Electricity Market Reform: what was missing?

The UK government's draft Energy Bill was introduced into the House of Commons on November 29 to a predictably mixed reception. Included as expected are CfDs, carbon price support, an emissions performance standard (EPS), and a capacity mechanism. The single, government owned counterparty to pay out the CfDs, along with the announcement of an increase in the Levy Control Framework (LCF) funding will in particular be considered in a positive light by low carbon investors.

But what was missing?

Apart from demand-side reduction measures, which the government has decided it needs to (at last) consult on, there is no de-carbonization target. This is the most noticeable omission in the bill, and has raised the most reaction. On one hand, the absence of a target is likely to have a negative impact on investor confidence, and on the other hand, confidence will be buoyed by the explicit increase of the LCF cap.

A large portion of the trebled levy cap could go to renewable generation as opposed to new nuclear, which is already facing final investment decision delays in Somerset.  This is the crux of the problem, which should be of vital concern to electricity consumers. The increase in bills is highly uncertain and will depend on the amount of gas in the energy mix and how much energy efficiency can be realized. 

2016 will indeed be a crucial time for low carbon power. The main question that secondary legislation and debate should clear up is how much of the funding will be allocated to wind projects that will operate well beyond 2030, and how much will go to nuclear projects that will not be online before 2020.

In the absence of a de-carbonization target, the debate and secondary legislation must reassure low-carbon investors that funding and support will continue past 2020 through to 2030, avoiding any fears of asset stranding should renewables targets be met before 2020.  

The thirst for precise details will remain during the course of 2013, and will be critical to complete the picture so that the goal of low carbon, cost effective, and secure electricity remains plausible.  At present, only the last goal will be met effectively. 

Further analysis is provided on the EMR on Datamonitor’s Knowledge Centre. 

http://www.datamonitor.com/kc/utilities/

Written by Yasmin Valji

Analyst in Datamonitor's Energy Team

Follow Yasmin on Twitter: @YasminV_DMEN 

If you have any questions or comments, please leave them below and the author will respond to you as soon as possible.

Want to know how to improve utility B2B customer satisfaction? Read on...

Datamonitor's Energy Buyer Research has found that utility customers have complex needs that extend well beyond receiving a low price from their supplier. In fact, customers that thought their supplier had the lowest price reported significantly reduced satisfaction scores than customers that felt their supplier tended to their separate procurement, billing, or account management needs. 

Datamonitor's Energy Buyer Research was conducted between April and August 2012 and involved the individuals responsible for buying gas or power in over 750 businesses across the UK. These were split into small- and medium-sized enterprises (SMEs) and major energy users (MEUs), with a spending threshold of £50,000 per annum separating them. 

SME customers that thought their supplier offered them the lowest price available reported a procurement satisfaction score that was 0.1 rating points below the market average, showing that customers do not respond well to a supplier that offers a low price but neglects to support the customer throughout the contract's duration. MEU customers that thought their supplier offered the lowest price behaved very similarly, giving a procurement satisfaction score that was almost half a rating point lower than the best performing strategy.

To improve SME customer satisfaction the most, it is clear that customers require speed from their supplier. Providing fast query resolution in the procurement and account management processes had the highest customer satisfaction scores. In terms of billing, SME customers reported the highest customer satisfaction when their queries about bills were resolved quickly. This is because smaller customers do not generally have the resources (in terms of personnel or time) to rectify errors or chase resolutions to queries, and thus rely more on support from their supplier.

MEU customers require something slightly different from their suppliers to increase satisfaction scores. The provision of a flexible product gave the highest procurement satisfaction rating, as MEU customers call for products that are adapted to fit their usage profiles, which are likely to change. Online access to bills/usage produced the customers that were most satisfied with their utility's billing process, allowing realtime tracking of costs to effectively manage cash flow. 

In addition, MEU customers that believed they had a personal relationship with their supplier had the highest account management satisfaction scores. A personal relationship is defined as having a single point of contact (a dedicated account manager) that is knowledgeable about their client and takes a proactive rather than a reactive approach to service. This can be a complicated strategy to employ, as staff need to have higher levels of training and dedication to perform a more specialist and niche role, but the benefits to satisfaction and customer retention are significant for larger (and probably higher margin) customers.

Although it is clear what the most effective strategies are in terms of increasing customer satisfaction, these do not take into account the cost of implementing each strategy. To draw a conclusion of which strategies are the most effective in terms of ratings from customers and cost to implement (both in terms of financial cost and resource cost), Datamonitor has applied a rating between zero and one. A rating of zero to implement a strategy indicates that it is very low cost, while a rating of one indicates it is very high cost. When compared to how high above the market average score for satisfaction the strategy is using a dual axis graph, it highlights which is the most effective strategy overall.

For SME customers, having internal processes to allow fast query resolution for SME customers produces customer satisfaction furthest above the market average; however, it is the fourth most expensive strategy to implement, requiring greater staffing levels, robust communication channels, and a host of extra services available to customers (such as maintenance teams) at short notice. On the other hand, these systems can also be used to answer queries effectively in the procurement process, which also gives a score well above the procurement market average, offsetting the cost required to focus on this strategy.

As discussed, for MEU customers, the most effective strategy in terms of the biggest increase in relation to the market is encouraging a personal relationship with customers during the account management process; however, this is relatively expensive with a rating of 0.6 given the extra staff required and the training needed to make sure key account managers are knowledgeable about their customers. In terms of the most effective strategy for the lowest cost to implement, this was again providing a fast response time to account management queries. This makes it a very effective strategy to implement for suppliers that have a broad customer base as it can be utilised for both SME and MEU customers, further offsetting the cost implications. 

Written by Tom Haddon
Analyst within Datamonitor's Energy Team
Follow Tom on Twitter: @TomH_DMEN

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UK Electricity Market Reform: a political compromise

The UK government's forthcoming draft Energy Bill is eagerly awaited by utility companies, investors, and consumers alike. An initial glimpse into the Electricity Market Reform has been given by the Energy Secretary Ed Davey, revealing a pragmatic and temporary solution to the UK’s energy challenges.

The rationale for the Electricity Market Reform (EMR) is to ensure sufficient scale and pace of investment in low-carbon generation, adequate security of electricity supply, and affordable energy costs for customers: what could be termed the sacred energy trinity.

EMR comprises a four-part package of CfDs, carbon price support, emissions performance standards, and a capacity mechanism.

Ahead of next week’s formal publication of the Bill Ed Davey confirmed on November 22 the provision of a cap under the Levy Control Framework (LCF) and the absence of a decarbonisation target for the electricity sector. Both have direct implications for low carbon investment in the UK over the next 20 years:

•            The LCF provides support for low carbon renewable generation. The Treasury has agreed on a cap of £7.6 bn (in real 2012 prices) and £9.8 bn (nominal 2020 prices) up to the 2020/21 financial year that can be passed onto consumers through the existing renewable energy levy part of their bills. As a point of reference this is a three-fold increase on the current subsidy cap for low carbon electricity for the 2012-13 financial year of GBP2.35 bn. The government estimate of the actual increase in the average household energy bill is GBP95 by 2020 (GBP20 in 2012), but Datamonitor notes that this estimate would be higher if it included the 20% over-run allowance permitted under the LCF and if the government’s suggestions for single tariff reform are realized.

•       The widely discussed 2030 decarbonisation target for the power sector will be absent from the bill. However, the bill will provide for a target range to be set in 2016.

In addition, and slightly overshadowed by the previous two points, is the fact that the bill will follow the recommendation of the Energy and Climate Committee and will establish a government-owned private company to act as the single counterparty body under the CfDs. Further, the government confirmed that it will action a capacity market, which may see auctions for capacity held from 2014 to cover peak demand in the winter of 2018/19.

From the low-carbon generators’ viewpoint, on the one hand the LCF is a positive announcement as it provides certainty as to the level of support that will be available. Similarly, the announcement of counterparty under CfDs that will mean enforceability of contracts will also provide reassurance to investors considering entering into CfDs – and it would mean that the government will not be directly liable for compensating generators.

However, on the other hand, the decision to postpone setting a de-carbonisation target sends clear signal to low-carbon generators – nuclear and wind alike – that the government considers new gas-fired generation to be part of the UK’s future energy landscape.

The Committee on Climate Change (CCC) summed the issue up when it said that the lack of a carbon target will leave “a high degree of uncertainty for investors and does not address widespread investor concerns raised in recent months”. 

Gas-fired generation investors, however, will feel reassured, but will wait for the government’s Gas Generation Strategy to be published in December to understand in more detail how the government plans to integrate gas with low-carbon generation by approving new gas-fired plants. Also of note for anyone interested in energy security is the extent to which the strategy will address the controversial issue of fracking.

The government has stated that the bill will “provide certainty to investors in all generation technologies and provide protection to consumers”. The government also aims to achieve a target of 15 per cent of electricity generated from renewables by 2020.

Datamonitor does not believe this last goal will be realised. The carbon price is still too low (a clearing price of 6.62 euro was realised in the UK’s latest EU ETS allowances) to stimulate investment in low-carbon generation.  Although it is true that the bill has the potential to help the UK to increase its share in renewables, it will not allow it to achieve its renewable targets – a de-carbonisation target arguably would have. 

Further, legally binding carbon reduction goals remain. The CCC has set the levels for carbon budgets from 2008 – 2022, advising reducing  emissions of all greenhouse gases by at least 34% by 2020 (relative to 1990). These targets are potentially incompatible with a substantial increase in gas-fired generation should renewable investment be lacking.

Clearly Prime Minister David Cameron is leaving the possibility open in 2016 to treat carbon reduction goals with pragmatism, elevating the UK’s energy competitiveness ahead of environmental concerns.

The elephant in the room is the lack of consideration for demand side reduction. Improving energy efficiency, increasing the use of renewable heat, insulation, and electric vehicles are just a few of the ideas that have been recommended to the government.

In summary, in the next few months there will be a thirst for more detail to give investors certainty. Low carbon generators will be somewhat reassured by this glimpse at the Bill, but will be desperate to know what price will be decided on and how much latitude the government will give to new gas generation in 2016.

Consumers will see their bills rise whatever does, or does not happen. The Bill is the result of heated political negotiation within the coalition government and the compromise that has emerged can be summed up as “more clean energy yes, but not too much, and not at any cost”.

The sacred energy trinity will not be achieved by the Bill – however it is a useful compromise in view of the inherent problems of coalition government. The future energy generation mix must be one that is balanced across the range of fuels to achieve energy security at a reasonable cost. This will certainly be at the expense of carbon reduction targets, but the political reality is that carbon reduction targets are the most adjustable part of the equation in voter’s minds.

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.

Ofgem: domestic proposals aim for engagement

Ofgem has launched a consultation on the revised Retail Market Review proposals for the domestic market, updating those put forward 12 months ago. This is a timely move given the recent wave of price rises from UK suppliers, but Datamonitor believes Ofgem should educate consumers about market dynamics and set realistic expectations, rather than calling for simpler tariffs and so curbing innovation.

The changes to the Retail Market Review (RMR) address outstanding concerns related to consumer engagement with the energy market, with a focus on requiring suppliers to give customers: "simpler choices; clearer information about products, prices and available savings; and fairer treatment."

The proposals are twofold: driving transparency and reducing suppliers' ability to make excess profits from disengaged and so-called "sticky" customers. Ofgem has also made the proposals more serious by reserving the option of calling in the Competition Commission for a Market Investigation Reference.

The review calls for simpler tariffs, which Datamonitor believes is unwise: simpler tariffs will reduce consumer appetite for tariff innovation, an important element in the success of a future large-scale smart meter roll out in the UK. Indeed, the roll out will require nuanced tariffs designed to influence customer behavior and ensure the benefits that smart meters promise.

The measures also include limiting suppliers to four tariffs per fuel, meter, and payment type; the end of multi-tier tariffs in favor of a standing charge and unit rate; and personalized information on bills regarding potential savings if the customer switched to a competitor's cheapest tariff. In addition, Ofgem is putting forward Tariff Comparison Rates to allow market-wide comparison, an improved Annual Statement complete with personalized information arming the consumer for engagement in the market, and the requirement to treat customers fairly.

One of the most common observations when retail prices rise is the disconnect between profits from retail accounts and group profits reported by suppliers. Retail margins are modest - usually around 4% - whereas overall profits are significant, often driven by profits from upstream business units. Suppliers' wholesale businesses benefit from the difference between going market rates and their cost of supply, achieved wherever a supplier has a portfolio of well-managed and well-hedged power stations and gas fields.

But profitable upstream supply is not always guaranteed (as anyone with a combined cycle gas-fired generator facing negligible or negative spark spreads will attest), and utilities are still obligated to deliver value to shareholders and invest in power stations and gas fields to ensure ongoing security of supply.

Additionally, any argument for a supplier offering a cheaper retail rate given its level of supply-side profit is effectively an argument for cross-subsidy between business units, which could be construed as loss-leading and anti-competitive, as it would disadvantage smaller suppliers without their physical assets to act as a hedging strategy.

Recent allegations about improper NBP trades by whistle blower Seth Freedman will not help suppliers, even though there is currently no evidence that UK retail suppliers were involved in any way. Whatever the outcome of FSA and Ofgem investigations into this issue, and whatever the size of the material impact on end consumers, this will remain a consumer relations headache. Indeed, many consumers may form the impression that wholesale costs themselves are unreliable, and therefore every effort must be made to highlight the reliability and improve the perception of suppliers' wholesale market operations.

While there are no direct measures that can effectively address the issue of suppliers' group-wide profits, communication and consumer education about market dynamics and setting realistic expectations for consumers would be a much better starting point than holding back tariff innovation. Datamonitor believes that the biggest risk with Ofgem's proposals is creating unrealistic expectations that the proposals will be able to apply any material downward pressure on prices.

Written by Rhys Kealley

Lead analyst in Datamonitor's Energy team

Follow Rhys on Twitter: @RhysKealley

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

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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

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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

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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

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The Case for a Pan-European Energy Regulator

In a keynote speech at the Financial Times Global Energy Leaders Summit 2012 held in London the chairman of Iberdrola, Ignacio Galan, called for the creation of a single regulator for the European energy sector. 

The speech rightly highlighted the barriers to a single European energy market. He noted a range of diverging energy policies, and underlined the damage to investment and inter-European competition from unstable regulatory frameworks and barriers to entry respectively.  Datamonitor sees two sets of issues in creating a single EU energy market, the structural or physical infrastructure, and the virtual or policy/regulatory infrastructure needed to integrate the national markets and allow energy companies to compete outside their home market. Both require the regulatory powers of a single regulator that transcends national borders. 

Recent analysis by Datamonitor largely supports Mr Galan’s comments. Many European utilities have identified the problem of insufficient investment in grids and interconnectors and barriers to entry to other markets, all of which prevent the creation of a single EU energy market. The barriers are such that Datamonitor considers a single regulator to be the most expedient way to accelerate progress in harmonising the markets. 

Where cross border projects are concerned a super regulator is clearly required. A common strategy, network codes, and oversight of those codes are needed, which is best implemented at an EU level. In particular, a regulator could ensure that utilities can access cross border capacity and ensure transparency in interconnection trading. In the absence of transparent and fair cross border regulation, it is likely that investment in interconnection capacity will remain insufficient. 

For an efficient EU energy market, the physical infrastructure – interconnection capacity and effective grids - is integral. Yet such infrastructure is highly capital intensive, complex, and in particular, long term, and which therefore calls for planning to ensure the infrastructure is fit for purpose in the future.  At present there are bottlenecks in interconnection capacity in Continental markets making it difficult for companies to sell power to end users in neighbouring countries, as many national wholesale markets remain illiquid.  

Once the structural barriers are tackled, the second step for a central regulator is then to create the conditions to harmonise the virtual structure, including a myriad of tax laws, subsidies, renewable energy support mechanisms and market reform packages.  The regulatory and policy landscape in Europe is sufficiently complex and diverse that it requires a central regulator to gain sufficient strategic perspective and enforce compliance. A central regulator could hope to create the conditions for efficient inter European trade, ensure stability to encourage investment, and allow prices that reflect supply and demand.  It would therefore be a decisive step towards a common European energy market.

Written by Yasmin Valji
Analyst within Datamonitor's Energy & Utilities team.
Follow Yasmin on Twitter: @YasminV_DMEN

New Leader in Gas for Datamonitor's Energy Survey

Gazprom Energy’s Market Entry Continues to Sweep Away the Competition as it Tops Customer Satisfaction Rankings for Large Gas Users

Gazprom Energy entered the UK B2B gas market with the acquisition of Pennine Gas in 2006 and has gone on to become the second largest supplier in terms of volume, based on tailored service to some of the largest gas consumers in the UK. This has culminated with the supplier topping Datamonitor’s Energy Buyer Customer Satisfaction Survey for the first time, dislodging Dong Energy (formerly Shell Gas Direct).

While there may be questions about the success of competition in the UK residential energy market, as highlighted by the current focus of the Energy Select Committee, competition is heating up in the B2B energy market, with independent suppliers beyond the Big Six gaining market share on the back of competitive deals and high levels of customer service.

Significantly, Gazprom Energy top the table for major gas customers. Gazprom Energy’s market share has grown rapidly, now accounting for more than 14% of gas volume sold to B2B customers. Shell Gas Direct, acquired by Dong Energy in May 2012, held the top ranking since 2008, making it the most consistent providers of customer service in the market but the transition period has had an effect on what customers are experiencing from the supplier.

The independent suppliers in the energy market are performing extremely well in terms of growing market share and maintaining high levels of customer satisfaction. The agility of the independent suppliers in providing tailored service and efficiently handling customer queries is reaping tangible benefits which many of the Big Six simply cannot match.

This is further confirmed in the power market with Smartest Energy topping the rankings for large power users for the second survey running. With a relatively smaller number of large energy users, the supplier can harness its flexibility to provide innovative products and customer service initiatives to obtain a market leading customer satisfaction score.  However, not all the Big Six are suffering at the rise of independent suppliers in the market.

E.ON Energy’s ‘Reset Review’ - which is intended to refocus the company’s efforts into improving the customer experience - is having clear benefits, with the supplier steadily increasing its customer satisfaction score to sit 2nd in the rankings for SME customers.

It is another smaller supplier, Haven Power, which tops the SME category ahead of E.ON Energy making it clear that business customers value premium levels of customer service from smaller suppliers.  Although it may still be price that dictates a lot of a customer’s decision making, customer service is and will continue to be an incredibly important factor in a highly competitive and increasingly informed market place.

Written by Rhys Kealley
Lead Analyst in Datamonitor’s Energy Team
Follow Rhys on Twitter: @RhysKealley

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