ENERGY PERSPECTIVE 02

Here comes the sun – 12GW of it

POLICY 04

UK sees fall in 2015 emissions,

but total EU emissions rise

Clarity needed on Scotland energy targets: Scottish Renewables

Energy UK hails increasing bill accuracy

IEA warns more progress needed on green technology

REGULATION 10

National Grid kicks-off major gas transmission charging change

ACER calls for improvements to transmission planning process

INDUSTRY STRUCTURE 15

McKinsey tips storage to transform the power landscape

Shift underway in LNG pricing and trading

NUTWOOD 18

What should happen to UK energy policy? – Peter Atherton

MARKETS 20

Monday 05/06 – Ofgem confirms the successful go-live of Project Nexus. Renault and Powervault announce a partnership to re-use electric vehicle batteries in home energy storage units. The GMB union urges the government to develop new nuclear and gas capacity to guarantee energy security.

Tuesday 06/06 – The results of the Billing Code audit for 2016 show a strong improvement in the level of compliance by suppliers. Analysis by BVG Associates finds Europe could achieve between 64GW and 86GW of installed offshore windfarm capacity by 2030. Scottish First Minister Nicola Sturgeon welcomes increased spending on oil and gas innovation in 2016-17. The International Energy Agency finds there is a viable pathway to limit the rise of global temperature to 2ºC and see the global power sector reach net-zero CO2 emissions by 2060.

Wednesday 07/06 – National Grid confirms that some contracts for difference auction applicants remain non-qualifying after review. Smart Energy GB finds that smart technology is helping rural communities harness renewable energy and benefit from cheaper energy. Ten periods of negative electricity imbalance prices are seen overnight, with windfarms being turned down as wind generated nearly 7GW.

Thursday 08/06 – A general election takes place across the UK, with the Conservatives remaining the largest party but in a hung parliament. Business and Energy Secretary Greg Clark retains his seat, albeit with a reduced majority, while his shadow counterpart Rebecca Long-Bailey and Climate Change Minister Alan Whitehead increase theirs. Former Energy and Climate Secretary Ed Davey also returns to Parliament as MP for Kingston and Surbiton. Statoil unveils plans to allocate 15%-20% of its annual investments into new energy solutions in 2030, pledging to build a material position in profitable renewable energy projects and low-carbon solutions.

Friday 09/06 – Theresa May asks permission from the Queen to form a government. May will probably have the support of the Democratic Unionist Party, though there will be no formal coalition. As we go to press, Greg Clark is reappointed to his role as secretary of state for Business, Energy and Industrial Strategy.

Tom Crisp Editor

01603 604421 t.crisp@cornwall-insight.com

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Seven years ago, solar capacity in GB was negligible, standing at below 100MW. Today it has grown to over 12GW. As a result, photovoltaic (PV) solar achieved new generation records last month. Solar output is now becoming a key variable in setting wholesale and system

prices, and presents new balancing challenges.

In this Energy Perspective, we evaluate the impacts of these developments, concluding that the challenges are inevitable but should be manageable, and will also reinforce incentives for the development of much-needed flexibility.

Revolution

Solar projects to date have mainly been connected to the distribution network so there is no definitive record of aggregate capacity. However, the latest estimates created by National Grid and Sheffield Solar suggest that the total installed capacity passed 12GW at the end of March this year. Our own analysis of capacity deployed under the Renewables Obligation (RO) and Feed-in Tariff (FiT) scheme concurs, with 7.2GW and 4.5GW installed respectively by the end of March 2017. We expect 300-400MW more this financial year, including modest additions of 26.67MW from solar capacity awarded Contracts for Difference.

Figure 1 shows an estimate of how GB solar capacity has grown over time. The pace of deployment has slowed since 2016 due to the closure of the RO to small-scale solar, reduced FiT budgets and the introduction of deployment caps.

But the level of solar capacity overall has meant that the record for estimated peak solar output was broken twice during May. On 10 May, 8,480MW was recorded, breaking the previous record of 8,420MW set in May 2016. Output surged again on 26 May when it reached a new high of 8,910MW at 1.30pm. This implied a national load factor of 74%, and a record 24% share of production in one half-hour period.

A day in the life

Distribution connected generation including solar is accounted for by National Grid in its role as

system operator as negative demand on the transmission system, rather than generation. High solar capacity is already significantly changing the shape of demand. Solar generation often coincides with the post-lunch reduction in demand on the typical consumption profile. On days where there is a large solar effect, the daily peak demand typically shifts from the early evening to either 8-9am or after sunset.

The general solar demand impact during the day lowers the marginal demand required to be met at what have historically been peak periods. This pushes older, less efficient, thermal power stations out of merit in the generation stack, sending wholesale electricity prices down. On 26 May, the day-ahead baseload power price dropped to a near 8-month low of £37.50/MWh, with the peak power price a little higher at £39.40/MWh. Further, it caused a depression in within-day power prices, which fell below £30/MWh during the afternoon.

A hard day’s night

This “shaving”, and sometimes reversal, of the peak/baseload spread, combined with the reduced and changing shape of transmission demand means old stations either turn down and run at losses in the middle of sunny-days or even turn-off. They then will seek to recover losses in evening periods once solar generation diminishes.

The effect, as we have seen in big solar markets like Germany and California, is that while prices in the middle of the weekdays move lower than the historic norm, the prices in the evening, after dusk, could be much higher. This means more volatility even if overall prices might be lower. There are other distributional effects. As solar capacity has grown, the “captured” price of solar, being the generation weighted £/MWh price solar projects realise has declined compared to baseload thermal technologies: the so-called “cannibalisation” effect. The changing level of captured prices for solar PV versus a benchmark

Jonathan Davison Senior Analyst 01603 604432

j.davison@cornwall-insight.com

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basket of other technologies illustrates the increasing impact of cannibalisation. There has been a trend of solar premiums to baseload reducing since 2015, with solar earning less than coal, gas and nuclear on average (see Figure 2).

A little over 60% of solar is under the RO, where generators are exposed to wholesale price movements unless they can fix out prices under their Power Purchase Agreement (PPA) arrangements. By contrast FiT projects are insulated from moves in wholesale prices unless they opt-out of the regulated export rate. Therefore, the cannibalisation effect will be most felt by RO solar projects. However, a substantial proportion of RO solar projects enjoy PPAs with the ability to fix prices up to three years ahead. If such options are exercised, it may be the offtaker feeling the pain rather than the generator.

We can work it out

Solar has a range of impacts on the wholesale market, but our analysis suggests that whilst system operational demands increase, the impact on system security is probably manageable at the current level of deployment.

There are several theoretical challenges with high penetration of solar for system operation, primarily stemming from variations between opaque forecast output and actual production at times of relatively low demand.

There is also a potential frequency issue. Frequency of the electricity network – measured in hertz (Hz) – is determined and controlled by the real-time balance between system demand and total generation. If demand is greater than generation, the frequency falls; conversely, if generation is greater than demand, the frequency rises. National Grid is under an obligation to maintain the system within safe operating parameters, which is +/-1% of 50Hz. To manage frequency during the summer flexible, and even inflexible, generation may need to be reduced at times of high solar output.

Low system inertia is another related issue. Inertia is the system’s ability to resist immediate imbalance between power supply and demand. Low system inertia can be a primary symptom of high solar output, as synchronous generators turn-

off. A system with low inertia may require National Grid to take action to manage system frequency.

At the distribution network level, locational voltage increases to levels non-compliant with regulatory limits as reactive power demand decreases with higher levels of solar deployment.

Many of these challenges are now commonplace. At the summer 2016 Transmission Operations Forum National Grid showed the impact of high and long solar output. Using the example of 29 May 2016, it noted the number and volume of reserve and real-time balancing actions it had to take compared with a day of lower solar output.

National Grid’s Summer Outlook 2017 said underlying demand over summer would fall again, down 300MW compared to last year. It further highlighted that additional actions may be necessary to maintain appropriate system reserve and frequency levels at periods of low demand.

Specifically, National Grid sees an increasing summer need to procure negative reserve or “footroom”. This is the difference between expected generation and reduced generation to the level of typical stable export limits at periods of low demand. High solar output is leaving little natural, responsive footroom in the system.

National Grid has various levers available to it. In 2016, and indicative of the concern that existing options may be insufficient, National Grid launched Demand Turn Up, a new balancing service to deliver additional footroom. This service rewards those that can economically offer to flex their demand upwards between spring and autumn.

This is in addition to work National Grid has undertaken to create more resilience in frequency response through introduction of Enhanced

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Figure 2: Difference in solar captured price vs other technologies

Solar Difference Vs baseload Solar Difference Vs Wind

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Frequency Response. In August 2016, it tendered for 200MW of battery storage to deliver rapid response to frequency changes.

So, even if the demands being placed on the system during the summer are intensifying, the beefed-up tool kit appears to be coping. To date, there is little evidence of dramatic impacts on system frequency from solar output. If there were, we would be witnessing more summer Negative Reserve Active Power Margin (NRAPM) warnings.

Helter skelter

National Grid identifies the possibility of 13.5GW of solar capacity by the end of February 2018. But the slowing pace of solar deployment with the exclusion from CfD allocation leaves new capacity additions relying on subsidy-free business models. Some private wire developments, where value comes from sharing of avoided network and policy costs of the consumer, have been successful. A good example is the Lightsource 4.8MWp solar project at Belfast International Airport. However, these opportunities are not plentiful.

Despite flattening new capacity growth, the real test could be how the output from the rapidly formed solar fleet interacts with intermittent output from wind. There is currently limited experience of how the system will cope with the combination of high day-time wind and high solar irradiance. This combination intensifies the system balancing challenges already described.

National Grid’s own analysis in the 2016 Summer Outlook identified no distinct correlation between wind loads and time of day. Further, whilst July experienced the lowest wind load factors, relatively high wind loads have been experienced in March-April and September-October, coinciding with reasonable solar output. On 25 March transmission system demand during the daytime dipped below overnight demand for the first time in GB’s history, with the negative demand effect of solar being a major cause, despite it being spring.

On 7 June we saw a combination of high winds and relatively high solar output contribute to a record peak of renewable generation output of 19.3GW. 9.5GW of this came from wind, nearly double the National Grid average assumption for summer of 4.8GW embedded wind, and on top of solar output of 7.5GW. Consequentially, a NRAPM was issued for parts of Scotland, Demand Turn Up was utilised, and system prices bottomed out at -£24/MWh in early morning and remained low all through the middle part of the day.

The prospect of intensifying future demands is partly why National Grid is examining the requirements, interactions, opportunities for simplification and technical parameters of balancing services through the System Needs and Product Strategy (SNaPS). The SNaPs prospectus is expected to be published this month. There are also efforts to transition the role of Distribution Network Operators (DNOs) to Distribution System Operators (DSOs) to manage balancing services, including voltage and frequency, at a local level.

The models outlined in the Towards a Smart System Call for Evidence set out a possible template to follow. There are already pilots and projects in train at DNO level to manage voltage issues, an example being UK Power Network’s Power Potential Project, which looks to improve low-carbon connections, decrease operational issues in the network, and reduce the cost of managing constraints.

Come together

So long as National Grid and, increasingly DNOs, remain creative and responsive in SNaPs, none of the effects we describe here appear too negative or unmanageable. Lower average prices but higher volatility is not an unexpected outcome of higher variable renewable output. The consequential adjustments markets and the SO make to accommodate variable renewables are necessary if we are to continue to decarbonise. Of course, the distributive effects of changing wholesale markets will create pain and cost, mainly for thermal plants, which had anticipated capturing peak prices at higher loads.

But this, and the SO’s response to demands placed on it by this change, also create real and new opportunities particularly for flexible service providers to step up and efficiently respond to system needs. In the case of solar, the spotlight falls on storage and demand, two areas with low current use but with enormous potential to provide a positive contribution to the system as we move into the next decade. In that sense, there may be the happy outcome of making a virtue out of necessity and creating foundations on which the smart and flexible system that policy makers are aiming for can be built.

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Cory Varney, Writer, c.varney@cornwall-insight.com

New figures from the European Environment Agency (EEA) show that the UK showed the largest decrease of greenhouse gas emissions across the EU during 2015.

Published on 1 June, the figures also illustrated that total EU greenhouse gas emissions increased by 0.5% in 2015 – the first increase recorded since 2010.

The EEA said that this had occurred during the strongest annual economic growth in the EU since 2007 (+2.2%) and had followed a 4% decrease in emissions since 2014. The increase was attributed to increasing road transport, both passenger and freight, and slightly colder winter conditions in Europe, which led to a higher demand for heating.

Road transport emissions, which account for around 20% of total EU greenhouse gas emissions, increased for the second year in a row – by 1.6%. Meanwhile, emissions from aviation also increased, accounting for around 4% of total EU emissions, rising by 3.3% in 2015.

Gains made in the fuel efficiency of both new vehicles and aircrafts was not enough to offset the additional emissions that were caused by a higher demand in both passenger and goods transport.

In total, since 1990, total EU greenhouse gas emissions have fallen by 23.7% – if emissions from international aviation are excluded. If included, this figure is 22.1% – surpassing the EU’s 2020 target of reducing emissions by 20%. See Figure 1.

During the same period the EU economy grew by around 50%, demonstrating, the EEA noted, that long-term economic growth is possible while reducing greenhouse gas emissions.

The EEA explained that one of the main reasons behind the emission reductions since 1990 include the effects of EU and national policies, which have led to the growing use of renewable energy, the use of less-carbon intensive fuels and improvements in energy efficiency. Other reasons included structural change towards a more service-oriented economy, the effects of economic recession, and milder winters. Elsewhere, it was found that greenhouse gas emissions under the EU Emissions Trading System (EU ETS) decreased by 0.7%, excluding aviation, whereas emissions from the non-trading sectors rose by 1.4%.

The data also revealed that total energy consumption and energy-related emissions increased during 2015, as a result of more use of both natural gas and crude oil. However, the reduced use of solid fuels for the third consecutive year, together with the sustained increase in renewables (particularly biomass, wind and solar), has meant that higher emissions have been offset. It was noted that electricity production from hydro and nuclear declined for the year.

UK emissions fell to 505mt CO2e, remaining the group’s second largest emitter (12%). The driver behind the reduction in the UK’s emissions was continuing reductions from increased output from renewables, though emissions from transport offset some of the decrease.

While the UK showed the largest decrease of greenhouse gas emissions, Spain, Italy and the Netherlands accounted for the largest increases. Lower GHG emissions in the UK were, according to the paper, the result of liberalising energy markets, the subsequent fuel switch from oil and coal to gas in electricity production and the shift towards more efficient gas turbine stations.

The report further said that, despite the increase in emissions, the carbon intensity of the EU energy system declined. This was due to higher shares of renewables and gas relative to coal in the fuel mix. EU greenhouse gas emissions from refrigeration and air-conditioning decreased, signalling an end to an “almost exponential” increase of hydrofluorocarbon emissions since 1990.

The paper puts a positive slant on the reasons for change but weather, economic and structural changes are external variables.

EEA

Figure 1: Aggregated greenhouse gas emissions

Source: EEA

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Emilia Jagiello, Writer, e.jagiello@cornwall-insight.com

Trade association Scottish Renewables has called on the Scottish government to set out how it intends to meet the “ambitious” targets contained in the draft Energy Strategy.

In its response, released on 31 May, Scottish Renewables welcomed the high-level vision in the strategy but maintained that clearer action plans are needed to show how the ambitious targets will be achieved.

The draft Energy Strategy sets out a vision for the future energy system in Scotland in the period up to 2050. Specific targets include sourcing half of all of Scotland’s energy demand from renewables by 2030 as well as decarbonising the transport, electricity and heat sectors. The group broadly supported the policy mechanisms proposed. But it recommended that the strategy should further develop clearer action plans to describe the steps that will deliver the 2050 energy vision.

Scottish Renewables also noted the need to take a flexible approach to decarbonisation. But, to ensure this transition at minimal cost to taxpayers, businesses and consumers, it said that the government must secure a competitive energy market that delivers low-carbon power to replace retiring capacity.

The group also suggested that the government must deliver upgraded energy infrastructure to meet future demand from increased electrification of heat and transport systems.

Concerns over the lack of clarity about the future relationship between the UK and the EU were raised. It recommended that the government ensure that changes to this relationship ensure the UK and Scotland remain an attractive environment for investors.

Though Scottish Renewables stated that it understood that the strategy does not include all the work being undertaken to achieve the decarbonisation goals, it stressed that “a continuation of ‘business as usual’ is “unlikely to deliver the required increase in capacity”. It called for the government to undertake additional actions focussing on planning processes; networks and innovation; and maximising renewable heat projects.

In particular, one of the key barriers to renewable heat uptake is a lack of knowledge of the low-carbon heat options available and how they can be best utilised. As the Scotland Energy Efficiency Plan will be one of the main policy tools for achieving heat decarbonisation, it is essential that the policy considers how best to address this and adopt an effective educational awareness-raising campaign targeted at consumers.

The body recommended that, to achieve targets, the Scottish government should prioritise maximising the use of policy levers, such as planning, public procurement, building standards, business rates, innovation and project funding, to deliver the Strategy’s aims as well as maximising the electrification of the transport system.

Lindsay Roberts, Senior Policy Manager at Scottish Renewables, said: “It is […] imperative that the Scottish government provides clear action plans which show how the ambitious changes contained in the draft Strategy can be achieved. That certainty – particularly in the heat sector, which faces significant challenges – would provide confidence in market opportunities and help stimulate the private sector investments required for the targets to be met.”

Roberts welcomed the inclusion of the 50% ‘all-energy’ target: “Including that target in the final Energy Strategy would ensure that renewables can play a key role in meeting our climate change targets while maximising the jobs and investment that our sector can bring to Scotland.”

Separately, Scottish Renewables launched a response to the Scottish government’s draft Onshore Wind Policy Statement. Similarly, the trade association supported the further development of onshore but highlighted that further cost reductions could be made as well as facilitating a route to market for the technology.

Scottish Renewables has set out a detailed and thoughtful response to the Scottish government’s draft energy plans. While Holyrood has so far been able to deliver impressive levels of decarbonisation, the next phase of the strategy will need more fleshed out plans.

Scottish Renewables

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Tom Crisp, Editor, t.crisp@cornwall-insight.com

Millions of consumers are receiving more accurate energy bills, according to an audit by PwC of the Billing Code, released on Wednesday 6 June.

The Billing Code was introduced in 2006. It aims to drive improved standards of performance and to provide a common framework around which energy suppliers can build better processes and controls. Current members of the Code are: British Gas, EDF Energy, E.ON, npower, ScottishPower and SSE, who send over 200mn bills to customers per year.

Participating energy suppliers are judged against five key commitment areas:

• switching

• meter reading

• energy bills and statements

• payments and refunds, and

• back billing

Some of the specific commitments suppliers are required to achieve under the code include not asking customers to pay any extra for energy used – and for which through the suppliers’ fault no accurate bill was received – if more than one year has elapsed before the bill is produced. Suppliers must also obtain a meter reading on a regular basis, at least every two years and use an agreed meter reading to open and close accounts.

Commitments on energy bills include making sure charges on the bill accurately reflect current tariffs and that, when there is a change to the tariff, customers are charged correctly for energy used; and sending energy bills or statements in a simple format so that customers can understand how the bill is calculated.

The results of PwC’s Billing Code audit for 2016, the third year they have been published, showed a “strong improvement” in the overall level of compliance by the five established members. SSE has only recently joined the code, and PwC is separately performing a desktop review of their compliance.

One supplier, EDF Energy, maintained the highest “Gold” award (see Figure 1), while British Gas, E.ON and ScottishPower achieved “Silver” and npower achieved bronze. The awards recognised the

efforts suppliers have made to comply with the code, with a gold award meaning a supplier is fully compliant with all areas of the code.

Overall conclusions drawn from the audit showed that, in the majority of cases, suppliers have robust billing processes and controls in place, enabling them to bill their customers accurately. The auditors found many areas of good practice particularly when it came to meter reading and back billing where five members were fully compliant with the code.

PwC found the Billing Code governance framework, which suppliers use to ensure compliance with it, helped them identify billing issues before they became a serious problem.

PwC’s Dave Reeman PwC said: “This is the third year that we have undertaken the review of the processes and controls in place at the members to assess their compliance with the Billing Code. The results of our work show an overall improvement in the scores achieved in comparison to the two previous years with npower moving from not classified to Bronze. The improvements in scores reflect the efforts made by suppliers to strengthen their processes and controls to ensure they are in compliance with the Code and that their customers receive a positive experience with them.”

The expansion in membership and improving performance under the Billing Code are of course to be welcomed. We would expect to see pressure to further widen the membership going forward.

As the move to principles based regulation becomes clearer, some of the elements of the Billing Code could plausibly be incorporated into broader themes of treating customers fairly.

Energy UK

Figure 1: Billing Code audit results

Source: Energy UK

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Cory Varney, Writer, c.varney@cornwall-insight.com

Research by the International Energy Agency (IEA) has revealed that only three of 26 tracked clean energy technologies are currently on track towards interim 2°C scenario targets in 2025.

In a report released on 17 May, Tracking Clean Energy Progress 2017, the IEA found that electric vehicles (EVs), energy storage plus solar PV and onshore wind were the only technologies on track.

The IEA outlined how a “new historic record” had been reached in relation to the electrification of passenger transport, with over 750,000 (EVs) sold in 2016, lifting the global stock to 2mn.

Despite a slowdown in market growth of 40% in 2016 from 70% in 2015, the report said EVs remained on track to reach 2°C scenario (2DS) levels in 2025. But the technology is at “significant risk” of missing the 2020 interim milestone, increasing risk of not reaching the 2025 goal.

Storage technologies continued “rapid scale-up” in deployment, nearing 1GW in 2016 due to favourable policy environments and reductions in battery prices, while solar and onshore wind saw strong annual capacity growth continue. Over the medium term, prospects for renewable electricity were said to be “bright” due to cost reductions and policy improvements in key markets, although only solar and onshore wind are “fully on track”. Overall, renewables are still falling short of longer-term 2DS levels – even though generation grew by a record 6% in 2016.

The IEA explained that the “on track” status of these three technologies is dependent on all other technologies “pulling their weight” in the transition. As this is currently not the case, and should progress fail to accelerate, the report warned that the on-track technologies may have to progress “even more ambitiously” so as to over-compensate to ensure the overall energy transition is on track.

Although, sufficient progress has not been delivered in most technologies, 15 are ranked “orange” by the report. This means they are showing advances and 10 of these were said to have shown recent improvements.

Nuclear saw its highest rate of capacity additions since 1990 in 2016, with 10GW of capacity installed. Although progress, doubling that rate to around 20GW annually is necessary to meet 2DS to offset planned retirements and phase-out policies in

certain countries. Three years of growth in gas-fired power generation above the global 2DS targets of 2.4% have offset earlier declines in generation and gone some way to correcting some fragility of the growth path. Despite this, the report said additional progress is required in efficiency and flexibility performance of plants to stay on track with the sustainable energy transition pathway.

Elsewhere, industrial sector action needs to accelerate to meet the 2DS trajectory and keep annual growth in final energy consumption below 1.2% from 2014 to 2025, which is less than half of the average 2.9% annual growth since 2000. There has also been “a lack of sufficient progress” in aviation, shipping and road freight among other transport modes during 2016.

The report further outlined how eight technologies are in the red, meaning they are “significantly off-track” and require renewed policy focus. Just three saw significant, promising recent improvements over the past year. The report outlined how coal continues dominating power generation, with a share of over 40% in 2016. To stay on 2DS track, coal-based CO2 emissions must fall by around 3%/year to 2025.

Carbon capture and storage has continued to prove its viability across sectors through a global portfolio of large-scale projects. However due to lack of investment decisions, the pipeline of projects has effectively stalled. The IEA called for targeted policy incentives to drive large-scale CCS projects forward into deployment to meet the 2DS target of over 400mn tonnes of CO2 being stored per year in 2025.

The report also outlined how almost two-thirds of countries still do not have building energy codes in place, while good potential exists for a global shift to renewable heat – although the resource remains untapped. An increase in 32% for renewable heat would be required by 2025 relative to 2014 to meet 2DS goals.

This comprehensive breakdown details exactly what is needed by technology. It clearly flags the significant further progress that needs to be made if the interim targets are to be met.

IEA

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The Conservatives have fallen short of an overall majority in the General Election, creating a hung parliament. Theresa May visited Buckingham Palace on 9 June to request the Queen’s permission to form a government, after reaching an informal agreement with the Democratic Unionist Party. The Queen’s Speech is scheduled for 19 June.

Over the weekend details of the Cabinet reshuffle were announced. Greg Clarke remains Secretary of State for Business, Energy and Industrial Strategy but former Education Secretary Michael Gove replaces Andrea Leadsom as Secretary of State for Environment, Food and Rural Affairs.

Our latest blog “Ouch! My head Hurts …” sets out our initial thinking on the election outcome and the implications for the energy sector, which we will be examining in more detail at our 20 June customer event – The Post-Election Energy Markets: New Consensus or Continuing Paradox? To request a place, contact Richard Wetherall on training@cornwall-insight.com.

BEIS confirmed on 6 June that the second stage of the allocation appeal process for the second contracts for difference auction (CfD) has been completed, meaning the auction window is likely to be mid-August 2017. The next stage is for applicants to appeal again to Ofgem by 13 June, or for them to accept the decision.

The two scenarios for auction timings are:

• The CfD sealed bid auction window runs from 23 - 29 June (if there are no appeals to Ofgem), or

• The CfD sealed bid auction window runs from 14 - 18 August

BEIS and National Grid are to provide another update on 14 June after the next appeals window closes.

EMR Delivery Body

Two-thirds (66%) of Britons believe the UK should remain part of the Paris Climate Agreement, a survey carried out by the Energy and Climate Intelligence Unit (ECIU) has found. Two-thirds (66%) of Britons believe the UK should remain part of the Paris Climate Agreement, compared to 16% who feel the UK should leave.

Published on 26 May, the survey also found almost seven in 10 (69%) respondents said Parliament should retain the Climate Change Act 2008, while one in 10 (11%) said it should be replaced.

Commenting on the findings, former Environment Minister Richard Benyon said: “These are important facts to remember when lone voices claim in the media that Britain should repeal the Climate Change Act or quit the Paris Agreement. To do so would be neither in the wishes, nor in the interests, of the British people.” “Cross-party support for, and action on climate change, has also been key to developing British leadership on this issue, something which voters want us to maintain as we leave the European Union”, he added.

ECIU

The CBI has labelled the decision by US President Donald Trump to withdraw from the Paris Climate Agreement as “disappointing”.

In remarks released on 2 June, Michelle Hubert, CBI Head of Energy and Infrastructure, said it was now time for governments to affirm their commitment by turning global ambition into national reality by investing and innovating, British businesses could be “at the heart” of delivering a low-carbon economy, and the CBI called for domestic policies that demonstrate commitment to this goal. “As other nations start to play a greater role and increase their ambition, the UK needs a level playing field for carbon costs, so that our energy-intensive industries can compete effectively in a global, low-carbon marketplace”, she added.

CBI

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Oil & Gas UK has urged the UK government to support the North Sea oil and gas sector in its industry blueprint, Vision 2035, released on 31 May.

The document listed four priorities for the next UK government: ensuring the UKCS is globally competitive for investment, to make sure Brexit negotiations support, develop and promote the oil and gas industry; and establishing practical steps to protect, progress and promote operators, the supply chain and the industry workforce. The trade association said that, if its priorities were delivered, the sector could generate additional revenue of over £290bn for the UK economy over the next 20 years.

Deirdre Michie, Chief Executive of Oil & Gas UK, said: “While we are still managing our way through tough times we must also look ahead. Vision 2035 sets out a compelling future […] which could be unlocked for our sector if we continue to build on the good progress already made.”

Oil and Gas UK

Smart Energy GB has highlighted a series of smart energy projects in rural areas that are delivering savings and allowing the integration of renewable energy.

Released on 7 June, A Smart Energy Future for Rural Areas said there are a variety of community energy projects in rural areas seeking to use smart technology and data. The aims of these projects included:

• reducing overall energy consumption

• improving the stability and security of local energy supply

• increasing use of renewable generation

• increasing use of energy that is produced locally, and

• reducing consumer costs and fuel poverty

Sacha Deshmukh, Chief Executive of Smart Energy GB, said: “In some rural and remote communities, the impact of smart technology has been transformational in maintaining a delicate balance between energy supply and demand. In others, smart technology is playing a key role in potentially altering the balance between renewables and fossil fuel generation.”

Smart Energy GB

The GMB union has urged the government to develop new nuclear and gas capacity to “keep the lights turned on”, while questioning the reliability of solar.

In a press release, issued on 5 June, the union highlighted figures that revealed solar produced less than 10% of power for four months in the past year. It warned of the impacts of days of “low sunshine”, with the majority of these taking place during the winter months. The GMB said that the UK must “face up to the fact” that the UK’s wind and solar fleets combined produce no electricity for more than half the time and they are part of a balanced energy mix, not a panacea.

Justin Bowden, GMB National Secretary, said there was a need for base load electricity capacity “we can rely on”, until a breakthrough in “large-scale, economically viable and reliable solar or wind power storage”. “Until there is a scientific breakthrough on carbon capture or solar storage, then nuclear and gas are the only reliable shows in town which those advocating a renewables-only energy policy have to accept”, he added.

GMB

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Josephine Lord, Regulatory Consultant, j.lord@cornwall-insight.com

Following extensive work in the NTS charging methodology forum (NTSCMF), National Grid has raised a UNC proposal that seeks to ensure compliance with the EU tariff network code (TAR NC) and to produce stable and predictable gas transportation charges.

UNC621 Amendments to the Gas Transmission Charging Regime, raised by National Grid on 5 June, represents an important milestone in the development of the charging arrangements. Ofgem initiated a review of gas transmission charging in 2013 on concerns about the growing level of the Transportation Owner (TO) entry commodity charge, which could be discouraging imports into GB, and because of the need to take account the then developing European network code on harmonisation of gas transmission tariffs.

Since Ofgem’s initial policy view set out in November 2015, the NTSCMF has been working on a broad agenda of potential changes, which were subsequently given greater focus and direction in February by the regulator setting out its updated policy thinking on key elements of the regime. This included that there should be floating payable prices at all exit and entry points, with no commodity charge for under- or over-recovery of allowed revenue, and the reduction of reserve price discounts for short-term capacity at all entry and exit points.

The proposal argues that the current Reference Price Methodology (RPM) used for capacity, the Long Run Marginal Cost (LRMC) methodology, produces charges that are volatile and unpredictable, which causes challenges for investment decisions and for predicting operational costs for connected parties’ year-on-year. LRMC uses strong locational signals linked to continued investment, a principle National Grid said network users considered as being of limited use and not a significant factor in decision-making due to the lack of expansion of the NTS.

The industry working groups concluded that a methodology based on Capacity Weighted Distance (CWD), an approach that is compliant with the TAR NC, would better suit the current and future expectations for the NTS, being more predictable and less volatile and more suited to a system that is about use and revenue recovery associated to use rather than linked investment.

The modification therefore proposed the CWD approach; this would continue to provide some locational diversity in charges through the use of locational capacity and the average distances applied. It is proposed that there is one single approach for all charging arrangements, both for Interconnection Points and other exit and entry points. For transmission services revenue would be split 50:50 between entry and exit as now.

The modification explores the adjustment methodologies that could be applied to transmissions services (broadly TO allowed revenue). They include: RPM adjustments; multipliers; specific capacity discounts; interruptible pricing; seasonal factors; and other adjustments or charges. For example, in respect of capacity discount, the TAR NC requires at least a 50% discount for storage capacity to avoid double counting and in recognition of its contribution to system flexibility and security of supply. The level and application of discounts will be discussed as part of the modification process.

For some aspects of the non-transmission services charging (the System Operator charge), there are no proposed changes, including for the distribution network pensions deficit charge, the meter maintenance charge and the St Fergus Compression charge. This charge will be produced as a p/kWh charge as now, and recovered as a flat unit price for all qualifying entry and exit points.

National Grid has stressed that the package is not intended to be seen as a final view; this will evolve through assessment in the UNC modification process. Some areas represent firmer positions but all areas will be discussed and debated and the modification will be updated periodically to reflect emerging thinking. The TAR NC requires compliance for charging methodologies from October 2019.

The proposal will initially be considered by the UNC Panel on 15 June.

The modification, reflecting the detailed modelling and discussions in the NTSCMF, is very broad in scope and represents a significant overhaul of the current arrangements to ensure they are both fit-for-purpose and network code compliant.

Joint Office – UNC621 Joint Office - NTSCMF

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Rowan Hazell, Regulatory Analyst, r.hazell@cornwall-insight.com

The Agency for the Cooperation of Energy Regulators (ACER) has proposed a number of changes to the European Union’s Energy Infrastructure Package, which aims to improve the planning and implementation of electricity and gas transmission infrastructure.

In a position paper published on 31 May 2017, ACER Position on Potential Improvements to the EIP, ACER outlined three areas for improvement, all of which were previously identified in a paper from last June. It is hoped that the recommendations made will help to deliver the objectives of the EU energy strategy, and support the transition towards a more sustainable energy system.

Under current regulations, the European Network of Transmission System Operators for Gas and Electricity (ENTSOs) are required to submit Ten Year Network Development Plans (TYNDPs) to ACER for its opinion. These plans include scenario developments, which are assessed using a cost-benefit analysis (CBA) methodology. The scenarios and CBA results are used to guide Projects of Common Interest (PCI) selection, along with other infrastructure implementation processes. However, under the current framework, only generic provisions for the scenario development phase are provided. In addition, a complex and lengthy procedure for the development and adoption of the CBA methodology is used.

ACER suggested that it should be given the power to approve, request amendments to, or directly amend the ENTSOs’ Scenario Development Reports and CBA methodologies, and that it should also have the power to issue binding guidelines on the major deliverables relating to the CBA. ACER hopes this will improve the treatment of project promoters and the transparency of the process.

The Agency also set out recommendations for streamlining the monitoring activities of infrastructure projects and information requirements for the PCI selection process. ACER is required to provide various data, monitoring reports, and opinions relating to the TYNDPs and PCIs. However, the information required to deliver these requirements reaches the agency from various sources, and ACER only receives information directly when annual PCI reports are submitted.

As a result, a full coverage of the required information is often not possible. This is therefore an area that ACER has identified for improvement, and its proposals for improvement set out the need for infrastructure to be monitored more rigorously.

ACER called for it to be given increased powers to request all the information that is required to comprehensively monitor the TYNDPs, PCIs and other projects. It also proposed that National Regulatory Authorities (NRAs) such as Ofgem should confirm the accuracy of submitted information. With regards to the data required for the PCI selection process, the Agency proposed that regional groups use an ACER proposal to decide the information requirements for the selection procedure. It is hoped that this will bring higher consistency and avoid multiple reporting by project promoters and the ENTSOs. The proposals also state that if project promoters are unable meet the information requirements, then their bids should be withdrawn from the PCI process.

When carrying out regulatory tasks, NRAs also require a range of information from various sources. There is a particular need for accurate and up-to-date project cost information such as investment plan data. This information is used to produce regular reports on Unit Investment Costs (UIC). However, there is not a specific legal basis that allows NRAs to enforce regular data submissions.

To enable regular UIC reports, it is proposed that the legislation is changed so that infrastructure stakeholders are required to provide the data that NRAs and ACER need. Currently, there is a requirement for data to be submitted at set intervals. The new proposals would allow for flexible updates, with the legislation re-worded, permitting ACER and the national regulators to request data submissions on a regular basis.

ACER’s proposals build upon those set out in its 2016 position paper, and if implemented should see significant improvements to the European Energy Networks. The proposed requirement to streamline monitoring activities could set the standard for a more coordinated system in the future.

ACER

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The gas industry’s new central systems were successfully implemented and became fully operational on 1 June.

The 23-day cutover plan, which set out the high-level activities needed to be undertaken in the build-up and aftermath of the implementation was also undertaken successfully, with the status of the project remaining green throughout.

On 6 June, the central systems were able to return to business as usual, and Xoserve published an update on the progress of the transition. 38 market participants had confirmed to PwC that they had successfully deployed the Nexus code, but one participant remained at risk. The participant’s cutover was planned to take place on 4 June, and PwC was attempting to make contact to determine the cutover status. Three market participants were late in reporting cutover completion, and PwC was contacting them to obtain updates.

Ofgem reflected on the success of Project Nexus in a letter published on 2 June. The co-operation between Xoserve, Ofgem, and the assurance partners PwC and Baringa was highlighted as being vital to the success of the implementation.

The regulator encouraged the continuation of a spirit of collaboration between partners, stating that this would be vital to the transition period as the new system beds down and responsibilities transition back towards Xoserve.

Xoserve Ofgem

2,182 accreditations were made under the Domestic Renewable Heat Incentive (RHI) from February to April this year, bringing the total number to 55,461 since the launch of the scheme in 2014.

Ofgem E-Serve published the latest quarterly update on the scheme on 31 May 2017, covering Q4 of scheme (year three). It is estimated that since the scheme launched over 1,702,926MWh of renewable heat has been generated by accredited systems – saving over 4.8mn tons of CO2 over the scheme’s lifetime.

Since the last quarterly report was issued on 28 February, the total payments to biomass schemes breached the £100mn mark and remained the most funded technology. Payments to ground-source heat pump, air-source heat pump and solar thermal technologies bring the funding total to £186.4mn. Air-source heat pumps were the most popular technology in Q4 2016, with 1,413 new accreditations.

The update also revealed that 340 RHI accreditations had been granted to registered social landlords during the reporting period, with air-source heat pumps accounting for 332 and solar thermal installations accounting for 8. To date, over £10.05mn in payments have been made to social landlords under the scheme.

Ofgem

Applications from two offshore transmission owners (OFTOs) seeking to have subsea cable failures classified as Income Adjusting Events (IAEs) were rejected by Ofgem on 31 May.

The Thanet and Gwynt y Môr windfarms, which are both jointly owned by Balfour Beatty and Equitix, submitted applications in June 2016 seeking to recover costs from failures to cables on their export circuits. The Thanet event took place on 23 February 2015, and saw a fault caused by the interaction between fibre optic cable and power cores.

The OFTO claimed that the failure was a result of manufacturing defects. The failure at Gwynt y Môr took place on 2 March 2015, and was thought to have been the result of damage to copper conducting cable and the fibre optic cable running alongside it. The licensee believed that they had been mechanically damaged prior to the transmission assets being transferred, either during storage or the manufacturing process.

Extensive repair work had to be undertaken at both sites to repair the cables, amounting to £11.7mn in costs at Thanet and £10.3mn at Gwynt y Môr.

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The OFTOs believed that the cable failures were unavoidable and should be classed as IAEs, allowing them to alter their incomes to reflect the repair costs. Ofgem disagreed, arguing that the evidence suggested that the OFTOs had not fully adhered to good industry practice, and that the risk of failure was reasonably foreseeable.

Ofgem - Gwynt y Môr Ofgem - Thanet

Countries across the EU could face electricity supply/demand imbalances this summer, ENTSO-E has said. Published on 1 June, the Summer Outlook 2017 report raised particular concerns around Italy and Poland but said GB is likely to have sufficient supplies.

In Italy, generation adequacy will have to be monitored following the closure of several power stations. Italian transmission system operator Terna has counter-measures at its disposal, “but a risk still exists of some planned load shedding in case of very strong heat waves and low hydro reserves,” the ENTSO-E said.

While Poland imports solar power from Germany to cover its peak demand, ENTSO-E said imports are limited “due to unscheduled flows through the Polish system”. Poland’s TSO could invoke demand side response or increase power imports, but ENTSO-E said these measures may not be enough to balance the grid and that load shedding could be needed. But the Polish TSO is of the opinion that implementation of a capacity market in Poland would help limit risks.

For Great Britain, the report forecasts summer minimum demand to be 17.3GW – 500 MW lower than the 2016 weather corrected outturn and reflecting a “continuing fall in electricity demand on the transmission system, with both lower peak and minimum demand levels”. As a result, ENTSO-E saw it likely that generators may be required to curtail output in peak periods. It also expects there to be sufficient generation and interconnector imports to meet demand peaks over the summer months.

Its analysis was conducted against the background of an evolving generation landscape with an increase of 13GW of variable wind and solar generation and a decrease of 9GW of controllable, mainly thermal generation between this summer and last. The report also contains an analysis of winter 2016-17, in particular the tight situation experience in western continental and in south-eastern Europe in January.

ENTSO-E

On 31 May ACER issued its fourth report on contractual congestion in the European gas transmission network, a situation in which levels of firm capacity demand exceed the technical capacity.

ACER identified congestion at 9% of the entry and exit sides of Interconnection Points (IPs). This year, only 23 sides of the 247 IPs analysed were congested compared to 41 out of 246 in the previous report. However, for another 55 IP sides the Gas Year 2017-18 product was not offered in 2016, whereas in 2015 only 23 IP sides were in a similar condition.

ACER said this meant that it is difficult to assess whether contractual congestion has improved overall in Europe. At the congested points, it found a slight increase of Firm Day-ahead Use It or Lose It (FDA UIOLI) was observed, and no application of Oversubscription and Buy Back was identified.

The Agency made a number of policy recommendations that included the European Commission consider amending the Congestion Management Principles Guidelines to review how full effectiveness can be achieved, particularly if they are applied as a preventative measure before contractual congestion occurs. It said more flexibility regarding the application of FDA UIOLI has been requested by a number of National Regulatory Authorities and is desirable.

ACER

Our latest Chart of the Week looks at new market entry in domestic energy supply.

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Cory Varney, Writer, c.varney@cornwall-insight.com

Low-cost storage has the potential to transform the power landscape, bringing with it “profound” implications, according to consult McKinsey.

Storage prices are already dropping much faster than expected, with battery-pack costs falling to less than $230/kWh in 2016, creating both challenges and opportunities for utilities the authors claimed.

McKinsey already believes storage to be economic for a large number of commercial customers to reduce peak levels of consumption. But today’s lower prices are beginning to see storage play a broader role in energy markets, shifting from niche uses, such as grid balancing, to broader ones, such as supporting renewables integration. Combining solar with storage – allowing households to make and consume their own power, rather than export to the grid – is also beginning to become an attractive opportunity for customers.

The economic value of battery storage varies by application, though McKinsey said the majority of these are expected to evolve and grow. For example, for utility and market applications, wholesale energy arbitrage, renewable energy technology firming and smoothing and load following are all expected to increase in economic value by 2020, as are reserve capacity and transmission, and distribution investment deferral. Storage and solar self-consumption is also expected to grow in economic value.

For those behind the meter – meaning small-scale installations located on-site, such as in a home or business – McKinsey said cheap storage will become increasingly disruptive. This is due to different combinations of storage and solar which will likely be able to arbitrage any variable rate design that utilities create.

McKinsey referenced net energy metering rules and feed-in tariffs, which both allow excess power to be sold back to the grid at favourable rates. Although helpful to solar, this has placed pressure on utilities. It reduces demand as consumers make their own energy, increasing rates for the rest with fewer bill payers to cover fixed investment in the grid, which provides backup reliability for solar customers. These customers are therefore paying for their own energy but not the full reliability of being grid connected. Utilities have designed rates

to reduce the incentive to install solar in response. However McKinsey warned that in a low-cost storage environment, such rate structures are unlikely to be effective.

This is because customers continue receiving close to full retail value for their solar generation, owed to how storage allows customers to shift solar generation away from exports to cover their own needs. This situation risks widespread partial grid defection where customers opt to stay connected to the grid, having that 24/7 reliability, but generate almost exclusively their own energy (80%-90%) – using storage to optimise solar for their own consumption. While full grid defection is not currently economical, McKinsey said it may make sense in some markets sooner rather than later.

In contrast, utilities in front of the meter – large-scale installations used by utilities for a range of on-grid applications – can benefit from storage through it helping them address challenges of planning and operating the grid in markets where loads are expected to be flat or falling. This would allow utilities to defer expensive new investments and reduce the risks of long-lived capital projects not being used. Utilities are also acting to procure storage assets, which addresses both long-term regulatory requirements and short-term needs.

To cope with how low-cost storage is changing, McKinsey called for utilities to disrupt themselves – or risk others doing this for them. To achieve this, it recommended two categories of action. The first of these being redesigning compensation structures and exploring new opportunities, as regulators and utilities will need to find new ways of recovering their investment in the grid. It called for utilities to use expanded services and new transaction fees to capture new earnings opportunities. The second course of action recommended was rethinking grid-system planning, something utilities must “radically change”, according to McKinsey. This would involve investing in software and advanced analytics to modernise the grid.

This is a useful statement of how storage technology is improving all the time and fundamentally changing the basic parameters of electricity markets around the world.

McKinsey

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Natalie Cole, Wholesale Analyst, n.cole@cornwall-insight.com

We are currently witnessing a paradigm shift in the way LNG is priced and traded around the globe industry, analyst Platts has claimed.

The US LNG: A Benchmark for the Future report, which was published on 1 May, claimed that momentum for shorter-term trading and “foreseeable” over-supply in the global LNG market will fuel the transformation of global LNG trading and pricing.

The price of LNG is currently determined by four commodities: Henry Hub, National Balancing Point (NBP), Platts Japan Korea Marker (JKM), and oil-indexation. Traditionally, oil indexation has dominated contracting for LNG, linked to North Sea Brent crude or Japan Customs-cleared crude, because of the liquidity and transparency of these markets. However, market participants now seek a pricing mechanism that reflects the supply and demand of the commodity being traded, meaning oil indexation is now losing ground to gas and LNG indexation. In Europe, the NBP has provided a deep and liquid market for pricing LNG cargoes.

In 1964, Shell shipped the first major shipment of LNG, from Algeria to the UK. Since then, LNG has typically been sold under long-term contracts, which were mostly priced off oil-indexation. The mechanism linked today’s gas price to the average oil price during a period before. Over the next four decades, LNG continued to be mainly sold under long-term contracts, despite the significant growth of the market.

However, since the new millennium, short-term LNG trading – defined as transactions under contracts of four years or fewer – has increased to around 30% of the market. Of these short-term transactions, half are now accounted for by spot transactions – defined as trades whereby cargoes are delivered within 12 months.

Platts explains that, since 2008, the outlook for natural gas in the US has switched, as market supplies increased. Driven by the combination of horizontal drilling and hydraulic fracturing methods.

This switch has led to five new LNG export terminals being developed. All five are being converted from existing LNG regasification terminals for imports, meaning projects are classed as brownfield. From permitting, time, infrastructure

and economic perspectives, these brownfield sites made US export projects much more competitive with other LNG liquefaction projects in development around the world.

An additional factor enabling US LNG to become more competitive compared to other LNG contracts around the world, is destination flexibility. LNG contracts usually have destination clauses which specify the delivery location, meaning cargoes cannot be diverted. However, US LNG contracts do not have destination clauses. This means that when LNG is loaded from US terminals, it can be diverted to countries paying a premium for the commodity.

Platts Analytics’ Eclipse Energy data showed that global LNG supply capacity hit an all-time high of 1.16bcm in February 2017. Platts forecasted US LNG capacity to multiply by almost three times by 2020, which would make it the world’s third largest LNG exporter, behind Qatar and Australia.

The combination of large volumes of flexible US LNG, and a diverse range of US LNG offtakers and the flexibility associated with these contracts, will have a profound impact on liquidity and transparency of the global LNG market.

These factors, combined with the desire for different pricing mechanisms for LNG, as well as the current and forward price transparency the newly introduced Platts Gulf Coast Marker and the ICE LNG futures contract will bring, mean that there is a real opportunity for US LNG to play a key role in global LNG pricing in the future.

The expansion of the global LNG market, the changes to the pricing structure and trading, as well as the increasing prevalence of US LNG, is especially important for the GB market, which is becoming increasingly reliant on LNG imports.

According to the latest data available from BEIS, LNG imports accounted for nearly a quarter of UK gas imports in 2016. This is particularly during times of lower available gas supply from other sources, even for example the ongoing issues at Rough gas storage facility.

Platts

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Between Q1 2016 and Q1 2017 levels of embedded generation increased 6%, an Electralink study has found.

The analysis of market settlement data, published on 31 May, showed that a significant proportion of this growth was due to the increase in solar PV and wind installations. In March 2017, the generation attributed to these sources increased 33% on the previous year.

National Grid predicts that 50% of generation will come from embedded sources by 2030. Generation from these sites can be intermittent and difficult to predict, and a proportion of power often also used on site, meaning that National Grid must account for the net output of generation minus on-site usage. Electralink highlighted one such example from May 2017 whereby poor weather caused renewable generation sites to under-produce, triggering a spike in the imbalance price to £1,510/MWh.

Head of Network and Energy Market Insights at Electralink, Dan Hopkinson, said: “Balancing supply and demand requires National Grid to accurately forecast embedded renewables and given the rapid development of this type of generation, near real-time embedded generation data detailing what is being generated and where is very valuable to the marketplace.”

Electralink

A new project, set to become Europe’s largest, and the UK’s first, battery flywheel system is set to be connected to the Irish and UK grids, the project partners announced on 2 June.

The collaboration between the University, Schwungrad Energie, Adaptive Balancing Power and Freqcon is expected to cost €4mn, with €2.9mn of the funding to come from the EU’s Horizon2020 scheme. The first trial will take place in Ireland before the equipment is scaled-up and installed at the University of Sheffield’s energy storage facility in Wolverhampton.

The technology converts surplus electrical energy to stored rotational energy by running a rotor at high-speed. It can then be immediately converted back to electrical energy when demand requires. Unlike traditional battery storage, flywheel systems experience minimal degradation over time, making them an attractive proposition as energy storage becomes more central to European energy markets.

Dr Dan Gladwin from the University of Sheffield said: “the UK national grid is becoming increasingly volatile due to the rising share of intermittent renewable energy sources […] Battery and flywheel technologies can offer a rapid response, and can export and import energy enabling this technology to respond to periods of both under and over frequency.”

University of Sheffield

Tidal project owner Atlantis Resources has successfully raised £4.05mn through the placing of 9mn shares at 45p/ share it has been announced.

In a statement released on 24 May the company confirmed it is intending to use the proceeds to identify and develop new opportunities, progress existing projects – including its MeyGen tidal array in the Pentland Firth – as well as general working capital and debt repayment.

On 31 May the company also released its final results for the year ended 31 December 2016. Group loss for the year was £7.3mn – a decrease of £9.3mn on the previous year’s profit, which took into account gains arising from the acquisition of Marine Current Turbines (£9.2mn) and the disposal of a 50% stake in Atlantis Operations Canada (£0.9mn).

Atlantis Resources

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UK energy policy has remained largely unchanged since 2003 when the then Labour government signed up the UK to the EU’s Greenhouse Gas (GHG) Reduction Directive. This Directive set the UK onto a policy pathway that had changed little in the following 13 years. The Directive committed EU countries to meeting a series of stringent targets for reducing GHG, with the end position being an 80% reduction by the year 2050. Policy makers decided very quickly that to hit this target the electricity generation sector in particular, and the energy sector in general, would need to be the vanguard sector to “de-carbonise”.

The reason for this was twofold, first policy makers believed that technologies to de-carbonise power generation were already sufficiently advanced to roll-out at the utility scale required. Second, by de-carbonising power first, other key sectors notably transport and heat could in turn be de-carbonised by moving them away from gasoline and natural gas onto the electricity system. All governments since 2003 have pursued this pathway and adhered to the timetable. Specific policy instruments to deliver the targets have of course seen considerable evolution as some have failed to deliver expected outcomes and others have thrown up unintended consequences.

Both the Conservative and Labour manifestos committed to continuing this pathway. So, a fundamental review or change in direction in policy is highly unlikely in the coming parliament, especially with the probability of a hung parliament. However, both parties do accept that some new thinking and changes to the way policy is being delivered is necessary.

The politics of energy policy

To consider what might happen going forwards, it is important to understand the wider political context. There remains wide-spread political consensus on several broad principles upon which policy is being framed.

There are three key areas of political agreement:

• tackling climate change should remain a core priority and that the energy sector should be in the vanguard. The pathway set out in the 2003 Directive and the Climate Change Act 2008 remains intact

• domestic energy supply is an essential service and a homogeneous product. Therefore,

political tolerance for significant price differentials between consumers is low and particularly it is not acceptable for the poorest customers to pay the highest prices, and

• whilst the pathway to decarbonise energy retains broad support there is also a general acceptance that policy instruments must take better account of value for money and security of supply.

As such any attempt to reform energy policy must take into account this political consensus – reforms that work contrary to one of more of these areas are highly unlikely to be adopted.

What has worked and what hasn't

To identify reforms that could improve the balance and execution of energy policy, it is worth briefly considering which policy instruments tried so far have been a success and which have not.

Policy Instruments that have not worked include:

• government choosing specific technologies and then negotiating directly with developers

• smart meter program

• new nuclear programme,

• the Green Deal.

But those that have worked:

• CfD auctions

• carbon price floor, and

• network regulation.

The lesson, perhaps, is that grand government schemes should be avoided.

Things that may happen anyway

Another thing to take into consideration is what developments may happen regardless of government policy?

These are by their nature very difficult to predict accurately, especially in terms of their timing and scale of impact on the energy market. The key thing for policy makers is that they should not frustrate or hinder these developments – and not ignore them. They include:

• shale gas and oil. The remarkable performance of US shale gas / oil produces in recent years strongly suggests that their disruptive influence

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will continue for at least the next decade but probably much longer. Therefore, the government should anticipate abundant global supplies of gas and oil at prices similar to today

• generation technology. In the first 70 odd years of power generation up to WW2 the economic solution was to build power station in the centre of towns and cities because it was cheaper to move the primary fuel to the power station than to move the electricity across country to the towns.

In the 70 years post WW2 this changed drastically and the economics dictated that very large power stations be built on top of the primary fuel and the electricity sent over a national grid to centres of demand. Some argue that developments in distributed generation and storage are about to reverse the trend and move us back to a power system dominated by small local power stations. This is certainly feasible (although not yet certain), and

• batteries and electric vehicles (EVs). Whilst this is closely linked to point two above, the development of battery technology and EVs are being driven by many commercial factors outside the power sector. Nevertheless, these are potentially disruptive technologies that could profoundly re-shape the power sector.

Policy themes and principles

As I have stated above, the continued political consensus on tackling climate change makes a

radical shift in energy policy in this parliament highly unlikely. But there is certainly scope to reform and deliver better outcomes, and there are a number of themes and principles the next government could adopt.

They include:

• grandiose government designed programs don't work - see Green Deal, FID’s, smart meters and Hinkley Point C for example

• auctions do work

• avoid arbitrary and fixed timetables for delivery as these tend to distort decision making

• ensure policy does not stand in the way of long-term global and technological trends, and

• don’t do anything that the public is not willing to pay for.

Drawing on these themes, one option is to expand the auction principle to all sectors of the economy. The government would say that it wanted to eliminate say 200mn tones of GHG emissions. Companies and agencies across many sectors would bid to achieve this. The cheapest solutions would win.

Cornwall associate Peter Atherton is a well-known equity analyst having headed utility research at several eminent City institutions, most recently Jefferies, and is a respected energy commentator.

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All near-term gas contracts experienced gains last week, as a weaker pound following the General Election supported prices. A weaker pound against other currencies increases the cost of importing gas.

Week-on-week, the day-ahead contract gained 2.2% to 37.5p/th, amid an undersupplied system. Lower temperatures throughout the week led to higher residential gas demand.

The month-ahead (July) contract rose 3.0% to 37.3p/th. The contract is now 3.0% above its level this time last year (36.2p/th).

All seasonal gas contracts increased last week. Winter 17 gas climbed 2.4% to 46.4p/th. Summer 18 gas went up 1.4% to 40.1p/th. On average, seasonal contracts rose by 1.9%.

Most near-term baseload power contracts increased last week.

An exception was day-ahead baseload power, which dropped 7.1% to £36.0/MWh. The contract slid to a near nine-month low on Tuesday of £35.8/MWh as record levels of renewables generation at peak times pushed spot prices lower.

The month-ahead contract (July) increased by 0.8% to £39.7/MWh.

The majority of seasonal baseload power contracts experienced gains last week, following gas prices higher. Winter 17 power climbed 2.0% to £46.7/MWh. On average, seasonal baseload contracts moved higher by 1.1%.

Brent crude oil prices dropped 3.8% to average $49.0/bl last week. On Friday, prices dropped to a six-month low of $48.0/bl, amid concerns over increasing US crude inventories and rising oil production from Libya.

API 2 coal lifted, and was up 0.9% to average $67.5/t. On Friday, prices reached a three-month high of $68.5/t. Coal prices were supported by higher Chinese demand, as the country increased its steel production. Higher coal-fired power generation in the US also lifted prices.

EU ETS carbon prices lowered 0.5% last week to average €5.1/t. Prices were driven lower by falling oil prices and a rise in selling by traders.