British hydrocarbon provinces. Source: DECC. Click to enlarge

After an 18-month hiatus, the Department of Energy and Climate Change has given the green light to resume shale gas exploratory ‘fracking’. Tim Probert explores the next steps towards the UK’s ambition to create a shale gas revolution. This article was first published in the February 2013 issue of Materials World.

There has been no end of hyperbole about shale gas in the UK over the past two years. But for all the wildly varying talk about the potential riches or environmental damage from shale gas, hydraulic fracturing (fracking) has been on ice since Lichfield-based Cuadrilla Resources was found to have caused two relatively large earth tremors in Lancashire of 1.5 and 2.3 magnitude in April and May 2011 respectively.

After an 18-month hiatus, the Department of Energy and Climate Change (DECC) finally gave the green light to resume exploratory fracking last December. Given the large gas-in-place resource estimates in UK shale basins and the potential for Her Majesty’s Treasury to accrue many billions of pounds in tax revenue the decision was never really in doubt.

Regulations

DECC has laid down some tough new regulations for exploration, primarily aimed at mitigating induced seismicity. Analysis carried out by Cuadrilla, and confirmed by DECC, concluded the cause of the tremors was the movement of the frack fluid into and along a fault which was already under stress. The additional pressure of the fluid caused the fault to move, resulting in the tremors.

DECC says many other faults in the Lancashire area have similarly unrelieved stresses, and could in a similar scenario likewise resulting in tremors. Shale gas drillers must, therefore, take a more cautious approach to the duration and volumes of fluid used. Fracking will also be subject to a “traffic-light” regime, so that operations can be quickly paused and data reviewed if an unusual level of seismic activity is observed.

DECC took a dim view of Cuadrilla’s response to the tremors, saying the company “demonstrated some weaknesses in its management of environmental risks”. In other words, the drilling team did not tell the Cuadrilla board about the incidents quite as swiftly as it should have done.

So DECC has imposed a strict regime for Cuadrilla’s exploration programme in Lancashire, setting the remedial action level for the traffic light system will be set at magnitude 0.5. This is seen as a conservative level as it far below a perceptible surface event, although larger than the expected level generated by fracking.

In order to simplify and streamline the regulatory process and to provide single point of contact for investors, DECC will create the Office for Unconventional Gas and Oil, working with the Department of the Environment and Rural Affairs (Defra) and other government departments.

Regulation of activities associated with shale gas exploration, such as groundwater protection and well integrity, will remain the relevant responsibilities of the Environment Agency and the HSE. Meanwhile, HM Treasury will announce a targeted tax regime for the shale gas industry at Budget 2013 on 20 March.

Cuadrilla activities to date

So far Cuadrilla has drilled three shale gas wells in Lancashire and has completed a 3D seismic survey of over 100 square kilometres of its 1,200 square kilometres license area known as PEDL165 in West Lancashire. As is well known, Cuadrilla has announced an extremely large gas-in-place resource estimate for PEDL165: 200 trillion cubic feet, equal to more than 60 years of supply.

Cuadrilla is understandably keen to establish gas flowback rates and recoverability factors as soon as possible. The company says it expects to restart fracking in the first half of 2013 upon receiving planning approval from Lancashire County Council.

If all goes to plan then Cuadrilla will seek to frack at least three wells in the initial exploratory stage. While the Preese Hall site in Wheeton near Blackpool has been plugged to avoid a repeat of the unfortunate earth tremors incidents in 2011, Cuadrilla will conduct intensive fracking at the Anna’s Road site in Westby near Lytham St. Annes, the Grange Hill site in Singleton near Poulton-le-Fylde and the Becconsall site in Banks near Southport.

The Anna’s Road site is seen as a crucial well for Cuadrilla. Starting from a vertical well, at over a mile beneath the surface, an extension will gradually ‘arc’ into a horizontal path. The well will be 8.5 inches in diameter and the 12-stage horizontal frack will extend 1,400 metres from the site to the west.

From this and Cuadrilla’s other exploratory wells, the company intends to produce gas, to be burned in an on-site generator to produce electricity, for one year to determine how much gas can be produced and how fast gas production declines.  At this point, Cuadrilla would approach DECC, if flow rates are sufficiently promising, notifying its intention to proceed to production stage.

As a pre-cursor to full-blown production, Cuadrilla is expected to drill approximately 20 wells from single-site ‘pads’, from which operators can move a drilling rig in order to drill several wells from the same site without the disruption of dismantling and re-erecting the rig each time. These wells, roughly two miles vertically and three miles horizontally, would be drilled over a larger area across Cuadrilla’s PEDL165 license area.

Again, these wells would be operated for a year to ascertain flow rate and recoverability.  At this stage, end-2014 or 2015, Cuadrilla would enter full-blown production. This would entail the development of a further 800-1,200 wells from around 100-120 pads spread over a 50 square miles area between Cleavleys to the north of Blackpool, Kirkham towards Preston and Lytham St Annes.

Exploring and developing shale gas plays will not come cheaply. Cuadrilla says well drilling costs are £20,000 per half-day, with an exploration well costing £10.5 million each, falling to £9 million in commercial extraction. At the time of writing, Cuadrilla was reportedly in negotiations with Centrica (owners of British Gas), ExxonMobil, BP and Shell to sell a stake in their shale gas assets.

Cuadrilla not the only show in town

UK shale gas exploration does not start and finish with Cuadrilla Resources. UK firm IGas Energy says test results indicate more than 9 trillion cubic feet of shale gas in place at its sites in Ince Marshes near Chester and Doe Green in Warrington and is evaluating possible drilling.

Eden Energy is a 50% partner of Bridgend-based Coastal Oil and Gas Limited with exploration licenses across South Wales from Cowbridge to Pontypridd, Neath, Port Talbot and Swansea. Eden Energy reports its seven licences in South Wales have gas-in-place resources of 34 trillion cubic feet.

In Scotland, Dart Energy intends to develop its Airth sites, estimated to contain 0.7 trillion cubic feet, near Stirling in Clackmannanshire. Dart Energy also holds several exploratory licenses for the Cheshire Basin and Gainsborough Trough in northwest England. Several more companies are expected to prospect for shale gas when DECC finally completes its 14^th licensing round for onshore oil and gas exploration.

Dart Energy’s acreage. Click to enlarge

Developing shale gas plays

In general, UK shale basins tend to be very different from the United States, they are much smaller and the geology is more complicated. Many of the US basins are intra-cratonic, which tends to form in geologically stable regions with relatively small amounts of faulting and deformation of the Earth’s crust.

By contrast, as in the geological past the UK was situated close to the boundary of several tectonic plates, many of the UK shale basins have undergone much more deformation. That means buried faults are contained within the basins that cut through and offset the shale deposits.

The good news is that the sequences of shale are very thick, and that is undoubtedly beneficial in a country like the UK with a high population density sensitive to developments. Yet the thickness of the shale could be a doubled-edged sword. The gas ‘pay zone’ is much deeper than the United States shale plays and therefore it may be more dispersed and more difficult to extract.

What is certain is that there will be ‘good’ shales and ‘bad’ shales with a huge amount of variability within them, as Dr. Nick Riley, the British Geological Survey’s (BGS) Team Leader for Unconventional Gas explains. “There’s a lot of single depositional tectonics going on,” he says.

“So not only do you have over-printing of faults between the late-Carboniferous and post-Carboniferous periods, you’ve got active faulting during the Carboniferous period and that is controlling a lot of the quality of the shale, the thickness of the shale. Plus at certain times of the Carboniferous period the sea level goes up and down as polar ice caps waxed and waned, which changes the organic nature of the shale.”

As yet there is no exploration data in the public domain appraising whether the ‘good’ shales have ‘sweetspots’ of shale gas all the way through. Geologists can, however, conduct burial history analysis to determine how quickly and steeply sediments were buried at the time they were originally deposited in order to make pressure estimates ahead of drilling any wells.

Dr Jonny Imber, a Durham Energy Institute structural geologist, says brittle layers of rock are preferable for extracting hydrocarbons from shale. “The hydraulic fractures will propagate more easily, and will remain open easily, within very brittle layers,” he says. “They tend to be layers which contain quartz and calcites.”

Shale gas companies look at the stratigraphy by extracting cores of rock to analyse the layers. “But the well is like putting a pinprick in a very large cushion, you don’t know what’s going on laterally. The key challenge is to try and work out how the geology varies as you move around the compass positions away from the well.

“Shale gas production often relies on natural fracture systems within the shales and a well is essentially a one-dimensional sample through a three-dimensional rock volume. It can be difficult to understand the geometry of the natural fractures just by looking at a single well.

“They can use seismic reflection data to produce a seismic survey over an area of interest, but the resolution of the seismic data is probably only around 30 metres vertically. It will give you a broad overview of the structure and the different layers but it won’t to get you anywhere near enough information,” adds Imber.

Even when ‘sweetspots’ are located, extracting hydrocarbons from shale is not straightforward, says the BGS’s Riley. “In places producing shale gas they can drill wells very close to each other in the same layer where one well will flow and the other will not. Also, one horizontal leg may not flow and they don’t know why. There is still a lot to learn.”

In the end, it will be case of suck it and see. Graham Tiley, Shell’s general manager for an unconventional venture in Ukraine, expects disappointments. “That is why it is called exploration,” he says. “We drilled three shale gas wells in southern Sweden and did not find the gas content in the shale and exited that project.

“At the end of the day, if you have drilled your 1,000 wells, the question is does the average recovery per well exceed your economic threshold. Some wells will come in lower. A few wells will hopefully come in much higher. But the absolute critical factor is your average recovery per well.”

Thickness and depth of UK shale plays. Source: Royal Society, ‘Shale Gas Extraction in the UK – A Review of Hydraulic Fracturing’, June 2012. Click to enlarge

Gaining public confidence in shale gas

Almost all energy developments attract controversy but shale gas has proven particularly hyperbolic. Much of the screeching from opponents to shale gas is overblown, yet there is no doubt that poorly-constructed wells could result in extensive groundwater pollution as has occurred in the United States.

In its report, ‘Shale gas extraction in the UK: A review of hydraulic fracturing’, the Royal Society said well integrity is the highest priority to practice safe fracking. Dougal Goodman, Chief Executive of The Foundation for Science and Technology and member of the Royal Society’s shale gas extraction working group, says monitoring should be carried out before, during and after shale gas operations to detect methane and other contaminants in groundwater and potential leakages of methane and other gases into the atmosphere.

“In the US there have been casing failures and with a very large number of wells drilled this is perhaps to be expected,” he says. “ In the UK the well design has to be reviewed by a third-party independent examiner, but we recommend that this independent examiner should also make on-site visits rather than merely review the paperwork for the design, drilling and completion stages.”

The HSE appears to have heeded the Royal Society’s advice. Steve Walker, Head of HSE’s Offshore Division says it will engage with the onshore drilling industry in order to gain public trust in shale gas. “One of the issues raised by the Royal Society was not so much concern about well integrity but public confidence in well integrity.

“The industry is also concerned about ‘cowboy frackers’ cutting corners to cut costs. So the industry is saying it will go above statutory requirements. [Shale gas developers] say ‘We not need to the well examiner to do ‘x’ but we will make sure they do it in order to get that extra public assurance’”.

Cuadrilla operates an ‘open house’ policy on its activities, says Chief Operating Officer Eric Vaughan. “We have given hundreds of residents, MPs and councillors tours of our fracking sites and we have a full-time visitor cabin when we are drilling so people can come and see what we do,” he says.

Yet the company has not covered itself in glory in recent years. Aside from the earth tremors, hugely damaging in a public relations sense, Cuadrilla was forced to abandon last November a borehole at the Anna’s Road site after a ‘packer’ – testing equipment used to investigate a cement failure – was lost and became jammed 2000 feet below the surface.

Incidents such as these do nothing to assuage fears that shale gas is not safe. “There is no love for shale gas in the UK”, says Simon Whitehead, managing director of energy PR firm Hill and Knowlton. “There needs to be an industry-wide, offensive campaign with a fresh new narrative giving more of a brand feel to shale gas developments. Fracking needs a re-brand, perhaps with a ‘kitemark’ for safe developers.”

Shale gas drilling rig. Source: Cuadrilla Resources

Developing community benefits from shale gas

Yet this may still not be enough to ensure shale gas operations go ahead. The industry recognizes that it may be rational for communities to oppose developments because they could come in for all the downside of fracking – road traffic, noise and potential groundwater pollution – without any of the upside.

Ultimately the social licence to operate resides within the communities and no amount of exploration licenses guarantee access to hydrocarbons without it. Public acceptance may require some tangible benefits and shale gas companies are talking with local and national government to explore ways to transfer some of the revenues back to the communities affected by drilling activities.

In Poland, Hutton Energy has set up a community advisory board comprised of key stakeholders: local residents, the local mayor, the landowner, company representatives and, in some cases, the local priest. Another developer in Poland, San Leon, even goes as far as working with priests to spread the good word about shale gas, attending Sunday worship and making donations towards church maintenance.

A similar approach may work in the UK, says Andrew Austin, CEO of IGas Energy, which operates 30 oil and gas fields with production in the East Midland and the Weald. “Around 10% of our operational expenditure, or 3% of our revenue, is on business rates, which remain in the local community,” he says. “Those rates may mean a weekly bin collection, or two more bobbies on the beat.

“In addition, we also make annual contributions to a voluntary community fund run by independent trustees. The local parish councils are able to bid for projects such as music festivals, village hall restorations, bus shelters and so on.”

Austin says shale gas developers will have a much higher probability of getting community approval if they build on the similarities to conventional oil and gas rather than highlighting the differences. “One of the biggest obstacles is to get over the impression that the drilling rig will stay forever like a mobile phone mast or a wind turbine. The rig is there for 90 to 120 days and then it goes; all that remains is a wellhead.”

The time for talk is over. Shale gas developers like Cuadrilla and IGas now need to get on with the business of exploration to ascertain the rates at which gas flows out of the shale. Then, and only then, will we know whether shale gas can make a meaningful difference in the UK.

THE EUROPEAN UNION’S (EU’s) AMBITIOUS plan to rollout smart meters to 80 percent of its 500 million population by 2020 is not going as well as hoped. This article was first published in the January/February 2013 edition of Intelligent Utility magazine.

Europe has enjoyed notable success with smart meters. In 2006, Italy became the first country in Europe to complete a national smart meter program after utility Enel conducted a five-year, $2.6 billion (US) scheme – mainly to reduce non-technical losses – for its 30 million customers.

Elsewhere, Scandinavia leads the way. Sweden also achieved full-scale penetration in 2010, while Finland, Norway, and Denmark are likely to achieve their targets by 2016. Yet for many EU nations who did not take it upon themselves to be early adopters, smart meter programs have struggled.

The European Union’s 2009 Third Energy Package, which sets out measures to liberalize Europe’s power sector, required each of the 27 member states to publish a cost-benefit analysis by end-September 2012. If the analysis found a positive business case, member states are compelled to install smart meters to 80 percent of consumers by 2020.

Most nations have reported a positive cost-benefit analysis, although there were some exceptions. The Czech Republic’s analysis was negative and has recommended its rollout start in 2018, while Germany has delayed the publication of its report until February 2013.

The three basic lessons
While utility benefits of smart meters are not in doubt, for the average European the case for consumers has not been well established. Significant tactical errors have been made, not least in the Netherlands, which proposed all 7 million households of the country should have a smart meter by 2013.

Faced with a growing moral panic over data privacy concerns, the Dutch government pushed for compulsory installation of smart meters, with refusal punished by a fine or six months in prison. After vigorous campaigning by consumer organizations it eventually relented and the Dutch Parliament moved to make installation voluntary.

The Dutch example is a salutary lesson in the dangers of putting the cart before the horse. Dr Philip Lewis, CEO of Finland-based utility analyst Vaasa ETT, says rollouts cannot be successful without consumer trust.

“There are three basic stages of consumer motivation,” said Dr. Lewis, a psychologist who now specializes in utility customer behavior. “First, there are reasons to be positive about overall smart meter developments at a national level. The second is to be positive about reasons to get involved with smart meters. The third is eliminating reasons not to get involved.”

Dr Philip Lewis, CEO, VaasaETT

Preaching the first lesson
Promoting them at a national level in Britain is the job of Maxine Frerk, deputy director and head of consumer engagement of the UK Department of Energy’s smart meter program.

Engaging consumers is proving tough in Britain, which is very much its own beast. Rather than regulated distribution network operators, deregulated energy retailers have the responsibility to procure and install 53 million gas and electricity meters, involving visits to 30 million homes and small businesses, by 2019.

It is an interesting policy choice and, in that respect, Britain is in a minority of one worldwide. The rationale is simple: Energy retailers have a relationship with their customers, and customer behavior change is a major element of their business case. So it was decided that it made sense for suppliers to be the primary interface for the rollout.

After years of inflation-busting price increases, tariff mis-selling and poor customer service at a time of stagnant wages and rising unemployment, however, British energy retailers are among the least popular organizations in the nation, barely more popular than banks, estate agents and even parking attendants.

So the energy companies will have assistance from the UK Department of Energy’s new smart meter `Central Delivery Body’ that will conduct a public awareness campaign about the benefits, which are estimated at a total £16 billion ($26 billion) in return for £11 billion in costs. Frerk believes a strong push from the center is needed because smart meter awareness and public trust in utilities is very low.

“Our latest survey of consumer awareness showed only 49 percent of respondents had heard of smart meters and from some of the other questions we asked, it’s not clear that even all of those did,” she said. “Getting consumers to just open their front door is the first challenge. If suppliers are faced with a lot of apathy, and find it hard to get access, it will increase costs.”

Putting the second lesson into practice
The British division of German utility E.ON aims to install 1 million smart meters by the third quarter of 2014, around the time the national rollout officially begins. The program started in 2011 and the company is close to 300,000 installations. By the designated end of the national rollout in 2019 it expects to install 8 million electricity and gas meters to 5 million homes.

The stakes are high for E.ON UK. Up for grabs are hundreds of millions of pounds in efficiency savings, the potential to offer critical peak period and other time-of-use tariffs and even the possibility of harnessing data for third-party marketing purposes.

“We’re investing £1 billion in this,” said Chris Lovatt, head of field operations, E.ON UK. “Our head office in Germany regularly asks me why they should spend it on smart meters when we could invest that money in, say, Brazil and see a much greater return. So we owe it to our customers and shareholders that this is done efficiently.”

E.ON has created two “centres of excellence,” essentially customer service contact centres to hold their customers’ hands through the end-to-end experience of smart meters. “We’re also creating a field centre of excellence to ensure all our meter technicians are technically skilled,” said Lovatt.

“They will also go through comprehensive customer service training so they’re able to have softer conversations with our customers to explain how the smart meter benefits them.”

E.ON is working with charities such as Age UK to ensure smart meters do not leave elderly consumers out on a limb. “Age UK was particularly concerned about the support that customers got post-installation, so we’re actually training some of their staff in five different regions across the UK to handle queries.”

Initial feedback shows that E.ON’s efforts are paying off. “The levels of NPS (Net Promoter Score) are in the high 20s, higher than anywhere else across our portfolio,” said Lovatt. “We’re feeding some of the knowledge gained from smart meters into our classic environment.”

Courtesy VaasaETT

Lessons learned the hard way
The message is clear: Consumer engagement should be done prior to the rollout with the technology coming at a later stage, and not the other way round. This was a lesson learned the hard way by Californian utility Pacific Gas and Electric (PG&E), which since 2007 has installed 9.5 million power and gas meters in 6 million households, taking 90 billion meter reading intervals per year.

At peak, it installed 18,700 meters a day with contractors and its internal workforce, equivalent to one every 2.5 seconds. Yet the path of smart metering did not run smoothly. “If we were to start again we would have done things differently,” said Jim Meadows, director of PG&E’s smart meter program.

“The more you separate out the installation from customer engagement, the more customers are suspicious about the motives behind smart meters. You need to make customers feel part of the bargain from the start. And in order to use the data efficiently you also need to have your operations center completely functional from the day the first meter is installed,” Meadows said.

Ogi Kavazovic, vice-president of marketing and strategy at Opower, says utilities should be thinking about their customer strategy at least a year before the smart meters are installed.

“The cost is probably less than 1 percent of the overall smart grid program costs yet many utilities don’t do it because they think consumers will change anyway,” he said.

The third lesson: Don’t be afraid of opt-outs
Despite their mandatory nature, European law may mean rollouts are subject to opt-outs.

PG&E believes opt-outs are to be welcomed. “If we learned one thing it’s that customers don’t like strictly mandatory programs,” said Meadows. “They like to know there’s an opt-out. In hindsight, we would have offered an opt-out from the start.”

E.ON UK says the carrot of energy savings should be sufficient to gain public acceptance, but U.S. utilities also know that wielding a big stick is useful. PG&E has an opt-out rate of just 0.5 percent, helped in part by the imposition of a $75 up-front fee and a further monthly charge of $10 per month to cover the expense of manual meter reading.

Opt-out rates in Europe are so far reassuringly small, said Lonneke Driessen-Mutters, head of smart meter operations at Dutch firm Enexis. “We have installed 220,000 smart meters and less than 1 percent has refused. It seems that just having the option to opt out is enough, but we are very vigilant that things will stay that way.”

Ogi Kavazovic, Vice President of Strategy & Marketing, Opower

The endgame: smart pricing
Post-installation, some European utilities may not be able to offer smart pricing but even without it there is much to be done with smart meter data, said Opower’s Kavazovic.

“Home energy reports give insights on consumption data and when customers call they can be given new insights, targeted discounts and coupons based on their data. As well as giving insight into their consumption, we also show the potential savings that could be made on the report,” he added.

Opower says its monthly mail energy report is the most effective method to engage consumers, but it also uses e-mail and web portals.

“Engage customers where they are not where you wish they are,” said Kavazovic. “In Europe, mobile phone channels look very promising.”
For most utilities, the endgame of smart metering is smart pricing. VaasaETT’s Lewis says consumers must feel part of the deal for time-of-use tariffs to be successful.

“Customers need to feel they are in control. When they introduced time-of-use pricing in Australia without consumer permission the backlash was so bad they had to stop it. There was a perception that some people were suffering from smart meters. We don’t want that to happen in Europe,” he said.

PG&E has a peak summer load of 16 GW. Its SmartRate tariff dictates that for 15 days a year a surcharge of $0.50/kWh is imposed between 14:00-19:00. In exchange, participants get credit for off-peak hours.

“You have some unintended consequences such as at 19:00 demand for air conditioning is higher than usual because of the higher heat of homes,” said Meadows, “But 80 percent of the customers find a way to save money. And we’ve had a 13 percent critical peak period load reduction.”

Dr. Lewis warns that customers must become accustomed to smart pricing. “You can’t suddenly shove it upon them and sit on them. There needs to be a fair and transparent link between the sacrifice and the reward, and customers have to explore what those benefits are for themselves directly.”

The psychologist sees best practice in Scandinavia where the Finnish utility Fortum has launched a product whereby customers can automatically control their hot water heating linked to the spot power market, Nordic. The heating system is timed throughout the day and is switched on or turned off depending on market prices.

“From the customer point of view it’s a profit-sharing scheme”, said Lewis. “The utility benefits by getting the customer engaged in sharing market volatility and the customers save by taking advantage of that volatility, rather than suffering from it.”

The EU is a big place and there can be no one-size-fits-all solution for a continent of 27 nations and 500 million people but, says Lewis, follow the three golden rules and progress will be less problematic, and less costly.

Mike Hill is an independent chartered engineer and director of Gemini Control & Automation based in Lytham St Annes, close to Cuadrilla Resources’ shale gas activities in West Lancashire.

Having worked as an oil & gas engineer, Hill is concerned about potential environmental damage from ‘fracking’ and has spent much of his time and money attempting to make UK authorities take the question of shale gas regulation more seriously.

In this clip, Hill says that without a post-drilling, on-site independent testing and verification regime, shale gas operators may be tempted to cut corners and thus jeopardise well integrity – vital for safe fracking operations. Interviewer: Tim Probert, October 2012.

One word will suffice to summarize the outlook for the biomass industry: uncertainty. Concerns are fourfold: the EPA’s Boiler (Maximum Achievable Control Technology) MACT, Non-Hazardous Secondary Material (NHSM) and Greenhouse Gas Tailoring Rules, and the Federal Production Tax Credit. This article was first published on RenewableEnergyWorld.com

Shale gas water lifecycle. Image: Cuadrilla Resources

Shale gas firms could find the temptation to save millions by falsely under-reporting volumes of ’fracking’ flowback fluid too strong to resist without strong regulation, according to a Lancashire-based engineer familiar with the industry.

To extract natural gas from shale rock a technique called hydraulic fracturing, also known as fracking, is used. Millions of gallons of fluid comprising water, sand and chemicals are piped underground at high pressure to create fissures to release the gas.

Approximately 25-75% of the fluid is returned to the surface. Called flowback fluid, it typically contains extremely high levels of sodium and chloride; naturally occurring radioactive material (NORM) like radium; hydrocarbons such as benzene; and trace elements of mercury, arsenic and lead; as well as the chemical additives used in fracking.

The high mineral content means flowback fluid is expected to be trucked to industrial water works for treatment and disposal. Operators must declare to the Environment Agency (EA) the volume of flowback water returned.

But Mike Hill, a Lancashire-based chartered engineer with working knowledge of fracking, said the EA does not verify the declared volumes of flowback water. “Through Freedom of Information requests I discovered the EA is not verifying the quantity of flowback fluid and their sampling visits will be announced two weeks in advance. In effect they are not regulating.”

Carte blanche to cut corners

Hill said without strong regulation shale gas firms would be given carte blanche to cut corners. “There could be 20 million gallons of flowback per ten-well pad. To lose a certain volume of this water along the way could potentially save an exploration company several millions of pounds in trucking, treatment and disposal costs.”

At present only a handful of firms, including Cuadrilla Resources, Coastal Oil & Gas and Dart Energy, hold shale gas licenses and only Cuadrilla has conducted hydraulic fracturing. When completed, however, the Department of Energy and Climate Change’s (DECC) 14th Onshore Oil and Gas Licensing Round could see dozens of firms hold exploratory shale gas licenses across large swathes of Britain.

There is no suggestion of any wrongdoing by Cuadrilla Resources or any other company, but Hill said there would be a ”huge temptation” for other shale gas operators and their sub-contractors to minimize costs.

“I’ve worked in hydraulic fracturing for some very large oil and gas companies and I know what it can do,” he said. “And I know how these companies will behave if they know for sure that they are not going to be inspected. What’s to stop the water disappearing in a river, lake or a field?

“Drivers on the motorway know the speed limit is 70mph, but equally they know there are no policemen and no speed cameras. There is always the temptation to speed.”

The EA said the storage and disposal of flowback fluid is likely to require a permit with strict conditions attached. A spokesman said: “We would ensure these conditions are adhered to via monitoring, auditing and sampling. Like any other industry, false reporting would be an offence which could lead to prosecution.”

Fracking is currently on hold after Cuadrilla Resources was found to have caused earth tremors of magnitude 2.3 and 1.5 in April and May 2011. However, DECC is expected to give a green light to shale gas companies to resume exploratory shale gas fracking in the coming days.

1. On nuclear strike price negotiations

Ed Davey: The negotiations for Hinkley Point C are ongoing. EDF would like to conclude by the end of the year and we’re working with them to try and do that. It’s a major negotiation and it’s going very well.

Jonathan Brearley (Director of Energy Strategy and Futures): When deciding strike prices we have to compare the levelized cost of electricity with what happens to the gas price. As this so uncertain we have a range of scenarios. For nuclear the levelized cost estimate is around £80/MWh by 2020. This doesn’t necessarily feed directly into the strike price as we have to factor in the cost relative to the future price of gas, which is very uncertain, and the length of the CfD contract.

Simon Virley (Director General for Energy Markets and Infrastructure): The EU State Aid talks are ongoing, we have a good constructive dialogue with the Commission and we have done so for many months. We’ll have to wait and see what the Commission comes back with when they finally make their views known.

2. On the Levy Control Framework

Davey: We have full flexibility over how the Levy Control Framework is spent to make sure we can meet our 15% Renewable Energy Directive target. We haven’t decided what the mix could be. It’s unlikely to [be spent entirely on wind] but clearly wind is going to get quite a lot as our Renewable Energy Roadmap envisages a great deal of offshore and onshore wind by 2020.

I will write a letter to National Grid next year to give them guidance over their first CfD delivery plan. Within that I will give them guidance to make sure we’re on the least cost pathway to 2050. Many consider the MARKAL model to be the least cost pathway with significant power decarbonisation. I will not be mandating them but I will be giving them clear guidance.  This is what I agreed with the Chancellor.

3. On a decarbonisation target

Davey: I’ve made the case for a target and as part of our agreements with the Chancellor we’ll be bringing forward amendments to give powers to set that. But the target will be set in 2016 when the Fifth Carbon Budget is set for the whole economy, not just for the power sector.

Linked to the guidance I’ll be giving to National Grid, I think this approach will give the signals the industry are looking for. Our central modelling, which is the least cost path to 2050, is 100g/kWh in 2030, but we are modelling 50g/kWh and if you had an endgame of 200g/KWh.

4. On energy efficiency ‘negawatts’

Greg Barker: It’s very difficult. The concept of the negawatt – that the cheapest unit of energy is the one you don’t use – is very simple. But actually creating an at-scale system which places value on that, which can be verified, traded and brings genuine additionality at scale is really difficult.

Britain could be a ‘World Leader’ in this and I want us to go beyond California and Japan and establish a new benchmark for delivering energy efficiency. But don’t let anyone tell you it is easy. Getting down to the nitty gritty is really, really difficult and I don’t underestimate the challenge.

5. On onshore wind ‘targets’

Davey: There are no targets in the Renewable Energy Roadmap, there are pathways and aspirations. We don’t micro-manage where all those private investors put their money.

Both John and I have been saying that we will meet our onshore wind aspiration but different people like to report our words slightly differently.

We are not dictating the mix of renewables now or in the future. This is not a statist approach saying ‘We’ll have 5 GW of this, 6 GW of that and 7 GW of the other’. We are moving towards the market deciding the amount of onshore wind in the 2020s.

6.  On whether the Energy Minister dislikes onshore wind

John Hayes:  There are issues about community consent and I’ve always said that there are issues about the aesthetics and the relationship between localities. The planning system takes into account the concerns between any development and its locality.

7. On shale gas

Davey: The Chancellor will have a number of things to say about shale gas in next Wednesday’s Autumn Statement. The Cuadrilla decision [to permit the resumption of hydraulic fracturing, aka fracking] is mine to make on an almost quasi-judicial basis and we haven’t set a date for that, and I’m not prepared to give a date for that.

There are certain things I have to have and things I have to go through in the proper process before I make that decision. I am going through that process now.

8. On a capacity market

Davey: We think the evidence for a capacity market is extremely strong. If you don’t have intervention we will have very expensive peak prices. A capacity market would reduce those peaks and offset the capacity payments.

We haven’t yet decided to introduce it because we want to see more evidence before we make a final decision next year.  This is a major intervention and it’s absolutely sensible we wait for further advice from National Grid and Ofgem.

9. On the impact on consumer bills

Davey: By 2020 the impact on consumer bills will be £94 a year. Our latest estimate suggests our energy and climate change policy will see bills down £95 by 2020 than they otherwise would have been. The cost of exempting energy intensive users from CfD levies would be socialized across the rest of business and consumers.

Barker: There’s a difference between prices and bills. It is misleading to focus only on price. In Germany, prices are higher but bills are about the same as the UK because they use less energy. In the 21^st century you have to incorporate usage and efficiency alongside price.

10. On whether an exemption for energy intensive users disincentivizes investment in on-site power

Barker: We are the early stages of a renaissance of industrial CHP. Yesterday I had a meeting with Business Minister Michael Fallon and the Economic Secretary to the Treasury [Chloe Smith] to think at a strategic level specifically to drive CHP and embed on-site generation in the economy.

Sizewell B, the last UK nuclear power station to be commissioned, in 1995. Courtesy British Energy

The UK’s record of building nuclear plants is dismal. Yet, as Tim Probert explores, previous exercises may seem like a walk in the park compared to building a new fleet of reactors in a liberalized power market. This article was first published in the October 2012 issue of Energy World magazine.

Few would disagree that while the UK has often been a pioneer in nuclear power, its track record of building atomic power stations is, at best, mixed. From the troubled Magnox programme to the protracted build-out of the AGR fleet and the saga of Sizewell B, the UK has never built a nuclear power station on schedule or within budget.

So when Tony Blair’s Labour government decided in 2007 that the UK should once again embark on building a fleet of new nuclear power stations, the omens did not look good. Just a year previously, BNFL had sold reactor vendor Westinghouse to Japan’s Toshiba, while nuclear generator British Energy was under state control having been bailed out in 2004 for £3 billion.

The rationale for the nuclear ‘renaissance’ was straightforward: to provide low-carbon, baseload power as a replacement for aging coal and gas plant, as well as the existing 16 reactors generating 10 GW, all but one of which are officially due offline by 2023. Then as now, however, no new nuclear power plant had been built successfully anywhere in the world without public subsidy.

The now defunct Department of Trade and Industry’s May 2007 White Paper, Meeting the Energy Challenge, said the economics of nuclear power had improved; rising fossil fuel prices and carbon pricing had made atomic energy more competitive and a viable private sector proposition.  Subsequently, several developers came forward with new build proposals. Approximately 19 GW of new build is either planned or proposed at five UK sites, all in England and Wales¹: Hinkley Point C and Sizewell C (EDF Energy); Oldbury and Wylfa B (Horizon Nuclear Power) and Moorside in Cumbria (NuGen).

UK new nuclear build map. Courtesy Nuclear Advanced Manufacturing Research Centre

Big hopes, small steps

Yet these plans have struggled to gain traction. In March, E.ON and RWE put up for sale their joint venture Horizon, which amounts to little more than some land adjacent to existing reactors in Gloucestershire and Anglesey, stating that building nuclear power in the UK would place too much of a burden on their already highly debt-laden balance sheets. Meanwhile NuGen, initially a joint venture between Iberdrola, GDF Suez and SSE before the latter pulled out last September, is not expected to make an investment decision until 2015 at the earliest.

The only nuclear plant being actively developed is Hinkley Point C in Somerset, a 3260 MW, twin-European Pressurized Reactor (EPR) facility. EDF Energy has let £50 million in contracts for site preparation works, although in May it deferred a £1.2 billion civil engineering contract pending a final investment decision (FID) to build two 1.6 GW European pressurized water reactors (EPR).

EDF says it aims to make an FID on Hinkley Point C by the end of the year, but it is still to clear some important EPR licensing hurdles for the HSE’s Generic Design Assessment (GDA). The Office for Nuclear Regulation’s July 5 report stated EDF still had 28 ‘GDA Issues’ to resolve, including security, reactor chemistry and integrity of the inner containment wall, before consent to commence reactor island construction could be granted. It is unlikely these issues will be resolved by the end of 2012.

Need for government support

Yet the most pressing barrier to construction of Hinkley Point C, and any other nuclear plants, is finance. As global head of power at French banking group Societe Generale Allan Baker says, financing nuclear power plants without government support is nigh on impossible.

“No financial institution is willing to take the risk on cash flows over 20-25 years without visible government support for the nuclear industry,” he says. “We have found it incredibly difficult to mobilize capital for an industry which is seen as very expensive and, to be blunt, non-competitive in a competitive electricity market.

“It’s not the costs of nuclear per se, but the uncertainty of costs, which is the killer for financial institutions. If you’re building something which costs $10 billion and there is a 20 per cent cost over-run, then there’s another $2 billion to find. Where does that come from? Does it come from the sponsors or additional debt? And will it be recovered soon, or over the entire lifetime of the plant?”

It is because of this need to offer certainty over construction risks that DECC is offering Feed-in Tariffs (FiT) with Contracts for Difference (CfD) under Electricity Market Reform (EMR) proposals in its 2012 draft Energy Bill. The CfD will offer a fixed price for nuclear output over as yet undetermined period, although it is expected that it will be at least 20 years.

In essence, a CfD is a contract to pay or be paid the difference between a market reference price and a DECC-agreed ‘strike price’.  CfDs are controversial, not least because DECC ministers have made repeated statements in the House of Commons that “there will be no subsidy” for nuclear and that nuclear will be on a level playing field with other low-carbon technologies like offshore wind.

In late July DECC entered into negotiations with EDF over the strike price for Hinkley Point C. Indications are that the price will be anywhere between £100-135/MWh. Crucially, £135/MWh is reflective of the current subsidy paid to offshore wind via the Renewables Obligation, while £100/MWh is DECC’s Offshore Wind Cost Reduction Task Force target by 2020 – the earliest that Hinkley Point C could realistically come online.

In a 13 August interview with The Daily Telegraph, EDF Energy CEO Vincent de Rivaz said he expects the strike price for nuclear to be lower than the current cost of offshore wind farms, but declined to say whether it also means matching £100/MWh by 2020.

Running at an estimated capacity factor of 80%, a 20-year CfD for the 3.2 GW Hinkley Point C could, therefore, be worth between £25-40 billion at current wholesale power prices of £45/MWh. This would represent a handsome return on investment for a plant with an estimated construction cost of £7-10 billion.

CfDs are due to come in to effect in 2014 but DECC is taking special measures in the Energy Bill, called ‘Investment Instruments’, to allow EDF to make an FID on Hinkley Point C before the end of the year. The primary instrument is ‘FID Enabling’, which would allow DECC to crystallize the outcome of the strike price negotiations for Hinkley Point C by way of a binding agreement before the Energy Bill gains Royal Assent by the end of 2013.

Hinkley Point B nuclear power station in Somerset. EDF Energy plans to build a 3260 MW, twin EPR reactor Hinkley Point C within the next decade

FID Enabling is ‘nonsense’

FID Enabling, however, is seen by some as deeply flawed. A legal expert told Energy World: “FID Enabling is nonsense. It doesn’t do what it’s intended to do. If you are taking FID before legislation was in place because you were concerned legislation was not in place, you couldn’t take any comfort from anything that was dependent on legislation being passed.

“You don’t have legal certainty. It’s like a ratification provision. It’s sort of says that if the government does something then it will be ratified by being an investment instrument after the event. It is not particularly satisfactory.”

The University of Greenwich’s Professor Steve Thomas says another unknown is whether nuclear CfDs will include price escalators, as they did for CCGTs in the 1990s. “Nuclear suppliers are not going to offer a fixed price contract for the equipment and they are certainly not going to give any guarantees for performance or operating costs. Financiers want to know what happens if things go wrong. This is why there may be escalators in the CfDs.

“This was always going to be the case regardless of Fukushima or even Flamanville and Olkiluoto, which merely confirm that any suggestion of the new generation of nuclear power plants having solved the old problems is, at best, unproven. Whether we would know that would be the case is uncertain. The CfDs of the 1990s were never published. I assume that the companies involved deemed them commercially confidential.”

DECC says that its negotiations with EDF are confidential, although it will publish the agreed strike price in time. However, even if EDF are satisfied with DECC’s offer of support for nuclear, there are two areas where the plan may still fail: European Commission state aid rules and potential judicial reviews from NGOs.

“If I represented Greenpeace I would be wondering what I am going to challenge,” says the legal expert. “I would be thinking about challenging the development consent order and then I would be thinking about challenging EMR.”

In a note on the Energy Bill², the University of Oxford’s Professor Dieter Helm said that the Energy Bill’s nuclear measures are vulnerable. “The problem with negotiated FiTs, especially for nuclear, is that they are potentially wide open to legal challenge if the strike price is based on questionable forecasts and indeed to the challenge that strike prices include subsidies to nuclear,” he writes.

“Subsidies are being and will be paid, raising the question of how government decides the subsidy level on a case-by-case basis and how “no subsidy” can be defined as “equal subsidy” and what that means given “different subsidies” for each low carbon technology. It is far from clear how the European Commission will treat the implied state aids, or indeed how the government would treat the subsidies issues were there to be a judicial review of the nuclear FiTs.”

Giving evidence to the Energy Select Committee on June 26³, DECC’s Director of Energy Strategy & Futures Jonathan Brearley said “the Commission may take different views on different technologies”, but in general DECC believes that the Energy Bill measures, including CfDs, will clear state aid rules.

Cutaway of an EPR nuclear reactor. Courtesy Areva

The counterparty conundrum

Why can they be so sure? Well, one reason is because the Treasury has decided it will not be the counterparty or, in other words, underwriting CfDs. Unfortunately, this decision has put the explicit rationale of EMR – to reduce the cost of decarbonizing the electricity sector – in considerable jeopardy.

Initially, the Treasury was to be the counterparty of CfDs, thus allowing investors to benefit from its AAA-credit rating to reduce the capital costs of investment in low-carbon power generation. Instead, DECC is attempting to fashion an alternative, which would be legally robust while still not technically underwritten by the Treasury.

It remains to be seen whether DECC will be able to offer a satisfactory, state-backed CfD for Hinkley Point C that can clear state aid rules. “Hinkley Point C is looking 50-50 at the moment,” says Professor Thomas.

“We shouldn’t discount the fact the EPR is in a pretty awful state. It will probably take another year to get through the GDA process. I think that Centrica will pull out, which will leave EDF even more exposed. EDF already has a big bill to pay for maintenance of its 58 existing reactors in France. So why would it really want to take a punt in the UK for Hinkley Point C?”

Thomas notes that EDF’s existing fleet of AGRs are set to have their lives extended by an average of five years. This will mean that most AGRs will be running well into the next decade, rather than all 14 being shut down by 2023 as previously assumed.

So if EDF really does pull out of Hinkley Point C, what next? Russia and China are reportedly looking closely at the Horizon sites, but are these realistic plans, or just speculation? Steve Kidd, Deputy Director General of the World Nuclear Association, believes it is highly unlikely Russia would be interested in Horizon.

“The Russians would have to start from scratch to license their reactor and this will take at least four years,” he says. “It’s more of a long-term aspiration. There’s no way that they would buy Horizon and get their own reactor licensed. Whoever buys Horizon has got to use either the EPR or Westinghouse’s AP1000.”

That leaves China, which is building both reactors domestically. Kidd, a regular visitor to China, says: “China is serious, they have lots of money and the State Nuclear Power Technology Corporation (SNTPC) would like to build the AP1000 abroad.

“The UK government would be very happy with more than one reactor design being built. SNPTC tells me that it is extremely keen but it may be biting off more than it can chew, as it plans to build AP1000s all over China.  I suspect it’s Westinghouse who is driving this in London, with SNTPC very much in the background.”

Whether or not China is serious, it remains highly questionable whether the Government would, in reality, be comfortable with a Chinese state-owned company owning UK nuclear space. So, if no EDF, no Russians, and no Chinese, then who?

“You can imagine that this will all end up in government hands eventually,” says one utility analyst. “They may nationalise the whole thing.” One potential scenario is for Her Majesty’s Government to take on from EDF the building of nuclear reactors, then selling the power plants after a period of successful power generation, e.g. one year, to the highest bidder.

“Nuclear has got to happen or the lights will go out,” says the analyst. “One way or another, the Government will find a way. But there is a great deal yet to play out before it gets there.”

References:

1. World Nuclear Association Reactor Database: http://www.world-nuclear.org/info/inf84.html

2.  EMR and The Energy Bill: A Critique by Professor Dieter Helm 27 June 2012 http://www.dieterhelm.co.uk/node/1330

3. House of Commons Energy and Climate Change Committee Draft Energy Bill: Pre–legislative Scrutiny – Volume II, 23 July 2012 http://www.publications.parliament.uk/pa/cm201213/cmselect/cmenergy/275/275ii.pdf

The installed 1.2 MW tidal stream turbine at Strangford Lough, Northern Ireland

The British city of Bristol is arguably the spiritual home of marine energy.  Tim Probert visits two companies at differing stages of development: Marine Current Turbines, recently acquired by Siemens and Offshore Wave Energy, a start-up struggling to raise finance, to find out how marine energy will be brought to market. This article first appeared in the October 2012 issue of Materials World magazine.

Bristol knows all about the power of tides. The huge tidal range of the River Avon has always presented it with a problem.

Before the construction in 1809 of a floating harbour that allowed vessels to stay afloat without being affected by the changing tides, ships anchored in Bristol would rest on the river bed and be subject to immense pressure as the water in the river ebbed and flowed from the sea.

This often caused considerable damage to the timbers and as a result Bristol-built ships became renowned for their sturdy craftsmanship, leading to the famous phrase ‘shipshape and Bristol fashion’. While much of Bristol’s maritime infrastructure has since been regenerated as shops and eateries, Bristol continues to harness the power of the tides.

Marine Current Turbines (MCT) is the poster child of the UK’s burgeoning tidal power industry. The company was founded in 1999 to develop Dr. Peter Fraenkel’s ideas for harnessing tidal stream currents to generate electricity via submerged power generating turbines.

Fraenkel, the now-retired former technical director of MCT, is seen as the ‘Godfather’ of marine energy in Bristol. Most of the city’s tidal and wave power companies can trace their lineage back to Fraenkel and IT Power, a renewable energy consultancy of which he was a founding partner.  Fraenkel dates his involvement with tidal power to the 1970s when he installed a turbine in the Nile River.

In 1994, Fraenkel installed a small tidal power generating unit in Loch Linnhe in Scotland to prove the concept of harvesting tidal streams and this led to Sea Flow, the world’s first offshore tidal turbine, which was installed in Lynmouth, Devon by MCT in 2003. Satisfied with the results from this non-grid connected, 300 kW system, the conceptual principles were applied to SeaGen, a 1.2 MW grid-connected system installed in Northern Ireland’s Strangford Lough in 2008.

SeaGen can be loosely described as a wind turbine in water, with the blades driven by marine currents.  The turbine is fixed on a pile and twin, 16m diameter rotors rotate with the tidal flow, pitching through 180 degrees to track direction and speed. The primary advantage of tidal power is that generation is predictable in the tidal cycle.

The Strangford Lough demonstration unit has been hailed as a success – it regularly generates 20 MWh daily and has achieved a capacity factor of over 60 per cent, twice that of wind power – and was an overarching factor in the decision taken by Siemens to invest in MCT in 2010, later taking 100 per cent ownership in March 2012.

Andrew Tyler, formerly chief operating officer of the Ministry of Defence’s Equipment and Support organisation, joined MCT as CEO in 2010.  Tyler has been charged with turning SeaGen into a commercial product and the lessons learned from Strangford Lough will now be applied to SeaGen-S2MW, a 2 MW rated machine with 20-metre diameter rotors, which MCT is developing to be an “industrial product” by the end of 2013, he says.

Engineering lessons learned

The primary engineering lesson learned from Strangford Lough, says Tyler, is the persistent challenge of turbulence-induced vibration. “We are harvesting a highly turbulent flow field and that turbulence is translated by the tidal device’s mechanics into the structure: the powertrain, the gearbox, stresses placed on the blades and so on.

“We can engineer this out but it manifests itself in lots of different ways. SeaGen has been of incredible benefit because so many of these problems emerge after years, not months, following installation.”

Subject to a force of over 100 tonnes, SeaGen’s rotor blades have suffered a number of fatigue cracks and even a break, forcing a redesign. Other factors included the reliability of the powertrain, i.e. gearboxes and slip rings. SeaGen uses a small, planetary wheel gearbox from Czech manufacturer Wikov and at one stage some pins sheared. The gearbox continued to work but the associated overhaul took several months.

The biggest differences between the turbine at Strangford Lough and SeaGen II are an upgrade of the powertrains from 600 kW to 1 MW and a cost-engineered structure. Tyler notes that Strangford Lough was significantly over-engineered, which is the right thing to do for a prototype if not always cost-effective for industrial products.

The design will undergo testing next year, initially onshore at a number of sites. A Bristol site will be used to test system level equipment and blades, while powertrain testing will be conducted at the National Renewable Energy Centre’s dedicated tidal turbine test facility in Newcastle.

MCT plans to build two arrays in the UK with SeaGen-S2MW:  the Kyle Rhea 8 MW project sited in a strait between the Isle of Skye and the Scottish mainland, and the 10 MW Skerries array off the north-west coast of Anglesey. Both are due online by the end of 2015 and MCT is currently seeking utility partners to invest in the projects.

A commercial tidal power project would consist of several turbines which are driven by the motion of the rotor blades. The SeaGen turbine is fixed on a structure within the sea current, which drives the rotor blades. Twin rotors rotate with the movement of the tidal flow and pitch through 180 degrees to optimally track tidal current direction and speed.

Costs and support mechanisms

The prospect of being eligible for five Renewable Obligation Certificates (ROCs) – equivalent to £210/MWh at current values – is not yet sufficient, so MCT is also seeking funds from the Department of Energy and Climate Change’s (DECC) £20 million Marine Energy Array Demonstration Fund, the Scottish Government’s £18 million Marine Renewables Commercialisation Fund, as well as the Renewable Energy Infrastructure Fund.

“It is a lot of support but we are right at the top of the cost curve, and we are under no illusions that our follow-on projects won’t require government capital support,” says Tyler. “Hopefully we will start to eat the ROCs, and we know receiving five ROCs is not sustainable. Anybody who thinks we are going to be in an Electricity Market Reform regime getting the long-term equivalent of five ROCs is on the wrong planet.”

So the onus is on MCT to bring down costs rapidly to be a commercial prospect. Tyler puts theprovisional capital cost from a SeaGen-S2MW tidal turbine at £5 million per megawatt installed in a 10 MW array.  “If one was to take a 35% capacity factor, we are just north of £200/MWh,” he says. This compares to offshore wind, which has a similar capacity factor, at around £140-150/MWh.

MCT’s objective is to be cost-competitive with offshore wind by 2020. While SeaGen has a major competitive advantage in having two powertrains on one turbine foundation, to arrive at even £200/MWh will require a great deal of cost reduction, admits Tyler.  “There will be natural economies of scale in areas of fabrication and integration of system to leverage the supply chain and the ability to enter into partnerships, buying steel in bulk and so on. And as with offshore wind, the turbines will be uprated and we have a roadmap of uprating potential to put larger powertrains and blades on the same foundations.”

Despite being a wholly-owned subsidiary of Siemens, Tyler says MCT will resist the temptation to use in-house, proprietary components. “You don’t arrive at a cost-competitive business if you gift yourself with self-sourced supplies, as there would be no competitive tension and that’s the road to rack and ruin. We are a stand-alone business within Siemens and we are charged with delivering the most cost-effective product. They won’t just give us equipment for free.”

The best way to drive down costs, of course, is to make more turbines. MCT sees enough potential business in the UK and France to keep it busy for the next 20 years, but it believes there is a big opportunity in the Bay of Fundy in the Canadian province of Nova Scotia and to a lesser extent Asia-Pacific.

A major drawback of constructing tidal as opposed to wind turbines, however, is a heightened requirement for site-specific engineering. As the gap between the seabed and the sea surface changes, tidal turbines need to be installed at different heights, requiring differently-sized foundations.

Moreover, the extreme tidal range of the Bay of Fundy would require an entirely separate concept, says Tyler. “We are not going to use different powertrains, blades, power processing or control systems, but the powertrain may not, as SeaGen does, move up and down on a crossbeam. We are looking at alternative structures to suspend the systems in the water.”

Tyler envisages MCT developing a small range of products suited to different classes of site.  MCT expects to be producing 50 tidal turbines a year within the next decade, although it has no current plans to build a manufacturing facility.  “We are going to have an integration facility to bring the powertrains together in Bristol but the fabrication and assembly of the marine structure has been put out to tender.”

Operating principle of OWEL’s wave energy converter

Wave power: Struggling to gain traction

While MCT is reasonably close to commerciality, other marine energy firms are struggling to build a demonstration unit. In stark contrast to MCT’s headquarters at the striking, glass- and timber-fronted Bristol and Bath Science Park, Offshore Wave Energy Limited (OWEL) is an essentially part-time operation, run from home offices.

The company was founded by Professor John Kemp, who built and tested models of a wave energy converter in his bath, and its major shareholder and technical consultant is IT Power. Highlighting the somewhat incestuous nature of the marine energy industry in Bristol, IT Power’s principal engineer is Jeremy Thake, who was MCT’s chief engineer before leaving to found Tidal Generation Limited, now owned by Rolls-Royce.

OWEL is developing a floating wave energy converter to compress air and drive a turbine.  Waves enter through a duct, creating a seal to trap pockets of air. As the waves move along the duct the pockets of air are compressed and pushed through in pulses to drive a unidirectional turbine.

OWEL’s chief technical officer Ned Minns says the device has a 25-year design life, with an initial capacity factor of 31%, rising to 32% and then steadily to 35% over the next five years. Minns has a target efficiency of 30% for wave-to-air power conversion which, combined with 80% for air-to-electrical power conversion, would provide a wave-to-wire efficiency of 25%.

Minns says wave power production is smoother and more consistent than wind or solar, but seasonal variations apply as winter conditions offer higher wave heights than in summer. There are also daily variations, meaning that a “stable sea state” lasts for on average three hours.

The torque of the generator can be tuned for a typical stable sea state, for example a wave cycle of 7.5 seconds and a height of 4m, to control the impedance of the turbine, while the water ballast can be adjusted to change the moment of inertia and therefore the pitch.  The device is anchored.

OWEL is currently designing a demonstration prototype and aims to install it at the grid-connected Wave Hub test centre 10 miles off the Cornish town of Hayle next summer. The prototype will be a single duct, 45m long, 350 kW device made of steel.  The aim is to build a triple duct, 70 m long, 2 MW unit built by 2016, with commercial deployment from 2018. Eventually, says Minns, OWEL’s device would be made of cheaper concrete, making them look not dissimilar to Mulberry harbours used by the Allied Forces during the Normandy landings.

Yet OWEL is struggling to raise funds to build even the prototype and is yet to sign a contract to lease a berth at Wave Hub. Chris Rich, OWEL’s Head of Finance and Investor Relations, says the cost will be at least £10 million and while it has a £5 million grant from the Technology Strategy Board it needs to be pari passu with the private sector.

OWEL intends to commericialise a triple duct, 70m long, 2 MW wave power unit by 2016

Passing through the Valley of Death

“We are at the Valley of Death,” says Rich. “We’d hope to be specifying and tendering the steel panels in the autumn and commence fabrication in the winter, but to be in that position we need £5 million to get the prototype built and fund overheads and working capital until the end of 2015.

“We are now in the market looking for equity investment, but the current financial climate is grim. Venture capital has dried up, partly because they are short of money and partly because of their experience with marine technologies to date.

“Investors in 2005/6 were promised a fantastic return within a few years, but the companies are still at the prototype stage. Prior to being bought out by Siemens, MCT had spent £70 million. It’s more capital-intensive than people first thought.”

Rich is confident that once the demonstrator is in place, OWEL will succeed. “The investor market says ‘Get this prototype working and we want to buy you’,” he says. “The likes of Alstom, Siemens and ABB have said ‘Get this prototype in the water throughout the winter at a capacity factor the right side of 30% and come back to us’.”

Rich, who works for OWEL as a sideline to his management consultancy business, say once commercial-scale wave power happens it will happen fast due to the relatively easy installation of floating devices.  “We expect wave power to be a cheaper option from 2020 onwards; we are aiming for £150/MWh.

“Our business plan does not include ROCs, as we won’t have arrays of them installed water by 2017, but at commercial-scale deployment scale, we believe we have a financially-viable product equivalent to 3 ROCs.”

Rich speculates it will be Aquamarine Power, whose major shareholders include ABB and utility SSE, will be the first wave power company to earn ROCs with its array of three, 800 kW ‘Oyster’ machines off Orkney by the end of 2013. AWS Ocean Energy, which is 40%-owned by Alstom, may be next with its 2.5 MW doughnut-shaped machine.

The Carbon Trust estimates wave and tidal energy has the potential to power 11% of the UK’s current energy needs by 2050, as well as to create 26,000 new jobs and bring £3 billion pounds a year to the UK economy. If these somewhat ambitious figures are to be proven, the marine energy industry must hope that both the private and public sectors give it their full support.

Vattenfall’s Horns Rev 1 offshore wind farm. Photograph by Christian Steiness

With an eye on its ambitious Round 3 offshore wind programme, the UK Department of Energy and Climate Change is targeting a 50 per cent technology cost reduction by 2020. Tim Probert explores how the industry is working to reduce the cost. This article was first published in the September 2012 issue of Energy World.

The core of any business model is a predictable return on investment, the difficulty is being sure of the return. As the UK prepares to build out her 32 GW Round 3 offshore wind programme, the uncertainty of construction costs has raised concerns among investors that the estimated £100 billion capital required may not be forthcoming.

Round 3 may seem a small step from Round 2, but in terms of capex and opex it is a giant leap. Existing offshore wind farms are sited in near-shore, shallow waters of up to 20 metres. To realise the North Sea’s full potential, however, Round 3 projects will be located further out to sea – potentially 200 km from shore at depths of 50 metres or more – which requires larger arrays, bigger turbines, deeper foundations and longer construction times.

As no other nation has attempted to build offshore wind at these depths and distances, nobody can be exactly sure how much these pioneering projects will cost to build. The costs of Rounds 1 and 2 are estimated at £135-145/MWh, around three times the current wholesale price of electricity, but Round 3 offshore wind farms are expected to be significantly more costly.

Engineering consultants Arup estimates the levelized costs of electricity (LCOE) in 2015 of Round 3 at anywhere between £168-£225/MWh, including transmission costs. However, the Crown Estate, which leases marine areas around Britain for offshore wind farms, believes this estimate to be fundamentally flawed because it assumes a 38 per cent capacity factor, as opposed to the current average capacity factor of 31 per cent.

The Crown Estate assumes projects deployed today will acheive a capacity factor of around 40-42 per cent, increasing to up to 50 per cent by 2020. The improved capacity factor will offset increased capex and opex, and subsequently it puts the LCOE of Round 3 offshore wind farms as broadly equivalent to current projects at £140-145/MWh.

The Department of Energy and Climate Change (DECC) is targeting the cost of offshore wind to come down to £100/MWh by 2020. While this is a very challenging target, steps are being taken by developers to slash costs by using better loading and installing methods, standardising substations and connections, improved cables and, perhaps most importantly, using larger wind turbines.

Offshore wind turbines: Bigger, better, stronger

The latest offshore wind farms employ turbines with a typical power capacity of 3-3.6 MW but, targeting Round 3, the world’s leading OEMs are set to bring to market machines with double the power. These turbines will be taller than The Gherkin and have turbine rotor diameters larger than the London Eye, standing in depths up to 60m, in some cases more than 200km from shore.

French manufacturer Alstom has designed its first ever offshore wind turbine – the 6 MW Haliade 150 – with Round 3 in mind. Aerodynamically optimized to operate at a depth of around 35 metres and a wind speed of 9.5 metres/second, Alstom is targeting installation of 200 turbines a year in the UK and France once serial production commences in 2014, equivalent to 1.2 GW of new capacity per annum.

Frederic Hendrick, Alstom’s vice president of offshore wind, believes 6 MW is the optimum size of turbines for Round 3. “We have paid a great deal of attention to the capacity factor of our offshore wind turbine, as we wanted to optimize the total cost of electricity rather than the total cost of the nacelle.

“It’s very important to optimize the total cost of power and substructure. We’ve paid close attention to the total mass, particularly in minimizing head mass (nacelle plus rotor). All the rest, the transformer, converters and low voltage switchgear is contained in the bottom of the tower, so the lower the head mass, the less the stress placed on the substructure.

“We looked at various power ratings up to 10 MW and what is required in terms of blade length, the weight of the nacelle and the implications for the turbine substructure, which can account for 30-40% of the total cost. We found 6 MW to offer the best value in terms of total cost of electricity.”

Siemens is also launching a 6 MW turbine aimed at Round 3. The German firm has begun construction of two test SWT-6.0 machines at Danish utility Dong Energy’s Gunfleet Sands array off the Essex coast. Once operational in November, these will be the biggest turbines so far deployed in the UK.

Both manufacturers have opted for direct drive permanent magnet generators rather than utilize gearboxes, which are prone to malfunction in the harsh, turbulent environment of an offshore wind farm. Henrik Stiedal, chief technology officer of Siemens Wind, says direct drive generators also reduce the weight of the nacelle, thus reducing stress on the substructure.

“So far, large wind turbines have always been heavier per megawatt than small ones,” he says. “The SWT-6.0 breaks this rule and has a weight per megawatt similar to many machines in the 2 – 3 MW range.”

It is not clear that ever larger turbines will be cost-effective, says Alstom’s Hendrick. “It would be easy to make a 10 MW turbine, but it would have a poor capacity factor.  Our customers need simple, robust, reliable and efficient machines to minimize maintenance costs, which are a killer for offshore wind.” Alstom is targeting a maintenance interval of one year for Halidade 150.

Larger turbines need larger foundations and at depths of 30 metres and below, low-tech, relatively low-cost steel monopiles hammered into the seabed start to become impractical. Steel jacket foundations, which resemble miniature oil rigs, will play a significant role in Round 3. Martin Grant, head of energy at engineering consultant Atkins, which designs steel jacket foundations in conjunction with fabricators Burntisland Fabrications in Fife, says the UK is well placed to drive down the costs.

“Thanks to North Sea oil and gas, the UK already has a world-class supply base for foundations, with major skills centres in Fife, Murray Firth, Inverness, the North East and East Anglia. The offshore wind industry is now becoming sufficiently mature that commercially-driven research is driving innovation and, as happened with North Sea oil production, costs will come down significantly.”

The Alstom Haliade 150 offshore wind turbine is undergoing testing near Saint-Nazaire in NW France Courtesy Alstom

Construction risk uncertainty

The primary mechanism to support the construction of offshore wind farms is, of course, DECC’s Renewables Obligation. Offshore wind farms eligible for two Renewable Obligation Certificates (ROCs), although this subsidy will fall 5 per cent in 2015/16 to 1.9 ROCs and to 1.8 ROCs in 2016/17.

While offering generous support to offshore wind, the RO is not viewed by investors as yet sufficient to support construction of Round 3 due to the ‘known unknowns’ of construction and technology risks. There have been a host of setbacks to befall offshore wind farms in what are relatively shallow waters compared to Round 3.

The 504 MW Greater Gabbard offshore wind farm, for example, a joint venture between RWE Innogy and Scottish & Southern Energy (SSE), has been beset by a lengthy construction over-run.  The project, which involves the installation of 140 wind turbines located 25 kilometres off the Suffolk coast, was initially due to be commissioned in 2009 but is now due to be completed by the end of 2012.

The delay is primarily due to welding defects in 52 of the array’s ‘transition pieces’, which form a base upon which the wind turbine stands. The project has also faced construction delays due to the bankruptcy of subcontractor Subocean, the death of a worker, and even the controlled explosion of a 680 kg mine laid by a German ship during the Second World War.

Meanwhile, Danish utility Dong found that grouting in the foundations of 164 turbines at its Horns Rev 1 & 2 and Burbo Banks offshore wind farms had failed, necessitating costly repairs, while at the Swedish utility Vattenfall’s Kentish Flats array, some turbines are on their fourth gearbox. The additional complexity of Round 3 means that potential early-stage investors fear a significant risk of returns being heavily diluted by construction over-runs.

Green Investment Bank to the rescue?

Fortunately, there may be a white knight on the horizon in the form of the Green Investment Bank (GIB). Investors view GIB as having a crucial role to play in plugging gaps, such as where the private sector is unable to bear the full risks of Round 3.

“Our vision is to replicate the success of the ICFC (Industrial and Commercial Finance Corporation), which eventually became 3i,” says Anthony Marsh, head of transactions at UK Green Investments, set up by the Department of Business, Innovation and Skills to oversee the creation of GIB. “The idea is to give a final push to technologies deemed ‘nearly commercial’. That’s why the GIB has ruled out investing in onshore wind, which does attract finance, and marine energy, which is deemed not nearly commercial enough.”

Marsh says the bank could directly invest in Round 3 projects in partnership with the private sector to reduce construction risk through ‘learning by doing’, thus attracting a wider range of investors in the longer term.  “The plan is to prove it works so that private capital piles in and then we move on to another technology,” he says.

“The holy grail is to get institutional, long-term funds into the offshore wind sector who are not investing because they think the risk/reward profile is not appropriate. They need long-term certainty and we’re here to encourage them to have that.”

As the GIB sits on the Government’s delicate balance sheet, the Treasury has capitalised GIB with just £3 billion but after 2015, when the bank will assume full borrowing powers, liabilities are expected to increase substantially. Andy Cox, head of power and utilities at KPMG, believes GIB is the key to unlock the £100 billion required for Round 3, but not necessarily as a front-line investor.

“At this stage GIB needs to be a pioneer focused on financing first-of-a-kind type projects by underwriting construction risks via guarantees rather than capital.  There is liquidity in the market but investors are wary of taking credit risk.

“The GIB could stand behind primary project contractors, which would assume a certain level of over-run risks, with a second tranche of construction support. By assuming some of the construction risks more private capital will be forthcoming.”

Calculating some of the more exotic construction risks of Round 3 projects like weather windows and non-availability of vessels is proving such a headache that insurers are unable to step into the breach, according to Jerry Biggs, CEO of UK renewable energy finance and insurance company Narec Capital. “There are gaping gaps in insuring offshore wind farms and some projects have been uninsured,” he says. “This is particularly unpalatable for debt finance.

Biggs believes GIB should work with insurance companies and research institutions like Narec (National Renewable Energy Centre) to develop models to underwrite challenging debt structures and in turn lower the cost of premiums, which account for 26% of opex on average. “Once they have that knowledge base, insurers will then undercut each other and bring down premiums rapidly,” he says.

Artist impression of the Anemometry Hub to be installed at the UK National Renewable Energy Centre’s Blyth Offshore Wind Demonstration Site near Newcastle. Courtesy Narec

Testing, testing

Narec is one of four organisations granted approval by the Crown Estate to construct a demonstration site for the next generation of offshore wind turbines. Narec’s 100 MW, £333 million Blyth Offshore Wind Demonstration Site near Newcastle will comprise 15 ‘pods’, which developers will rent to test large-scale turbine prototypes, organized in three arrays at water depths ranging from 38m to 57m.

The site, due to be fully operational by summer 2014, will also feature an ‘Anemometry Hub’, a high-specification research platform fitted with the latest technologies for measuring wind resource and collecting marine conditions and marine life data.  Benj Sykes, DONG Energy’s director of UK wind power operations, believes demonstration sites such as Blyth are the key to driving down the costs of Round 3.

“We have investment partners including Dutch pension funds and Lego and to keep our partners happy we must have low-risk technology as well as low-cost technology,” he says. “The only way we can achieve that is by taking it out to sea. Supporting the technology through the demo phase mean that utilities like DONG will be able to deploy it with confidence.”

German utility RWE and GE are developing the ADELE system to compress air at times of high electricity availability and place the resulting heat in an interim thermal storage device and to inject the air into subterranean caverns. When electricity demand rises, the compressed air can be used to generate power in a turbine – while recovering the heat. Source: RWE

The first law of thermodynamics states energy cannot be created or destroyed, only transformed from one type of energy to another. The second law of thermodynamics states when an energy transformation is made, some of the energy lost as heat. That is why there can never be a perpetual motion machine and why energy storage technologies have hitherto struggled to gain traction.

Yet the UK is home to a plethora of energy storage companies attempting to battle these laws of thermodynamics via such technologies as compressed air, large batteries, cryogenics, flywheels and thermal storage. A recent seminar put together by EcoConnect – ‘Electricity Storage: Renewables’ Holy Grail’ highlighted a number of challenges that the industry needs to overcome before it can hope to compete with pumped hydropower as a reliable source of energy storage.

Here my top ‘takeaways’ from the event:

1. The UK Department of Energy and Climate Change (DECC) is to create an energy storage subsidy scheme

DECC hopes to support energy storage through a scheme of grants from this autumn. DECC’s Head of Innovation Delivery Ian Ellerington said: “We have just received business case approval for an energy storage scheme and we are working on the delivery plan. We aim to officially advertise for participants on 14 September and there will be £10-20 million available.

“I am also encouraging DECC’s electricity markets team to take energy storage into account so that there will be a marketplace for suitably developed technologies.”

DECC’s Head of Innovation Delivery Ian Ellerington

2. Commercial deployment of energy storage is going nowhere until changes are made to UK and EU regulation

The natural customers for energy storage are the Distribution Network Operators (DNOs), such as UK Power Networks and Western Power Distribution, which operate the 12 regional distribution areas. Being able to own/contract energy storage would enable the smoothing of the supply and demand peaks and reduce network reinforcement costs.

However, this would require some recognition that these regulated companies can be a market participant in intra-day transmission system dispatch in order to stimulate deployment. This is currently outlawed as it is the responsibility of the transmission system operator (TSO), i.e. National Grid, to balance networks at a regional level.

Furthermore, while there is nothing stopping TSOs owning energy storage, regulation may prohibit their usage, says Anthony Price, director of the Electricity Storage Association. “The EU says the power industry has to be vertically separated and disaggregated with no cross-subsidies yet demands that energy storage is operated by TSOs,” he said. “They could have storage, but it’s not clear how they could use it. There’s a great deal of investigation as to how to get the rules changed, but don’t hold your breath.”

Steven Fawkes, partner in Matrix Group’s corporate finance

3. The current business case for energy storage is challenging

Energy storage has high capital costs and low load factors, says Steven Fawkes, partner in Matrix Group’s corporate finance. “Part of the problem for investors is trying to put the demand response benefits of storage into a viable business case, as they occur in different areas and benefit different parties. So it’s very hard to have a regime and compile a business case that stacks up for grid-scale energy storage.

“It’s an equity investment play at present,” he said. ”Unless you have a medium- or long-term contract, such as a STOR (short-term operating reserve) contract from National Grid, there will be no debt finance for energy storage. It’s only for venture capital at present.  Energy technology is not like IT, it takes a very long time to develop and many investors are turned off by the delay.”

Gareth Brett, CEO of cryogenic energy storage system developer Highview Power added: “We’ve been at this since 2005 and spent £12 million to date, plus a £1 million DECC grant and we’re still trying to build a commercial demonstration project. It is likely to cost £20 million and we’re trying to find a host.”

Anthony Price, Director of the Electricity Storage Association

4. Energy storage could fundamentally change the way power is sold, so utilities are running scared

At present, utilities are rewarded on the basis of selling units of electricity. The more they generate and sell, the more they are profitable.  Storage technologies could be so disruptive and revolutionary the market could turn on its head, said Price.

“If everyone had their own generation and storage facilities, there would be no electricity market. But unless we can reform the market structure and regulation which currently absolutely locks out change, we aren’t going to be able to use these disruptive technologies.”

Clearly this is a very tough sell to utilities, says Highview’s Gareth Brett. “We’re trying to sell the future to a utility sector that is legendary for its conservatism,” he said. “No-one is going to get a bonus for installing #0001 of a new technology.

“Couple that with uncertainty over how the market will reward storage, or indeed a lack of market signals as to who would own storage facilities, and you have a real challenge. Utilities don’t want the lid blown off their economics and so gaining understanding of a disruptive technology is really very hard.”

Fawkes added it will only be when the giant power equipment OEMs like ABB, Siemens and GE adopt these technologies will energy storage will really take off. Partnering with such companies may be energy storage technology developers’ only hope, he said.

Gareth Brett, CEO of Highview Power

5. Energy storage throws up schemes at the outer fringes of sanity

Bernard Hanning of Skystream invited delegates to invest in his idea for a 1.5 MW solar-powered airship, which could be easily transported and plugged into the grid to be eligible for feed-in tariffs. As yet, there are no takers for Mr Hanning’s project.