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.

Increase in carbon costs likely as EU cut supply of allowances

The European Commission has published the annual surplus indicator for the EU Emissions Trading System (ETS) Market Stability Reserve. As long as the surplus exceeds the level set in the legislation, a total of 397 million allowances will be placed in the reserve, 24% of the total permits currently in the market. This is an increase on the 2018 publication, which saw almost 265 million allowances placed into the reserve in January 2019. The allowances will be placed into the reserve in the period of September 2019 to August 2020.


Purpose of the Market Stability Reserve

The Market Stability Reserve (MSR) was introduced to address the large oversupply of carbon allowances that built up following the 2008 global financial crisis. This saw carbon prices reach all-time lows for an extended period of time and by the end of 2016, the European Emissions Trading Scheme had an oversupply of 1.7bn tonnes worth of EUAs. The oversaturation of allowances provided a weaker incentive to reduce emissions.

The MSR will see 900 million allowances, which were removed between 2014 and 2016, transferred to the Reserve, rather than be auctioned in 2019-20. After this, unallocated allowances will also be transferred to the reserve.

Each year, the Commission will continue to publish the total number of allowances in circulation by 15 May. This will allow them to examine whether more allowances should be placed into the reserve or whether allowances should instead be released. This will allow the Commission to better regulate the allowances available.


An impact to carbon prices

The restriction of carbon allowances as part of the Market Stability Reserve has been the cause of substantial price increases since 2017. The cost of carbon is currently at €26/tCO2e, having doubled in value year-on-year.

The impact of further allowances placed in the reserve is likely to see continued price rises, as the MSR continues to restrict the availability of supply to the market. The introduction of the reserve caused prices to rise from €4 to over €25 in eighteen months. With the volume of allowances into the EU ETS system remaining tightly restricted, there is the likelihood of further price rises, notably towards the all-time high of €30/tCO2e, last seen in 2008, shortly after the EU ETS was created.

A further increase in carbon prices, particularly if prices were to break to new highs at over €30/tCO2e, would provide a strong bullish signal to the wider energy mix, and likely result in higher wholesale gas and power prices.


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UK holds record storage levels

UK medium-range storage stocks are at record highs for the time of year with reserves more than 50% full just over a month into the summer season. A combination of low gas demand during Q1 2019 and the record levels of LNG imports that have reached the UK since October left the UK oversupplied. Medium-range storage stocks reached full capacity by the end of November 2018 and remained at record highs through December and January before operators began a spell of heavy withdrawals, seeking re-injections during the summer season when prices were expected to be even lower.

Since 1 April excess gas was exported to Continental Europe over the Interconnector. However, annual maintenance on the UK-Belgium gas interconnector halted the availability for the UK to export gas to the Continent. Britain had previously acted as transit nation for Norwegian supplies passing to Europe. While exports were unavailable LNG imports continued at a record pace. Twenty LNG tankers arrived in April delivering the most LNG in one month since 2011.

With demand limited – particularly during the very hot Easter holiday weekend, oversupply in the gas system forced flows into storage.

During the Interconnector’s ten day shutdown injections into storage averaged over 400GWh per day. Stocks more than doubled from 3.2TWh to 7.8TWh. The average level of storage for this time of year is just 3.8TWh and the previous highest level was just under 5TWh in 2016/17. Current reserve levels are 107% above average for the time of year.

With the loss of the Rough storage facility, the UK has limited storage capacity, with around 15TWh of medium-range sites. These offer a faster injection and withdrawal process, but lack the scale of the Rough facility which operated on a seasonal basis. Total European gas storage reserves are also at very high levels. LNG imports flooded North West Europe during Winter 2018/19 and the Continent enjoyed a similarly mild Q1 2019. Total European reserves are broadly tracking the previous strongest year for storage in 2013/14. Before the end of April, total gas stocks in Europe were over 50% full with 500TWh of gas in reserve.

The healthy short-term fundamentals have driven Balance of Summer gas contracts back towards the levels from early April, with the front-month contract at lows not seen since August 2017. With storage stocks fuller than ever before at this stage of the summer, there will be limited availability for injections later in the season. This will limit demand and could lead to further price falls over the summer, unless LNG imports or Norwegian production turns down significantly.

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Task Force publish initial findings on BSUoS

In collaboration with the ESO (Electricity System Operator), Ofgem announced their decision to create a Balancing Services Charges Task Force in November 2018.

The main goal of the Task Force is to conduct investigation and analysis that can support decisions on the future direction of Balancing Services Use of System (BSUoS) charges. These charges recover the costs of ESO balancing actions that are necessary to handle the daily operation of the National Electricity Transmission System.

Whilst considering wider implications (i.e. Targeted Charging Review SCR, TNUoS, Electricity Network Access Project SCR, etc), the Task Force have delivered an initial Draft Report, providing three deliverables to assess whether Ofgem should attempt to improve cost-reflective signals through BSUoS, or whether BSUoS should be treated as a cost-recovery charge.

Deliverable 1 –
Does BSUoS currently provide a useful forward-looking signal?

Following assessment, the Task Force has found that BSUoS charge does not currently provide any useful forward-looking signal. This makes the charges hard to forecast, reducing the influence of the charge on user behaviour.

They believe reasons for this are that the current BSUoS charges are complex and becoming increasingly volatile. In addition, there are other market signals that are more noticeable to users, which then take priority. The Task Force also note that the charge is applied across the transmission basis equally.

Deliverable 2 –
Potential options for charging BSUoS differently, to be cost-reflective and provide a forward-looking signal

The Task Force assessed whether individual elements of BSUoS have the potential for being charged more cost-effectively and hence could provide a forward-looking signal. They identified four potential options:

  1. Locational Transmission Constraints
  2. Locational Reactive and Voltage Constraints
  3. Response and Reserve Bands
  4. Response and Reserve Utilisation

Deliverable 3 –
Feasibility of charging potentially cost reflective elements of BSUoS to provide a forward-looking signal

The Task Force assessed the feasibility of the four potential options from Deliverable 2. They concluded that whilst there are some theoretical advantages to all four potential options identified, the implementation of each would not or could not provide a cost-reflective and forward-looking signal to drive efficient and effective market behaviour.

An important constraint to consider is that BSUoS is based on total costs incurred by the ESO, which can see significant variation. The Task Force believes that an effective forward-looking signal should come from marginal costs, rather than the total costs, so that market parties face only the cost they impose on the system. Although they have determined that it is unclear how to accomplish this through BSUoS.

In addition to this, if a forward-looking BSUoS signal was to be developed the Task Force expects that this signal could end up being ineffective. Other signals already in place through the market and charging arrangements could lead to double-counting issues. This can create the risk of under or overestimation of charges, leading to market distorting signals.

Current Conclusion – Any change to customers?

The Task Force has so far concluded that it is not feasible to charge any of the BSUoS components in a more cost-reflective and forward-looking manner that would effectively influence behavior that would help the system and/or lower costs to customers. It is on this basis that the costs included with BSUoS should all be treated on a cost-recovery basis.

It is for Ofgem to decide, but the Task Force recommends that cost-recovery charges should aim to minimise market distorting signals, to benefit both the system and customers. They note that the current construction of BSUoS may inadvertently be sending signals that are detrimental to the system, but the structure of the charge is out of the scope of the Task Force.

The Draft Report has been framed as a consultation with a response date of 17 May 2019. Feedback received during this period will be considered in the final version of the report, expected to be published 31 May 2019, and submitted to Ofgem.


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