom UK, Mitsubishi Power Systems, Areva, Doosan, Gamesa and Vestas, which represent future investment in new nuclear, renewables and gas generation. That such a range of companies feel threatened by the opacity of future energy policy should hopefully inspire more transparency in the UK government’s upcoming Energy Bill. 

Written by Yasmin Valji

Analyst, Datamonitor Energy & Utilities

Follow Yasmin on twitter: @YasminV_DMEN

Comments or questions on blog posts are welcome and the author will respond to you as soon as possible.

UK: Horizon nuclear joint venture reduced to two bidders

The French-Chinese consortium led by Areva in partnership with China Guangdong Nuclear Power Group has withdrawn from the bid to take over two nuclear sites in the UK owned by Horizon Nuclear Power. While no official statement has been made as to the reason for the withdrawal, insufficient electricity market reform in the UK may have been a contributor to the decision.

The deadline for bids to take over the Horizon nuclear joint venture - September 28, 2012 - came and went with just two of the three consortia still in the race.  At stake is the Horizon project, which includes plans to build 6GW of capacity at two nuclear power stations at Wylfa on Anglesey (Wales) and Oldbury (Gloucestershire).  Horizon owns the two nuclear sites but the German partners in the joint venture, E.ON and RWE, pulled out in March 2012.

The consortium that has opted out is French-Chinese, led by French Areva and the China Guangdong Nuclear Power Group (CGNPC). The consortium had signaled its interest in making a bid in July 2012. No official commentary has been issued by Areva to explain the withdrawal but press reports indicated that it was due to a lack of backing from CGNPC. However, Areva and CGNPC know each other well and have worked closely together in the past, with Areva having built new generation European Pressurized Reactors for CGNPC in Taishan, southwest China.

The two remaining consortia include one led by the US firm Westinghouse (owned by Toshiba), and a Japanese consortium led by Hitachi in partnership with the Canadian company SNC-Lavalin.

Other bidders were rumored to have been interested in Horizon, including the Russian nuclear conglomerate Rosatom; however, the withdrawal of Areva is a big blow to the UK government as the bid was perceived to be serious. Of note is the absence now of Chinese investors in the Horizon bid: CGNPC was part of the Areva consortium and China's State Nuclear Baoti Zirconium was part of the Westinghouse/Toshiba bid.

Thus Areva's withdrawal from the Horizon bid is more significant than it initially appeared. It is a signal that foreign investors, in this case major Chinese investors, perceive the risk/return ratio in nuclear generation in the UK to be unfavorable enough to cause them to "wait and see."

The government has estimated that GBP110bn of investment is required for electricity generation, but the Horizon bid begs the question that if the Chinese are not interested, who will be able to make such large commitments in a relatively capital-constrained market?  Fortunately for the UK, Japan, like Germany, has eschewed nuclear generation, meaning that firms like Hitachi and Toshiba need new export markets for their nuclear technology.

The Areva withdrawal is a signal to the government that the instruments in its electricity market reform are insufficient to inspire investor confidence in low-carbon generation. In particular, the price that will be received by generators in low-carbon generation under the feed-in tariffs with Contracts for Differences is clearly a crucial element and one that will need to be transparent when the Energy Bill is introduced into the UK parliament in the autumn.

The decision on the Horizon bid is expected in early November. If all goes to plan, the two sites could be operational by 2022-23.

Written by Yasmin Valji

Analyst in Datamonitor's Energy team

Follow Yasmin on twitter: @YasminV_DMEN

Comments or questions on blog posts are welcome and the author will respond to you as soon as possible.