Targeted Charging Review decision

Ofgem has published its decision on the Targeted Charging Review.

Background

Ofgem has two main projects that serve as a review of transmission, distribution and balancing charges to facilitate a transition to a more effective network. These are:

  • The Access and Forward-looking charges review is looking at the ‘forward-looking charges’. This sends signals to users about the effect of their behaviour and encourages them to use the networks in a particular way; and
  • The Targeted Charging Review (TCR). This examines the ‘residual charges’ which recover the fixed costs of providing existing pylons and cables, and the differences in charges faced by smaller distributed generators and larger generators (known as Embedded Benefits).

Specifically, the TCR has evaluated two elements of network charges within the Significant Code Review (SCR) process. These are reforms to how residual charges are set and the non-locational Embedded benefits.

Decision on Residual Charges

Ofgem has decided to implement a fixed residual charge for final demand consumers. These will be levied for transmission charges in 2021 and distribution charges in 2022. These are characterised as a series of fixed bands, including a single fixed charging band for domestic consumers and a range of fixed charging bands for non-domestic customers.

For transmission charges, charges for non-domestic consumers will use a series of fixed charging bands set for all of the country.

Changes to distribution charges will see domestic consumers pay a single residual charge set for each licensed area. Non-domestic consumers will be charged on the basis of a set of fixed charging bands also set for each distribution area.

Bands for non-domestic customers will be determined by a consumer’s voltage level. Where further segmentation is required, further boundaries can be defined based on agreed capacity for larger consumers with readily available data, and net consumption volume for smaller consumers.

The series of fixed charging bands will be published at a national level and will then be set for each Distribution Network Area. Ofgem will review and revise these charging bands and their boundaries as appropriate so that the outcome of such reviews can be implemented alongside of new electricity price controls.

Ofgem believes this to be the strongest option of those considered, as it is the least avoidable leading to minimised harmful distortions. The regulator received feedback from stakeholders supporting its view that the option would help achieve a positive balance across the charging segments.

Decision on ‘non-locational’ Embedded Benefits

The key purpose of the review of Embedded Benefits was to reduce harmful distortions which impact competition and the efficiency of the electricity market. In order to meet this objective, Ofgem has outlined a three-step process to achieve a full reform:

  1. The implementation of partial reform in 2021, to deliver the benefits to consumers by removing the two Embedded Benefits (the Transmission Generation Residual which will be set to zero and the offsetting of suppliers’ balancing services charges by reducing the Suppliers net imports at the Grid Supply Point) which cause harmful distortions.
  2. The launch of a second taskforce to consider the application of the TCR principles to balancing services charges.
  3. The second taskforce’s work and resulting modifications should deliver reforms to balancing services charges.

Implications for Triad

Ofgem has decided that the reform to transmission residual charges should be implemented in 2021 and distribution residual charges in 2022. The regulator believes that this is an appropriate compromise between addressing the largest distortions within the market to deliver consumer benefits, while reducing the distributional impacts on consumers.

A preferred implementation option of April 2021 for transmission residual charge reforms will eliminate the incentive for Triad avoidance in the following winter periods. This leaves one final Triad season to take place over Winter 20/21.

How this may affect consumers

Through the TCR residual charging reforms, Ofgem aims to reduce the distortions caused by the current system. This encourages network users to take measures to lower their contributions to residual charges.

Where residual charges incentivise behaviour – such as load reduction which reduces the share of charges paid for by that user – this results in an increase in the share to be paid by other network users. This in turn increases the incentive for other users – who then pay an increased proportion of the residual charge – to take action to reduce their charges.

It is Ofgem’s view that all final demand users who benefit from the electricity network should pay towards its upkeep in a fair manner.

Under the final TCR decision, Ofgem expects the cost of maintaining the electricity grid to be spread more fairly. As a result, the regulator says that consumers will save £300m yearly, from 2021, with £4bn-£5bn in cumulative consumer savings up to 2040.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the timeliest updates you can find us on Twitter and LinkedIn.

Market shrugs off highest energy demand of the season

The UK has recently experienced three straight weeks of below seasonal-normal temperatures. The colder than normal weather combined with low wind generation and ever darker evenings have driven up energy demand. Last week saw UK gas and power demand rise to their highest levels for the winter so far. This was driven by a significant increase in domestic consumption as households ramped up their heating to combat the cold.

Minimum temperatures in London dropped to minus 2 degrees, the lowest since early February. In parts of Scotland, temperatures overnight reached lows of minus 10 with another cold spell forecast for next week.

Temperatures

Year-on-year gas demand

Overall gas demand reached 350mcm. This is the highest since early February, with domestic gas consumption rising to over 240mcm as households increased heating use. Year-on-year gas demand was 100mcm higher as November 2018 saw the UK enjoying a late heatwave with a prolonged spell of above average temperatures. This kept gas demand under 250mcm.

LDZ Gas Demand

The increase is even more prevalent in LDZ gas demand. This has averaged 190mcm/d so far in November, the highest in more than five years. Domestic gas demand in November is so far 45% higher month-on-month. It’s 20% higher than the same period in November 2018.

LDZ gas demand graph

October gas demand was also the highest in over five years with consumption up 20% since 2017. As a share of overall gas demand, LDZ has also climbed strongly in recent months. Domestic use accounts for over 70% of the country’s overall gas consumption.

Gas is also playing an increased role in the electricity sector, which adds another element to this winter’s higher gas demand. Demand from power stations reached 78mcm last week, the highest since January. Electricity generated by gas power plants has averaged 14.9GW per day in November. This is the highest since January and an increase of 2GW on November 2018. This is despite a continued trend of reduced electricity demand from 2018 to 2019. Lower wind output, which is on average 1.5GW lower year-on-year is contributing to the increased gas use for electricity generation.

Monthly generation graph

The last time domestic gas demand was close to this high was in 2016. Front-month gas prices climbed nearly 30% as temperatures dropped in early November. In November 2018, front-month gas prices averaged 50p/th – 25% higher than the current Dec 19 contract.

However, so far this winter, gas prices across the curve have moved lower, breaking below a long-standing trading range. The December 19 gas contract has fallen 20% since the start of October, while the Summer 20 prices are at their lowest level in over 18 months.

Gas months graph

 

High demand no match for supply flexibility

If demand is higher then why has the price reaction been muted or even bearish? Increased gas demand from home heating and the electricity sector during the last three weeks of cold temperatures have seen very little price support. This is because the impact of the increased consumption has been entirely offset by the levels of spare and flexible gas supplies available to the market. This is notably from an influx of LNG tankers and record high levels of gas in storage. Supply levels are persistently matching fluctuations in demand with flexibility from Norway, LNG and storage helping to manage the higher demand levels seen recently.

LNG Imports

The UK has enjoyed an influx of LNG arrivals this winter, with Britain an attractive destination for tankers amid an oversupplied global market for the fuel. Fifteen tankers arrived in October, eighteen tankers are booked for November and seven arrivals are confirmed for December. LNG imports for Q4 2019 have already surpassed levels from Q4 2018.

lng imports graph

The influx of LNG and flexibility from Norwegian and UK gas flows have left storage withdrawals and Interconnector imports struggling to get gas onto the grid. Both sources offer around 150mcm of combined gas supplies which can be attracted to market when required. It is this extent of spare capacity available to the gas system which has kept prices so depressed, in spite of rising demand levels.

Gas Storage Withdrawals

Storage withdrawals had averaged 8mcm/d for the winter and colder temperatures last week lifted that withdrawal rate to around 40mcm/d. The potential for sendout is over 90mcm/d across the country’s seven facilities.

However, even with last week’s increased withdrawals – which have seen reserves declining at 0.4TWh per day – stocks are still at record highs for the time of year. European storage stocks are also at all-time highs, after surpassing 1,000TWh in September, with zero net withdrawals recorded so far this winter.

gas storage graph

European imports via the Interconnector have been untouched, with gas prices unwilling to increase to a sufficient premium over the European market to encourage deliveries. If the price response was sufficient, however, an additional 60-70mcm per day of gas could be available. This is further strengthening the health of the current gas system and its flexibility in responding to spells of higher demand.

With the extent of spare capacity available, the gas system is able to manage prolonged spells of below seasonal-normal temperatures. It will likely take a severe cold snap, alongside a breakdown in supply or a slowdown in LNG imports to warrant a significant rebound in prices across the energy market.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the timeliest updates you can find us on Twitter and LinkedIn.

Loose gas creating tight margins in the power market

Gas has led the way, particularly in the balance of winter contracts. These falls have come partly due to the very high levels of storage but also because of all the spare capacity that could be called upon if required. As a result, power prices have fallen due to the lower fuel cost.

LNG has been the main game changer with the deluge of tankers flooding in to Europe over the last year. Increased export capacity in the US and Russia has led to the increase in extra imports to Europe. It is also a symptom of the global oversupply in the worldwide market place. The liquid commodity markets and high import capacity make the UK an ideal location to offload any excess supply. LNG terminals are currently operating at 75% of their capacity, with all the extra gas being sold into the NBP pushing prices lower.

 

LNG imports graph

LNG imports graph

European imports have been virtually non-existent throughout the winter but more gas could be attracted through these pipes. There is a potential capacity of 94 MCM/d to come over the BBL and the Interconnector. To start attracting this gas the premium over TTF would firstly have to rise above the NBP entry charge of 1.56p/th and then cover the cost of using the pipelines. This means that if prices increase their premium over the continent to more than 2p/th additional gas will start coming to Britain.

 

IUK flows with Belgium
IUK flows with Belgium

 

Given the competition between supply sources, storage just cannot make it onto the grid, even on higher demand days, and this capacity overhang is weighing on prices.

 

Gas spare capacity graph

Gas spare capacity graph

However, the falls in prices for power have been less substantial and purely driven by the falling cost of fuel. Fundamentally the UK grid is seeing some of its tightest conditions in years. With nearly 3GW of coal capacity having retired in the last 12 months. The remaining coal units are now running as baseload and all flexibility is coming from gas. There remains spare capacity but this is the least efficient or most costly plant.

On windless, cold days we are seeing some stress on the system. Currently Monday, 18 November, has a negative margin with 300MW still required to meet anticipated demand. This has pushed power prices to their highest since February at £54.50MWh.

 

Power capacity graph
Power capacity graph

 

On Wednesday evening we saw the highest demand of the winter so far, of 45.2 GW. The above chart shows where generation was coming from at the peak on the left, with remaining output available for Monday on the right. While this shows the potential generation that could come on at the current price levels, it isn’t expected to on Monday, hence the negative margin.

So far Monday’s price reaction has been relatively muted, but it has occurred at a time when the gas systems oversupply is weighing heavily on the whole energy market. If it was happening amidst different market conditions the price outlook would be very different.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the timeliest updates you can find us on Twitter and LinkedIn.

How the clock change impacts UK energy demand

The clocks are scheduled to go back one hour this Sunday 27th October. The change will cause an obvious shift in usage of the electricity system as evenings draw in earlier in the day.

It also accelerates the seasonal trend towards higher demand during the colder, darker winter months, placing increased pressure on power margins. This can lead to spikes in electricity prices, should supplies struggle to meet the higher demand.

 

Jump in demand decreases as overall downward trend continues

As forecasts currently stand, the average peak demand for the week following the clock change will be 4.4% higher than the week before. Consumption is expected to rise by almost 2GW as lighting usage increases during the traditionally higher post-work demand period.

 

Average Weekday Peak Demand Weekly average before Clock Change (GW) Weekly average after Clock Change (GW) Difference (GW) Increase (%)
October 2019 (Forecast) 38.9 40.6 1.7 4.4%
October 2018 40.0 43.6 3.6 9.0%
October 2017 40.7 43.7 3 7.4%
October 2016 42.2 44.8 2.6 6.2%
October 2015 43.9 45.2 1.3 3.0%
October 2014 43.0 44.0 1 2.3%

 

However, the forecasted rise in average peak demand in 2019 is lower than in recent years. Notably 2018 which saw the highest percentage change, as consumption rose by almost 4GW week-on-week.

Overall peak power demand has been dampened marginally this year, with consumption after the clock change peaking at 40.6GW on average, 3GW lower than last year. This reduction can be attributed partly to half-term school holidays, which fall on the week either side of the clock change depending on school catchments. Higher renewable levels have also contributed to reductions in demand.

The ongoing trend in reduced energy consumption year-on-year continues, meaning that demand is rising from a far lower base. Improvements in energy efficiency have been helping to reduce electricity use over the last ten years. A large part of the reduction in peak demand has been the use of new technology, resulting in smart and more efficient appliances, able to do more with less.

Expected demand before this month’s clock change is 5GW lower than the highest peak in 2015. Furthermore, the forecasted post-clock change peak is the lowest on record.

 

Graph displaying electricity demand during the clock change

The role of renewables

The increase in wind and solar capacity in recent years has contributed to the overall demand reductions. Higher volumes of on-site renewable capacity allow more generation to be provided off-grid as homes and businesses generate their own electricity supply during windy or sunny spells. This reduces demand on the national transmission system. The high levels of solar availability during the summer season were a particularly strong influence on demand levels this year as on-site solar panels increased embedded generation. This reduced demand requirements for the transmission network.

Wind power continues to deliver a growing percentage of the UK electricity mix. By the end of September 2019, the UK’s fleet consists of over 10,000 wind turbines with a total installed capacity of over 21.5GW. Overall wind generation in the UK has so far been 33% higher through 2019 than over the same time period last year.

 

Graph showing monthly wind generation

What happens when there’s no wind?

While high winds have the capability of cutting power demand, one of the biggest dangers to the National Grid electricity network is a high demand scenario, at a time when wind output is very low.

Lighting has a bigger impact on electricity demand than heating, as the majority of home heating is gas-fired. However, during severe cold snaps, electricity demand does spike as additional heating is needed to cope with the very low temperatures. This scenario occurred during the Beast from the East cold snap in February last year. However, robust winds provided high levels of low cost electricity to the grid.

A lack of wind would see supply margins placed under significantly more stress during a similar cold snap this winter. This would require additional supply being provided by gas and coal plant or imports to make up for the increased demand. Such a scenario is likely to require significant price rises in the Within-day and Day-ahead markets.

The National Grid’s Winter Outlook for 2019/20 expects that there will be a sufficient supply margin to accommodate a wide range of security of supply scenarios. However, the organisation’s statistical 1-in-20 peak demand forecast predicts a demand of 499mcm/d, greater than the highest recorded gas demand. This is an unlikely scenario, but demonstrates how a period of high demand and low renewable availability could coincide to increase short-term prices.

An end to the clock change?

There have been proposals dating back to 2015, from members of the European Parliament, to end summer time observance. In September 2018 the European Commission proposed an end to seasonal clock changes, asking that member countries decide by March 2019 which time they would observe year round. The proposal was approved in March 2019, by 23 votes to 11. However, the start date has been postponed until 2021 to allow a smooth transition.

The United Kingdom is due to leave the EU before the reform becomes effective, meaning that it would be left to the government to make their own decision on observing summer/winter time. If continued, Northern Ireland would have a one-hour time difference for half the year with either the Republic of Ireland or the rest of the UK. The House of Lords launched an inquiry in July 2019 to consider the implications of this, with a call for evidence ongoing.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the timeliest updates you can find us on Twitter and LinkedIn.

Climate Emergencies and Net Zero – what you need to know

Global scientific data supports action

The action follows a highly critical 33 page report publicised in 2018 by the Intergovernmental Panel on Climate Change (IPCC). The IPCC is the United Nations body for assessing the science related to climate change.

The report focused on the impact of limiting global warming to 1.5°C. Limiting warming to 1.5°C rather than 2°C significantly reduces the climate change risks according to Professor Jim Skea, who co-chairs the IPCC.

What’s alarming is the scale of the challenge ahead of us to ensure we achieve these targets and do not allow the situation to escalate further.

Five steps to achieving the 1.5°C have been announced:

  1. Global emissions of CO2 need to decline by 45% from 2010 levels by 2030
  2. Renewables are estimated to provide up to 85% of global electricity by 2050
  3. Coal is expected to reduce to close to zero
  4. Up to seven million sq km of land will be needed for energy crops (a bit less than the size of Australia)
  5. Global net zero emissions by 2050.

Paris Agreement

The Paris Agreement brings together nations towards a common cause to undertake ambitious efforts to combat climate change. It was originally signed by 196 countries back in 2016.

In line with the IPCC report its core aim is to keep the global temperature increase this century well below 2°C above pre-industrial levels. In particular, to pursue efforts to limit the temperature increase even further to 1.5°C.

2019 – a watershed year for climate change?

Together with the impact of Greta Thunberg – the 16 year old Swedish activist – there have been a number of key factors driving the climate change movement this year. At Glastonbury festival in June 2019, 2,000 festival goers joined protestors to stage a procession across the site.

At the United Nations Climate Action Summit in late September you may have missed the news that Russia, the world’s fourth largest polluter will finally join the agreement. This announcement was overshadowed by the stirring “You have stolen my dreams” headlines surrounding Greta Thunberg’s appearance. Hailed as “the voice of the planet” she’s already been nominated for the Nobel Peace Prize.

Despite the raised awareness there are real fears that most of the world’s biggest firms are ‘unlikely’ to meet the targets set. Only a fifth of companies remain on track according to fresh analysis by investment data provider Arabesque S-Ray. Of 3,000 listed business only 18% have disclosed their plans.

UK reaction

In reaction to the IPCC report, UN Paris Agreement and other related research findings and movements, the UK public sector is taking positive, proactive steps to mitigate climate change risks.

Councillor Carla Danyer led the charge in Bristol by first declaring a climate emergency and this has sparked a wave of similar responses.

In June 2019, the UK became the first major economy to pass a net zero emissions law. The new target will require the UK to bring all greenhouse gas emissions to net zero by 2050. Net zero means any emissions would be balanced by schemes to offset an equivalent amount of greenhouse gases from the atmosphere, such as planting trees or using technology like carbon capture and storage. Other countries setting similar targets include Ireland, Denmark, Sweden and France as well as the US state of California.

Many UK councils, NHS Trusts and universities have publically declared their long term targets. Some aiming for speedier action by declaring net zero 2030 targets. These include Ipswich Borough, Vale of Glamorgan and Telford & Wrekin councils.

Unsurprisingly, Bristol University is one of the leading educational facilities leading the way. To date they’ve cut carbon emissions by 27% and are well on their way to achieving their target to become carbon neutral by 2030. The University of Cambridge, along with others, has set a net zero target of 2038 and has announced it is adopting science-based targets. On one website – climateemergency.uk – 228 councils are listed as having signed up to the targets.

In Boris Johnson’s first speech as Prime Minister, he affirmed the UKs commitment to a net zero future. Johnson proclaimed “Our Kingdom in 2050… will no longer make any contribution whatsoever to the destruction of our precious planet brought about by carbon emissions,” he said. “Because we will have led the world in delivering that net zero target.”

Steps towards a better future

According to the Centre for Alternative Technology (CATs) Zero Carbon Britain research a modern, zero emissions society is possible using technology available today.

Below we’ve outlined some key initiatives that can help the UK achieve its net zero ambitions:

  • Businesses implementing science-based targets.
  • Improving built environment efficiencies. Upgrading old buildings and ensuring new buildings must meet higher energy efficiency standards.
  • A shift to electric vehicles and the continued battery storage revolution.
  • Decentralised energy. Home and local energy generation.
  • Shift to renewable energy sources.
  • New policy.

The Aldersgate Group issued a green policy manifesto to Boris Johnson on 1 August 2019. They are a politically impartial, multi-stakeholder alliance championing a competitive and environmentally sustainable economy. Members of the group include Friends of the Earth, BT, M&S, Tesco, National Grid and Sky. Their green manifesto focuses on 4 key areas for the government to take decisive action and provide greater policy detail:

  • Delivering a Clean Growth Strategy Plus (CGS+) that matches the ambition of the net zero target. This should consist of a targeted update to the existing Clean Growth Strategy to increase ambition where required (for example on zero emission vehicle roll-out). Plus it should incorporate concrete policies that accelerate private sector investment to decarbonise priority sectors. These include surface transport, buildings and support the competitiveness of industry during this transition.
  • Passing an ambitious Environment Bill that safeguards environmental protections currently enshrined in EU law. They believe it must set ambitious and legally binding targets for environmental improvements in line with the vision of the 25 Year Environment Plan.
  • Implementing the Resources and Waste Strategy, through the introduction of detailed regulatory measures and fiscal incentives that drive greater resource efficiency and cut waste across the economy.
  • Building on the Green Finance Strategy, to rapidly grow private capital flows into the green infrastructure required to deliver the UK’s net zero target and the objectives set out in the 25 Year Environment Plan.

Our view

At EIC we believe new government policy is one of the most important steps needed to turn sentiment into action. Legislation relating to major energy users such as ESOS and SECR are steps in the right direction but they aren’t enough. Without doubt more effective policy is needed, to not only ensure energy and carbon is measured, but also that carbon reduction strategies are developed and implemented across the UK. Too often business cases for energy and carbon reduction are created and filed, never to be signed off.

What has caused September price swings?

Concerns over supply, demand and flexibility within energy markets ahead of the highest demand period of the year were highly price supportive.

Black Swans

In less than a week of trading, front-month gas prices climbed 25%, and the corresponding power contract rose 15%.
The Winter 19 power contract spiked £4.55 in just one day, while Winter 19 gas jumped over 6p/th, the largest daily move on a seasonal contract since at least 2008.

gas season prices

The initial price spikes were triggered by the simultaneous discovery of three ‘black swans’, an industry term describing unpredictable events that go beyond normal expectations of the situation.

season power prices

A fourth such event occurred a few days later when rebels attacked Saudi Arabian oil facilities. Brent and WTI crude oil prices saw the highest within-day spikes in 30 years, with both markets gaining more than $8/bbl in one day. The jump in the oil market provided more bullish support to the wider energy mix, with longer-dated gas and power contracts moving to new highs on the back of the increased oil costs.

crude oil prices

As these unpredictable events have developed, energy prices have given back some of the exceptional gains. However, prices remain elevated across the month, above the lows seen in early September. Here we explain what these issues were and how they are impacting on the energy market.

Groningen Gas

The Dutch Government reported that the production cap at its Groningen gas field will be lowered to 11.8bcm for the upcoming gas year from 1 October 2019. The state also confirmed that the site – previously Europe’s largest – would close entirely by 2022, eight years earlier than expected.

groningen gas production

Production at the field has been gradually slowing for seven years after drilling led to a series of earthquakes, forcing legislation to limit output. In 2013 the field was producing 54BCM/y, declining to 11.8BCM for 2019/20. While the reduced supply from Groningen was somewhat expected within the market, supply was expected to be available for another eight years. This curtailment helped to support a sudden price rise across the curve.

dutch gas production

The loss of production has been reflected in the loss of flexibility within Dutch gas supply, and therefore reducing the ability to respond to spikes in demand or other supply issues. Five years ago Dutch gas production was able to ramp up to 277MCM/d in response to high demand on a cold day. However, production last winter peaked at just 164mcm, while output so far in September 2019 has averaged under 50mcm/d.

OPAL Pipeline

The OPAL pipeline in Germany connects the Nord Stream pipeline with connections in central and western Europe. This month the European Commission overturned a ruling in 2016 which had effectively allowed Russian giant Gazprom a near monopoly of the volume of the pipeline, with 90% access. A complaint from neighbouring countries, led by Poland, saw this ruling challenged and the Russian transit through the link must now be cut to 40%.

The OPAL pipeline had allowed Russian gas to reach central Europe via Nord Stream and onwards, without transiting war-torn Ukraine. The EU decision will see Gazprom’s access cut by half, potentially reducing the availability of Russian gas to enter Europe, unless other transit routes are made available.

French nuclear power plants

EDF reported welding issues with at least five of its nuclear reactors, which could force shutdowns of the power stations. This would greatly reduce available power supplies for France, where 80% of its generation is supplied by nuclear and the majority of domestic heating is electric. Demand for imports will increase as will demand for more expensive and less efficient gas and coal plant, which also increases the consumption of carbon.

The UK’s interconnection with France sees imports from France provide the marginal supply to Britain, ensuring the countries’ pricing is closely aligned. Issues with French nuclear manufacturing had previously occurred in autumn 2016 when over 40% of France’s nuclear fleet closed down. This caused record spikes in UK power prices, with the Day-ahead market at over £150/MWh, and the front-month contract doubling from £40/MWh to over £80/MWh.

UK day ahead power prices

The potential loss of nuclear generation adds significant risk to the coming winter, particularly if tighter power supplies coincide with cold, windless weather conditions when gas demand is already at its highest levels for the year.
Since the initial announcement, EDF Energy has confirmed just six nuclear reactors are affected by the welding issues identified. The company believes no immediate action is required, an announcement which triggered a pull back in prices. However, the ultimate decision on whether to close nuclear plants for repairs lies with the French nuclear regulator ASN.

Saudi Arabia oil attack

The last piece of news impacting energy markets in September was a series of rebel drone attacks on major Saudi Arabian oil processing facilities at Abqaiq and oil fields at Khurais. The United States has blamed the attack on Iran, but Tehran claim no involvement. US-Iranian tensions were already heightened after a failed nuclear power agreement last year and attacks on oil tankers in the Middle East.

The rebel attack in Saudi Arabia forced around 7 million barrels per day of production offline, halving the country’s output and impacting on more than 5% of global oil supply.

However, Saudi Arabia confirmed it met customer orders by tapping into substantial storage reserves. Furthermore, the affected facilities would be back to pre-attack volumes by the end of September. Tensions remain heightened in the region but the swift return to operation of the affect facilities prompted oil prices to drop back from the earlier peaks.

Price Outlook

Uncertainty lingers over these issues, despite fresh developments so the potential for further price spikes remains in play. However, within the recent volatility on energy contracts, prices across gas, power, oil, coal and carbon remain within a sideways range. In fact, the majority of contracts range-bound since the start of the summer season.

The threat of a break below this range has been mitigated by the recent price spikes. However, the highs reached in July have yet to be tested. How the energy market breaks out of this range will determine future price action.

Renewable Obligation mutualisation costs added to customer bills

What are mutualisation costs?

To ensure that the Renewables Obligation (RO) scheme runs smoothly, Ofgem calculates a buy-out price and mutualisation ceiling. Where suppliers do not present a sufficient number of Renewables Obligation Certificates (ROCs) to meet their obligation in the reporting period, they must pay the equivalent buy-out price of the shortfall into a buy-out fund.

This fund is used to cover the administration costs of the scheme. It is distributed proportionally to suppliers based on the number of ROCs they produced towards meeting their individual obligation.

The mutualisation ceiling is set for the yearly obligation period. Mutualisation is triggered in the event of a relevant shortfall, meaning that the remaining costs must be distributed across the industry’s other suppliers apportioned to their market share.

What this means for customers

The 2017-18 period saw a shortfall of £58.6m, leading Ofgem to announce it would tighten rules for new market entrants.

Following this and a spree of market exits again, in the compliance year 1 April 2018 to 31 March 2019, not all suppliers met their obligation. This resulted in some of these suppliers also failing to make the subsequent buy-out payments into the required fund.

As of October 2018, Ofgem revealed a combined shortfall of £102,903,066.44 in the England & Wales, Scotland and Northern Ireland buy-out funds.

This means that remaining suppliers will be required to pick up the shortfall, following redistribution of late payments. Suppliers will be required to pay their share of the mutualisation pot, which totals £57.8 million. Therefore customers can expect to see an increase to the RO portion of their energy bill as suppliers apply one-off charges to those with contracts through the 2017-18 period.

EIC Forecast

At EIC, we track the Renewables Obligation and the many other Non-commodity costs, through our forecasts. If you’d like to find out more you can contact us here or call 01527 511 757.

Winter energy price cap level to see bills fall

The impact on customers

The new level will see the default price cap fall from £1,254 to £1,179 (over a 6% drop). The pre-payment meter cap will fall from £1,242 to £1,217 per year (around a 2% drop).

Ofgem expect energy bills to fall this winter for around 15 million households. Exact savings for each household will depend on; the cost of their current deal, how much energy they use and whether they use both gas and electricity.

The justification for this decrease has come from a significant fall in wholesale prices between February and June 2019. Healthy market fundamentals, record gas storage stocks, and periods of low demand across the last winter all contributed to this.

Households are able to cut their bills further by comparing tariffs to find the cheapest that will suit them.

The price cap moving forwards

Ofgem plans to update the level of the cap in April and October every year in order to account for the latest costs of supplying electricity and gas.

The price cap is a temporary measure, to be in place until 2023 at the latest. This allows Ofgem time to implement further reforms to make the energy market more competitive, enabling it to work more effectively for all consumers.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the most timely updates you can find us on Twitter and LinkedIn Follow us today.

Visit our webpage to find out more about EIC Market Intelligence and how we keep our clients informed at a frequency to suit them.

 

 

How will Brexit impact on the energy industry?

More than three years have passed since the United Kingdom voted to leave the European Union. Debate is still ongoing over the process of our departure, any possible “deal”, payments or a transition period. However, following his appointment to Prime Minister, Boris Johnson has hardened the UK’s negotiating position, promising that the UK will leave the EU on 31 October 2019, deal or no deal. Here we attempt to provide some insight into how this may impact various facets of the energy industry.

The energy sector in the UK had already seen significant changes with the Energy Act 2011 and various proposals for reform of the electricity market. The possible impact of Brexit on the UK and global economy could be far-reaching. However, the direct impact on the energy industry is likely to be more muted. Oil and gas markets are traded on an international level and the EU has little influence over the make-up of a member state’s energy mix. There will be no danger of blackouts or supply shortages and in the short-term you may see little day-to-day change. However, the longer-term outlook for post-Brexit energy may be altered, with one of the major issues being the UK’s relationship with, or role within, the EU’s Internal Energy Market (IEM).

The EU Internal Energy Market (IEM) – will Britain stay a part?

The IEM is a borderless network of gas and electricity transfers between EU member states. Common market rules and cross-border infrastructure allow for energy to be transferred between countries tariff-free.

Post-Brexit, Britain is likely to have less influence over EU energy regulation but will be able to adopt a different, potentially lighter, framework for its energy polices. The extent to which the UK still adheres or follows the EU energy regulation will be dependent on any ‘deal’ reached before the deadline.

Continued access to the IEM is a key priority for the UK Government in its Brexit negotiations. This would allow the country to continue to take advantage of various benefits associated with the IEM including increased security of supply, market coupling, cross-border balancing and capacity market integration.

Having recognised the benefits of the IEM the Government is seeking to retain as free as possible access to internal market and to maintain a strong influence on energy within the EU.

Plans to increase interconnectivity with the Continent are continuing and enhancing with many new interconnector links currently in development (see below). Irrespective of negotiations, this will require close co-operation with the EU Internal Energy Market going forward.

However, there are some inconsistencies in regards to UK plans encompassing full membership of the IEM. Continued participation is likely to involve the UK adopting various European legislation, which may not tally fully with UK judicial ambitions unless the UK remains part of the institutions which handle EU energy regulation (ACER, ENTSO-E and ENTSO-G for example).

Will Brexit impact on connectivity between the UK and Europe – what about interconnectors?

The ongoing negotiations regarding the UK’s 2019 exit from the E U, are having no real impact on developments, with four new interconnector links now under construction.

The Government wants to see all the current planned projects through to operation, the majority of which will not be completed until after the UK has left the EU in 2019. Former Business Secretary Greg Clark had indicated he was keen for the UK to remain in the EU’s I E M, although the final result will depend on the outcome of Brexit negotiations.

Regardless of the outcome, the UK’s energy networks’ connections to the EU will remain in place. The Government recently posted guidance on the trading of gas and electricity with the EU if there is no Brexit deal. The publication highlights that there are only small changes expected to interconnector operations. Interconnector operators have been advised to engage with relevant EU national regulators to confirm any requirements for the reassessment of their access rules.

The main area that may see impact is for proposed interconnectors, which are still in stages of project development, without final financial decisions. Uncertainty caused by Brexit, surrounding commercial, regulatory and operational impacts, will likely see planning stages re-visited to adjust for these challenges.

The UK may lose access to the Connecting Europe Facility (CEF) going forward. The CEF help to provide funding for interconnectors across Europe through targeted infrastructure investment. The Government have confirmed that any commitments that have already been made by the CEF regarding interconnectors into the UK will be safe following the UK’s withdrawal. However, it is not clear whether companies in the UK will be able to seek investments for new projects.

How will Brexit impact on the carbon market? Will the UK be part of the EU ETS?

The Government has published plans for the implementation of a UK carbon tax in the case of a ‘no-deal’ Brexit. Under a ‘no deal’ scenario, the UK would be excluded from participating in the EU ETS. This would mean current participants in the EU ETS who are UK operators of installations will no longer take part in the system.

In this instance, the UK government will initially meet its existing carbon pricing commitments through the tax system. A carbon price would be applied across the UK, with the inclusion of Northern Ireland, starting at £16/tCO2, less than the current EU ETS price, maintaining the level of carbon pricing across the UK economy post-Brexit.

The tax would be applied to the industrial installations and power plants currently participating in the EU ETS from 4 November 2019. The aviation sector would be exempt from this tax.

Will EU state aid rules still apply to the UK?

Unless the UK remains part of the European Economic Area (EEA), then the EU state aid rules would no longer apply. The Government has said it will transfer existing EU state aid law into domestic law after Brexit. The Competition and Markets Authority will take over responsibility of state aid enforcement. Going forward UK rules may diverge from the EU but the extent of this will be limited by the terms of a future UK-EU trade deal. In the immediate aftermath of Brexit, no significant change to state aid rules are expected.

How will Brexit affect the nuclear sector?

The UK indicated its intention to withdraw from the European Atomic Energy Community (Euratom) and the associated treaty (the Euratom Treaty) on 29 March 2017 as part of the Article 50 withdrawal process.

A report from the House of Lord’s energy sub-committee in January 2018 highlighted the potential for this withdrawal to impact UK nuclear operations such as fuel supply, waste management, and research.

However, the Government has made clear withdrawal from Euratom will not affect nuclear security and safety requirements. A Nuclear Safeguards Bill was introduced to Parliament in October 2017, highlighting how this will be achieved by amending the Energy Act 2013.

The Government will also continue to fund nuclear research in the UK, through programs like the Joint European Torus, Europe’s largest nuclear fusion device. Going forward, the UK will negotiate nuclear cooperation terms with other Euratom and non-Euratom members.

Will Brexit affect the UK’s climate change targets?

The UK passed law in June to reach Net Zero carbon emissions by 2050. The country’s climate change targets will remain unchanged, regardless of whether a Brexit deal is reached. However, there are expectations that potential economic impact from a no-deal Brexit may act as a significant hindrance to decarbonisation efforts.

Additionally, there are several international issues in this area which will need to be settled. The UK’s emissions reduction target forms part of the EU target under the Paris Agreement and this will need to be withdrawn. The UK would also need to submit its own Nationally Determined Contribution under the United Nations Framework Convention on Climate Change (UNFCCC) processes. It is yet to be determined whether the UK will continue to participate in the EU ETS post-Brexit but plans under a no-deal scenario were outlined in the October 2018 budget.

The House of Commons Business, Energy and Industrial Strategy Committee has strongly recommended remaining in the EU ETS at least until the end of Phase III in 2020. The UK’s 5th carbon budget adopted in 2016 assumes continued participation in the EU ETS, and will need to be altered if the UK leaves the EU ETS.

What about renewable energy?

After Brexit, the UK will no longer be obligated by renewable energy targets as part of the EU Renewable Energy Directive. Additional freedom from state aid restrictions has the potential to allow the Government to shape renewable energy support schemes.

The development of large scale projects may be impacted by the availability of funding from EU institutions such as the European Investment Bank. However, renewable and low carbon energy will remain a focal point of UK energy policy post-Brexit, with national and international decarbonisation obligations unaffected by their relationship with the EU.

As part of the European Union (Withdrawal) Act 2019 EU legislation will be initially transposed into UK law from 31 October 2019. For some elements of the EU law, the UK will need to reach an agreement with the EU in order to maintain the status quo.

Will coal plants stay open?

Coal-fired power plants in the UK are required to adhere to the EU Industrial Emissions Directive (IED) which places conditions on such plants in order to control and reduce the emissions and waste generated by these power plant. Strict emissions limits often require substantial investment in technology to reduce pollution. Several plant determined this was not cost effective, and will close down. All but one coal plant has chosen not to adhere to the new regulations and will close by 2023. The Cottam plant announced it will shut down at the end of the summer, while Fiddlers Ferry will close its remaining units in March 2020. Despite Brexit, these unabated coal plant will close. The Government has confirmed its policy to remove coal from the fuel mix entirely by 2025.

The Medium Combustion Plants Directive 2015 (MCP) operates in a similar manner, limiting the emissions of harmful pollutants. The UK has adopted both the IED and the MCP into its European Union (Withdrawal) Act, meaning that in the short-term these regimes will continue beyond October 2019. In the long term, the UK and EU will need to agree on common standards following Brexit.

What about EU investment in energy projects?

Several EU initiatives promote investment in energy infrastructure which encompasses funding towards UK projects. The European Investment Bank (EIB) for example has invested over €13bn into UK energy projects since 2010.

The draft EU Withdrawal Treaty anticipates this funding will continue, at least for projects approved by the EIB for investment before 29 March 2019.

After withdrawal from the EU, the UK will not be eligible for specific financial operations from the EIB which are reserved for EU member states. New projects may be supported by the EU depending on the nature and whether it aligns with the EU’s own energy policy. Cross-border projects, such as interconnectors and pipelines, may be available to non-member states.

The UK Treasury has sought to boost funding certainty and has vowed to underwrite all funding obtained via a direct bid to the European Commission and has also confirmed Horizon 2020 projects will still be funded.

What about the gas market, will supplies be affected?

The UK already operates a diverse import infrastructure, consisting of interconnectors and LNG terminals to allow for the import of gas, mitigating against supply risks. Operations and gas flows are expected to continue as normal, irrespective of any Brexit.

A more significant impact is likely to come from the expiry of long term supply contracts and restrictions which allow for selling capacity on a long term basis. The tariff network coderestricts the price at which interconnectors can sell their capacity. With Brexit it is unclear whether interconnectors will continue to be bound by these restrictions.

Other benefits like the Early Warning Mechanism and the Gas Advisory Council may be lost unless the UK can negotiate to retain its role in these.

For Brexit to have a significant impact on gas prices (barring any substantial currency moves) then the withdrawal from the EU would need to lead to export tariffs on EU gas flowing to the UK.

STAY INFORMED WITH EIC INSIGHTS

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the most timely updates you can find us on Twitter and LinkedIn Follow us today.

Visit our webpage to find out more about EIC Market Intelligence and how we keep our clients informed at a frequency to suit them.

 

Weekly Energy Market Update for 29 July 2019

Gas

Balance of Summer gas prices continue to move lower. The September gas contract has moved to new lows in anticipation of low demand for the remainder of the summer. August gas prices fell 3% across the week but are finding support from expectations of heavy maintenance, which will reduce North Sea production next month. Weakness at the front of the curve reflected healthy supplies and low energy demand levels.

The UK experienced its hottest ever July day, but the extreme heat made little extra impact on gas demand. Overall gas consumption remained at its summer lows with weak domestic consumption and excess gas being injected into already very healthy gas storage sites.

UK gas storage stocks rose 15% last week, while total European gas reserves are fuller than ever before. This will reduce injection demand for the rest of the summer and limit the ability of storage to absorb excess production. This would risk further oversupply, pushing prices to lows that will encourage producers to reduce output, as the demand will not be there. Winter 19 prices followed the summer market lower but the rest of the curve saw little change.

Contracts from Summer 20 onwards spent the last week stabilising in the middle of their July range. The strong gains seen in the first half of July have been partly reversed after costs fell heavily early last week. Prices retreated after reaching levels that would have attracted spot LNG cargoes to Europe, an additional supply source that is not required. Any further losses on the curve are being capped by the continued strength in the carbon market. Carbon costs are holding around €29/tCO2e, close to all-time highs.

Gas Graph

Power

Power prices moved lower last week, in line with the weaker gas contracts. However, price movement was more gradual. Seasonal contracts remain above their early July lows, following the strong rally seen in the first half of the month. While prices have dropped back from their mid-month highs, the market remains elevated, supported by the continued strength in the carbon market and higher coal prices. The cost of carbon allowances remains close to record highs at €30/tCO2e, having risen nearly €25 over the last two years.

Peak electricity demand rose marginally last week, supported by low wind and demand for cooling as the UK experienced its hottest ever July day. However, demand levels only peaked around 34GW, within the summer range, heavily limited by the UK’s lack of air-conditioning infrastructure. Peak consumption is forecast to drop to new lows of 32GW this week. Gas dominates the fuel mix but the impact is muted by the low summer demand levels.

Stay informed with EIC insights

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the most-timely updates you can find us on Twitter and LinkedIn. Follow us today.

Visit our web page to find out more about EIC Market Intelligence and how we keep our clients informed at a frequency to suit them.

Future Energy Scenarios

Future Energy Scenarios

The National Grid ESO (Electricity System Operator) has published its yearly Future Energy Scenarios (FES) report detailing four separate pathways that cover the future of energy to 2050 and beyond.

The ESO has taken onboard changes in policy, combined with technological progress and market forces, to create a range of credible scenarios. The scenarios have been modelled to reflect varying levels of decentralisation and the speed of decarbonisation.

The Pathways

Community Renewables (CE) – In this scenario there is a large focus on local energy schemes, boosting individual consumer engagement. Improved energy efficiency is a priority. Strong policy support promotes innovation and the transition towards renewables.

Consumer Evolution (CR) – This scenario sees a shift towards local generation and increased consumer engagement, like Community Renewables. However, a lack of strong policy direction means that progress is slow.

Two Degrees (TD) – Large-scale solutions are developed and consumers are provided with alternative heat and transport options. Priorities include increasing renewable capacity, improving energy efficiency and accelerating new technologies.

Steady Progression (SP) – This scenario evaluates the pace of the low-carbon transition at a rate comparable to today, slowing towards 2050.

Work on the FES 2019 document predates the UK government’s target for Net Zero emissions by 2050. Therefore, the scenarios follow the original Climate Change Act 2008 target of an 80% reduction in greenhouse emissions by 2050, compared to 1990 levels.

Of the scenarios, Community Renewables and Two Degrees meet the 80% target with common themes of strong policy support and high consumer engagement. One of the main drivers in reducing the UK’s carbon emissions to date has been environmental legislation.

Is Net Zero likely?

The ESO included a Net Zero spotlight in the FES 2019 publication to reflect the recent Net Zero publication by the Committee on Climate Change (CCC).

Analysis in the FES 2019 report aligns with the Net Zero publication by the CCC. This states that reaching Net Zero carbon emissions by 2050 is achievable, but only through immediate action across all key technology and policy areas.

In this scenario, the ESO highlight that electrification of the industrial and commercial sectors is vital in reducing emissions. Carbon capture, usage and storage (CCUS) technologies also have an essential role to play.

At the 2019 Future Energy Scenarios Conference the new target was acknowledged and will likely be taken into account for the pathways modelling in FES 2020.

Stay informed with EIC Insights

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the most-timely updates you can find us on Twitter and LinkedIn. Follow us today.

Visit our web page to find out more about EIC Market Intelligence and how we keep our clients informed at a frequency to suit them.

Long-Term Forecast Report

Our team of specialists work hard identifying trends, examining historical figures and forecasting for the future. Their expertise has enabled us to produce the Long-Term Forecast Report. A valuable tool which illustrates the annual projected increases to your energy bills and calculates your energy spend  allowing you to confidently forward budget and avoid any nasty surprises.

Capacity Market T-1 auction clears at all-time low

Capacity Market T-1 auction clears at all-time low

The rescheduled 2018 T-1 Capacity Market (CM) auction cleared at an all-time low price of £0.77/kW, falling from the previous low seen at the last CM auction of £6.00/kW. A total of 129 CMUs (Capacity Market Units) were awarded agreements, procuring a total 3.6GW capacity.

Overall, gas-powered and combined heat and power (CHP) units received the majority of agreements, obtaining 45 and 30 respectively.

The low clearing price proved discouraging for demand-side response (DSR) units with a total of 29 DSR agreements awarded to providers, down from 74 DSR agreements in the 2017 T-1 auction. Storage projects were also deterred, with 6 total projects awarded agreements.

A full breakdown of the results and applicants is provided by National Grid ESO here.

Current State of the Capacity Market

The CM scheme is currently under suspension, following a ruling on 15 November 2018 by the European Court of Justice that its design was biased against small-scale, clean energy units and therefore shouldn’t be eligible for State Aid approval. Under EU State Aid rules, it is required that member states need to consider alternative options to meeting power demand, before subsidising fossil fuel generation.

The Court’s decision means that payments made under the CM scheme will be frozen until the UK Government can obtain permission from the European Commission to continue in an official capacity.

The European Commission has to undertake a formal investigation of the CM to clear it. If successful, the Department of Business, Energy and Industrial Strategy (BEIS) has said that auction results to date will still stand and that payments are legal.

In the meantime, BEIS has asked the National Grid Electricity System Operator (ESO) to keep the Capacity Market scheme running, short of making payments. BEIS has said that if those with contracts deliver their obligations, they may then be eligible for deferred payments if the market is reinstated.

BEIS expects a decision by the Commission to be made by early next year.

Stay informed with EIC insights

Our Market Intelligence team keep a close eye on the energy markets and industry updates. For the most timely updates you can find us on Twitter and LinkedIn Follow us today.

Visit our webpage to find out more about EIC Market Intelligence and how we keep our clients informed at a frequency to suit them.