In this issue:
1. Climate Change Levy (CCL) to increase by 65% from 1st April 2019.
2. Third Party Intermediary Code of Practice (TPI COP)
3. Smart Metering – What assumption?
4. Unidentified Gas: The Issue and Way Forward
5. Faster and More Reliable Switching
1. Climate Change Levy (CCL) to increase 65% from 1st April 2019.
For some time the natural gas Climate Change Levy (CCL) has increased every April in amounts which would rarely give rise to comment. But the 1st April 2019 increase is notably different. Introduced back in 2001, CCL is an energy tax aimed at driving businesses to reduce their energy consumption. Energy suppliers, ourselves included, collect the tax and pay it to HM Revenue and Customs.
But as a direct result of a tax shortfall which will come from the abolition of the Carbon Reduction Commitment Energy Efficiency Scheme, CCL for natural gas will increase by over 65% from 1st April 2019.
Where a business with a typical annual gas consumption of 100,000 kWh may have expected to pay £203 of CCL for the 2018/19 tax year, come next year this will grow to £339, a significant difference especially for those smaller businesses who are trying to manage their operating costs.
The options are limited. The main purpose of the tax is for organisations to reduce their consumption of power and natural gas, which in turn helps save carbon and goes towards supporting the national climate change target. Some organisations may qualify for reduced CCL rates if they enter into a Climate Change Agreement with the Environment Agency (a process in itself which is restricted to only certain market sectors and deliberately administrative in its operation).
The message for customers is to assess your energy usage and determine whether you can reduce your consumption in the short term to mitigate the impact of this tax in the long run.
2. Third Party Intermediary Code of Practice (TPI COP)
TPIs have promoted the expansion of products and services available to the consumer, helping fuel the competitive nature of the market which is typically associated with the non-domestic sector. TPIs we work with are varied in their operating size, business model and customer base all requiring their own bespoke type of account management. TPIs are intrinsic providing the non-domestic market with the natural catalyst for it to competitively operate.
Whilst the vast majority of TPIs are diligent and service the needs of the consumer, the existence of rogue organisations takes the shine off what is otherwise a self-regulating market.
It is in this context that we find ourselves in a debate as to whether TPIs should be regulated in the same way that we as an energy supplier are. Previous attempts by Ofgem back in 2013-14 amounted to little and were deferred pending the Competitions and Market Authority review of the Energy Industry (which itself found little evidence to support the view of wide stream anti-competitive practices).
Positive attempts have been made to enhance the credibility of the market in the form of trade associations (such as the Utilities Intermediaries Association) as well as a voluntary code of practice operated by some suppliers. The latest initiative has come out from Electra Link. Unlike other attempts, this one appears that it has the potential to go places if the level of work that has already gone into devising it is anything to go on.
Its programme and delivery timeframe are rather ambitious, perhaps contentious, with a target launch of early 2019 and a requirement to reveal commission rates in the spirit of transparency. Such a code for Electra Link would better protect the consumer and overall improve TPI-Supplier relations through standardised formats such as Letter of Authorities. At the same time, continued lobbying by the Code Board will lead to Ofgem introducing a requirement on suppliers to potentially publish commission rates for transparency purposes. Already burdened with regulations additional supplier license conditions are not a popular choice for a supplier, who would be otherwise looking towards an independent COP anchored down by robust governance.
And Ofgem’s position?
In its recent response to Future Supply Market Arrangements (31st July 2018) Ofgem accept that TPIs play a “prominent role” which could lead to “risks for domestic and non-domestic consumers.” The report, however, stops short of committing to regulatory intervention and continues to follow a familiar line that enhanced consumer protection laws should deal with TPIs and other licensees.
Time will, of course, tell us how Electra Links TPI COP will evolve, although one thing is clear. The growing diversity and prominence of TPIs, combined with increasing technologies and future retail arrangements (with the advent of faster switching), will push the TPI sphere of influence greater into the spotlight in the future.
3. Smart Metering – What assumption?
Former Energy Minister, Mike O’Brien was asked in an interview with the Telegraph for his views on Smart Metering. To the frustration of those smart meter advocates, he stated that he “barely looked at” his own smart meter and ultimately “didn’t use” it. Mr O’Brien went on to say that he “got rid of it.” The comments may have gone unnoticed had it not been pointed out that Mr O’Brien had been one of the Smarmasterminds Out masterminds during Gordon Brown’s government. An interesting point Mr O’Brien makes is that “bad assumptions” were made during the design of the programme.
The “bad assumptions” that Mr O’Brien is referring to?
As a supplier, we are licensed to take all reasonable steps to ensure that a Smart Metering System is installed on or before 31st December 2020. As a non-domestic supplier, we are captured within this scope as we supply energy to meters which have a flow rate below 11 cubic meters per hour. There are exemptions of course, the relevant one being that we can make a meter point Advanced before the current deadline of 5th December 2018 (although this is being reviewed). Advanced meters suit the non-domestic market well. An Automated Meter Reader (AMR) is either retro-fitted onto existing meters or embedded within the body of it. Data is sent to us via an AMR service provider (ASP) and we can produce an accurate bill from it. Furthermore, consumption data is stored online allowing customers to access it and monitor their energy usage on an hourly basis. It’s a proven technology that works well and is already benefiting a significant number of customers in the non-domestic space.
Smart meters are very different. A smart meter is not just limited to a physical meter but also comes with additional equipment namely a communications hub. The hub provides the power feed for the gas meter to function, allowing two-way data transmissions between the supplier and the meter via an independent Data Communications Company (DCC). This two-way set up requires a high degree of security to protect data transmissions from being intercepted by a would-be hacker. Compared to existing AMR arrangements, a smart meter set up is complex.
The assumption made a decade ago was that a supplier would install a smart meter on both the gas and electricity meter simultaneously. The assumption, however, did not fully consider those consumers who may have had separate electricity and gas suppliers and/or already had an AMR installed. Additionally, it was not fully understood how a first-generation smart meter would function should a consumer switch to an energy supplier who was unable to support smart operations. Such assumptions have brought with it challenges for the industry in terms of choreographing the installation of such equipment, meeting the rigorous DCC security requirements and finding smart metering partners who have the capability and technical resources to help support the suppliers roll out objectives. This has invariably caused delays and brought with its cost.
Nevertheless, the industry is improving, slowly. According to the Department for Business, Energy & Industrial Strategy (BEIS) the number of second generation (SMETS 2) smart meters have started to be installed at a rate of over 2000 installations per week. Such volume will eventually penetrate the market helping to eliminate the interoperability issues which have been associated with first-generation smart meters.
4. Faster and More Reliable Switching
Following the overhaul of both industry and internal systems last summer to accommodate the changes brought about by Project Nexus, it would appear that it is all change again at some point in 2020. The reason? In February 2018 Ofgem confirmed that they were pushing ahead with plans that would create a new Industry Central Switching Service (most likely to be run by the Data Communications Company) which would harmonise both gas and electricity switches. The ultimate aim of this is to increase the speed and reliability of customer switching.
Under the current plans, a customer would be able to switch their energy suppliers from the current 21 days switching period to one working day for domestic customers and two working days for non-domestic customers. It is proposed that there is a transition period for suppliers from the current set up to the new order, during which next-working-day switching will only be permitted if suppliers meet certain criteria to ensure that their customer will not experience any harm.
Behind the scenes, fundamental changes will be required to industry file flows, gas nominations, confirmations, and objections. Code of Practice relating to electricity and gas are planned to be merged into one super Retail Energy Code. There are current debates relating to the new governance arrangements which could potentially empower unlicensed parties such as TPIs and Metering Agents. Contd…
The Cost?
Current estimates in relation to its delivery are high, with Ofgem’s chosen model expected to be in the region of £600m. This cost will mainly be borne by suppliers initially and then passed onto consumers. Given recent experience of industry programmes (Project Nexus and Smart Metering), it isn’t surprising to find that some are sceptical about the current cost, delivery timescale, and programme scope plans.
The Benefit?
For the domestic consumer, there is value in the programme, just like the convenience of switching your bank account within hours the industry will enable you to switch your energy supplier. For the non-domestic supplier, however, there is little benefit. The non-domestic market is dominated by fixed-term commercial contracts, during which time an energy supplier would object to a transfer should the terms of the agreement be breached. Despite such points, it is highly unlikely that non-domestic suppliers will escape the reality of changes to come.
5. Unidentified Gas: The Issue and Way Forward
In order to understand the Unidentified Gas issues that currently face the market, we need to rewind the clock before the implementation of Project Nexus.
Project Nexus was a large UK Gas industry project that was implemented on 1st June 2017. The project replaced the previous central IT system and introduced new meter reading and settlement processes. One of the significant consequential changes was the replacement of the Unallocated Gas (UAG) process with an Unidentified Gas (UIG) process.
The new UIG process was designed with the intention of providing a more accurate volume of unidentified gas. Before Project Nexus implementation, an independent expert (the AUGE) calculated, in advance, the volume of unidentified gas for the non-domestic sector using available information. This was then charged out to suppliers in accordance with market share by volume.
Since Project Nexus, the total amount of unidentified gas is derived on a daily basis from a formula that subtracts shrinkage, Daily Meter (DM) allocations and Non-Daily Meter (NDM) estimates from the total gas input into the system. The amount of gas that is then “missing” is the UIG volume.
In this new regime, UIG itself became a standalone daily balancing item having previously been grouped together under a general allocation to NDM supply points. With its new status came with it an enhancement to its algorithm incorporating wider “uncertain” factors such as weather, meter registration error, and theft in order to accurately forecast gas consumption. In general, UIG is now calculated taking a bottom-up approach rather than the previous top-down application which incorporated all uncertainty. With such refinement, it was believed that any remaining settlement error (the “baggage” which had always been attached to UAG) would remain stable at around 1% of Local Distribution Zone (LDZ) throughput.
What happened?
Far from being a stable balancing item, the settlement error is greater than anyone could have foreseen. The UIG volume is not only higher than predicted but also widely unstable on a daily basis as well as between allocations and settlement runs. Between June to November 2017, Xoserve data revealed that the average UIG level was at 4.65% of total demand. For most shippers, the daily fluctuation and swing of UIG have been as wide as +/- 25%, with such volatility and volume making it impossible to forecast.
Far from the stability predicted, non-domestic suppliers are now battling uncertainty, with cash flow disruption – those smaller shippers having no option but to buy extra or sell excess gas. Since June 2017 suppliers have been pushing to load readings in the hope that overall UIG would reduce, in the belief that swings would calm down following reconciliations, but this has made little difference. One estimate showed that over 80% of meter points had been reconciled since 1st June 2017, with only 9% of total UIG being reallocated, a ratio which suggests that something fundamentally is wrong.
Today shippers are now exposed to greater risks relating to balancing, its finances and the ability to forecast UIG. Industry costs are estimated to be in the tens of millions, with some shippers passing through the costs to their suppliers who in turn have passed onto their end consumers. Step in Ofgem…
The way forward?
An initial flurry of urgent modifications were raised by Non-Domestic Shippers late last year, with a push to restore or return to elements of the old regime. All were rejected by Ofgem, “we consider that none of the proposals would reduce the overall volume and volatility of UIG (as currently defined) or provide greater certainty to the market as a whole.” Instead, the latest steer from Ofgem has been for the root cause to be determined and to this end they have recently approved the latest modification (July 2018) for Xoserve to be handed the resources for a task force to dissect UIG and provide a remedy. At the same time complimentary modifications have been raised to improve the accuracy of NDM forecasting (for example bringing in new profile groups). The process will be painfully slow, with real deliverables expected by spring 2019.
In the meanwhile, there is a drive for suppliers to obtain meter readings and install Advanced or Smart meters to reduce their settlement costs and improve their reconciliation volumes. All together these changes should help bring the volatility in the daily estimates of UIG down. However, it is likely that the days where shipper enjoyed UIG at 1 to 1.3% rates are gone, a figure perhaps was always artificially low due to the absence of the small non-daily meter portion of the market.
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