Jersey Electricity — Updated modelling of net zero implications

JEL is the sole supplier of electricity to the island of Jersey. The electricity business is responsible for generating around 75% of group revenues and operating profits. JEL also operates a range of other businesses including property rental, retail and business services. GoJ remains the largest shareholder, with 62% of the ordinary share capital and 86.4% of the voting rights.

In March 2021, GoJ appointed an advisory panel for the Citizens’ Assembly on Climate Change. Throughout the rest of 2021, the panel consulted with Jersey residents and reviewed technical documentation to inform policy decisions and ultimately net zero targets to be ratified by GoJ. In December, GoJ published a consultation draft of the Carbon Neutral Roadmap. A significant part of Jersey’s decarbonisation strategy will be based on the electrification of heating systems and road transport. This presents an opportunity for JEL to grow its unit sales. Greater clarity on policy initiatives could provide impetus to JEL’s share price; our indicative valuation of 800p, which takes account of decarbonisation scenarios, is 51% above JEL’s share price of 530p.

We model potential additional electricity demand based on our assessment of the feasibility of the government targets, corresponding policies and funding for incentives in the consultation draft of Carbon Neutral Roadmap. We cross-check our projections against two scenarios, net zero by 2050 and net zero by 2040, that we modelled in our June 2021 outlook report.

In this report we analyse JEL’s efforts to fulfil its core objective of secure, affordable and sustainable electricity, review the initiatives it has taken that are designed to help the island achieve a zero-carbon future and analyse the opportunities that could arise from Jersey’s ongoing consultation relating to a ‘carbon neutral roadmap’.

Revenue for FY21 was £119m, an increase of 6% over FY20 (£112m). The revenue growth was driven by higher unit sales of electricity (639m versus 619m in FY20), due to a recovery in retail and hospitality sectors as COVID-19 restrictions eased, increased working from home and colder than normal weather, combined with a 2.5% tariff rise from October 2020. However, revenue for H122 was down 3% versus H121 (£65.0m versus £67.1m). This was due to milder-than-usual weather combined with less working from home resulting in lower domestic consumption, causing a 4% decrease in unit sales to 359m in H122 (375m in H121). In contrast, cost of sales and operating costs increased by c 3% and c 2% respectively in H122 versus H121, resulting in a decrease in recurring operating profit margin to 11.8% in H122 from 16.8% in H121. This led to a 34% decrease in net income to £5.5m in H122 (£8.3m in H121). On the other hand, PBT for FY21 was £19.1m, which is 29% ahead of FY20 (£14.8m). However, adjusting for a revaluation gain of £6.1m and a non-recurring (and non-cash) ex-gratia award for pensions in service (£1.8m), gives underlying PBT of £14.8m, which is a slight increase on FY20 (£14.7m). Similarly, adjusted operating profit for FY21 (£16.3m) was slightly ahead of FY20 (£16.1m).

On a divisional basis, adjusted (recurring) operating profit for Energy (£12.5m) was 2% ahead of FY20 (£12.3m). This was due to the increase in volume sales, but was partially offset by higher energy costs that were not fully passed on to the consumer during the period. For H122, as unit costs decreased compared to H121, and due to energy costs continuing to rise, reported operating profit decreased by 31% y-o-y. For FY21, Retail had another stellar year with 11% revenue growth to £20m and margin expansion from 6.6% in FY20 to 7.7% in FY21, giving rise to a 30% increase in operating profit to £1.5m. The strong performance in retail has been driven by its online business and increased demand from people staying at home due to COVID-19 restrictions. For H122, this trend has started to reverse, which has seen revenue decrease by 12% y-o-y and operating margin decrease from 9.4% in H121 to 6.9% in H122. This resulted in a 35% decrease in operating profit year-on-year. For FY21, Building Services’ operating profit remained steady at just over £0.2m following its turnaround in FY20. This steadiness continued in H122 with reported operating profit of £0.1m. Operating profit for Property was £1.4m, which is below FY20 (£1.7m) when adjusted for £0.4m of accelerated depreciation. However, similarly, Property remained steady in H122 with reported operating profit of £0.7m. Other businesses were also below FY20 on an operating profit basis (£0.6m vs £0.8m).

For FY21, operating cash flow (pre-tax, pre-interest) was £26.5m, which is £4.5m lower than FY20 (£31.0m), mostly due to a swing in working capital movement (by £4.7m). Capex was £9.3m, which is £2m below FY20, due to deferred investment on items such as the new transformer for Queen’s Road. FCF was £7.6m, which increased JEL’s net cash to £10.0m (from £2.6m at end FY20), after deducting long-term IFRS 16 lease liabilities of £3.1m (FY20: £2.9m). By the end of H122, net cash had decreased slightly to £9.8m (including lease liabilities of £3.3m). JEL increased its final dividend by 5%, to give a total dividend for the year of 17.4p per share (FY20: 16.5p), and has also increased its interim dividend (for H122) by 5% to 7.6p.

In our March 2019 outlook note on JEL, we outlined in some detail the potential changes being considered for the regulatory system. Up to this point there have been no concrete proposals for change and no move on the part of the GoJ to amend the Electricity Law of 1937, which it remains committed to reviewing. JEL therefore continues to operate on a self-regulated basis, aiming to meet two self-imposed regulatory targets. That is, JEL seeks a return of 6–7% (pre-tax and interest) on its energy business (operating fixed assets net of customer contributions) on a rolling five-year basis and ensure its tariffs remain within ±10% of the EU-15 average (inclusive of all taxes).

In FY21, JEL’s reported return on assets was 5.9%, which on adjustment for non-recurring (and non-cash) past service costs of £1.8m becomes 7.0% (up from 6.8% in FY20). It is within JEL’s targeted range and the current rolling five-year average rate of return remains below 7.0% (at 6.9%). The five-year return figure reflects a period of steady profitability following the volatility caused by the interconnector failure in 2012–13.

In comparison, Ofwat used a rate of return (pre-tax nominal) of c 5.0% for the UK water companies in its latest periodic review of the sector (PR19). Ofwat’s allowed rates of return are below those used by JEL, although we would caution against an over-simplistic comparison of headline rates of return. The method for calculating invested regulatory capital can differ significantly between industries and, in addition, the UK water sector benefits from an annual inflation-linked increase in its regulatory capital value; JEL does not. However, by way of illustration a 1.5pp (from 6.5% to 5.0%) reduction in allowed pre-tax returns would result a reduction in operating profit of c £2.7m pa (FY21 recurring operating profit was £16.3m, excluding revaluation of investment properties).

Although JEL remains a self-regulated entity, delivery of satisfactory standards of service for customers remains another key benchmark. JEL has taken part in the UK Customer Satisfaction Index for the last three years (2019–21). In 2021, it gained a rating of 78.4%, which is above the average for utilities of 73.5%. It positions JEL fifth out of 34 utilities, with only two power utilities (Octopus Energy and UK Power Networks) scoring higher. It is JEL’s highest score yet; it compares to 77.0% in 2020 and 78.0% in 2019. According to previous surveys of customer opinion carried out for JEL, the three most important elements of customer service are cost and price stability, security of supply and environmental performance. We examine JEL’s track record in each of these three areas below. In particular, we review in greater detail JEL’s environmental performance in light of the impact it has had in reducing the island’s carbon emissions, the declaration by the GoJ of a climate emergency (May 2019), and the business opportunities that might arise from further decarbonisation.

On a monthly average basis, the day-ahead wholesale electricity price in France increased fivefold y-o-y from €51/MWh in December 2021 to c €272/MWh in December (peaking daily at €455/MWh in December); it reduced to c €200/MWh, on average, in January and February before reaching a new high in early March (€560/MWh), following Russia’s invasion of Ukraine. On average, from October 2021, monthly average prices have equated to a fourfold increase y-o-y. The strong increase in prices since the end of H121 can be attributed to unprecedented increases in natural gas prices combined with unexpected maintenance of nuclear reactors. In total, 17 of the country’s 56 nuclear power plants were undergoing planned or unexpected maintenance during H221. This has caused France, which has been one of Europe’s largest exporters of electricity over the last few years, to become a net importer over November 2021 to January 2022, although we understand levels of imports are decreasing due to mild weather since the start of the year. As many of the nuclear outages are now expected to last well into 2022, to prevent power outages France is increasing its utilisation of domestic coal fired plants. It expects to exceed its self-imposed limits (for climate change reasons) on coal usage and despite high European carbon price, this should help alleviate wholesale prices, to some extent. However, as there appears to be no end to the gas crisis, we struggle to envisage long-term wholesale electricity prices below €60–70/MWh (real).

JEL’s pricing mechanism with EDF is split between a fixed price element (roughly one-third) and a market-exposed element. In addition, there are transport costs payable to RTE (the grid operator). Fortunately, JEL has always been cautious in hedging its market exposure and, we are informed by management, is materially hedged over FY22–24 with a capped price mechanism likely kicking in during FY23 and FY24. The hedges (and capped price mechanisms) are significantly below prevailing market prices and more akin to the wholesale price before the energy crisis, in H121. We assume JEL’s wholesale price exposure is €70/MWh (real) from FY25, which is a c 25% increase above our estimated cost for FY24 (in real terms). This is notably above the average wholesale price (using day ahead prices) over the period May 2019 to May 2021 of €40/MWh, however, is inherently subjective to forecast. Although JEL seeks price stability, any cost increases are ultimately passed to the consumer. We believe that JEL’s recently announced tariff increases will help mitigate against this projected discontinuous jump in electricity costs in FY25. We estimate that a further tariff increase of 4% (in real terms) would be required by FY25, in order to maintain return on capital for FY25 above 6%. This rise would be notably higher were it not for our forecast increase in volume sales and is significantly lower than price increases in the UK and expected increases elsewhere in Europe (discussed below).

JEL increased tariffs by 4% from 1 January 2022, and recently announced a tariff increase of 5% from 1 July 2022 and an intention to implement a further 5% rise from 1 January 2023. These tariff increases are a result of unprecedently high wholesale prices and JEL wanting to smooth the trajectory of tariff increases towards FY25 when it becomes more materially exposed to wholesale electricity prices. This tariff increase is modest compared to the increase in the French wholesale electricity price (discussed in the sub-section above) and is a testament to JEL’s cautious approach to hedging.

Exhibit 4 shows EU-15 retail electricity prices for H221, which are the latest available data from Eurostat. These are prices from during the start of the European energy crisis, and do not factor in more recent price hikes. For a like-for-like comparison, we use JEL’s domestic price from H121, before the 4% increase in January 2022, of 15.7p/kWh (or 18.8c/kWh). JEL’s tariff is 18% below the EU median price.

As an indication of how prices have increased during the energy crisis, based on UK energy price cap data, which has an impact on c 22 million customers, the average price cap for 1 October 201 to 30 September 2022 implies a 49% increase over a year earlier (in nominal terms). In addition, Reuters has reported that German electricity bills will go up by an average of 63.7% in 2022.

Another factor that is mitigating against JEL’s requirement to increase tariff prices is the increase in volume sales (we forecast a 10-year CAGR of 2%). The upwards pressure on volume sales from Jersey’s decarbonisation is particularly significant from FY25, when JEL becomes exposed to market prices. It should help mitigate against the need for further significant tariff increases beyond those planned in July 2022 and January 2023. However, if GoJ’s policy support for electric vehicles (EVs) and heating do not result in decarbonisation as quickly as our projections (which are significantly below GoJ’s own ‘aspirational’ targets) then there would be additional upwards pressure on tariffs.

JEL imports 95% of its electricity from EDF (through undersea cabling to mainland France). In the absence of significant on-island power generation, JEL is heavily reliant on this supply. France has set a legally binding target of net zero by 2050 and will itself see a significant increase in electricity demand due to the electrification of road transport in the coming years, although it hopes to offset a significant portion of this by reducing electricity consumption by 40%. Until October 2021, France was one of Europe’s largest electricity exporters. Based on data from Ember, in 2021, France produced 528TWh and exported 42TWh (c 8% of production); the net exports include 3TWh of net imports in November and December. Based on data from the National Low Carbon Strategy, published by France’s Ministère de la Transition Ecologique et Solidaire in March 2020, France’s total projected energy requirement in 2050 is 1,060TWh, of which 55% is expected to be met from carbon-free electricity, equating to an electricity requirement of 583TWh. To meet this and maintain its current level of exports, we estimate France will need to increase electricity production by 97TWh pa and replace 51TWh pa of existing fossil fuel generation capacity (coal, oil and gas). This equates to required new electricity production of 148TWh pa, which is a 28% increase in existing production. This estimate does not take into account any underutilised capacity implicit in the 2021 production figure, including the nuclear outages, nor does it account for the replacement of any ageing non-fossil fuel power generation sources that reach the end of their useful economic life before 2050.

JEL’s metric for measuring security of supply is customer minutes lost (CML). In FY21, according to JEL, only five minutes were lost, the same as in FY20 and better than all other years over the last 10 years (Exhibit 5). With the exception of a spike in minutes lost in 2012 due to the failure of the interconnector, the extent of interruptions has remained low (10-year average of nine minutes). In comparison, in 2019/20 UK distributors averaged roughly 35 CML, based on data from OFGEM.

The success in restricting CML can be attributed to the efficacy of JEL’s capital expenditure programme, which has entailed average annual capital expenditure of c £19m (depreciation c £10m per year over the same period) over the last 10 years, including strengthening and upgrading of the interconnectors with France. Total interconnector capacity totals 202MW versus a record peak demand figure of 178MW (March 2018) (peak of 170MW in FY21). Most recently JEL brought into service (December 2018) the St Helier West Primary Substation (£17m cost), which relieves pressure on supplies to St Helier and is designed to ‘future proof’ the network.

Interconnector capacity of 202MW allows up to 1,770GWh (or 1,770m units) of peak demand electricity. Based on this, combined with the historical peak demand to annual sales ratio (see Exhibit 6), we estimate that JEL could increase imported electricity to up to around 800GWh (or 800m units) without overstretching the system at peak demand; 800GWh implies a ratio of peak demand to annual sales of 2.2x. This compares to forecast units sold in 2030 of 766m units.

Only in FY18, which was an outlier, was the ratio higher (at 2.5x); using this ratio instead implies potential imported electricity of just 720GWh (or 720m units).

In addition to the risks associated with the movement in the French wholesale price, JEL must also manage the currency risk related to the purchase of its power (in euros) but with a sales price denominated in sterling. To manage this, JEL enters into forward currency contracts (on a rolling three-year basis) to reduce exposure and assist in tariff planning. In broad terms, over the last 10 years, JEL has matched the effective exchange rate of its underlying electricity purchases with the average prevailing spot rate for £/€ (both average c 1.19).

However, as can be seen in 2017 and 2018 (Exhibit 7), JEL was able to lock in average power purchase exchange rates significantly above the spot rate thanks to the prevailing strength of sterling in 2015 and 2016 (mostly before Brexit-related currency weakness). However, in 2019 the hedging position began to unwind, with the £/€ rate associated with the purchase of electricity declining from a relatively favourable 1.27 in 2018 to 1.17 at the end of 2019. The current £/€ spot rate of around 1.15 is slightly below the 10-year average. All else being equal, a strengthening of sterling would reduce energy purchase costs for JEL. In its 2020 annual report, JEL stated it was ‘materially’, but not fully, hedged for 2021–23.

As we have noted in previous reports, JEL imports around 95% (FY20: 95%) of its electricity through three undersea supply cables from France. Although the majority of the imported power is sourced from nuclear stations, a third of the imports are from renewable hydro sources. The mix of nuclear and hydro provides JEL (and the island) with very low carbon electricity and, at a carbon intensity of 23g CO2e/kWh, it is c 10% of the carbon intensity of the emissions of the UK’s electricity system as a whole (233g CO2e/kWh) based on figures produced by the Department for Business, Energy and Industrial Strategy. The carbon intensity of JEL’s electricity is also c 90% below that of local gas and heating oil and the company has played a key role in reducing the greenhouse gas emissions of the island (by 47% between 1990 and 2017).

Beyond the importation of low-carbon electricity, JEL continues with other environmental initiatives. It now owns and operates four rooftop solar plants, under long-term power purchase agreements (PPAs), with a combined capacity of nearly 1MW. The largest of the solar plants were both commissioned during FY21 at Jersey Dairy and Woodside Farm (combined 805kWp). During FY20 JEL installed Jersey’s first Solar Hub, combining a 53kWp solar photovoltaic (PV) array and two 22kW EV charge points, which followed the installation (in partnership with SunWorks) of a photovoltaic array at La Collette (81kWp) in FY19. In total, the four plants are estimated to generate c 1,000,000kWh pa).

JEL has appointed a dedicated solar project officer to its energy solutions team to seek out more suitable sites for solar PV installations and has said it is happy to enter long-term PPAs with local developers to help facilitate the financing of projects. Promotion of energy efficiency also forms part of JEL’s environmental strategy and a key part of this is the island-wide roll out of smart meters, which JEL completed during FY20; around 51,000 smart meters have now been installed in Jersey. JEL has also entered a tree-planting project with Jersey Water (a National Trust initiative), planting 6,000 trees on a 20-acre site in the Mourier Valley over a three-year period.

This section should be read in conjunction with the same section of our June 2021 outlook report. In March 2021, GoJ appointed an advisory panel for the Citizens’ Assembly on Climate Change. Throughout the rest of 2021, the panel consulted with Jersey residents and reviewed technical documentation to inform policy decisions and ultimately net zero targets to be ratified by GoJ. In December, a consultation draft of Carbon Neutral Roadmap was published by GoJ. A significant part of Jersey’s decarbonisation strategy will be based on the electrification of heating systems and road transport. These two sources of emissions account for about two-thirds of total emissions in Jersey. We estimate that c 45% of residential properties (c 20,000) use non-electric heating, mostly fuel oil but also liquified petroleum gas (LPG), and just over 1% of vehicles are electric.

Based on our detailed modelling, we estimate that full electrification of these two areas could increase electricity demand by 454 GWh (or 454m units of electricity), representing a 71% increase on the 639m units sold by JEL in FY21. This is slightly less than our estimate of 477GWh in our previous June 2021 outlook report, as we now assume that commercial customers switching from fossil fuel heating to electric heating use a higher proportion of heat pumps than residential customers (and therefore consume less electricity). In our modelling, we also take into account the impact of energy efficiency measures and increased demand from new housing builds and medicinal cannabis. We formulate our projections based on our assessment of the feasibility of the government targets and corresponding policies in the consultation draft of Carbon Neutral Roadmap. We cross-check our projections against two scenarios, net zero by 2050 and net zero by 2040, that we modelled in our June 2021 outlook report. We do not cross-check against our net zero by 2030 scenario from that report, as it is clear from the consultation draft of Carbon Neutral Roadmap that carbon neutrality by 2030 is unattainable without the purchase of carbon offsets (which are not included in our modelling).

Proposed policies relating to heating set out in the consultation draft, dated December 2021, of Carbon Neutral Roadmap include:

In recent years JEL has actively sought to assist islanders in switching from fossil fuel heating to electricity via its expanded energy solution team. In July 2018, to augment the rate of switching, JEL opened a Smarter Living hub and customer information centre within its Powerhouse retail outlet. We estimate new electric heating conversions during the year from the change in the number of customers using JEL’s discounted heating tariff adjusted for the number of new builds (estimated from JEL’s increase in new supply customers), which we assume all use electric heating from 2019; 50% had electric heating in 2016–17 and 75% in 2018.

In 2021, 941 customers were added to JEL’s heating tariff, which, adjusted for estimated new builds of 390, suggests there were an estimated 551 heating conversions; JEL’s energy solutions team retrofitted 316 of these homes to electric heating (225 in 2020). The decrease in customers switching to JEL’s heating tariff compared since 2019 is mostly due to restrictions relating to the COVID-19 pandemic.

In the consultation draft of Carbon Neutral Roadmap, GoJ is targeting 16,000 residential boilers and 1,700 commercial boilers are switched to electric heating systems by 2030 and all remaining boilers by 2034. In our view, this is aggressive not least because GoJ is budgeting to subsidise just under 1,000 residential heating system replacements, in total, over the next four years (2022–25), at a cost of £5.7m, compared to an average of 2,000 replacements per year required to meet the government’s 2030 target. Furthermore, GoJ is proposing to prohibit new fossil fuel boilers being installed from 2026 (and inconsistently on p52, para 7.26 of the consultation draft of Carbon Neutral Roadmap, it suggests prohibiting them from 2030); with an average life of a boiler of 15 years, presumably these properties would not want to switch to an electric heating system by 2034, unless sufficiently incentivised. In addition, we believe the number of boilers to be switched in such a short period (17,700 by 2030) far exceeds the current on-island technical resource, thus heating engineers would need to be recruited from outside of Jersey and housed.

As such, we are cautious in our projections and assume that new electric heating systems are installed on a linear basis of 838 per year to 2050. This is still notably higher than 2021 and above the highest-ever level of 781 conversions in 2019 (pre-COVID-19). We would need to see significant impact from GoJ’s policies, assuming they are passed into law, before we become more aggressive in our projections. Our annual heating conversion assumption comprises 727 residential heating systems and 112 more complex commercial heating systems. We estimate that commercial heating customers consume more than three times the residential heating customers. Thus, the incremental increase in electricity units for this (base case) scenario is higher than the net zero by 2050 scenario in our previous outlook report, which assumed only residential conversions to 2030 (followed by an accelerated pathway including commercial conversions beyond 2030). We assume the average electricity consumption per residential conversion steadily decreases from c 8,500kWh (or units) in 2021 to c 6,400kWh by 2030 due to a higher proportion of heat pumps being installed, particularly in larger residential properties. We assume the share of heating pumps in new residential conversions increases steadily from 5% in 2021 to 40% by 2030. For the same reason, we assume a reduction for commercial customers from c 29,000kWh in 2021 to c 19,000kWh by 2030, on average. We assume the share of heating pumps in new commercial conversions increases steadily from 40% of new conversions in 2021 to 80% by 2030. This assumption is highly subjective and cannot be easily substantiated.

Proposed policies relating to EVs set out in the consultation draft of Carbon Neutral Roadmap include:

At the end of 2021, there were c 1,250 pure EVs on Jersey (2020: c 850), representing c 1.1 % of the estimated licensed vehicle base (‘parc’) of roughly 115,000 vehicles (2020: c 0.8%). We estimate a licensed vehicle base from the registered vehicle base in Jersey of 127,661 vehicles (GoJ data at 31 December 2021), by assuming 10% of registered vehicles are not in use. This is consistent with data from the UK Department for Transport, which imply that between 8% and 12% of vehicles were declared off road (SORN) on an annual basis over 2015–21. Based on our estimates, new EV sales as a percentage of total new vehicle sales have been increasing annually from under 1% in 2016 (based on 56 EVs sold) to 8% in 2021 (based on 426 EVs sold). We define new vehicle sales as new vehicle registrations in Jersey and thus they can include older vehicles imported to the island. We use the two terms interchangeably.

In our base case, from 2030 we assume only non-petrol or diesel cars and small vans are newly registered, in line with GoJ’s proposed policy. As Jersey is a small island, battery range anxiety should be less of an issue than elsewhere, thus we assume all newly registered vehicles from this point are pure EVs, rather than a mix of plug-in hybrids and pure EVs. Similarly, for larger vehicles, we assume only pure EVs are newly registered from 2035 (in reality, some of these could be hydrogen vehicles; however, GoJ’s stance on hydrogen infrastructure is not yet fully developed). Our assumed profile for new EV sales as a percentage of new vehicles sales is closer to our previously modelled net zero by 2040 pathway than net zero by 2050 (see Exhibit 10).

We assume the parc of vehicles (and total registered vehicles) increases by 0.5% per year, which equates to an increase of 585 vehicles per year (650 pa for total registered vehicles), on average, over the period to 2030. The annual increase in total registered vehicles equates to new vehicles sales less vehicles scrapped (which includes removals and exports). GoJ is proposing to set aside c £6.1m for incentives to speed up the adoption of EV. This is intended to incentivise the purchase of 1,606 EVs and 1,031 EV chargers. Based on our assumed profile of new EV sales as a percentage of new vehicles sales, we estimate new EV sales of c 7,000 vehicles over the five-year period to 2026 and by 2030 annual EV sales of c 4,500 vehicles (which equates to c 85% of new vehicle sales). On this basis, arguably the GoJ’s incentive scheme might need to be extended.

We note that the consultation draft of Carbon Neutral Roadmap provides an ‘aspirational’ target of 59,000 EVs on the road by 2030. This compares to c 23,000 EVs in our base projections, which are derived from GoJ’s policy measure of prohibiting petrol and diesel cars and small vans from 2030 and all other vehicles at subsequent dates between 2030 and 2040 (which assume by 2035). To achieve 59,000 EVs on the road by 2030 (which equates to new EV registrations of c 7,375 per year over the next eight years), in our view all fossil fuel vehicles would need to be banned immediately and the proposed EV incentive scheme funding pool increased to at least c £200m, amongst other things.

Due to the size of the existing parc and adopting a current vehicle ‘scrappage’ rate (including removals and exports as well as scrapped vehicles) of roughly 4% of parc per year, even with new EV sales as a percentage of total vehicle sales over 80% by 2030. As shown in Exhibit 11, in our base projections EVs only account for c 20% of the total parc by 2030, which is roughly halfway between our net zero by 2050 and net zero by 2040 scenarios. Even in our net zero by 2040 scenario, EVs only account for c 25% of the total parc by 2030 and this is despite new EV sales as a percentage of total vehicle sales reaching 100% by then. This is due to the sheer size of the existing parc coupled with the current vehicle ‘scrappage’ rate (including removals and exports as well as scrapped vehicles) being in the region of 4–5% of parc per year. This implies the existing parc would take 20–25 years to be replaced with EVs, unless scrappage rates dramatically increase. GoJ’s proposed vehicle scrappage scheme, while a starting point, only extends to the scrappage of 500 vehicles; this removes just 0.4% of the existing parc (of 115,000 vehicles).

See our June 2021 outlook report. We have made no changes to our assumptions.

Authorised growing of cannabis for medical reason is now possible on Jersey. Cultivation of cannabis is energy intensive, primarily driven by the need for UV lighting. Based on conversations with JEL, we estimate this could increase volume sales by 5m units in FY22. We await data relating to the initial success (or otherwise) of the industry before forecasting any growth beyond this; we thus assume a flat 5m units pa for now.

The most recent board changes are the retirement of Aaron Le Cornu, who retired at the 2021 AGM, and the resignation of Peter Simon who stood down due to a new business opportunity. As part of succession planning, Mr Le Cornu’s retirement from the board had already been anticipated by the recruitment of Amanda Iceton in June 2020. Kayte O’Neill, who works with National Grid was appointed at the March 2022 AGM. The board has eight members, the chairman, five other non-executive directors and two executives, Chris Ambler (CEO since 2008) and Martin Magee (CFO since 2002).

JEL’s three-tiered shareholding structure, including ordinary, ‘A’ shares and preference shares, remained unchanged in FY21. The ordinary shares (19m in issue) entitle the holder to one vote for every 20 shares held, whereas the ‘A’ Shares carry the right to one vote for every 100 shares held. Due to this shareholding structure, the States of Jersey (SoJ) continues to hold all the ordinary shares and owns 62% of the total capital but possesses 86.4% of the total voting rights.

Below we list the principal sensitivities determining JEL’s profitability:

We have enhanced our traditional valuation approach for JEL by including a 10-year DCF analysis, which better considers the longer-term impact of the energy transition. We place less emphasis on the peer valuation, using it only as a cross-check.

Overall, the valuation, which is an average of our DCF and SOTP valuations, is 800p (rounded), which is up 15p (2%) versus our last published valuation (in June 2021). The uplift in valuation can be attributed mostly to an improvement in net cash position and increase in value of the property business offset by a slightly lower valuation for the core energy business and other businesses.

We estimate regulatory assets to be in the region of c £180m (and assume JEL earns a return on these assets equal to its cost of capital on these assets). We value the property business (rental properties owned by JEL) using balance sheet carrying value and the other businesses (retail, business services, other) at 7x prospective EBITDA (UK 250: 7x; UK 350 retailers: 7x). Overall, the SOTP valuation has risen 18p since we published in June 2021. The principal factors behind the increase in valuation are the property business +20p (due to revaluation gain), improvement in net cash position +22p and other adjustments +13p, partially offset by declines in estimated asset base -7p and other businesses -30p (due to derating of UK indices from 10x to 7x EBITDA).

We update our DCF methodology to better reflect the longer-term energy transition; we adopt a 10-year cash flow forecast period followed by terminal value. Our valuation for JEL is based on our adjusted decarbonisation scenario (base case), which takes account of GOJ’s proposed policies and funding allocated to incentives, but does not go as far as adopting GoJ’s proposed targets for EVs and electric fuel heating conversions.

Key assumptions and drivers for our cash flow model are as follows:

Our DCF valuation of 783p per share is based on a WACC of 6% and a TGR of 2% and includes an energy business valuation of £153m and other businesses valuation of £59m. The energy business valuation is lower than the £178m in our SOTP valuation, which was estimated using a regulated assets approach. The difference between the two valuations can be explained by converting the pre-tax return of 6.5% (targeted on the regulatory assets) to a post-tax return of 5.2% (adjusting for a 20% tax rate) and using this as the WACC in the DCF valuation; 5.0% WACC = £190m for the energy business; 5.5% WACC = £170m (Exhibit 15 above). Other businesses are valued 31% higher using our DCF methodology compared with the SOTP (£59m versus £45m); this is due to a combination of the DCF reflecting longer-term growth prospects (not always captured using peer multiples) along with a relatively low WACC of 6%.

We use peer valuation as a cross-check, rather than driving our valuation, due to a lack of comparable companies to JEL. In our approach, we use P/E and EV/EBITDA multiples, which imply a valuation of 817p per share (see Exhibit 16 below). This is above our DCF- and SOTP-based valuation for JEL of 800p per share. National Grid, Terna and Red Eléctrica, which are electricity grid operators, are the most comparable companies to JEL; we use an average of multiples from these companies in our peer valuation. We use 2023 multiples only because also using 2022 multiples (and averaging) would distort the implied valuation, as JEL’s return is just 5% in FY22, significantly below its target range of 6–7%, which we expect it to achieve in all subsequent years. We note the P/E is distorted by significantly higher net debt to equity ratios among JEL’s peer group; EV/EBITDA removes this distortion, so is arguably a better metric. EV/EBITDA alone implies a valuation of 1,021p per share, which is considerably above our valuation.

Profitability and returns: we base our forecasts for FY22 and FY23 on the assumption that the core energy business delivers profitability in the range of the targeted return. In FY21, reported return on electricity assets was 5.9%, which on adjustment for non-recurring (and non-cash) past service costs of £1.8m becomes 6.98%. We forecast a return of 5.0% in FY22, which includes the recently announced tariff increase of 5% from 1 July 2022. This results in a dip in profitability in FY22 (forecast recurring operating profit of £12.5m vs £16.3m in FY21), before returning to profitable growth from FY23, assisted by a further planned tariff increase of 5% from 1 January 2023.

For FY23–25 we forecast returns of 6.9%, 6.7% and 6.0%, which assumes a further c 4% tariff increase in real terms in FY25, when JEL becomes unhedged against wholesale price exposure. For FY26–31, assuming wholesale prices remain at an estimated €70/MWh (real) and given our projected volume sale increases, we believe an average c 6.5% return can be achieved without any tariff increases (in real-terms).

Capex: JEL has spent c £22.5m pa (in real terms) on average over the last 10 years, but with the substantial investment programme largely complete, we expect capex to remain below this, on average, for the period 2022–31 (£17.0m pa, real). We forecast capex (real) of £15.9m in FY22 and £21.6m in FY23 (FY21: £9.6m), which equates to nominal capex of £15.9m in FY22 and £22.2m in FY23 (FY21: £9.3m). The increase in capex in FY22 is due to an estimated £4m investment in a new transformer at Queen’s Road. We had previously assumed this investment would be spread equally over FY21 and FY22; however, it has mostly been deferred from FY21. The further increase in capex in FY23 is mostly due to an estimated £10m pa investment in a new gas turbine spread over FY23 and FY24. The total investment of £20m is larger than our previous estimate of £12m and reflects JEL’s objective of enhancing energy security. We estimate growth capex (real) of £27m (in total) spread over FY24–31 to bolster the on-island grid infrastructure to support our forecast increase in volume sales resulting from GoJ’s net zero targets.

Pensions: we assume that the pension surplus of £21.4m at end-H122 reverses back to £18.8m by end-FY22, and that payments are c £2.1m less than the charge to the P&L over FY23–31, such that the surplus is unwound by end-FY31. Although we include the impact of this on the cash flow statement, we exclude these adjustments from FCF in our DCF valuation and instead adjust for the pension surplus in our enterprise value to equity value adjustment.

Tax: for tax payable (P&L) we assume an effective tax rate of 20% for FY21 and FY22 (FY21: 15%). The effective rate in FY21 was lower due to the £6.0m property revaluation gain not being taxable. For tax paid we make approximate adjustments for accelerated capital allowances and assume payment in the following year.

Dividends: our forecasts assume a 5% per year increase in the DPS for FY22 and FY23, with a cash impact from payments of £5.5m in FY22 (FY21 final dividend plus FY22 interim dividend) and £5.7m in FY22 (FY22 final dividend plus FY23 interim dividend). The DPS is forecast to be well covered by earnings: 1.6x in FY22 and 2.0x in FY23, despite the recent unprecedented increases in wholesale energy prices in Europe.

Cash flow and balance sheet: in the absence of any repayment of outstanding long-term debt of £30m (which expires in 2034 and 2039) or a special dividend, we forecast that cash decreases slightly to £38.2m in FY22 and £35.5m in FY24 (FY21: £43.1m). This is primarily due to higher capex because of the investment in a new transformer at Queen’s road in FY22 and a new gas turbine in FY23 and FY24.