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.

UK Capacity Market suspended by European Court of Justice

Somewhat lost amongst the noise surrounding the proposed Brexit Agreement comes the news that UK’s Capacity Market (CM) will undergo a temporary suspension.

 

What is the Capacity Market?

The Capacity Market allows plant to offer capacity to the electricity system at a price set by auction. The market has been introduced to prevent a short-fall in electricity generation due to the closure of older fossil fuel plant. Every year, the Government decides how much capacity will be needed to safeguard the system. Both generators that are currently operating, and those that are being developed, can take part in the scheme.

 

The Court’s Ruling

The ruling from the European Court of Justice (ECJ) follows Tempus Energy’s challenge to the UK Government that took place in 2014. The company took issue with the decision to grant the UK’s Capacity Market with State Aid approval, making claims that the design was biased against small, clean energy, making it easy for coal, gas, and diesel generators to control the market.

The ECJ said that the European Commission was wrong to not more closely investigate the UK’s plans to establish the CM in 2014, when the organisation was originally responsible for assessing whether the policy complied with State Aid rules.

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 rules also require any measures taken to increase capacity to be designed in a way that encourages operators of new clean technologies.

 

What’s next?

The ECJ’s decision means that payments made under the Capacity Market scheme will be frozen until the UK Government can obtain permission from the European Commission to continue.

Furthermore, the UK will also not be allowed to conduct any further CM auctions for energy firms to bid on new contracts. The nearest auctions were scheduled for early 2019.

Sara Bell, CEO of Tempus Energy, said: “This ruling should ultimately force the UK Government to design an energy system that reduces bills by incentivising and empowering customers to use electricity in the most cost-effective way – while maximising the use of climate-friendly renewables.”

 

How will this affect you?

The Government has released a statement saying that security of supply will not be impacted over this winter.

They acknowledge a ‘standstill period’ on the Capacity Market during which they will be working closely with the European Commission in order to aid their investigation and seek approval for the Capacity Market.

The cost of the Capacity Market is recouped via customers and currently accounts for 2.9% of an electricity bill.

The suspension of the payments to generators may result in customers receiving a refund, or at least a halt to ongoing payments while the suspension is in place.

However, if the scheme is cancelled all together it would lead to the removal of one cost to customers; the Capacity Market charge is just one of numerous non-commodity charges, paid on top of the wholesale price of energy, that are rapidly increasing.

 

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How will Brexit affect the UK 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 potential impacts 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 states 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 Internal Energy Market (IEM).

 

The EU Internal Energy Market (IEM) – will the UK 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 tariff-free between countries.

Post-Brexit, the UK 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 March 2019.

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 cooperation with the EU Internal Energy Market going forward.

However, there are some inconsistencies in regards UK plans encompassing full membership of the IEM. Continued participation in the IEM 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 Brexit negotiations 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. Business Secretary Greg Clark had indicated he was keen for the UK to remain in the EU’s Internal Energy Market, although the final result will depend on the outcome of Brexit negotiations.

Regardless of the outcome, the UK’s energy network 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, advising operators 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; those which are still in the stages of project development, without final financial decisions. Uncertainty caused by Brexit, surrounding commercial, regulatory, and operational impacts, will likely see planning stages revisited 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 has confirmed 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.

 

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 (CMA) 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 is expected.

 

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 they generate. 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, and several have already done so.

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 March 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 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 if 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 or prices be affected?

The UK already operates a diverse import infrastructure, consisting of Interconnectors and Liquefied Natural Gas (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 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 code restricts 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.

 

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.

 

What about environmental impacts?

We’ve taken a look at the potential affect of Brexit on the UK’s climate change and renewable energy targets – find out more at our blog.

 

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What impact will Brexit have on UK climate change targets?

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 potential impacts 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.

 

How will Brexit impact on the carbon market and 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 Emissions Trading Scheme (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, marginally 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 1 April 2019.

The House of Commons Business, Energy and Industrial Strategy (BEIS) 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.

 

Will Brexit affect the UK’s climate change targets?

The UK’s climate change targets are expected to continue unaffected by whatever Brexit deal is reached. The Climate Change Act 2008 established that such goals are undertaken on a national level.

However, 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.

 

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 (EIB). 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 2018, EU legislation will be initially transposed into UK law from 29 March 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.

 

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Autumn Budget light on energy

During the Chancellor’s hour-long speech the overall focus was on tax and spending, with little said about climate change. What energy-related announcements were made?

 

Climate Change Levy

CCL is a tax on energy delivered to non-domestic users within the UK. Businesses participating in Climate Change Agreements (CCAs) can avoid up to 90% of this levy by investing in agreed energy efficiency and emissions reduction measures.

This latest Budget announced upcoming changes to CCL rates. The Government’s ongoing efforts to rebalance the main rates paid for corporate gas and electricity use will see the two prices brought more in line with each other.

The electricity rate will be lowered in 2020-21 and 2021-22, whilst the gas rate will be increased in 2020-21 and 2021-22 so that it reaches 60% of the electricity main rate by 2021-22. Other fuels, such as coal, will continue to be aligned with the gas rate.

 

The impact to your energy bills

The increase in revenue for the Treasury will come as a direct result of higher energy bills for businesses. An increase in the CCL for 2019 was already expected as a result of the closure of the Carbon Reduction Commitment (CRC).

 

Carbon Price

Carbon Price Support (CPS) is applied to the power sector in the UK, with the exclusion of Northern Ireland, and has been a key driver in the reduction of coal usage in the UK fuel mix.

The Government has decided to maintain the UK’s carbon tax at £18 per tonne of CO2, until April 2021. However, the budget provides plans for the Government to reduce the CPS from 2021-22 if the total carbon price remains elevated.

In addition to this, 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 scheme. 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 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 per tonne of CO2, marginally 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 1 April 2019.

 

A freeze on fuel duty

Already announced ahead of the Budget, the Government has promised that fuel duty will be frozen for the ninth year in a row. This will see the tax on fuel, currently 57.95p per litre of petrol, diesel, biodiesel, and bioethanol, remain fixed over the winter period.

 

Enhanced Capital Allowances

The Budget also included changes to Enhanced Capital Allowances (ECAs), which are designed to encourage UK businesses to invest in high-performance energy efficiency equipment. The Government plans to end ECAs and First Year Tax Credits for technologies on the Energy Technology List and Water Technology List, from April 2020. The Government believe these ECAs add unnecessary complexity to the tax system and that there are more effective ways to support energy efficiency.

There is no new funding in place yet, but savings will be reinvested in an Industrial Energy Transformation Fund, to support significant energy users to cut their energy bills and help transition UK industry to a low carbon future.

The Government will extend ECAs for companies investing in electric vehicle charge points to 31 March 2023. This is part of the Government’s ambition for the UK to become a world-leader in the ultra-low emission vehicle market.

 

What about renewable energy?

Despite the recent landmark ‘1.5C report’ from the Intergovernmental Panel on Climate Change (IPCC), the Budget was very light on details concerning climate change and the environment. There were no announcements within the Budget to encourage new investment in renewable energy in the UK, despite industry calls to support new onshore wind and solar.

Leading renewable developers have previously urged the Government to clear a path for subsidy-free onshore wind farms, allowing developers to compete for clean energy contracts. Cost projections, published by the Department for Business, Energy and Industrial Strategy (BEIS), show that onshore wind is currently the cheapest power source available.

 

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Positive Winter Outlook from National Grid

National grid has published its yearly Winter Outlook report for the 2018/19 season. The report forecasts an electricity margin of 7.1GW, which is 0.9GW more than last year.

Transmission system demand is predicted to peak at 48.2GW, 2.5GW less than last winter, during the week commencing 10 December 2018. This includes the sum of national demand (48.85GW), alongside the demand from power stations (600MW) and the base case interconnector export value (750MW).

The Winter Outlook expects this season to operate differently to last year. Over the last two winters, gas was the cheaper fuel type for electricity generation. However, as global gas prices have risen, it’s more likely that coal will replace gas generation to some degree over the season.

 

Interconnectors

In 2014, the interconnectors were not eligible to participate in the Capacity Market’s (CM) T-4 auction. As a result, they hold no CM obligations for winter 2018/19, including interconnector capacity, as some contracts were secured by interconnectors in the Early Auction.

The Winter Outlook expects an average import flow of 2,130MW, out of a total 3,000MW (2,000MW from the French IFA interconnector and 1,000MW from the Netherlands BritNed interconnector), and an export flow to Ireland of 750MW.

National Grid anticipates that forward prices in Continental European markets will be lower than in Britain. As a result, we will likely see a net flow of power from the Continent to the UK during peak power demand periods. However, outages within the Belgium nuclear fleet, which have extended to November and beyond, could result in increases to Continental prices, causing uncertainty on interconnector flow direction.

Nemo Link, a new interconnector, is under construction and may come into commercial service at the end of January 2019. Once commissioned, it will provide a 1GW capability between Belgium and the UK.

 

Gas

The gas demand forecast for winter 2018/19 is 46.6 billion cubic meters (bcm), lower than the winter 2017/18 outturn. Peak demand for the coldest weather conditions (or a 1-in-20 winter, meaning exceptional demand on a winter day which statistically occurs once every 20 years) is forecast at 483mcm/day, with a margin of available supply of 92 million cubic meters (mcm).

The report estimates that for an average cold day this winter, the demand forecast is expected to be 407mcm/day. The non-storage supply forecast is 360mcm/day, to which 92mcm of storage can be added, providing National Grid a cold day supply forecast in excess of the forecast demand.

Average gas exports through the IUK to Continental Europe are expected to be lower than winter 2017/18 due to the expiry of long-term contracts. As a result, National Grid predicts that deliveries through from the Balgzand Bacton Line (BBL) may be price-sensitive through the season.

Following a decision by the Dutch government to cut Groningen production, output from the site will be reduced from 21bcm/year in winter 2017/18 to 12bcm/year by winter 2022/23. Production from Groningen this year will not be dictated by a cap, but instead will be weather dependent, producing no more than necessary to meet security of supply.

 

Liquefied natural gas (LNG)

During seven of the last eight months, supply of LNG to the network has been lower than in the same period in the previous year. Demand for LNG is comparatively high in Asian markets, especially in China where gas is expected to continue to grow, as it replaces coal in the Chinese heating sector. High demand, and the associated high prices have drawn LNG away from European markets.

The Winter Outlook does not expect LNG supply to the country to be high on many days this winter. However, if demand and prices rise substantially within the UK, LNG imports will increase, just as they did at the end of February 2018.

 

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Gas and power prices surge – take action

The Winter 18 gas and power contracts are up by 52% and 50% respectively in the last year. The following seasons have also risen, however not by as much. Winter 19 gas and power contracts are 34% and 38% higher year-on-year.

If you’re on a fixed contract, all is not yet lost, though we’re urging you to act quickly.

 

Gas and power surge

 

A clear impact of the price rises is that gas and power for next year are much more expensive than a year ago. However, next year’s prices, and the year after that, for gas and power are still at a discount.

The market remains in a heavy period of backwardation. This is when contracts for a commodity are cheaper in the future than they are for periods closer to delivery. This isn’t because the market expects prices to be lower in the future, but largely due to the market pricing for current supply shortage levels.

Gas remains in high demand, partly because of the cold winter and the earlier effects of the ‘Beast from the East’ depleting storage reserves. Injections this year have been strong but may not be enough to reach the highs from last year.

Another factor at play is that gas prices elsewhere in the world are much higher. This is encouraging those with the ability to move gas to higher price destinations. The recent market rises have been substantial, but have only returned prices back to where they were trading four years ago.

 

long-term gas contracts

 

Furthermore, it’s only the front seasonal contracts that have risen to this elevated range. The front Winter gas contract is holding between 65p/th and 75p/th, with the Summer market range between 56p/th and 66p/th. If you haven’t fixed your October 18 start contracts yet, don’t delay any further.

 

What’s the risk to your energy bills?

Even if the market only moves to the middle of the above stated ranges the wholesale element could still increase significantly.

If the above curve flattens in line with the longer-dated contracts moving up to the range that prices were at just four years ago, you could be hit with a further 20% price increase. The below table outlines how your annual electricity spend would increase if your business were hit by this rise:

 

 

Current annual electricity spend

Contract start date

£10,000

£100,000

£1,000,000

1 April 2018

£10,057 £100,573 £1,005,725
30 August 2018

£11,412

£114,122

£1,141,219

Further 20% rise

£12,483 £124,826

£1,248,258

 

The shortage now is partly due to the low storage levels seen at the end of winter, which has prompted substantial injections. However, structural problems remain, particularly in regard to a lack of UK storage capacity. Dutch gas production will continue to decline, as will supply from the North Sea. The ongoing worldwide transition from coal to gas will also support demand. As a result competition for gas is here to stay, encouraging higher gas prices for the UK to attract sufficient supply.

Wholesale costs for suppliers have risen significantly in the last two years. Many gas and power contracts are at record highs, after prices accelerated their move higher earlier this year, and again during August. These increased costs will be passed on to consumers in the form of higher bills, with suppliers paying more for their energy at a wholesale level.

 

It’s time to take action

EIC can help you manage these price rises. Back in April, our energy experts advised businesses to fix their October 2018 contract starts immediately for 24 months. Those that followed our advice at the time saved themselves 42% on their wholesale gas cost and 34% on their wholesale electricity cost, compared to what they’d be paying now.

 

How we can help you with energy procurement

Here at EIC, we pride ourselves on our market knowledge and giving timely advice to our clients. We can help businesses of all sizes to find the right energy contracts for their needs.

If you’re a larger energy user, we can help you with fixed price energy procurement to help you secure prices and provide budget certainty. We’re also on hand to help you with flexible energy procurement, should you find fixed contracts too restrictive; we can help you take advantage of a volatile energy market and make sure you capitalise on market rises and falls. Our aim is to maximise contract flexibility whilst minimising your costs.

We can also help you budget effectively for your energy costs by providing year-on-year price projections for the next five years with our Long-Term Price Forecast Report.

To find out more about our energy procurement services, and how we can help you find the right contract for your business needs, call us on 01527 511 757 or email info@eic.co.uk.

Domestic energy price cap proposal announced by Ofgem

The proposal follows the passing of the Government’s Domestic Gas and Electricity (Tariff Cap) Act, which became law on 19 July. This legislation was passed by Parliament to provide a temporary price cap for domestic customers on Standard Variable Tariffs (SVTs) and default tariffs, assigning Ofgem with the duty to ensure a fair price.

Ofgem has currently opened a statutory consultation on the announcements, allowing suppliers and stakeholders to comment on the proposals before 6 October. The regulator is working towards having the cap in place by the end of 2018.

 

The impact on customers

The introduction of the price cap will see a requirement for suppliers to cut their prices to the level of, or below, the cap. This is proposed to be £1,136 per year for a typical dual fuel customer paying by direct debit and £1,219 per year for a customer paying by standard credit.

Exact savings for each household will be dependent on the cost of their current deal, how much energy they use, and whether they use both gas and electricity. On average it’s been estimated that the typical customer, on a dual fuel deal of gas and electricity, will save around £75 a year. Ofgem believes the price cap would save consumers a total of around £1 billion.

 

The price cap moving forwards

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

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

 

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Zonal transmission losses hit electricity bills

In April 2018, major changes were made to how National Grid charged for transmission losses from the electricity system. As these changes are now being reflected in electricity bills, consumers need to make sure these costs are being passed on correctly.

The net impact of the changes in transmission losses is that consumers in the north of the country are going to see notable benefits, while the south will see an increase.

 

What are transmission losses?

Transmission losses refer to the electricity lost in the main high-voltage transmission network, as it travels from generators to where it is needed. The losses are a normal and an unavoidable result of the physics of transmitting energy over any distance. However, these losses still need to be accounted for and, as a result, generators are required to provide more energy than is actually used to ensure the system is balanced.

In electricity bills, transmission losses reflect the cost to consumers for providing this extra energy. Though they are not a huge part of an energy bill, amounting to less than 1%, the modifications regarding how these losses are calculated could result in a large change in this small element of overall costs.

 

How have these charges changed?

Following the Energy Market Investigation conducted by the Competition and Markets Authority (CMA) in June 2016, it was decided that regional variations in transmission losses charges would be introduced. The CMA concluded that losses didn’t reflect the actual costs for operating the system, due to the fact that all consumers paid the same level of losses, regardless of their location, or proximity to generators.

In theory, those regions closer to where the electricity is generated will see lower levels of energy network losses compared to those who are located more remotely from generators. Therefore, the CMA’s solution was Zonal Transmission Losses. Each region would face different levels of losses, reflecting the actual costs of delivery to their location.

Previously, all consumers faced a cost based on the same calculation; all metered consumption was uplifted by the same amount – around 1% or multiplied by 1.01. The cost of the losses reflected the difference between the metered cost of energy and the cost for suppling the uplifted volume of electricity.

As of April 2018, each of the 14 transmission supply zones – which correlate to the 14 main electricity distribution networks –have a different multiplier for the extra energy to be supplied – the Transmission Loss Multiplier (TLM). These are also seasonal, as the level of energy lost on the network is impacted by weather and temperature conditions.

 

What is the impact of these changes?

For the largest businesses, which have bills that pass-on transmission costs directly, losses can change on a half-hourly (HH) basis, reflecting the changing level of energy requirements on the system throughout the day. Average monthly TLMs since April 2018 show how the multiplier has changed significantly in the last few months. This can be seen in the graphs below.

 

northern monthly TLMs

southern and eastern monthly TLMs

wales and western monthly TLMs

 

As shown, the zonal TLMs vary significantly around the average TLM for all regions, estimated to be remaining at the 1.01 level.

Of particular note is that both Scottish zones have a TLM below one. As the multiplier is less than one, this in practice means that those exposed directly to these half-hourly TLMs in Scotland could see negative transmission losses costs. This is to reflect that the majority of the UK’s generation is in the north, with consumers closer to sources of generation, while the bulk of demand is in the south, much further away from the majority of generation.

This wide variation in TLMs means there is also the potential for large swings in transmission costs based on location. The actual annual costs for transmission losses will also vary based on consumption over the year, particularly given that the changes will be seasonal too.

Based on the data on TLMs seen so far, it is estimated that transmission costs will be around 110% more than they might have been in the Midlands supply zone, while northern Scotland will see these costs drop by nearly 200%. Though this sounds significant, we must highlight that the scale of costs relative to the other parts of the energy bill are small, so in many cases consumers may not notice a huge difference in their overall annual bill as a result.

 

TLM variation

 

 

We can help ensure your bills are correct

Whatever the impact on your final bill, you should be aware of the variations that came into force in April. With such a wide variation in Transmission Loss Multipliers, it’s important that bills are checked for accuracy, particularly if a contract allows for full pass-through of the costs. Even a small error could – over time – lead to notable costs to businesses.

Here at EIC, we have an in-depth understanding of all the charges that can appear on your energy bills, and how you can control them to lower their impact.

To find out more about our energy bill checking service visit our website.