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.

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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.

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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.

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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.

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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.

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An update on Smart Export Guarantee

The Department of Business, Energy and Industrial Strategy (BEIS) has published a response to their consultation on the future for small-scale low-carbon generation, which sought views on policy proposals for a Smart Export Guarantee (SEG).

The SEG will require suppliers with at least 150,000 domestic customers to provide a minimum of one tariff offer to small-scale low-carbon generators. Exporters of up to 5MW capacity of anaerobic digestion, hydro, micro-combined heat and power, onshore wind, and solar photovoltaics are eligible for payment.

It is the government’s opinion that small-scale low-carbon electricity generation should be supported by competitive, market-based solutions. To this effect, the government will not specify a minimum tariff rate in order to allow the market to develop. However, a supplier must provide payment greater than zero at all times of export.

The SEG is a replacement for the Feed-in Tariff (FiT), which closed to new generators in March 2019. The Feed-in Tariff scheme was originally introduced in April 2010 in order to incentivise the development of small-scale renewable generation from decentralised energy solutions. Generators were paid a fixed rate determined by the Government, which varied by technology and scale.

How will this impact you?

All suppliers that meet the SEG criteria will be required to offer at least one tariff by an expected date of 31 December 2019, providing small-scale generators with a choice of who they want to export to.

Currently, there are very few suppliers that offer tariffs of this nature. However, as the deadline approaches it can be expected that all larger suppliers will begin to offer their own options, allowing generators to choose the best tariff for themselves.

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Government to make further adjustments to Capacity Market

Following a consultation in March on additional measures to keep the Capacity Market (CM) running smoothly during the current standstill period, the government has published a decision detailing planned legislative changes.

The government maintains that the CM scheme is still the right mechanism to provide security to electricity supplies at the least cost. In order to continue this, the government intends to:

  • Replace the planned T-4 auction with a T-3 auction for delivery in 2022/23.
  • Allow certain renewable technologies to participate.
  • Remove the historical floor from the interconnector de-rating methodology.
  • Make minor corrections and additions to the CM Rules to ensure they are clear and operate as intended.

When implemented, these rules will see renewable technologies allowed to bid for contracts for the first time under the Capacity Market, having previously failed to qualify due to funding through subsidies. Renewable generators that do not receive support via the Contract for Difference, Renewables Obligation or Feed-in Tariff schemes will be allowed to participate.

The rearranged date for the delayed 2018 T-1 Capacity Market Auction is scheduled to go ahead on 11-12 June 2019 for delivery in the 2019/20 year.

The 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, clean energy 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) have 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.

How the closure may affect you

In the short-term the Capacity Market charge will still be levied on customer’s bills, currently accounting for 0.3p/kWh, approximately 2.5% of a bill. This means that consumers will likely see little immediate change.

However, the ongoing suspension could mean a halt to the charge. An unsuccessful investigation by the European Commission could potentially see UK consumers receive a refund for previous CM charges paid through their electricity bills. This could be partially offset by a resultant hike in wholesale energy prices as guarantees of supply from larger operators are no longer certain.

Smaller operators in the scheme may be faced with a dilemma as missed capacity payments could result in cash flow issues. However, a closure to the Capacity Market could see the early shutdown of some coal plants, raising market power prices, and providing opportunity to these smaller operators.

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Ofgem update Targeted Charging Review timeline

Ofgem has published a letter to stakeholders to provide an update on timing and next steps on Future Charging and Access reforms. The regulator has three ongoing projects that serve as a review of transmission, distribution and balancing charging to help facilitate a transition to a more effective network. These are:

  • Electricity Network Access and Forward-looking Charging reform (Access reform)
    • A Significant Code Review (SCR) designed to develop improved access and forward-looking charging arrangements
    • A wide-ranging review of Distribution Use of System (DUoS) charges
    • A focused review of Transmission Network Use of System (TNUoS) charges
  • Targeted Charging Review (TCR)
    • A review of residual network charges, as well as some of the remaining Embedded Benefits to explore how costs may be more fairly shared amongst users
  • Balancing Services Charges Task Force
    • Designed to operate in parallel to the SCR and TCR, Ofgem have established an industry-led task force to evaluate Balancing Services Use of System (BSUoS) charges
    • The Task Force are evaluating how cost reflective and effective current BSUoS charges are

The new timeline

Ofgem have updated the timelines for the TCR and Access reform, providing clarity on dates in their original consultations.

The TCR consultation nominated April 2020 and April 2021 as potential dates for the reform of Embedded Benefits to come into effect. Ofgem have now ruled out April 2020, citing April 2021 as their preferred date. Options for the implementation date for new residual charging arrangements were April 2021 or phasing between 2021 and 2023. The regulator has indicated that they now consider April 2023 as a leading option, alongside the other two.

Regarding the Access reform, Ofgem originally scheduled changes to transmission charges to come into effect in April 2022, and changes to distribution arrangements in April 2023. This has now been revised to April 2023 for both changes.

Future Triad periods

Under the TCR proposals transmission demand residual charges (Triads) would be changed to a fixed or agreed capacity, avoiding the incentive for Triad avoidance in the future. The nomination of a potential implementation date of April 2023 for new residual charging arrangements increases the likelihood that the last Triad could be Winter 2022/23, totaling three Triad periods overall.

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UK LNG terminals filling up fast

With 16 tankers now booked for May, this month has already marked more LNG coming to the UK in 2019 than the whole of last year. With that, capacity at the terminals is dwindling. Across the three terminals – South Hook, Dragon and Isle of Grain – there is enough capacity to store 1.25BCM of gas, a similar amount to all the UK’s Medium Range gas storage. However, despite the strongest average daily sendout since 2011, storage at the three terminals is rapidly filling and there is limited scope for demand to increase to absorb further LNG on to the grid.

The gas market remains well supplied with demand continuing to edge lower. The plentiful supply is largely thanks to LNG which in recent weeks has been making up an increasing share of UK supply to over 30%. Average daily sendout for the last month has been the highest since 2011.

Of the 16 tankers that are booked so far this month 12 have gone to South Hook which has enabled the terminal to send out at over 50MCM/d. Of these tankers seven have been Q-Flex carrying around 126MCM of gas and five have been Q-Max carrying 155MCM. With sendout at 50MCM/d it is getting through a Q-Flex every two days, and a Q-Max every three. This means stock at the terminal has grown from 35% full at the end of April, and is expected to be over 90% full at the end of this week, with three tankers set to arrive in the next six days.

 

Sendout, other than boil off, from the other two terminals has largely stopped since 14 May. With Dragon 64% full, and having only a third of the capacity it will have to increase flows in order to accommodate a tanker. Following the arrival of the Ougarta, from Algeria, into the Isle of Grain this week the terminal is going to be over 90% full and therefore will have no room for further cargoes without increasing withdrawals.

 

Therefore, if the UK is going to receive similar amounts of LNG in the near future sendout is going to have to increase. How much potential demand there is to absorb this gas is limited, with the interconnector running at booked capacity and storage already 50% full. The potential for further and prolonged oversupply in the gas system could lead to more declines in short-term energy prices. The front-month gas contract has already dropped to its lowest level in three years at 30p/th.

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Record Breaking Solar Generation

A week of clear skies and warm temperatures has seen the UK break its all-time record for solar PV generation twice in as many days.

National Grid reported a new all-time peak for solar generation on Monday 13 May at 9.47GW. This surpassed the previous record which had held for two years, when supply hit 9.38GW in May 2017.

 

 

This record was then broken again the following day, when output peaked at 9.55GW on Tuesday 14 May. On that day, at its peak, solar generation was producing 27% of UK electricity.

Peak solar generation has averaged 8.7GW since Saturday as temperatures climbed over the weekend and weather conditions turned significantly brighter. The previous week when conditions were far cloudier, generation peaked at less than 5GW on average.

 

Growth in Solar Capacity

The new record for solar generation has come despite minimal growth in installed solar capacity in recent years. Total installed solar capacity has risen by just 0.5GW since April 2017, following the closure of the Renewables Obligation subsidy scheme. Total capacity is currently 13GW, having grown nearly 10GW in the three years from 2014 to 2017.

 

Impact on Demand

Solar output has a narrower window of generation than other fuel sources. High levels of solar generation during daylight hours are more impactful on reducing system demand, both the overall daily peak and the afternoon low. Solar generation raises the volume of embedded electricity, in which homes and businesses are generating their own supply via solar panels. Embedded generation removes the demand for that electricity from the transmission network. The higher the availability of embedded generation the lower the system demand. This is why the transmission network sees a sizable reduction in consumption across the middle part of the day, when solar output is at its strongest.

During the record solar generation on Tuesday, demand on the transmission network saw a drop of more than 6GW from the early morning high. Consumption dropped to just 25GW before climbing again for the post-work peak.

 

 

Peak electricity demand on the network is at record lows and is forecast to fall even further as the summer season progresses. 2019 as a whole has seen peak consumption trend lower than previous years, reflecting the greater efficiencies and renewable availability on offer. In the last week of May, a half-term school holiday, electricity demand is forecast to peak at just 31GW, an all-time low.

 

 

A Benefit to All Customers

In addition to the environmental advantages of renewable generation, distributed solar provides many benefits to the grid and by extension to all electricity consumers. Reduced demand on the system improves grid security and the often onsite nature of solar generation leads to less losses in electricity.

The demand reductions caused by higher levels of distributed solar generation, mean that less fuel is being used to power the electricity network. As demand falls wholesale prices fall,  the less efficient gas plants are no longer required so overall cost of generation is lower. These dips in demand means that hourly prices for the early afternoon are now on at similar levels to the prices normally recorded in the middle of the night. As more solar reduces prices in the daylight hours the cumulative effect of all the additional generation is to bring prices lower.

The government is currently analysing feedback on the proposal for a Smart Export Guarantee (SEG), designed to replace the now-closed Feed-in Tariff. This scheme would legislate for suppliers to provide tariffs to pay small-scale low-carbon generators, such as solar panel owners, for the electricity they export to the grid. Some suppliers have already begun to offer tariffs, based on the same concept, to incentivise the export of solar power to the grid.

 

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