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Despite strong FY23 results, we continue to view consensus’ valuations as reflecting an overly optimistic assessment of Centrica’s long-term cash return and investment plans, as market normalisation continues to impact a declining EPS profile (a -26% CAGR 2024-27E). Risks remain on an overreliance on Centrica’s upstream businesses to underpin FCF generation given an ongoing reduction in commodity pricing alongside natural asset decline. The balance sheet remains attractive, and buybacks will continue to provide a level of support to the shares, however greater visibility on returns on capex will be required to re-rate the stock in our view. HOLD.
Centrica plc
Amidst acute fears over commodity price exposure, Centrica 1/ did not warn, 2/ reassured on FY24 and mid-term guidance and 3/ reported strong net cash which in our view sets the co up for further share buybacks in July. We take our numbers and TP down a touch, mostly on more conservative assumptions in services given UK GDP print today, but still see 50% upside and reiterate O/P. No signs of commodity distress Centrica expect gas prices and volatility to remain subdued but expressed confidence in medium-term guidance and did not talk-down 2024 numbers. This should provide some comfort for Centrica investors but it also reads reassuringly for the sector in our view, serving as a reminder that companies have in many cases already assumed a commodity price reset in their ''24-26 guidance. Strong net cash tees up further buybacks in our view Centrica reported net cash half a billion GBP higher than consensus worth c+7% on market cap. On the call the co stated GBP1bn of that is customer credit balances (vs. last year GBP640m) which has triggered debate with clients given Centrica also has receivables from customers (net of credit loss provisions) in excess of GBP1bn, implying an all-in positive customer cash position. What matters in our view is that 1/ SoTP cash is better than expected, and 2/ Centrica''s balance sheet is now well-positioned for an increase in the share buyback programme, which we think is plausible at 1H results in July. Trading at 2.5x EV/EBITDA, and this is not a distressed company. Reiterate O/P Centrica is now down 20% since its highs last Sept. This exceeds the net NPV impact of the fall in commodity prices - each GBP10/MWh on l.t. UK power is only worth ~2% on our SoTP equity value and we''d already assumed a negative commodity price reset back in Sept. Moreover, the stock still trades at c2.5x EV/EBITDA which does not make sense given the now-stable business performance, net-cash balance sheet and potential SBB upgrade catalyst....
Following departure of the covering analyst, we are suspending coverage of Centrica, withdrawing our forecasts, target price and recommendation with immediate effect.
In simplistic terms there is a mismatch between where the windmills are mainly located (Scotland, N Sea) and the principal centres of demand (North West, Midlands, South East) so power generally flows north => south. The amount of transmission capacity is insufficient and there are bottlenecks, the most high profile being the B6 boundary (think Hadrian's wall of electricity) between Scotland and England (ASTI projects are seeking to address this). Renewables north of B6 are often constrained off and replaced by other sources (likely gas) south of B6. Wind farms get paid constraint payments for lost output and the system (i.e., customers) pays for whatever else steps in to replace. The system has to balance and the physical limitations are what they are, so the issue of paying for replacement gas is part of a broader question and the REMA consultation process is considering this type of issue. What the BBG article is suggesting is that the expected output from wind farms has been overstated, and hence the constrained off payments are higher than they should have been. The article suggests that the cumulative overpayment is £51m over five years, so arguably not as sensational as the headlines suggested as this is <£2/customer over that period. If there is malpractice, we would expect redress payments as in previous cases involving generators (EPSHB, Drax and SSE) , but if £51m is the industry number, we wouldn't expect such payments to be market moving for the likes of SSE.
CNA DRX GOOD NG/ SSE
EDF has announced the outcome of its review of the Hinkley Point C project which has led to a re-evaluation of the schedule and costs, with the aim now being to bring Unit 1 into service around the end of the decade. Several scenarios have been analysed. The first scenario around which the project is organised is targeting becoming operational in 2029, with a schedule based on a target productivity for the electromechanical work, which action plans are being drawn up to achieve. The second scenario which forms the base case and assumes certain risks inherent in the ramp-up of the electromechanical work and the testing schedule materialise, would see Unit 1 operational in 2030. The third, or unfavourable scenario, assumes a further 12-month risk materialises that could lead to Unit 1 being operational in 2031. This updated timeline compares to EDF’s previously communicated (May ‘22) expectation of a start of electricity production in June 2027, albeit with a risk of delay then put at 15 months. The cost of completing the project has continued to balloon and EDF now estimates this at £31-34bn (2015 prices) vs. £25-26bn (2015 prices) estimated in May ‘22. This delay has potential ramifications for energy security and it is possible that we could reach the end of the decade with only one nuclear power station (Sizewell B) in operation. It also continues to call into question the ability of the nuclear industry to deliver on time and on budget, noting that the government wishes to reach FID on Sizewell C before the end of this parliament, as part of an ambition to deliver up to 24GW of nuclear power by 2050. For those that have merchant capacity such as SSE (thermal, non-CfD renewables) and Drax (OCGTs, hydro), the delay arguably increases the value of such assets and reinforces the need for the post RO/CfD bridging mechanism for large-scale biomass (Drax) that government is consulting on. The T-4 capacity market auction for delivery year 2027/28 takes place on 27th/28th February and although Sizewell B is the only nuclear plant that has pre-qualified, the results of the auction where 45.3GW (de-rated) has pre-qualified/conditionally pre-qualified vs. target capacity of 43GW, could underscore the need for capacity.
Forward wholesale prices have continued to fall since our December update and with 18 days left in the observation window for the April 2024 price cap, we have updated our estimates. Our estimates see Q224 at £1,665 (vs. £1,705), Q324 at £1,538 (vs. £1,641), and Q424 at £1,591 (vs. £1,693). The range of outcomes for Q224 is narrowing, but Q324 and Q424 are fully marked-to-market, and our estimates for 2H are therefore highly volatile. These represent the lowest cap levels since winter 2021/22, although still significantly above historic levels, and we stop short of suggesting that they bring dollops of cheer. For many, the cost of energy/living crisis remains acute. For electricity, our Q224 estimate sees a standing charge of 52.63p/day and a unit charge of 25.09p/kWh, our Q324 estimate sees a standing charge of 52.69p/day, and a unit charge of 22.66p/kWh, with our Q424 estimate seeing a standing charge of 53.27p/day, and a unit charge of 23.48p/kWh. For gas, our Q224 estimate sees a standing charge of 31.02p/day and a unit charge of 5.93p/kWh, our Q324 estimate sees a standing charge of 31.06p/day and a unit charge of 5.40p/kWh, with our Q424 estimate seeing a standing charge of 31.79p/day, and a unit charge of 5.62p/kWh. Switching nudged down in December (Figure 8), but we continue to have a situation where a market offer could price well below the current level of the cap, although the MSC (Figure 5) has continued to increase, and the Ban on Acquisition-only Tariffs (BAT) will enter supplier calculations when formulating offers. The MSC expires at end March, and we look for an update from Ofgem on the future of the BAT on or before communication of the April cap level on 23rd February. We are cognisant of some fixed price offers below the cap, but, as we have stressed on many occasions, exit charges need to be taken into account in the switching decision, particularly given the level of our cap estimates from Q2 onwards. We continue to believe that switching will be driven by customer service and innovative products rather than aggressive price competition.
Energy security continues to top the global political agenda having intensified following well documented conflicts in Europe and the Middle East. Nevertheless, governments worldwide are increasingly paying closer attention to the challenges and opportunities of developing and using renewable energy technologies. Given the complex business environment and an uncertain economic outlook, renewable focussed companies will likely see some initial challenges this year. Our 2024 outlook analyses the key trends across hydrogen, wind, batteries, and CCS in addition to companies we see as the key beneficiaries of decarbonisation efforts this year.
CNA ITM IES IKA HE1 DRX CPH2 CHAR CWR ATOM AT/
Launch of the Track-1 Expansion process in HyNet. Following the agreement of Heads of Terms with the CO₂ Transport and Storage Company (T&SCo) in October, the process to further expand the HyNet cluster has begun with a call for applications from CCUS projects wanting to take part in the expansion by 2030. The agreement of Heads of Terms with the T&SCo in the East Coast Cluster (ECC). Agreement has been reached on the key commercial principles through the Heads of Terms with the East Coast Cluster T&SCo, The Northern Endurance Partnership. DESNZ remains committed to the expansion of the East Coast, including the Humber, subject to matters such as affordability and value for money, and has welcomed the submission of Northern Endurance Partnership’s proposed storage appraisal plan for expansion through the new Bunter Closure Stores. DESNZ will now consider the best timing for launching an expansion process from 2024, based on an assessment of store readiness, beginning in the New Year. In early 2024 HMG will ask Track-2 clusters (Acorn and Viking) to submit plans for assessment of an ‘anchor phase’ of initial capture projects provisionally targeting deployment from 2028-29, subject to technical feasibility, affordability and value for money. To provide context for the anchors, HMG will also request that T&SCos provide a provisional cluster expansion plan for a ‘buildout phase’ of network and storage expansion to enable additional projects. DESNZ has advised that capture projects wishing to connect to Acorn and Viking clusters pre-2030 may consider engaging with the T&SCos directly, if they have not already done so. Vision for the UK CCUS published. A 63pp document “Carbon Capture, Usage and Storage: A Vision to Establish a Competitive Market ” (LINK) sets out a vision to make the UK a global leader in CCUS through the development of a commercial and competitive CCUS market with three phases envisaged; (i) Market creation: Getting to 20 to 30 mtpa CO₂ by 2030; (ii) Market transition: The emergence of a commercial and competitive market; and (iii) A self-sustaining CCUS market: Meeting net zero by 2050. The Vision has a number of references to BECCS, including: “CCUS is critical for energy security. By using CCUS, we can build more dispatchable gas-fired power plants and Bioenergy with CCUS power plants (power BECCS), complementing renewable generation to ensure energy security that aligns with our net zero ambitions”, and “Our modelling assumptions suggest power BECCS is expected to be one of the largest GGR contributors to our net zero ambitions”.
The Q124 price cap outturned at £1,928 (TDCV 2,700kWh electricity, 11,500kWh gas), exactly in line with our final estimate published on 15th November. With the recent fall in forward wholesale prices, and Ofgem’s proposal to include a £16 temporary adjustment to the cap from April 2024 to reflect additional bad debt related costs, we update our cap estimates for the remainder of 2024. Our updated estimates see Q224 at £1,705 (vs. £1,881), Q324 at £1,641 (vs. £1,842), and Q424 at £1,693 (vs. £1,881). Given that c.2/3rd of the Q224 observation window is still open, and with Q324 and Q424 fully marked-to-market, our estimates are highly volatile. These represent the lowest cap levels since winter 2021/22, although still being well above historic levels, we stop short of suggesting that they bring Christmas cheer. For many, the cost of energy/living crisis remains acute. For electricity, our Q224 estimate sees a standing charge of 52.566p/day and a unit charge of 25.41p/kWh, our Q324 estimate sees a standing charge of 52.60p/day, and a unit charge of 23.87p/kWh, with our Q424 estimate seeing a standing charge of 53.06p/day, and a unit charge of 24.76p/kWh. For gas, our Q224 estimate sees a standing charge of 30.97p/day and a unit charge of 6.21p/kWh, our Q324 estimate sees a standing charge of 30.98p/day and a unit charge of 6.01p/kWh, with our Q424 estimate seeing a standing charge of 31.60p/day, and a unit charge of 6.22p/kWh. There was a minor uptick in switching in November (Figure 8), but we now have an interesting situation where a market offer could price well below the cap, although the MSC (Figure 5) has increased, and the Ban on Acquisition-only Tariffs will enter supplier calculations when formulating offers. We are cognisant of some sub-cap fixed price offers below the cap, but, as we have stressed on many occasions, exit charges need to be taken into account. We continue to believe that switching will be driven by customer service and innovative products rather than aggressive price competition.
Ofgem has today published sector specific consultation methodology (SSMC) documents for the RIIO-T3 regulatory period which will run from April 2026 through to March 2031. The suite of documents includes an overview, a finance annex, annexes for ET, GT, GD, and the collated consultation questions. Network companies are expected to deliver four key outcomes in RIIO-3. 1. Infrastructure fit for a low-cost transition to net zero: Network companies must facilitate a low-cost, environmentally sustainable, low carbon energy system that enables the transition to net zero, with infrastructure built at pace. 2. Secure and resilient supplies: Network companies must deliver a safe, secure and resilient network that is efficient, data-rich and responsive to change. Consumers should have access to gas and electricity supplies that are resilient to physical, financial, climate, and cyber shocks. 3. High quality of service from regulated firms: Network companies must deliver a high quality and reliable service to all consumers and network users, including those who are in vulnerable situations. 4. System efficiency and long-term value for money: Network companies must deliver an efficient cost of service, minimise the costs to consumers of system transformation, and ensure consumers and network users get a fair deal. Ofgem’s approach to estimating the cost of capital and assessing financeability is proposed to be substantially in line with the approach taken in RIIO-2, using CAPM as the primary tool when estimating the cost of equity, calculating a single cost of equity (at a notional level of gearing) for each network sector, a 5-year review period, and considering financeability 'in the round'. The aim is to keep the financial policies and methodologies stable from RIIO-2, but two macro developments are compelling Ofgem to review the way it uses the regulatory finance toolkit. We focus here on those relating to ET. There is a step-change in ET infrastructure investment needs across GB to build out a zero carbon, more flexible and more secure energy system at pace. Regulation needs to offer consistency, clear signals and direction, so as to provide certainty and assurance to investors that projects are viable, investable and deliverable. Through the next ET price control and beyond, Ofgem expects network companies will need to seek 'fresh' equity, over and above what they would be able to fund via retained earnings, and at a time where there is greater competition for investment and capital in the UK water and global regulated infrastructure sectors. Ofgem plans to develop the notion of 'investability', alongside its existing financeability assessment, to better understand whether the allowed return on equity is sufficient to retain and attract the equity capital that the sector requires. The beta sample, equity issuance allowance, the trailing average cost of debt methodology, and regulatory depreciation policy could all be reviewed.
The observation window for the Q124 price cap closed this evening. Using the updated TDCV (electricity 2,700kWh, gas 11,500kWh) our final estimate for Q124 is £1,928 (vs. £1,933 previously), a 5% increase vs. 4Q23. For the remainder of 2024, our updated estimates see Q224 at £1,881 (vs. £1,896), Q324 at £1,842 (vs. £1,854), and Q424 at £1,881 (vs. £1,890). With the Q224 observation window opening tomorrow, our estimates for Q224 onwards are marked-to-market, and these estimates will be highly volatile. Q1 is the highest consumption quarter of the year, and our estimates suggest a monthly bill of c.£220 during this period (Figure 4). This is slightly above the average monthly bill in 1Q23 (net of government support), and clear evidence that the cost of energy/living crisis is not dissipating. For electricity, our Q124 estimate sees a standing charge of 53.36p/day and a unit charge of 28.63p/kWh, our Q224 estimate sees a standing charge of 52.60p/day and a unit charge of 27.56p/kWh, our Q324 estimate sees a standing charge of 52.62p/day and a unit charge of 26.44p/kWh, with our Q424 estimate seeing a standing charge of 53.05p/day and a unit charge of 27.31p/kWh. For gas, our Q124 estimate sees a standing charge of 29.60p/day and a unit charge of 7.41p/kWh, our Q224 estimate sees a standing charge of 30.96p/day and a unit charge of 7.23p/kWh, our Q324 estimate sees a standing charge of 30.97p/day and a unit charge of 7.16p/kWh, with our Q424 estimate seeing a standing charge of 31.60p/day and a unit charge of 7.26p/kWh. As per Figure 8, there was a minor drop in switching in October, but over our forecast horizon we continue to see our estimates as in-line with where a 12-month fixed price deal could price. We note Ofgem’s narrative re the MSC, but its quantum has been insignificant for a while (Figure 5), and we remain sceptical as to how much an impediment to offering fixed price tariffs it currently is and will be over the period to March 2024. We maintain our view that we will not see a deluge of cut-price deals, and a belief that switching will be driven by customer service and innovative products. As we have stressed on many occasions, if this plays out, uptake of such tariffs will depend on personal preference and exit charges.
Using the updated TDCV (electricity 2,700kWh, gas 11,500kWh) we now estimate Q124 at £1,933 (vs. £1,976), Q224 at £1,896 (vs. £2,050), Q324 at £1,854 (vs. £2,006), and Q424 at £1,890 (vs. £2,027). The observation period for Q124 has less than a fortnight to run, suggesting it is unlikely that we will see material movement in our estimate, but Q224 onward is marked-to-market, and these estimates are highly volatile, as evidenced by the 7-8% drop vs. our previous estimates. Q1 is the highest consumption quarter of the year, and our estimates suggest a monthly bill of c.£220 during this period (Figure 4). This is slightly above the average monthly bill in 1Q23 (net of government support), and clear evidence that the cost of energy/living crisis is not dissipating. For electricity, our Q124 estimate sees a standing charge of 53.36p/day and a unit charge of 28.68/kWh, our Q224 estimate sees a standing charge of 52.54p/day, and a unit charge of 27.44p/kWh, our Q324 estimate sees a standing charge of 52.56p/day and a unit charge of 26.29p/kWh, with our Q424 estimate seeing a standing charge of 53.00p/day, and a unit charge of 27.13p/kWh. For gas, our Q124 estimate sees a standing charge of 29.60p/day and a unit charge of 7.44p/kWh, our Q224 estimate sees a standing charge of 30.92p/day, and a unit charge of 7.40p/kWh, our Q324 estimate sees a standing charge of 30.93p/day and a unit charge of 7.30p/kWh, with our Q424 estimate seeing a standing charge of 31.57p/day, and a unit charge of 7.38p/kWh. As per Figure 8, there was a minor uptick in switching in September, but over our forecast horizon we see our estimates as in-line with where a 12-month fixed price deal could price. We note Ofgem’s narrative re the MSC, but its quantum has been insignificant for a while (Figure 5), and we remain sceptical as to how much an impediment to offering fixed price tariffs it currently is and will be over the period to March 2024. We maintain our view that we will not see a deluge of cut-price deals, and a belief that switching will be driven by customer service and innovative products. As we have stressed on many occasions, if this plays out, uptake of such tariffs will depend on personal preference and exit charges.
Ofgem has published its decision on the overarching framework design for the network price controls for electricity and gas transmission and gas distribution that will run from April 2026. Gas transmission (GT), gas distribution (GD) and electricity transmission (ET) price controls from April 2026 will resemble an evolution of RIIO-2 for ongoing activities and will keep the broad framework for ongoing costs, outputs, incentives and the financial framework (including the ongoing use of a single calculated return on capital at an appropriate notional level of gearing, applied across both existing RAV and new investment), and will be called RIIO-3. For ET, alongside RIIO-3, Ofgem will add a parallel major projects regime where the decision-making timeline will not necessarily fit with a RIIO-style price control: (i) Regulatory design for funding major new network investments in the ET sector will use the FSO’s Centralised Strategic Network Plan (CSNP) as the 'needs case' to support funding requests. (ii) Competition 'for the market' will remain an option for delivery of large new infrastructure in future price controls, particularly in the ET sector, but only where it will not delay delivery of key projects and can be shown to benefit consumers. Ofgem will continue to develop a regime for competition to the Transmission Owners (TOs) for potential use in future price control periods, with a clear expectation that the large majority of projects will continue to be designed and procured by the existing TOs during the next price control period. (iii) Decisions for new investments on major projects, where project need is determined by the FSO, is to build upon the current Accelerated Strategic Transmission Investment (ASTI) process to provide staged approvals of major projects, with Ofgem scrutiny focused on reviewing implementation of effective procurement by the TOs. Ofgem expects to set the allowed return on capital in line with the recommendations of the 2023 UKRN Guidance, but has alluded to considering the risks attributable to electricity and gas in how it measures the sector-specific elements of the cost of capital, including beta. The cost of debt calculation approach may be updated to reflect the quantum and pace of investment. Ofgem plans to consult on the methodologies for GT, GD and ET in December 2023 and to publish its decision in Spring 2024, alongside targeted Business Plan Guidance for RIIO-3 business plans due in December 2024. The consultation process for the ED RIIO-3 price control which will come into effect in 2028 will begin in late 2024
We last published a price cap estimate at the beginning of September. Following Ofgem’s announcements last week re a consultation on additional debt costs, an operating cost review benchmarking working paper, and the lapsing of the Market Stabilisation Charge (MSC) in March 2024, allied with recent wholesale price movements, we thought an update has merit. Using the updated TDCV (electricity 2,700kWh, gas 11,500kWh) we now estimate Q124 at £1,976 (vs. £1,985), Q224 at £2,050 (vs. £1,983), Q324 at £2,006 (vs. £1,932), and Q424 at £2,027 (vs. £1,974). Although the observation period for Q124 has a month to run, Q224 onward is marked-to-market, and these estimates are highly volatile. Q1 is the highest consumption quarter of the year, and our estimates suggest a monthly bill of c.£226 during this period (Figure 4). The cost of energy/living crisis is not dissipating. For electricity, our Q124 estimate sees a standing charge of 53.34p/day and a unit charge of 29.41p/kWh, our Q224 estimate sees a standing charge of 52.5p/day, and a unit charge of 29.79p/kWh, our Q324 estimate sees a standing charge of 52.52p/day and a unit charge of 28.96p/kWh, with our Q424 estimate seeing a standing charge of 52.91p/day, and a unit charge of 29.37p/kWh. For gas, our Q124 estimate sees a standing charge of 29.60p/day and a unit charge of 7.64p/kWh, our Q224 estimate sees a standing charge of 30.89p/day, and a unit charge of 8.18p/kWh, our Q324 estimate sees a standing charge of 30.90p/day and a unit charge of 7.99p/kWh, with our Q424 estimate seeing a standing charge of 31.52p/day, and a unit charge of 8.05p/kWh. As per Figure 8, there was a minor uptick in switching in August, driven by switches within the larger supplier group, but over our forecast horizon, we see our estimates as c.2.5% below where a 12-month fixed price deal could price. We note Ofgem’s narrative re the MSC, but its quantum has been insignificant for a while (Figure 5), and we are sceptical as to how much an impediment to offering fixed price tariffs it currently is. We maintain our view that we will not see a deluge of cut-price deals, and a belief that switching will be driven by customer service and innovative products. As we have stressed on many occasions, if this plays out, uptake of such tariffs will depend on personal preference and exit charges.
There is little doubt that Centrica has successfully turned a corner since its pandemic lows. However, the recent rally in the share price (c. 75% YTD), fuelled by increased buybacks and dividend growth, has been overdone in our view. On balance, we believe Centrica’s current valuation reflects an overly optimistic view of the company’s long-term cash return and investment plans, as market normalisation leads to a declining EPS profile (a -32% CAGR 2023-27E). We therefore believe the current share price represent a compelling opportunity for investors to take profits. SELL.
We have previously commented on the divisions that well-intentioned but badly executed policies like ULEZ have caused, and the risk of public pushback against the net zero pathway. Yesterday’s speech by Rishi Sunak is a response to the manifestation of this risk, and a consequence of siloed introduction of policy. Key components of the package announced include: Moving back the ban on the sale of new petrol and diesel cars by five years, so all sales of new cars from 2035 will be zero emission. Delaying the ban on installing oil and LPG boilers, and new coal heating, for off-gas-grid homes to 2035, instead of phasing them out from 2026. Raising the Boiler Upgrade Grant by 50% to £7,500 to help households who want to replace their gas boilers with a low-carbon alternative like a heat pump. Setting an exemption to the phase out of fossil fuel boilers, including gas, in 2035, so that households who will most struggle to make the switch to heat pumps or other low-carbon alternatives won’t have to do so. Chancellor and Energy Security Secretary to bring forward new reforms to energy infrastructure, including a spatial plan. A “fast track” through the nationally significant infrastructure project planning regime, available for major eligible transmission projects, to ensure they are prioritised. The bar for connections to the grid will be raised with an end to first come first served. Media headlines have portrayed this as watering down of net zero, Sunak calls it a “more pragmatic, proportionate, and realistic approach to net zero”. However, just because the UK has reduced emissions faster than the rest of the G7 since 1990, it shouldn’t justify kicking the can down the road. Policy flip-flopping jeopardises the UK's opportunity to build a green economy and could see green capital allocated to other countries that are perceived to be more open to such investment and/or offer incentives. In turn this could push up the cost of capital for such projects, which ultimately feeds through to end user pricing. The measures are largely focussed on individuals and unlikely to delay generation and transmission, where simply put, we must crack on and build at pace. In this respect, fast tracking transmission is likely to be positive. There could be some impact on distribution spend, but Ofgem’s RIIO-ED2 Final Determination pointed to net zero totex being c.15% of the package. With FY24-26E capex for distribution amounting to 18% and 30% of group capex for National Grid and SSE respectively, rephasing 15% does not damage their equity stories, in our opinion.
DESNZ has announced the results of CfD Allocation Round 5 (AR5). Unlike the previous round which had three pots, AR5 only had two. Pot 1 contained Energy from Waste with CHP, Hydro (>5MW and <50MW), Landfill Gas, Offshore Wind, Onshore Wind (>5MW), Remote Island Wind (>5MW), Sewage Gas, and Solar Photovoltaic (PV) (>5MW). The budget was £190m (2011/12 prices) with delivery years of 2025/26, 2026/27, and 2027/28, with no capacity caps. 1,928MW of Solar PV capacity cleared at a price of £47.00/MWh, with 1,481MW of Onshore Wind capacity, and 224MW of Remote Island Wind capacity clearing at a price of £52.29MWh, all in 2012 prices. No offshore wind cleared. Pot 2 contained ACT, AD (>5MW), Dedicated Biomass with CHP, Floating Offshore Wind, Geothermal, Tidal Stream, Wave. The budget was £37m (2011/12 prices) with delivery years of 2026/27 and 2027/28. There were no capacity caps, although with a £10m minima for tidal stream. 53MW of Tidal Stream capacity cleared at a price of £198.00/MWh, and 12MW of Geothermal cleared at a price of £119.00/MWh, both in 2012 prices. In the previous round (AR4) concluded in July 2022, 10,792MW cleared. Offshore wind was the dominant technology with 6,994MW at £37.35/MWh (2012 prices) for delivery year 2026/27. 2,209MW of solar and 30MW of EfW at £45.99/MWh, 888MW of onshore wind cleared at £42.47/MWh, 41MW of tidal at £178.54/MWh, 32MW of floating offshore wind at £87.30/MWh, and 598MW of remote island wind at £46.39/MWh also cleared for delivery years spanning 2023/24 to 2026/27. The challenges facing the offshore wind industry in respect of capex and financing costs and the consequent inadequacy of reference prices have been well documented, and Vattenfall has stopped development of Norfolk Boreas (awarded a contract in AR4). An eleventh-hour modest increase in the AR5 budget was never going to turn the tide, and the electricity generator levy has also dented the attractiveness of GB as a place to invest. The auction flop, although unlikely to be a surprise, is a major blow to government’s ambition to see 50GW of offshore wind by 2030, and something that should sharpen thought processes in the corridors of power. Keeping Drax on the system post March 2027 looks ever more important, and we suggest that government moves at pace in agreeing a post 2027 bridging mechanism.
The price cap for Q423 was published on 25th August and stands at a £1,923 when expressed using current TDCVs (2,900kWh electricity, 12,000kWh) or £1,834 when expressed using the TDCVs applicable from October, which will be used in communicating the Q124 cap. On this basis, we now estimate Q124 at £1,985 (vs. £1,901), Q224 at £1,983 (vs. £1,911), Q324 at £1,932 (vs. £1,870), and Q424 at £1,974 (vs. n/a). We caveat that, given the open position on Q124, and mark-to-market nature of Q224 onward, our estimates are highly volatile. Using existing TDCV, our Q124 estimate is £2,083, back above the £2,000 level for what is the highest consumption quarter of the year. The cost of energy/living crisis is not dissipating. Government should move at pace to bring in social tariffs. For electricity, our Q124 estimate sees a standing charge of 53.34p/day and a unit charge of 29.70p/kWh; our Q224 estimate sees a standing charge of 52.51p/day, and a unit charge of 29.17p/kWh; our Q324 estimate sees a standing charge of 52.54p/day and a unit charge of 27.73p/kWh, with our Q424 estimate seeing a standing charge of 52.94p/day, and a unit charge of 28.60p/kWh. For gas, our Q124 estimate sees a standing charge of 29.60p/day and a unit charge of 7.66p/kWh; our Q224 estimate sees a standing charge of 30.91p/day, and a unit charge of 7.74p/kWh; our Q324 estimate sees a standing charge of 30.91p/day and a unit charge of 7.64p/kWh, with our Q424 estimate seeing a standing charge of 31.54p/day, and a unit charge of 7.77p/kWh. Over our forecast horizon, we see our estimates as c.3% above where a 12-month fixed-price deal could price, and, as per Figure 8, there was a minor uptick in switching in July. Octopus’ acquisition of Shell Energy Retail, expected to close in Q4, would position it as #1 in electricity supply, and #2 in gas (#2 on a dual-fuel basis), but we maintain our view that we will not see a deluge of cut-price deals, and a belief that switching will be driven by customer service and innovative products. As we have stressed on many occasions, if this plays out, uptake of such tariffs will depend on personal preference and exit charges. CfD Allocation Round 5 (AR5) results are due 7th/8th September. Much has been said about the budget for this round, which was recently increased by 11% to £227m. However, with capex and financing costs having risen, the trend of decreasing offshore wind prices looks set to be over, and AR5 could disappoint in terms of capacity procured. This should sharpen governmental focus on security of supply. Press reports point to positive news on onshore wind build, but government also needs to prioritise pace over perfection when it comes to REMA, agree a post 2027 bridging mechanism for Drax asap, and dial-up on domestic energy efficiency with an industrial approach to retrofitting and insulation.
Ofgem has also published its decision on the EBIT allowance in the price cap, maintaining the methodology proposed in the May 2023 consultation to combine a fixed component, that does not change when the cap is updated, and a variable component that scales with the overall cap level. This leads to an indicative EBIT allowance of £44 per customer (annualised) for the Q4 cap period. This compares with £34 per customer for the same period under the previous methodology. The nominal pre-tax ungeared cost of equity is updated to 12.26% (up from 12.2% in the May 2023 consultation) to reflect an increase in the daily spot yields on 10-year Gilts (as of July 2023), with capital employed of £368 per customer for the Q4 cap period at benchmark consumption. Our estimates had already incorporated the proposed changes to the EBIT allowance, and today's decision should not be seen as a surprise. We will update our Q1/Q2/Q3 24 cap estimate in due course, but as we have commented many times before, energy prices remain significantly above historic levels, and we do not expect a return to these historic levels in the foreseeable future. Many will find these levels challenging, and again we stress that targeted support is needed. Introducing social tariffs is one such way of achieving this, and government/Ofgem/industry should move at pace to ensure that nobody is left behind on the journey to net zero.
Although the observation window for the Q423 tariff cap runs to 17th August, our updated estimate of £1,834 (vs. £1,835 previously) is the final estimate we will put out for this period. We acknowledge that with 11 observation days to go, forward wholesale price movements can still influence the cap level, but the range of outcomes is narrowing. For the subsequent three quarterly periods we now estimate Q124 at £1,901 (vs. £1,941), Q224 at £1,911 (vs. £1,948), and Q324 at £1,870 (vs. £1,895). We again caveat that given the mark-to-market nature of Q124 onward, our estimates are highly volatile For electricity, our Q423 estimate sees a standing charge of 54.3p/day and a unit charge of 27.38p/kWh, our Q124 estimate sees a standing charge of 54.3p/day, and a unit charge of 28.23p/kWh, our Q224 estimate sees a standing charge of 53.2p/day and a unit charge of 28.02p/kWh, with our Q324 estimate seeing a standing charge of 53.3p/day, and a unit charge of 26.90p/kWh. For gas, our Q423 estimate sees a standing charge of 30.8p/day and a unit charge of 6.82p/kWh, our Q124 estimate sees a standing charge of 30.8p/day, and a unit charge of 7.20p/kWh, our Q224 estimate sees a standing charge of 31.6p/day and a unit charge of 7.35p/kWh, with our Q324 estimate seeing a standing charge of 31.6p/day, and a unit charge of 7.25p/kWh. Over our forecast horizon, we see our cap estimates as broadly reflective of where a 12-month fixed price deal could price, with the latter above the October cap estimate. We note that So Energy is offering a one-year fixed-price tariff at £1,876 (TDCV) for a SW London postcode, albeit with an exit charge of £75 per fuel. This is below British Gas’ 14-month fixed-price tariff at £1,975 (TDCV, SW London postcode, £100 per fuel exit charge), but in line with the annual spend implied by our cap estimates. We maintain our view that we will not see a deluge of cut-price deals, and our belief that switching will be driven by customer service and innovative products. As we have stressed on many occasions, if this plays out, uptake of such tariffs will depend on personal preference and exit charges.
In the June 2022 RIIO-ED2 Draft Determinations Ofgem sought views on the impact of inflation deviating from the long-run assumption, and whether an adjustment to the approach to allowed returns was required. There was no adjustment for RIIO-ED2 but Ofgem indicated it would consult on the issue on a cross-sectoral basis during 2023. Today’s Call for Input starts the process. Ofgem suggests that the current exceptional inflationary environment may have highlighted potential challenges for the normal operation of the Cost of Debt mechanism, resulting in equity outperformance in the form of additional RAV growth and higher consumer bills which are carried forward into future periods. Initial Ofgem analysis, from RIIO-1 commencement to end FY23, is that the inflation leveraging effect has resulted in c.£1.5bn additional RAV growth for networks. Sector RAV was c.£54bn at FY22. The Call for Input only considers the Cost of Debt mechanism, with the key criteria for evaluating policy options being (i) protecting consumer interests; (ii) ensuring prices are fair for the consumer and are efficient; (iii) regulatory stability and predictability; (iv) optimal allocation of risk; (v) price control legitimacy; and (vi) credibility of voluntary plans submitted. Five high level policy options are outlined: No policy action in relation to this issue: this may be the most appropriate solution if over the long run Ofgem can demonstrate that consumers have not incurred (and likely will not incur) detriment as a result of the policy. Distribution policy reporting and transparency: increased focus on company disclosure, with Ofgem expecting companies to give appropriate weight to shoring up financial resilience, ensuring sufficient equity availability for the expected increase in investment. Changes to future price control design: as part of the next set of network price controls Ofgem could consider methodology changes to reduce or remove the out/underperformance effect or enhance the calibration of the control. Out or underperformance true-up: Ofgem could consider applying an adjustment (e.g., to RAV) at the end of the RIIO-2 price controls to adjust for licensees’ actual out or underperformance over a defined evaluation period, with the extent of the adjustment ranging from a partial to full adjustment. Voluntary submissions by licensees: Ofgem has indicated that it would welcome further dialogue with licensees and suggestions as to how they could share benefits of inflation-driven equity outperformance with consumers. Ofgem has made it clear that inflation protection is considered a cornerstone of the price control framework, and that no other inflation mechanisms are in scope. There are a range of policy options put forward, and given the scale of the investment challenge, in our view, it is important that any changes introduced are not retroactive in nature.
Alongside 1H results, Centrica outlined a belief that its retail/optimisation businesses could deliver a sustainable c.£800m in operating profit (Figure 3), equivalent to 11-12p EPS, with an additional contribution from infrastructure. This narrative tallies with our 19th June report (Why waste words? Undervalued!) where we pointed to business-as-usual EPS from retail/optimisation of c.12p. Our updated estimates (Figure 5) see EPS rise across our forecast period. Unpicking, we support Centrica’s view of 11-12p EPS from retail/optimisation, although we consider guidance on British Gas Residential as cautious and model higher, given our view that we will not see a deluge of cut-price deals. Capital deployment was the other thrust of the aforementioned report, and the relative merits of investing and extending the share buyback programme. With a settled portfolio (Figures 1 & 2), Centrica outlined a strategy that aims for £600-800m investment p.a. through to 2028, of which £100-200m is in existing businesses, together with a £450m extension to the buyback programme. Our new estimates incorporate the buyback and the additional capex where this is visible. In the outer years, we currently model lower levels of capex than Centrica’s ambition, but suggest that the balance sheet can accommodate the spend outlined by Centrica (Figure 12). We roll our valuation point to FY24E, this being a contributory factor in moving our target price up to 215p. Granularity of the valuation bridge is set out in Figure 8, with the most material change being a markedly higher net cash position than we had previously estimated. The stock has had a strong run but remains significantly undervalued in our opinion. We are not done yet. BUY.
Running the numbers post yesterday''s strategy update, we find substantial additional value and raise our TP nearly 30% to 210p, implying c60% further upside despite the +c40% move YTD. The reason is that Centrica is delivering results in hard cash, dropping straight into the SoTP and to boot, the co now has a credible growth strategy and high-single-dig EPS CAGR potential in green-aligned flexible generation. This is now a growth as well as a value story: reiterate Outperform. 50p of additional value from strategy update Compared to our expectations going into yesterday, Centrica has conjured up: 1) c30p/sh of additional value by guiding to sustainable EBIT generation cGBP200m/pa higher than our previous ests., mainly on higher EMT and business supply, 2) c20p/sh of additional net cash driven by margining inflows and 3) c10p/sh of value creation potential on a new flexible generation and metering investments. Despite raising our WACC and assuming net cash outflows in 2H, we raise our PT by over quarter to 210p, implying 57% upside on top the +7% move yesterday. Flexible generation investment plan has created a growth story We assume Centrica is not able to reach the top end of its GBP800m investment target by 2028, and assume lower returns than the 9%+ asset IRRs the co is aiming for, and yet we arrive at an 8% EPS CAGR from 2025 once extraordinary trading/upstream earnings have subsided. We see ample room for value-creative growth in flexible generation given strong recent profitability in this area from peers, and empirical evidence of rising opportunities from grid intermittence. Lack of catalysts less of an issue now there is a story to tell Centrica has hitherto been a somewhat event-driven special situation as the co recovered from a wave of disposals and cancellation of the dividend during COVID. In the lead up to yesterday''s update we had been cautious that the stock may find itself bereft of catalysts going into the second half. But...
Centrica published a very strong 1H23 to June 30 with a net operating profit up by 55% on the back of a surge in British Gas Energy operating profit to £969m (1H22: £98m, 1H21: 530£) leading the British newspaper Daily Express to deploy the headline ‘Daylight robbery’ while the current tariffs are becoming politically difficult to justify.
Big beat, buyback programme extended Centrica has reported 1H23 results this morning. Adjusted operating profit of £2,083m, up 51.9% vs. 1H22A, was above our estimate of £1,670m. EPS of 25.8p, up 134.5% vs. 1H22A (INVe 19.7p). DPS of 1.33p, up 33% vs. 1H22A (INVe 1.25p). Divisionally, contributors of note to operating profit were British Gas Energy Supply at £969m (INVe £857m), British Gas Services & Solutions at £20m (INVe £15m), EMT at £384m (INVe £268m), and nuclear at £295m (INVe £222m). The 1H outturn suggests that our FY estimates for look light. The net cash position at 30th June was £3,061m, compared to our estimate of £1,100m, although margin cash inflow is a contributor to the strong position. The share buyback programme has been extended by £450m. A presentation will take place at 10:30am (link). Snapshot of strategy Delivering c.£800m of sustainable AOP from its Retail and Optimisation businesses, with additional material cash flows from existing Infrastructure assets over the medium term. This includes British Gas Residential, British Gas Services, EMT & Bord Gais. Our pre-existing estimates for this cohort are c.£750-900m over FY24E to FY28E. Green-focused investment strategy with annualised investment building to £600m-£800m until 2028, delivering average portfolio post-tax unlevered returns of 7-10%+, with further Group portfolio benefit. This level of capital deployment is significantly above our existing estimates. Centrica is pointing to net debt/EBITDA of <1x over the medium term Centrica expects to maintain Return on Average Capital Employed of at least 20% through the investment horizon. Centrica has positioned the dividend policy as progressive trending to 2x earnings cover over time.
In April 2023 Ofgem consulted on proposals to implement a common minimum capital requirement and modifying the licence so that Ofgem can direct suppliers to ringfence Customer Credit Balances (CCBs). Ofgem proposed that suppliers must maintain a Capital Floor of £0 Adjusted Net Assets per customer, and meet a Capital Target equivalent to £130 Adjusted Net Assets per dual fuel equivalent customer from 31st March 2025. Additionally, Ofgem proposed that suppliers not meeting the Capital Floor would be in breach of the licence. Suppliers not meeting the Capital Target would be required to submit a Capitalisation Plan showing how they intend to do so and be subject to Transition Controls until an acceptable plan is in place. On CCBs Ofgem proposed that ringfencing of CCBs should be available in circumstances where suppliers are not meeting the Capital Target and where they do not have sufficient funds to refund customer balances in a severe but plausible switching event (the Cash Coverage trigger). In a decision published today, Ofgem has decided to proceed with the introduction of a minimum capital requirement Floor and Target, but has removed intangible assets from the definition of capital and lowered the Target to £115 per domestic dual fuel equivalent customer. Ofgem could review the capital adequacy requirement to ensure that the level is still appropriate if there are significant changes in regulation or government policy, or if the common risks facing suppliers otherwise change materially, if it is in the consumer interest to do. Suppliers below the Target but above the Floor will be in the Intermediate Position and will be subject to default Transition Controls until they have a credible Capitalisation Plan in place (see Figure 1). The default Transition Controls are a sales ban and a ban on non-essential payments, with Ofgem of the view that paying dividends while a supplier is below the Capital Target is not in the Consumer Interest. The restrictions will cease to apply automatically when a credible Capitalisation Plan has been agreed. Ofgem is proceeding with ringfencing CCBs as consulted on. Ofgem can direct CCB ringfencing if a supplier is below either the Capital Target or the Cash Coverage trigger level. Where a supplier is below the Capital Target Ofgem will consider whether to direct a licensee to ringfence some or all of its CCBs. The Cash Coverage trigger requires the licensee to maintain monthly balances of cash in the bank at a level equal to or greater than 20% of gross CCBs net of unbilled consumption owed to their fixed DD customers. The Cash Coverage will be implemented when the licence changes take effect, and the Capital Trigger Target will be implemented from 31st March 2025.
Centrica will report 1H results and give a strategy and returns update on 27th July. The stock is a favourite amongst sector specialists and is up 30% YTD, placing a high weight of expectation on the event in our view. We expect updates on medium term earnings expectations, capex and shareholder returns as well as heavily front-weighted 1H numbers. Despite strong performance and crowded positioning we think there''s still headroom for the co to please investors on the day. Outperform. Buoyed by recent events Centrica has seen a string of positive events in the last few months, amongst them 1) a favourable regulatory announcement on retail price cap margins, 2) an expansion of capacity at its Rough gas storage facility from 30bcf to 54bcf, and 3) an upgrade to FY23 EPS guidance to close to 25p. But we think the recent outperformance has also been driven by expectations that the company will unveil new capital return initiatives at 1H results. Our past work suggested that Centrica''s spare balance sheet capacity, if fully deployed, could be used to drive as much as 60% EPS accretion. A lot hanging on 1H results ... Our main expectations are: 1) heavily front-weighted earnings in 1H vs. 2H as alluded to in the recent FY guidance upgrade, 2) a steer from the company on its expectation for sustainable medium-term earnings, 3) a focus on organic investments including some updated guidance on capex and returns, and 4) an update on share buybacks. Any guidance on earnings and share buybacks would also be relevant for dividend expectations: we see medium-term DPS consensus as undemanding at c.4p. Assessing the travel and arrive risk Given strong share price performance into the event and crowded investor positioning, we think the risk of an anti-climax bears some consideration, especially given the backdrop of higher UK bond yield/sovereign risk and the approaching elections. But we believe the sheer scale of Centrica''s spare balance sheet capacity,...
The observation window for the Q423 tariff cap has been open for a little over a month, and after a trend of declining estimates the recent uptick in wholesale prices (Figures 8/9) pushes our estimates for each of the upcoming quarters back above the £2,000 level. Our Q423 estimate rises to £2,003 (vs. £1,870 previously), with the subsequent three quarterly periods now estimated at £2,132 (vs. £1,952), £2,139 (vs. £1,948), £2,004 (vs. £1,851). We again caveat that the infancy of the current observation window for Q424, and the mark-to-market nature of Q124 onward estimates, make these estimates highly volatile. For electricity, our Q423 estimate sees a standing charge of 54.3p/day and a unit charge of 28.69p/kWh, our Q124 estimate sees a standing charge of 54.3p/day and a unit charge of 30.95p/kWh, our Q224 estimate sees a standing charge of 53.1p/day and a unit charge of 30.33p/kWh, with our Q324 estimate seeing a standing charge of 53.1p/day, and a unit charge of 27.69p/kWh. For gas, our Q423 estimate sees a standing charge of 30.8p/day and a unit charge of 7.17p/kWh, our Q124 estimate sees a standing charge of 30.8p/day and a unit charge of 7.70p/kWh, our Q224 estimate sees a standing charge of 31.5p/day and a unit charge of 7.92p/kWh, with our Q324 estimate seeing a standing charge of 31.6p/day, and a unit charge of 7.43p/kWh. Our estimates using Ofgem’s new TDCVs (2,700kWh electricity, 11,500kWh gas), to be used in communicating the cap level from October, are set out in Figure 6. Over our forecast horizon, we see our estimates are broadly reflective of where a 12-month fixed price deal could price, with the latter slightly above the July cap level. This is supportive of our view that we will not see a deluge of cut-price deals, and a belief that switching will be driven by customer service and innovative products. Indeed, we are aware of fixed-price tariffs being offered to existing customers but priced above the unit prices in the Q323 tariff cap. As we have stressed on many occasions, uptake will depend on personal preference and exit charges. We may well enter 2H with a continued benign competitive backdrop and note that May’s domestic electricity switching levels were below those in both the two preceding months (Figure 10).
FY23E operating profit/EPS raised materially by 23.6%/30.8% respectively (Figure 1). Energy supply is the principal driver (Figure 2) as the technicalities of backwardation phasing and adjustment allowances flow through the price cap. FY24E operating profit/EPS also rise by 4.0%/4.2% respectively as we factor in a higher EBIT allowance in the price cap, consistent with Ofgem’s higher allowance, and consistent with our view of a more stable supply market. The phasing of recovery via the price cap is likely to drive 1H supply profits to an all-time high, which we suggest could top £800m (Figure 3), with group adjusted operating profit of £1.6-1.7bn. Although we expect fixed-price deals to return in July, we do not expect a deluge of cut-price offers, in part due to the BAT, although it remains a risk. British Gas may also seek to increase support for customers struggling with energy bills. The element of caution we bake into 2H is reasonable at this stage. 1H23 results (27th July) will see Centrica provide an update on strategy and capital framework. The challenge will be to ensure that the message of the strategic direction and opportunities does not get lost in the inevitable, but unfair media frenzy surrounding the1H supply contribution. The fact that this is largely down to price cap timing recovery might be conveniently ignored by some. Beyond FY25E, we see c.15p/share of sustainable earnings on a business-as-usual basis, of which c.3p/share is from upstream activities. Future upside could come from innovation in tariff offerings, EV charging where the Hive charger has been launched, and growing the heat pump offering. Our target price moves to 175p (Figure 4). Deploying £500m per annum for four years at a 300bp WACC spread would add c.7p, or c.20p if funnelled into a share buyback programme. Centrica is undervalued and has options. BUY.
YTD performance ‘strong overall’ Ahead of today’s AGM, Centrica has put out a trading update, with performance over the first five months of the year described as “strong overall”. Given its current outlook, Centrica expects 2023 full-year group adjusted EPS to be around the top end of the range (16.5p-24.7p) of recent sell-side analyst expectations, heavily weighted towards the first half. Our pre-existing estimate is 19.8p. In Retail, adjusted operating profit in 1H is expected to be significantly higher than in previous years, the main driver of which is a material positive impact in British Gas Energy from allowances in the UK domestic default tariff cap relating to costs incurred in prior periods. In Optimisation, performance in Energy Marketing & Trading has remained strong to date. In Infrastructure, availability and volumes from its gas production, nuclear and gas storage assets have been good, helping to offset the impact of lower wholesale commodity prices. First-half net cash generation is also expected to be robust. Uncertainties remain over the balance of the year, including the impacts of weather, commodity prices, the economic environment, any changes to regulation or government policy, asset performance and the competitive backdrop for our energy supply businesses, resulting in a range of possible outcomes for the full year. Strategy & capital framework on 27th July Interim Results are scheduled for 27th July, at which Centrica intends to provide an update on its strategy and capital framework.
The observation window for the Q423 tariff cap has been open for two weeks. Following Ofgem’s announcement of the Q323 cap at £2,074 (at existing TDCV), and a statutory consultation on the methodology for setting the EBIT allowance, we have updated our price cap estimates, incorporating the EBIT changes being consulted on. The headline is that with recent softening of wholesale prices (Figures 8 and 9), our Q423 estimate falls to £1,870 (vs. £1,933 previously), our lowest ever estimate for this period, although we caveat that given the infancy of the observation window, this estimate is likely to be highly volatile. We also introduce estimates for Q124, Q224 and Q324 which are £1,952, £1,948 and £1,851 respectively. The granularity is set out in Figure 3, with period-to-period movements largely due to swings in the backwardation allowance component of the wholesale allowance. For electricity, our Q423 estimate sees a standing charge of 54.4p/day and a unit charge of 27.53p/kWh, our Q124 estimate sees a standing charge of 54.3p/day and a unit charge of 29.22p/kWh, our Q224 estimate sees a standing charge of 53.2p/day and a unit charge of 28.48p/kWh, and our Q324 estimate seeing a standing charge of 53.2p/day, and a unit charge of 26.30p/kWh. For gas, our Q423 estimate sees a standing charge of 30.9p/day and a unit charge of 6.34p/kWh, our Q124 estimate sees a standing charge of 30.9p/day and a unit charge of 6.61p/kWh, our Q224 estimate sees a standing charge of 31.6p/day and a unit charge of 6.77p/kWh, with our Q324 estimate seeing a standing charge of 31.6p/day, and a unit charge of 6.49p/kWh. The ratio of electricity unit prices to gas unit prices is above 4x across our forecast period, unhelpful in persuading the public to switch from gas fired heating to heat pumps. Ofgem has also set out new TDCVs (2,700kWh electricity, 11,500kWh gas) to be used in communicating the cap level from October. We don’t envy Ofgem’s communication challenge with this change, and in Figure 6 we present our estimates and history recast at these lower consumption levels. Over our forecast horizon, we see our estimates are broadly reflective of where a 12-month fixed price deal could price, and we believe that fixed price deals will return. However, with the Market Stabilisation Charge (Figure 7) still above zero and the Ban on Acquisition Tariffs, meaningful return of such offers is more likely from Q323. We do not expect a deluge of cut-price deals, and believe that switching will be driven by customer service and innovative products. Uptake will depend on personal preference and exit charges.
Ofgem has set the energy price cap for the July to September quarter at £2,074 for typical domestic consumption values (TDCV). Our final estimate for Q3 was £2,044, 1.4% below the outturn. The principal difference appears to be a c.£20 difference on CfD costs. Ofgem has also published a statutory consultation on setting the EBIT allowance in the price cap. The headline from Ofgem is that the annualised allowance based on current (highly indicative) price cap expectations for cap period 11a (Oct-Dec 23) is c.£47 per typical customer, which is c.£10 higher per typical customer. We will digest the contents of the 95 page document, participate in an investor call this afternoon, and update our October forecasts in due course. Our initial reaction on the consultation is that it is marginally positive for suppliers, being slightly above the c.£40/dual-fuel customer that we model for Centrica. The tariff cap from July is below the level of the Energy Price Guarantee (EPG) and consumer pricing will be at levels not seen since summer 2022. However, price levels are still considerably higher than historic levels, and challenging for many. We may sound like a broken record, but Government/industry/Ofgem need to work together at pace in bringing forward social tariffs. We are of the opinion that the tariff cap/EPG crossover could see fixed price deals return. However, with the Market Stabilisation Charge still above zero and the Ban on Acquisition Tariffs, meaningful return of such offers is more likely from Q323. That said, we do not expect a deluge of cut-price deals, and believe that switching will be driven by customer service and innovative products. Uptake will depend on personal preference and exit charges. To switch, or not to switch, the question remains.
The observation window for the Q323 tariff cap closed yesterday, Ofgem will announce the Q323 cap level on 25th May, additionally publishing at 7am a statutory consultation on setting the EBIT allowance in the price cap. Forward wholesale prices have moved down since we last published a tariff cap estimate, but given that our previous estimate already reflected the passing of most of the observation window, our final July (Q3) cap estimate is little changed at £2.044 (vs. £2,051). However, our October (Q4) estimate, which does not assume any change to the EBIT allowance, is effectively marked-to-market on the commodity component and hence volatile, falls to £1,933 (vs. £2,080), the lowest cap estimate we have published since early 2022. For electricity, our Q3 estimate sees a standing charge of 48.34p/day and a unit charge of 29.51p/kWh, with our Q4 estimate seeing a standing charge of 48.88p/day, and a unit charge of 28.72p/kWh. For gas, our Q3 estimate sees a standing charge of 26.57p/day and a unit charge of 7.40p/kWh, with our Q4 estimate seeing a standing charge of 27.42p/day, and a unit charge of 6.62p/kWh. A tariff cap of this level will position SVT pricing below the level of the Energy Price Guarantee (EPG), pointing to consumer pricing at levels not seen since summer 2022. However, price levels are still considerably higher than historic levels, and challenging for many. Government/industry/Ofgem need to work together at pace in bringing forward social tariffs. These estimates are broadly reflective of where a 12-month fixed price deal could price, and we are of the opinion that we will see fixed price deals return. However, with the Market Stabilisation Charge (Figure 6) still above zero and the Ban on Acquisition Tariffs, meaningful return of such offers is more likely from Q323. That said, we do not expect a deluge of cut-price deals, and believe that switching will be driven by customer service and innovative products. Uptake will depend on personal preference and exit charges. To switch, or not to switch, that is the question.
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EMT is the glue that links Centrica’s portfolio, but a black box that needs opening Centrica’s Energy Marketing & Trading (EMT) business is arguably the glue that links the other pieces in the Centrica jigsaw (Figure 1), and in FY22, a year of extreme commodity prices, and elevated levels of volatility, not only did EMT post its highest ever profit, it was also the highest contributor to group profitability. Yet EMT is a somewhat of a black box, posing an investor education challenge for Centrica. EMT has three pillars, and is aligned with global trends Centrica’s approach to opening the box is to host a series of teach-ins on the three component pillars of EMT, of which yesterday’s on LNG Trading & Shipping was the second, following on from one on Route-to-Market for Renewable and Optimisation Assets last December. A common strand is that both are aligned to global trends in the energy transition (Figure 3), which, in the case of gas, is continued use, and a shift to LNG (Figure 4). LNG has an anchor in Sabine Pass/Grain, with optimisation opportunities Over the past eight years, Centrica has grown its business from 27 cargoes in 2014 to 284 in 2022, and a 17-fold increase in the number of charters concluded, creating a global business where the physical portfolio is supported by deals of varying duration (Figure 5). Contracts at Sabine Pass and Isle of Grain anchor the portfolio, with de-risking through a variety of hedging strategies that keep open the opportunity for optimisation (Figure 6). This is enhanced by additional sourcing and sale contracts that provide increased optionality and diversification (Figure 7). No guidance, save for a view that medium-term LNG profit could top £100m As expected, Centrica were reticent in providing financial information for the LNG business, both historic and guidance, but shared a view that LNG could be a £100m+ profit business in the medium-term. Sufficient information provided to move our numbers, no, but supportive of our view that EMT on a normalised basis will be a bigger contributor than historic levels (2022 excepted).
The LNG teach-in did not bring any updates to formal guidance but Centrica emphasised recent growth in its physical LNG capabilities (# of traders, ships, transacted cargoes) and suggested the business could generate GBP100m in mid-term earnings, in line with the estimates in our model. There was also disclosure on hedging of their US gas contract with Cheniere, which suggests some longer term 2026+ earnings upside at current spreads. Centrica reiterated that it intends to revisit the capital distribution strategy in late July, which we continue to see as a key catalyst. Outperform. Growth in physical LNG KPIs and contracted assets Centrica disclosed that it has seen steady growth in physical traded LNG cargoes from 35 in 2016 to 284 in 2022, a 40% CAGR, and emphasised the growing importance of LNG in the global energy market with global LNG demand projected to rise by ~50% by 2030. They also emphasised it has enhanced the business with freight trading capabilities added in 2020, its long term regas capacity contract on the Isle of Grain and long term vessel charters. Reticent on precise numbers but suggesting GBP100m mid-term profitability The presentation did not contain much in the way of explicit quantitative guidance but two snippets were important in our view: 1) CEO suggested LNG could generate ''a 9-figure sum'' in the medium term so GBP100m, which is broadly in line with the assumptions in our model and 2) disclosed that its 92TBtu Cheniere US gas contract is 46% unhedged by 2026 - we estimate c.GBP80m of potential mark-to-market profit on this unhedged position alone based on current US/Europe forward spreads (see p2 for calculation / email us for live spreadsheet), which presents possible upside to our own earnings estimates, although spreads are volatile and likely difficult to hedge currently. Capital framework update coming in July Centrica''s CEO reiterated that they intend to revisit capital distribution at 1H results in late July,...
We think Centrica''s 1H results in late July could be a major catalyst for the shares. We think the co could announce a bazooka dividend policy and share buyback programme: scenarios in this note suggest buybacks and acquisitions could cut Centrica''s share count by as much as 40%, drive 60% EPS accretion and allow the co to pay a 2025 DPS 110% ahead of consensus. Reiterate Outperform; our TP implies c50% upside. Shareholder return powder keg We estimate bumper earnings in 2022/23 due to high and volatile commodity prices will leave Centrica with GBP2.7bn net cash by the end of next year, worth nearly half of current market cap. This positions the company to embark on a dividend, buyback and acquisition spree which could be transformational for earnings and shareholder returns. In this note we examine a scenario where Centrica spends GBP2bn on acquisitions and ramps buybacks to GBP1.2bn pa (vs. GBP0.5bn currently), whilst maintaining leverage comfortably below historical levels on prudent commodity price assumptions. Lower share count = higher dividend capacity Our scenario would imply 15% EPS accretion from acquisitions and a further 35% from the buyback of 2.5bn shares between now and 2025. With higher earnings and a lower share count, dividend capacity would increase, potentially allowing a 9p dividend by 2025 on our ests., vs. consensus currently at 4p and our 6p base case forecast. We base our scenario on underlying EPS 24% below cons due to our low commodity price assumptions, and scenario net debt/EBITDA only reaches 1.3x (on below-cons underlying EBITDA) vs. historically reaching 1.5x. Yet we still reach 9.2p of 2025E DPS, which on Centrica''s historical 5.5% yield would imply a c170p/share, supporting our 165p TP. SBB and LNG update provide support into July Whilst we wait for results, Centrica has GBP300m of existing share buyback programme to execute over the next 6 months, worth c15x of ADV. There is also an LNG teach-in due in the coming...
Carbon Capture Usage and Storage: First projects will be announced to progress to the next stage of the negotiations to rollout the first Carbon Capture clusters. Delivering Great British Nuclear: Great British Nuclear will be responsible for driving the delivery of new nuclear projects, with the aim that up to 25% of the UK’s electricity could be from nuclear sources by 2050. The first job for Great British Nuclear will be launching a competition to select the best Small Modular Reactor technologies for development. Delivering a Hydrogen economy: Funding awards to new hydrogen projects across the country, from the £240m Net Zero Hydrogen Fund. Shortlist of 20 projects to take to the next stage in the first electrolytic hydrogen allocation round. Accelerating deployment of renewables: Bidding opens for CfD AR5 with an initial budget of £205m. Floating Offshore Wind Manufacturing Scheme launched, providing up to £160m. Reducing energy bills by increasing energy efficiency: Up to 80% of people across the country in council tax bands A-D will qualify for support to make their homes more energy-efficient under a new ECO+ scheme, to be called the “Great British Insulation Scheme”. Reducing our reliance on fossil fuels to heat our buildings: A new £30m Heat Pump Investment Accelerator, designed to leverage £270m private investment to boost manufacturing and supply of heat pumps in the UK. Boiler Upgrade Scheme extended until 2028. Driving Household electricity bills down: Confirmation that the Govt will set out plans during 2023/24 to rebalance gas and electricity costs in household bills. Speeding up planning: A new set of revised Energy National Policy Statements for consultation which will speed up planning approvals for energy infrastructure. An investigation by the Electricity Networks Commissioner will examine what else can be done to speed up the network. Decarbonising transport: Launch of the Local Electric Vehicle Infrastructure fund, along with an On-Street Residential Chargepoint Scheme. Mobilising Private investment: Jeremy Hunt will unveil an update to the Green Finance Strategy that will mobilise the billions of private investment needed for net zero and nature recovery. It includes consulting on requirements for the UK’s largest firms to publish net zero transition plans, mirroring requirements for financial firms; consulting on regulating ESG rating providers; and announcing a series of new investment roadmaps sign posting opportunities in the offshore wind, hydrogen, CCUS and heat pump sectors. The UK Infrastructure Bank (UKIB) has announced that it will appoint managers for equity funds covering both short and long duration electricity storage. The Bank will invest up to £200m across the two funds on a matched basis, crowding-in wider sources of finance into the sector, and expects to make direct investments in electricity storage going forward.
We have updated our tariff cap estimates to reflect closing commodity prices of last night. Our July (Q3) cap estimate is now £1,981 (vs. £2,056), and our October (Q4) estimate is £1,966 (vs. £2,071). These estimates, marked-to-market, will be volatile, but are again the lowest estimates we have published for Q3 and Q4. For electricity, our Q3 estimate sees a standing charge of 48.34p/day and a unit charge of 28.77p/kWh, with our Q4 estimate seeing a standing charge of 48.34p/day, and a unit charge of 28.98p/kWh. For gas, our Q3 estimate sees a standing charge of 26.57p/day and a unit charge of 7.06p/kWh, with our Q4 estimate seeing a standing charge of 26.57p/day, and a unit charge of 6.83p/kWh. This latest reduction in our estimates is welcome, but it does not disguise that these estimates are still considerably higher than historic levels, and challenging for many. We reiterate our view that social tariffs are needed. We urge government/industry/Ofgem to work together at pace in this respect. These estimates are arguably reflective of where a 12-month fixed price deal could price, and it is right to ask the question as to when we could see fixed price deals return. The Market Stabilisation Charge (Figure 6) still above zero and the Ban on Acquisition Tariffs lead us to believe that the return of fixed price offers is more likely in the summer. However, we do not expect cut price deals, and believe that switching will be driven by customer service and innovative products. Policy costs fall largely on electricity, which given the push to electrify is perverse. Government committed to publishing proposals on “rebalancing” the costs placed on energy bills away from electricity in 2022, to incentivise electrification across the economy and accelerate consumers’ and industry’s shift away from volatile global commodity markets. We still await these proposals, and if government is serious about delivering net zero via increased electrification, it needs to bring these forward at pace. At TDCV, cap policy costs ex VAT are £131 (electricity) and £34 (gas). We estimate the cost to government to remove these from the bill at c.£4.6bn, should removal rather than rebalancing be the preferred route. There is a growing narrative from a variety of stakeholders that the UK investment landscape is less appealing given government intervention (EGL, windfall tax), lack of pace on investment frameworks, uncertainty from structural change, and incentives elsewhere (e.g. the US Inflation Reduction Act). We urge the government to prove that it is committed to delivering net zero by bringing forward measures to incentivise green investment.
HM Treasury has announced that the Energy Price Guarantee (EPG) will be kept at £2,500 for an additional three months (April to June). The suggestion in the press release (HERE) is that this will save a typical household £160. Versus the £3,280 price cap, we agree, but the more relevant comparator is the £3,000 level to which the EPG was intended to rise. The incremental saving for a typical household is c.£100. We estimate the cost to HM Treasury of extending the guarantee at c.£2.6bn. Updated to reflect closing commodity prices of last night, our July (Q3) cap estimate is now £2,056 (vs. £2,094), and our October (Q4) estimate is £2,071 (vs. £2,124). These estimates, marked to market, will be volatile, but are again the lowest estimates we have published for Q3 and Q4. For electricity, our Q3 estimate sees a standing charge of 48.34p/day and a unit charge of 29.89p/kWh, with our Q4 estimate seeing a standing charge of 48.34p/day, and a unit charge of 30.44p/kWh. For gas, our Q3 estimate sees a standing charge of 26.57p/day and a unit charge of 7.41p/kWh, with our Q4 estimate seeing a standing charge of 26.57p/day, and a unit charge of 7.35p/kWh. We welcome the extension of the EPG, but our tariff cap estimates for Q3 and Q4 are still considerably higher than historic levels, and challenging for many. We reiterate our view that social tariffs are needed. We urge government/industry/Ofgem to work together at pace in this respect. A more immediate and workable measure would be to eliminate the prepayment meter uplift in tariff cap. The uplift is currently £45/dual-fuel and, with c.4m prepayment customers, the cost to government of absorbing the differential would be c.£180m.We expect this to be confirmed in the budget. Policy costs fall largely on electricity which, given the push to electrify, we view as perverse. Government committed to publishing proposals on “rebalancing” the costs placed on energy bills away from electricity in 2022 to incentivise electrification across the economy and accelerate consumers’ and industry’s shift away from volatile global commodity markets. We still await these proposals, but at TDCV, cap policy costs ex VAT are £131 (electricity) and £34 (gas). We estimate the cost to govt to remove these from the bill at c.£4.6bn. There is a growing narrative from a variety of stakeholders that the UK investment landscape is less appealing given government intervention (EGL, windfall tax), lack of pace on investment frameworks, uncertainty from structural change, and incentives elsewhere (e.g. US Inflation Reduction Act). We urge to Chancellor to bring forward measures to incentivise green investment,
DESNZ published a summary of responses to the Review of Electricity Market Arrangements (REMA) consultation yesterday. A number of options have been discounted (Figure 1 overleaf), but what remains is still very broad, with numerous questions left unanswered. Government intends to publish a second consultation this year, but no timeline beyond that has been set out, albeit it is noted that decisions on shorter-term reforms will be taken where viable. There is broad support for change (Figure 2) with the overarching questions being those that garnered the most consultation responses. We highlight that 80% were of the view that current market arrangements are not fit for purpose, and that there is a case for change. Change brings uncertainty, and we take some heart from the statement that “the government acknowledges the need to provide transparency and to maintain investor confidence…” All options for wholesale market reform have been retained despite divided opinions on these options (Figure 3). The idea of a split wholesale market saw a little under half (47%) of the respondents in favour, whereas the idea of continuing to consider both nodal and zonal pricing was supported by only 35% of respondents. We question the extent to which supply can move closer to demand, and vice versa, and suggest that the uncertainties caused by continuing to consider location marginal pricing could impede the pace of much needed investment. Supplier obligations on low carbon power have been ruled out (Figure 4), but minor reforms to CfDs, CfDs with more price exposure, and CfDs based on deemed output will be taken forward from an investment perspective. If there is change, we would expect that the risks associated with price and volume will be reflected in CfD pricing. A cap and floor mechanism for flexibility saw mixed response (Figure 5), but it is favoured by those who seek to develop long-duration storage (pumped-hydro, hydrogen), and we suggest that in this respect a framework is developed at pace. Only 32% of respondents were in favour of a supplier obligation for flexibility, although government will continue to explore the role of suppliers in providing demand side flexibility. We view consumers as integral to the net zero journey, and welcome government keeping this under consideration. Optimising the Capacity Market attracted almost universal support (Figure 6), and the option of a time-limited transitional Strategic Reserve will be further evaluated. All operability options are to be taken forward, there being a clear view that the current form of CfDs discourages the provision of ancillary services (Figure 7). The cross-cutting options have been dropped, including Equivalent Firm Power (Figure 8).
Following the recent FY22 results, we have updated our estimates. A more cautious approach to Energy Supply given the ongoing implications of the cost-of-living crisis, and lower contribution from Upstream given revised expectations for achieved prices, are in part offset by lower finance and tax charges, but our FY23E EPS falls by 10.4%. FY24E and FY25E, however, move upwards, by 9.3% and 11.2% respectively. Many moving parts in both directions in our valuation (Figure 4) result in our target price being nudged down slightly to 165p/share. This continues to position us as highest on the Street. Centrica alludes to being well into Phase 2 (‘Stabilise the business and improve operational performance’) of its turnaround, and increasingly engaging with Phase 3 (‘Deliver growth and position ourselves for net zero’). The latter piques our interest, as the chances of getting to net zero, without the whole value chain playing its part, are slim to non-existent, in our opinion. This creates opportunity for companies with a portfolio approach like Centrica, who can combine physical assets with trading expertise, as well as leveraging the opportunities that are likely to flow from the significant downstream presence of British Gas. Our approach to valuation captures business as usual but, over time, we expect the additional value proposition to be become clearer, although we suggest that there is an onus here on Centrica to frame and quantify the opportunity. In this respect, we view the upcoming LNG teach-in (April), and longer-term investment/return plans (July), as potential catalysts.
Ofgem has set the energy price cap for the April to June quarter at £3,280 for typical domestic consumption values (TDCV), with the granularity as set out in Figure 2 overleaf. The Energy Price Guarantee (EPG) is currently set to rise to £3,000 in April, from £2,500, suggesting that the cost to the public purse of the EPG in Q2 will be c.£1.8bn. Updated to reflect closing commodity prices of last night, our July cap estimate is now £2,094 (vs. £2,165), and our October estimate is £2,124 (vs. £2,190). These estimates, marked-to-market, will be volatile, but are again the lowest estimates we have published for July and October. Given where the April cap has landed, and where our updated estimates for the July and October caps sit, the clamour to maintain the EPG at the existing level of £2,500 is likely to increase. As we have previously suggested, it is easy to have sympathy for these views, but it would increase the risk to government, and with the EPG, as constituted, a one-size fits all mechanism that is simple to administer, it also offers support to households who might not need it. That said, we would not rule out a change of heart by the government given our estimate that extending the £2,500 level for three months would cost c.£2.6bn, but there may well be an argument that funding is better directed to the NHS, for example. The lower price cap will also likely see a lower market stabilisation charge (MSC) from April. The MSC is a payment that an acquiring supplier pays to the existing supplier if a customer switches and current wholesale prices are below those in the tariff cap. It could be argued that the current level of the MSC (c.£363 at TDCV, published 27th February) is delaying the return of fixed price tariffs and more innovative products. Although we don't expect a return to the type of price competition of a few years ago, a lower MSC could see service and product-led offers, and we look for suppliers to bring tariffs to market that offer value to both the consumer and supplier.
Ofgem has set the energy price cap for the April to June quarter at £3,280 for typical domestic consumption values. This compares to our estimate of £3,332, and estimates slightly below £3,300 from two other respected commentators. The granularity of the cap is set out in Figure 1, and it can be seen that the principal difference between our estimate and the announced level is due to the CfD allowance being negative, at a slightly greater level than in Q1. The Energy Price Guarantee (EPG) is currently set to rise to £3,000 in April, from £2,500, suggesting that the cost to the public purse of the EPG in Q2 will be c.£1.8bn. Given where the April cap has landed, and where our last published estimates for the July (£2,165) and October (£2,190) caps sit, the clamour to maintain the EPG at the existing level of £2,500 is likely to increase. It is easy to have sympathy for these views, but it would increase the risk to government and, with the EPG as constituted is a one-size-fits-all mechanism that is simple to administer, it offers support to households who might not need the support. There may well be an argument that funding is better directed to the NHS, for example. The lower price cap will also likely see a lower market stabilisation charge (MSC) from April. The MSC is a payment that an acquiring supplier pays to the existing supplier if a customer switches and current wholesale prices are below those in the tariff cap. It could be argued that the current level of the MSC (c.£340 at TDCV, published 20th February) is delaying the return of fixed-price tariffs and more innovative products. Although we don't expect a return to the type of price competition of a few years ago, a lower MSC could see service- and product-led offers, and we look for suppliers to bring tariffs to market that offer value to both the consumer and supplier. For Good Energy, we suggest that tariffs of this ilk could pique interest in the stock.
The observation window for the April price cap closed on Friday, and our final estimate stands at £3,332. This estimate includes the Covid-19 true-up costs and the BSUoS transitional adjustment as set out in decisions published by Ofgem on Friday. We have set out granularity of this estimate in Figure 3. Consumers will still be protected by the £3,000 Energy Price Guarantee from April. The observation window for the July 2023 cap opens today, and our updated estimate is based off forward prices as last night’s close, as is our October 2023 estimate. Our July estimate is now £2,165 (vs. £2,369), and our October estimate is £2,190 (vs. £2,407). These estimates, marked-to-market, will be volatile, but are the lowest estimates we have published for July and October. We are cognisant of suggestions that we could soon see the return of fixed price offers given the level of wholesale prices. The Market Stabilisation Charge (MSC), still positive for both electricity and gas would (based on the 13th February MSC) would require a payment in excess of £350 for the typical dual-fuel customer, but we view it as plausible that we could see fixed price offers below the £3,000 Energy Price Guarantee. Given the level of our cap estimates for July and October, the level of exit fees would need to be taken into account in assessing the attractiveness of a fixed price offer.
Centrica released a historical year, amid unprecedentedly high energy markets that supported earnings in the trading activities but also the Upstream business unit. Centrica decided to proceed with the first dividend payment since 2019 as well as an increase in its share buyback operation. Also, criticism concerning these exceptional results should lead the group to reach a key player position in the customer help and support segment, and increase investment in retail and services and solutions.
Strong FY22 earnings were expected after the positive Jan trading update but FY22 also brought 1) better net cash and provisions, 2) a GBP300m extension to the share buyback programme, and 3) a promised update on ''expected returns'' (implying potential dividend/SBB policy in our view) at 1H results in July. Supportive for the equity story: we raise our PT by 15p to 165p. Numbers were good beyond just EPS 34p of EPS met the 30p guidance given in Jan but underlying net cash was better in our view: GBP1.2bn (guid GBP1bn), despite a GBP1.2bn margin outflow in FY22 (GBP0.5bn at 1H) and GBP0.6bn working capital outflow. Pension and decommissioning liabilities also came in ahead of our ests. Centrica did not provide financial guidance for FY23 but alluded to strong locked-in profits in LNG for FY23/24. Capital return - keeping the bull case alive We think capital returns (dividend/buybacks) are a critical catalyst for Centrica and the company delivered two pieces of good news: 1) co will extend existing GBP250m share buyback (SBB) programme by an additional GBP300m and stated that initial SBB was only 40% complete, suggesting cGBP450m still to deploy, and 2) alluded to a more formal update on capital return at the 1H results. We see this as supportive especially after the recent prepayment meter newsflow had created fears that capital returns may be abandoned or delayed. Not ruling out MandA When questioned on the conference call the CEO did not rule out using Centrica''s growing cash pile on acquisitions, citing past successful transactions in e.g. trading and storage. We think this could make investors somewhat nervous given (in our view) a preference for capital returns. Updating our estimates We update our model for FY22 actuals; we raise our EBITDA slightly on higher hedged commodity prices in FY23/24 but this is offset by higher depreciation, leading to limited changes to our EPS. However we raise our PT to 165p on better Dec''22 net cash and provisions.
Adjusted operating profit tops £3bn, EMT the largest contributor Centrica has reported FY22 results this morning. Including the Spirit disposed assets, adjusted operating profit was £3,308m, up 249% vs. FY21A, well above our estimate of £3,008m, and consensus of £2,683m. Adjusted EPS of 34.9p, up 759% vs. FY21A (INVe 31.8p, consensus 28.7p, company guidance ‘above 30p’). FY DPS of 3.0p (INVe 3.0p, consensus 3.05p). Net cash of £1,199m compares to our estimate of £1,406m. Divisionally, the biggest contributors to operating profit were Energy, Marketing & Trading at £1,400m (INVe £1,228m), E&P at £730m (INVe £901m), and nuclear at £724m (INVe £677m). E&P, of course, is more heavily taxed. British Gas Energy Supply contributed £72m, below our estimate of £104m, with British Gas Services & Solutions posting a loss of £9m, below our estimate of £10m profit. British Gas residential customer numbers were up 4% vs. 2021, boosted by a number of SOLR appointees. Centrica intends to extend the existing £250m share buyback programme by an additional £300m. A presentation will be held at 9.30am, accessed via www.centrica.com/investors. Broadly positive outlook for 2023, but wide range of outcomes Given the range of external factors outside of its control, Centrica again points to a range of outcomes for many of its business units, but has called out the benefits of its balanced portfolio. Capital expenditure is expected to increase in 2023 compared with 2022. More detail on longer-term investment plans and expected returns to be provided alongside Interim results in July 2023. In the Retail businesses, Centrica is looking for some financial recovery in 2023 in Services. In Optimisation, although conditions seen in 2022 might not repeat in 2023, the capabilities to capture volatility are highlighted. In Upstream, wholesale prices remain elevated compared to historic levels, and with hedges rolling off, higher capture prices in gas production and nuclear activities are expected.
Figure 1: Capacity Market – T-1 23/24 provisional results (derated MW) Source: National Grid ESO Figure 2: Capacity Market – DSR & storage awarded contracts (derated MW) Source: Investec Securities analysis, National Grid ESO
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Not only will tomorrow’s electricity system be markedly bigger than today’s, but the supply side will be dominated by intermittent renewables, principally wind and solar. Variable demand and intermittent supply poses a problem, a challenge, but problems are there to be solved. So, what’s the solution? There will not be a single solution, but flexibility will play a major part; its development and deployment crucial to helping deliver an affordable net zero. Storage looks set to be a large part of the flexibility space. Already a meaningful asset class, storage is likely to see significant growth on the road to net zero 2050, with need and opportunity for a full range of discharge duration, location both in-front and behind-the-meter, and an opportunity for innovative technologies to complement those we already have. There are multiple revenue streams open to storage providers depending on many factors, including type, discharge duration, and location. Some streams might be mutually exclusive, but overall they are driven by market growth, and the ability to revenue stack looks set to make storage an increasingly exciting asset class. We identify key participants (a non-exhaustive list) in the storage space who could benefit from the growth pathway. We segment these into five different models: (i) Full value chain; (ii) Ownership; (iii) Developers; (iv) Optimisation and route to market; (v) Domestic. We suggest that consolidation and M&A are likely in a very fragmented industry, and flag that there are currently a limited number of listed pure-play operators. However, there are a number of ways for an equity investor to get exposure to storage, in both the listed company and fund spaces. In the listed company space, we flag Centrica (BUY, TP 170p), Drax (BUY, TP 1,100p), Good Energy (BUY, TP 420p), SMS (BUY, TP 1,396p), and SSE (BUY, TP 2,120p). Dedicated storage funds include Gore Street Energy Storage Fund (N/R), Gresham House Energy Fund (N/R) and Harmony Energy Income Trust (N/R). Other funds which have interests in storage include Foresight Solar Fund (BUY), JLEN (BUY), NextEnergy Solar Fund (HOLD), Octopus Renewables Infrastructure Trust (SELL), and TRIG (BUY).
BEIS issued a press release yesterday indicating that Secretary of State Grant Shapps has given suppliers a deadline of Tuesday to report back to him on what remedial action – such as providing compensation – they plan to take should they have wrongfully installed prepayment meters in the homes of vulnerable customers. He has also called on Ofgem to set up a new customer reporting system for households to pass on their own stories of how they are being treated – especially those who are vulnerable – and not just rely on energy firm bosses to share information with their regulator. Where acts of wrongdoing are uncovered, it is clear to us that action needs to be taken by the perpetrators and those who regulate, but we suggest that there is much more that needs to be addressed. With Ofgem soon to publish its decisions on strengthening financial resilience and amending the methodology for setting the EBIT allowance in the tariff cap, supply was already very much in focus, but recent events bring to the fore the overarching question of ‘what should the supply market of tomorrow look like, and how can we ensure that nobody is left behind?’. There is a clear need for social tariffs, and it is imperative that government and Ofgem move at pace to implement a structure, although we recognise that designing a mechanism and the funding thereof is not an easy task. Ahead of any such tariff being introduced we ask whether it is right that the tariff cap for those on prepayment meters is higher than those who pay by direct debit. Yes, there is a cost-to-serve differential, but with c.4m households on prepayment meters, and a £80 differential in the respective tariff caps, surely it is possible for Ofgem to socialise the c.£320m aggregate difference and have a settlement mechanism to reflect the number of prepayment meters suppliers support? In light of the ongoing cost of living crisis, we have also updated our tariff cap estimates, and our latest forecasts have nudged up from those that we published on 27th January. Our April cap estimate now stands at £3,316 vs. £3,298 previously. Our July estimate is now £2,369 (vs. £2,247), and our October estimate is £2,407 (vs. £2,288). We again stress the volatility that a shorter observation window allied with a mark-to-market approach imparts on the upcoming quarter, with our July and October estimates fully marked-to-market.
The Times reported this morning that third party contractors working for Centrica''s British Gas subsidiary had forcibly installed pre-payment meters in the homes of vulnerable customers. Subsequently the energy regulator Ofgem announced later in the morning that it has launched an investigation into the matter, and Centrica announced that it has suspended warrant prepayment meter installations and launched its own investigation. We think the possible direct consequences of the issue, based on similar events at peers historically, could be a fine on Centrica (if found to be guilty of any wrongdoing) and potentially some form of reactive mandatory support from the company or industry for prepayment meter holders. Based on past precedent, we would not expect such measures to be transformational in the context of Centrica''s market cap, likely substantially less than the cGBP300m wiped off the shares already today even in a worst-case scenario. We see the bigger driver of the reaction as being 1) fears that renewed political focus on the company could limit headroom to announce higher dividends or share buybacks, and 2) strong recent performance in the shares. Regarding (1), the news might jeopardise the chance of a major dividend or SBB announcement at FY results in a fortnight, but this was not something we expected in our Outperform case and we don''t think the market was pricing in a major capital return event this soon. We see a possibility that noise over the event fizzles with the news cycle over the coming weeks and we do not see it as threatening our Outperform case on the stock. Our TP is unchanged.
British Gas suspends all warrant activity and will complete a thorough, and prompt, investigation There is extensive coverage in The Times this morning regarding British Gas force-fitting prepayment meters. Against the backdrop of the cost of living crisis, the need to protect the vulnerable, and recent correspondence between BEIS Secretary of State Shapps & Ofgem’s CEO Jonathan Brearley, this is clearly not good practice, and most definitely not a good look. An investigation by Ofgem is said to have been opened. Centrica is a portfolio company & UK supply is only c.3.5% of our adjusted operating profit in FY22E, albeit c.29% of our SOtP. Despite this, the YoY jump in group profits that we expect at FY22 results on 16/2 are likely to be the focus for those who wish to suggest that profits are being made at the expense of the vulnerable. The PR course that Centrica has to navigate has arguably got harder. Centrica put out a short statement last night: “Protecting vulnerable customers is an absolute priority…”, “…on Wednesday morning, we took a further decision to suspend all our prepayment warrant activity at least until the end of the winter”; “We think Government, industry and the regulator need to come together to agree a long-term plan to address this and ultimately create an energy market that is sustainable.” The latter tallies with our previously expressed view that social tariffs are needed, and that both energy and water companies need to go the extra mile to ensure legitimacy of their actions.
Our latest tariff cap estimates have fallen from those that we published on 23rd January. Our April cap estimate now stands at £3,298 vs. £3,359 previously. Our July estimate is now £2,247 (vs. £2,465), and our October estimate is £2,288 (vs. £2,508). We again stress the volatility that a shorter observation window, allied with a mark-to-market approach, imparts on the upcoming quarter, with our July and October estimates fully marked-to-market. These are the lowest estimates we have published for these three specific quarters, as evidenced by our tracker (Figure 2). Indeed, if we take our 2H23 estimates, we have not been suggesting these levels for over a year. As things stand, 2H23 is below the £3,000 Energy Price Guarantee that will be applicable at this time which, to a degree, is a relief. However, such levels are still nearly double price levels of winter 21/22, and the cost-of-living crisis will remain acute for many. In a speech last Monday, Ofgem’s CEO echoed our call for a social tariff in energy: “Therefore, we think that there is a case for examining, with urgency, a social tariff that limits the impact of extremely high prices and reduces volatility for a defined set of vulnerable groups.” In water, Ofwat has today published a summary of company responses to a request for details their plans for supporting customers. All water companies have social tariffs, although these are generally cross-subsidised, and funded by those not on social tariffs. A small number of companies are singled out for making additional contributions, with five contributing their own funding (Dŵr Cymru Welsh Water, Hafren Dyfrdwy, SES Water, United Utilities and Yorkshire Water), while Severn Trent Water extended its Big Difference Scheme, creating capacity for an extra 100,000 people through making efficiencies in its business operations. That said, Ofwat has made a broader call for increasing funding for social tariffs from efficiencies and company contributions: “During these pressing times, companies should continue to improve the support they offer and identify ways to directly fund additional help. This might include through operating efficiencies, cost neutral approaches and contributions from their own money (in line with those companies already leading the way on best practice by doing so)”. This very much underscores that, given their special role and position, both energy and water companies need to go the extra mile to ensure legitimacy of their actions.
The ten priority missions (Figure 1) to harness public and private action by 2035 call for significant low-carbon generation build, a rooftop revolution, CCUS, grid infrastructure, and energy efficiency. As we have long opined, there are multi-year investment opportunities across the whole energy value chain, and we see these over-arching priority missions as entirely consistent with this viewpoint. Cleaner, greener homes – hitherto, it feels like that we have a policy to have a policy on decarbonisation of heat, which, allied with badly insulated housing stock (Figures 3 and 4) is not a great place to be. We welcome the call to get off the fence (Figure 2), and view the request for certainty on gas boiler phase- out as positive for the deployment of heat pumps, a driver for energy suppliers such as Centrica, Good Energy, and Octopus which are active in this space. Improving energy efficiency of the housing stock is a driver for the likes of SIG and Travis Perkins. Shifting sands of regulation – it is clear that regulation (Figure 6) and the broader planning environment need to be facilitators of the pathway to net zero, and we have previously welcomed Ofgem’s ASTI framework as a significant positive step, and positive for National Grid/SSE. We see logic in the suggestion that Ofgem’s remit is updated to incorporate the Government’s net zero target. Bring on BECCS – CCUS is a necessity to deliver net zero, and needs to be deployed across both industry and power. The review calls for a clear roadmap beyond 2030 (Figure 7), but there is also a message that engineered greenhouse removals are essential to capture residual emissions. We view BECCS as such a technology, and one that can be deployed to capture CO2 at scale, with Drax at the forefront of this direction of travel in the UK. We look forward to publication of the biomass strategy and BECCS remuneration framework as key steps on this pathway in 2023. Turbocharging renewables – go further, go faster, and stamp on the accelerator (Figures 8 and 9). Got a roof, stick a solar panel on it. Community wants onshore wind, then build it. The message here is clear, crystal clear. Crack on. In turn, this offers opportunities for renewable developers, as well as energy suppliers which can provide a wider product suite to an increasingly engaged consumer base. People are vital – with almost half the actions in the Government’s Net Zero Strategy requiring public action, it is a necessity that consumers are given agency and provided with trusted information and advice (Figure 11), and that the transition is affordable. Given multiple touch points (Figure 12), flexibility is likely to be an exponential growth area, one which will see new revenue opportunities/business models, and something we suggest that the likes of Centrica and Good Energy can exploit.
CNA DRX GOOD NG/ SHI SSE TPK
Following the recent trading update, and changes to the Electricity Generation Levy, we have updated our estimates. Higher Energy Marketing and Trading profitability, a higher contribution from Upstream (nuclear output and Rough extraction), and reduced finance charges are the drivers of a material uplift in our EPS estimates for FY22E (+23.7%). FY23E (+0.5%) and FY24E (+2.1%) benefit from changes to the EGL (Figure 1). Minor tweaks to our valuation (Figure 4), and we nudge our target price up to 170p/share, continuing to position us at a Street high. Potential catalysts include FY22 results (16th February), and a statutory consultation from Ofgem on ‘amending the methodology for setting the Earnings Before Interest and Tax (EBIT) allowance’ in the tariff cap, expected in February. With significant potential upside on offer, we reiterate our BUY rating.
FY22 EPS guidance upgrade to above 30p Centrica has issued a trading update this morning ahead of FY results on 16th February. The company has continued to deliver strong operational performance since the previous trading update on 10th November 2022. Infrastructure asset availability and volumes have remained good, and Centrica has delivered incrementally strong optimisation performance. Centrica now expects to report 2022 full-year adjusted EPS above 30p (INVe undiluted 25.7p) vs. previous guidance of ‘towards the top end’ of a range in which 26p was the upper bound at the time of the 14th November trading update. We have placed our estimates under review, but expect the moving parts to be the Energy, Marketing & Trading business, and a contribution from Rough given extractions late last year. Cash generation has also been good, and closing net cash is expected to be above £1bn (INVe £1.2bn). Russell O’Brien joins as CFO, Kate Ringrose steps down Russell O’Brien will be appointed CFO and an Executive Director on 1st March 2023. The current CFO, Kate Ringrose, will step down as CFO and an Executive Director on 28th February 2023 and is expected to leave Centrica towards the end of 2023 after an orderly transition. We wish her well in her future endeavours. Russell has previously served in a number of roles at Shell, including roles as global CFO for both Shell’s Integrated Gas and Retail businesses, leaving as Group Treasurer at Shell, and a role in which he was instrumental in delivering shareholder value and setting a clear financial framework for investors.
Marking-to-market the unobserved days in the observation period for the April 2023 tariff cap, our April estimate now stands at £3,317 vs. £3,458 in our previous estimate. Our July estimate is now £2,478 (vs. £2,640), and our October estimate is £2,546 (vs. £2,704). These movements underscore how volatile our mark-to-market approach is. The Energy Price Guarantee (EPG) rises to £3,000 in April, continuing to protect consumers in Q223. However, with our July and October estimates below the £3,000 EPG, effective April, we continue to suggest that the tariff cap will be the relevant metric for households in H2, and not the EPG. Our estimate of the cost to government in fiscal 23/24 is now c.£2.3bn vs. c.£3bn previously. Our estimates are based on a continuation of the 1.9% EBIT allowance in the tariff cap. However, Ofgem consulted on the methodology for setting EBIT in November (Further consultation on amending the methodology for setting the Earnings Before Interest and Tax (EBIT) allowance), in a consultation that is now closed. This consultation did not suggest an EBIT range, nor the amount of capital to be employed, albeit that there were numerous proposals as the component parts of the cost of capital, which we concluded (see Softly-softly, missed opportunity, 27th November) pointed to a cost of capital slightly above that in the current cap formulation. Additionally in an accompanying financial resilience consultation at the time (Statutory Consultation – Strengthening Financial Resilience), Ofgem opined that £110-220 per customer is materially lower than the likely level of capital employed under the EBIT proposals. We concluded that downside risks to the c.£40/customer through the cycle EBIT margin in our Centrica modelling were limited. In a presentation shared yesterday, Ofgem suggests that the current range for the cost of capital is 9.3% to 12.7% (vs. our estimates of 10.22% to 11.08% in November), also setting out per customer EBIT allowances under a number of scenarios (see Figure 3). The no collateral scenarios suggest lower allowances than those with collateral included, but the ‘no collateral, mid scenario’ supports our c.£40/customer through the cycle margin for Centrica , and is consistent with the EBIT margin that our latest cap estimates suggest (Figure 2).
The Energy Bill Relief Scheme (EBRS) provides a discount on wholesale gas and electricity prices for all non-domestic consumers, and is effective from 1st October 2022 to 31st March 2023. For those on fixed contracts, the discount reflects the difference between the government supported price (£211/MWh electricity / £75/MWh gas) and the relevant wholesale price for the day the contract was agreed. For businesses on variable/deemed contracts, the discount was based on the difference between the government supported price gas and the relevant wholesale price, but subject to a maximum discount of £345/MWh (electricity) and £91MWh (gas). The Government was clear that the above levels of support were time-limited, but recognising the pressures that businesses face, has announced a new scheme, the Energy Bills Discount Scheme (EBDS), which will run from 1st April 2023 to 31st March 2024., with cost cap of £5.5bn at estimated volumes. The EBDS will be available to everyone on a non-domestic contract including businesses, voluntary sector organisations, and public sector organisations who are on existing fixed price contracts agreed on or after 1st December 2021, signing new fixed price contracts, on deemed/out of contract or standard variable tariffs, or on flexible purchase or similar contracts. Eligible non-domestic consumers will now receive a unit discount to their energy bills during the 12-month period from April 2023 to March 2024, subject to a maximum discount of £19.61/MWh (electricity) and £6.97/MWh (gas). The new wholesale price thresholds are £302/MWh and £107/MWh respectively. Non-domestic energy users particularly vulnerable to high energy prices due to their energy intensive and trade exposure will receive a higher level of support, subject to a maximum discount. For qualifying businesses, the maximum discounts and wholesale price threshold for electricity are £89/MWh and £185/MWh respectively, and £40/MWh and £99/MWh respectively for gas. This discount will only apply to 70% of energy volumes. Sectors eligible are set out here. Current forwards (Figures 1 and 2) are below the threshold, so those agreeing fixed contracts in the current environment are unlikely to receive support, while for those on non-fixed contracts, it will depend on whether the threshold is breached. The big losers are likely to be those who agreed fixed contracts in mid-June to mid-December period of last year (Figure 3).
Forward wholesale electricity and gas have fallen markedly over the past four weeks, giving rise to significant reductions in our tariff cap estimates. The observation period for the April 2023 cap opened on 17th November and closes on 17th February, meaning that the higher forward prices of November/early December are already locked-in, but marking-to-market the unobserved days, our April estimate now stands at £3,458. Our July estimate is now £2,640, and our October estimate is £2,704. As discussed in previous notes, these estimates will continue to be extremely volatile given our mark-to-market approach. The Energy Price Guarantee (EPG) rises to £3,000 in April, continuing to protect consumers in Q223. However, while our July and October estimates are below the EPG, we suggest that the tariff cap will once again be the relevant metric for households, and not the EPG. The cost to government in fiscal 23/24 would also outturn below that for fiscal 22/23, our estimates suggesting a cost of c.£3bn vs. c.£25bn respectively. Given that government has indicated that it intends to consult on amending the scheme as soon as is feasible after April 2023, so that those who use very large volumes of energy have their state support capped, a tariff cap level below the EPG will mitigate this risk for this cohort. Dual-fuel costs, however, are still considerably higher than historic (pre-April 2022) levels, and with the £400 winter 22/23 energy bills support scheme falling away in April, water and council tax bills set to rise, and for up to 160,000 Londoners, an expanded ULEZ from late August, the cost-of-living crisis is clearly not dissipating. Social tariffs in energy are clearly needed, and we look to HM Treasury, BEIS and Ofgem to work together to put these in place as soon as possible.
Draft Determinations – Ofgem has published RIIO-2 final determinations (FD) for electricity distribution (ED) this morning, and is hosting a presentation this afternoon. There is a forest of paper to work through, a process that will take a while, but we set out an initial high-level view below. Totex – as expected, baseline totex has moved up vs draft determinations (DD). For NG FD totex is £6bn, 7% up vs. DD, in line with our modelled assumption of £5.9bn, and 13% below NG’s ask. For SSE, FD totex is £3.6bn, 9% up vs. DD, in line with our modelled assumption of £3.6bn, and 15% below SSE’s ask. Allowed returns – proposed allowed returns have moved up vs. DD, with the WACC at 3.93% CPIH real (3.93% for three DNOs incl. NG’s East Midlands, and SSE’s SSES). This compares to 3.26% CPIH at DD (3.29% for three DNOs incl. WPD’s South Wales). The increase reflects the higher cost of equity and a 55bps upwards adjustment to the 17-yr trailing average in the debt calculation. Allowed return on equity – the allowed return on equity at 60% gearing is 5.23% vs. 4.75% at DD. WACC above consensus – Ofgem collated consensus, published earlier last Friday, pointed to a range for the allowed return on equity of 4.80%-5.62%, with a median of 5.20% and a mean of 5.16%. The range for the allowed return was 3.30%-3.65%, with a median of 3.59%, and a mean of 3.54%. In the round, no major impact – Our cost of equity range estimate was 5.24%, with an allowed return of 3.45%, broadly in line with consensus. Versus the assumptions in our pre-existing NG and SSE models, Ofgem’s allowed return suggests a positive impact vs. our pre-existing modelling. National Grid response – “We will now review in detail the full package contained within the Final Determination to see whether it incentivises sufficient investment to ensure safe, secure and reliable supply of electricity alongside the need to help transition to a low carbon domestic energy system, at the lowest cost to customers.” “…we anticipate that we will make a decision on whether to accept or appeal the licence modifications by February 2023.” SSE response – “SSEN will now carefully examine the full details of Ofgem's Final Determination to gauge the extent to which it correctly represents a fair and balanced outcome for customers and investors. This assessment will run into next year and will take place alongside continued preparations and mobilisation for delivery of the new business plan from April.”
The observation window for the April 2023 cap opened on 17th November, and our updated estimate is based off forward prices as at the close on Friday 25th November. Forward prices have moved up since our last estimate, and our April estimate now stands at £3,974. Our July estimate is £3,416, and we introduce an October estimate of £3,451. As previously discussed, these estimates will be extremely volatile given our mark-to-market approach. Our updated estimates now include an assumed recovery of £16/dual-fuel consumer for the year from April 2023 in respect of Ofgem’s minded-to-position on true-up payments under the Supplier of Last Resort (SoLR) Payments process. The price cap currently includes £61/consumer for SoLR claims, these being recovered over the year from April 2022. Reflecting recent consultations from Ofgem, we include £7.90/customer for RO ringfencing, and £27/customer transitional allowance in respect of potential changes to BSUoS charges in the cap. Both of these numbers are electricity only, and are at benchmark consumption of 3,100kWh, as opposed to TDCV consumption of 2,900kWh. Ofgem is consulting on amending the methodology for setting the EBIT allowance in the price cap. A statutory consultation is expected in February, with a subsequent decision in May. If changes are made, these could be implemented in the July cap. At this juncture, our estimates assume continuation of the 1.9% EBIT margin allowance. The Energy Price Guarantee (EPG) has been extended for a year from April 2023, albeit at the higher level of £3,000, and the cap should be viewed as a key driver for the reference price for calculating the level of support offered by the government under the EPG. Figure 3 sets out our estimates of the unit charges under the EPG. However, the government has indicated that it will keep the EPG under review and may revisit the parameters of the scheme, for example if the forecast cost increases significantly. Government will consult on amending the scheme as soon as is feasible after April 2023 so that those who use very large volumes of energy have their state support capped, whilst the vast majority of households can continue to benefit. As such, it is possible that the tariff cap becomes relevant for a group of consumers before April 2024.
Ofgem published a slew of documents on Friday. Three stand out. Further consultation on amending the methodology for setting the Earnings Before Interest and Tax (EBIT) allowance. The consultation does not suggest an EBIT range, nor the amount of capital to be employed. However, there are numerous proposals as the component parts of the cost of capital, which point to a cost of capital slightly above that in the current cap formulation. In the accompanying financial resilience consultation, Ofgem opines that £110-220 per customer is materially lower than the likely level of capital employed under the EBIT proposals, leading us to conclude that downside risks to the c.£40/customer through the cycle EBIT margin in our Centrica modelling are limited. Statutory Consultation – Strengthening Financial Resilience. Lax oversight and ease of market entry, allied with unsustainable pricing, and a lack of, or inability to hedge, were all contributory to the multiple supplier failures seen in the supply market, notably in the latter part of 2021. Ofgem estimates the cost of failure being/to be paid for by consumers at £2.6bn, excluding Bulb. OBR estimates point to a £6.5bn cost of Bulb, but it cannot, or will not provide granularity on this figure, and it is a number we struggle to comprehend. It is not unfair to suggest that considerable blame for the mess that ensued in the supply market should be laid at Ofgem’s door. Against this backdrop, Ofgem is consulting on an enhanced Financial Responsibility Principle (FRP), a market-wide capital requirement, and ring-fencing Renewables Obligation receipts. It has stepped back from ring-fencing consumer credit balances. Given the impact to date of supplier failures on customer bills, we are surprised that Ofgem appears to be taking a softly-softly approach with a long glide path to an unspecified capital requirement. The same can be said about ringfencing, where ringfencing the RO is in, but ringfencing CCBs is out, despite the mutualised costs from each being broadly similar. Ofgem’s analysis suggests that the net consumer benefit of ringfencing both the CCB and RO is marginally less than ringfencing the RO alone, but given the special nature of energy and the fact that customer money is involved, it strikes us that there is merit to a tougher approach. Price cap – Programme of Work. Ofgem sets out its priorities over the next two to three years, arguing this gives reassurance that it will continue to monitor the cap methodology while balancing cap changes from market uncertainty, alongside others required to ensure customer protection. The cap is a key driver for the reference price for calculating the level of support under the Energy Price Guarantee, and Ofgem argues that this should provide confidence to market participants that it will continue to set the cap independently. Push back against the powers conveyed to government under the Energy Prices Act perhaps?
Ofgem is set to publish RIIO-ED2 Final Determinations next Wednesday 30th November, with an investor call to be held the same day at 2pm. There are a multitude of moving parts to a price control, and ultimately it is important to look at the package in the round. Components to look out for include the allowed returns on equity and debt, the gearing assumption, the nature of the debt tracker (17-year trailing average at draft determination (DD)), baseline totex, uncertainty mechanisms, ongoing efficiency (1.2% at DD), and the incentive package (negative skew at DD). We have updated our cost of equity calculation for the move in gilts since DD, and look for 5.24% CPIH real. We use the DD cost of debt, and with a 60% gearing assumption, we suggest a WACC of 3.45% CPIH real. At DD the cost of equity was 4.75%, and the WACC 3.26% (Figure 1). We expect Ofgem to move on baseline totex, and our assumptions are 6% higher than draft determinations for National Grid (Figure 2), and 11% higher than draft determinations for SSE (Figure 3). It is also worth contextualising distribution in the context of what are much bigger groups. National Grid Electricity Distribution is 17% of our sum-of-the-parts (EV), while for SSE, distribution similarly accounts for 17%. Next week is important, but given the weight of distribution in the overall mix for both companies, the share price reactions could be muted.
Ofgem has announced the January price cap at £4,279 for a typical dual-fuel customer (2,900kWh electricity, 12,000kWh gas). Our final estimate was for £4,226, c.1% below the out-turn. The granularity is shown in Figure 1 overleaf, where it can be seen that we were £26 too high on wholesale costs, and £24 too high on the negative CfD adjustment in our model. The difference on the wholesale cost appears to be in electricity, with Ofgem’s direct fuel cost being £331.05/MWh vs. our £327.98/MWh. In gas, Ofgem was at £113.63/MWh vs. our £113.85/MWh. The split of the dual-fuel tariff cap is £2,126 for electricity and £2,153 for gas. Our estimates were £2,080 for electricity and £2,146 for gas. We expect announcements from Ofgem tomorrow on its work to create a more stable retail market, and Ofgem will be holding an investor call on the same day at 11am to discuss. The Energy Price Guarantee of £2,500 for the typical consumer is in place until the end of March, rising to £3,000 for the following 12 months. We will be updating our price cap estimates in due course, and Ofgem will announce the April 2023 cap level on 27th February 2023.
The UK’s chaotic political backdrop over the past few months was not helpful to the utility space, Centrica included. The Electricity Generation Levy could yet prove detrimental to energy security and/or the cost of new build, but at least we now have semblance of clarity, for now. The cost-of-energy debate is not going to go away any time soon, and undoubtedly Centrica will attract continued heightened attention, but we take comfort on the supply market from the Autumn Statement: “…will be to deliver a fair deal for consumers, ensure the energy market is resilient and investable over the long term, and support an efficient and flexible energy system.” An update on Ofgem’s work to create a more stable retail market, expected later this week, is part of this, and should be supportive of a direction of travel to more innovation in tariffs, decarbonisation of heat, and a broader range of route to market, all of which should benefit CNA in the medium to longer term. Following the recent trading update, changes the Energy Profits Levy, and the introduction of the Electricity Generation Levy, we have updated our estimates. Higher Energy Marketing and Trading profitability and a higher contribution from nuclear are the drivers of material uplifts in our EPS estimates for FY22E (+42.9%), and FY23E (+31.0%) respectively (Figure 1). Our valuation point is rolled over to FY23E, with the granularity of changes set out in Figure 4. We move our target price up to 165p/share. Centrica is hosting a virtual investor teach-in on its Energy Marketing and Trading business on 1st December, and we are hopeful that this will provide visibility on a sustainable earnings stream. We view this as a potential catalyst, and reiterate our BUY rating.
The Chancellor has announced an Electricity Generation Levy. The levy will be applied to groups generating electricity from nuclear, renewable and biomass sources. It will not apply to electricity that is generated under a CfD. In scope generation will be subject to a 45% tax charge on a measure of ‘Exceptional Generation Receipts’ calculated as: Generation Receipts - Electricity Generation (MWh) x Benchmark Price (£75/MWh) - Allowance (£10m per annum). The levy will not be deductible from profits subject to Corporation Tax. The revenue measure will not include revenue that renewables generators earn from the sale of ROCs or revenue from capacity market payments. The levy will take effect from 1st January 2023 and be applied to receipts from in-scope generation after that date. It will be legislated to end by 31st March 2028. The levy will not be applied to pumped storage hydroelectricity, battery storage, gas, coal or oil generation. HM Treasury and HMRC will reach out to relevant generators to discuss with them how the model set out in the technical note will be implemented in legislation. The draft legislation will be published in mid-December. The Energy Profits Levy will be increased from 25% to 35%, applicable from 1st January 2023 to March 2028. We have undertaken some sensitivity analysis on each of Centrica (Figure 1), Drax (Figure 2), and SSE (Figure 3). This analysis utilises our published estimates, adjusts for updated disclosed hedges, mark-to-market on open positions, and applies the Electricity Levy. The valuation impact is positive. We maintain a view that changing the rules in the middle of the game could be detrimental to the pace, cost and quantum of investment in the electricity value chain, given elevated UK risk. We also cannot rule out the levy influencing the way that some generators will despatch their assets, with consequent implications for energy security. However, we welcome a semblance of clarity, which should positively impact Centrica, Drax and SSE. The Energy Price Guarantee will be extended for a year from April 2023, albeit at a new level of £3,000. We suggest that this will cost c.£9bn, below HMT’s £13bn estimate. There will be additional cost of living payments to those on means tested benefits (£900), pensioners (£300), and disability (£150). An HMT led review of the Energy Bill Relief Scheme will determine support for non-domestic energy consumers, excl. public sector, beyond 31st March 2023. A new Energy Efficiency Taskforce will aim to reduce the UK’s final energy consumption from buildings and industry by 15% by 2030, against 2021 levels. The Business and Energy Secretary will publish further details on energy independence plans and launch a new Energy Efficiency Taskforce shortly.
The observation window for the January price cap closed yesterday, and our final estimate stands at £4,226. We have set out the granularity of this estimate in Figure 2 overleaf. Consumers will still be protected by the £2,500 energy price guarantee from January-March. The observation window for the April 2023 cap opens today, and our updated estimate is based off forward prices as last night’s close. Our April estimate now stands at £3,640, and our July estimate at £3,107. Our updated estimates now include an assumed recovery £16/dual-fuel consumer (Figure 6) for the year from April 2023 in respect of Ofgem’s minded-to-position on true-up payments under the Supplier of Last Resort (SoLR) Payments process. The price cap currently includes £61/consumer for SoLR claims; these being recovered over the year from April 2022. Ofgem is also consulting on amending the methodology for setting the EBIT allowance in the price cap, and a statutory consultation is expected this month, with a subsequent decision document in February. If changes are made, these may come into effect in the April cap. At this juncture, our estimates assume continuation of the 1.9% EBIT margin allowance. Although our April and July estimates are below the peak we see in January, they are both above the level of the Energy Price Guarantee, and clearly represent an impending bill shock. Ongoing support for many households is needed, and essential for physical and mental wellbeing. We are conscious of the constraints on the public purse, and suggest it is imperative that targeting is a key part of any extension of support post March. However, in order to shield all consumers from the impact of significant jump in unit costs from April, a time-limited extension of the broad Energy Price Guarantee at a higher level has merit, in our view. Taking seasonality of consumption into account, our current price-cap estimates suggest that a time-limited six-month extension of the Energy Price Guarantee at £3,000 would cost c.£6bn. Arguments against such an extension would be that with the full observation windows for both the April and July caps ahead of us, this equates to a blank cheque, as well as creating consumer expectation of further support for winter 23/24, should commodity prices remain elevated.
EPS expected to be towards top end of consensus range Centrica has issued an unexpected trading update this morning indicating continued strong operational performance from its balanced portfolio since interim results in July. Centrica now expects full year adjusted EPS to be towards the top end of the range of the more recent sell side analyst expectations of 15.1-26p (INVe 18p). Volumes from its electricity generation and gas production activities have remained strong, while in October Centrica announced the reopening of the Rough gas storage facility, all of which contribute to strengthening the UK and Ireland's security of supply. In Energy Marketing & Trading Centrica’s optimisation and route to market activities are continuing to perform very well. Inflationary and economic pressures have impacted the cost base and customer numbers in British Gas Services & Solutions, while warmer than normal weather in October has contributed towards lower volumes and profits in British Gas Energy. Consequently, Centrica expects adjusted operating profit in its Retail division to be lower than current expectations. Reflecting the recent performance and outlook, together with the work undertaken in recent years to strengthen the balance sheet and ensure appropriate liquidity, Centrica has announced that it plans to commence a share repurchase programme of up to 5% of its issued share capital. The uncertainties that remain over the remaining two months of the year include: the impacts of weather, commodity price movements, asset performance, the potential consequences of a weak economy and high inflation on commercial performance in British Gas Services & Solutions, and bad debt in energy supply.
Over the past twelve months, our price cap estimates have underpinned our view that there would be a cost of energy crisis, a cost of living crisis, inflationary pressures, an impact on discretionary spend, and that there would be political casualties. Not necessarily things one wants to be correct on, but we have been, on each and every one. With (ex PM) Liz Truss’ £2,500 Energy Price Guarantee in place throughout the winter, the level of the price cap for Q123 is of greater relevance for calculating the amount that the government should reimburse suppliers, but from April it will be of grave concern to many, given the uncertainties as to whom will receive support after this date. With a week to go in the observation window (closes 16th November) for the Q123 cap, we have updated our estimates, and now estimate the Q123 cap at £4,211, the Q223 cap at £3,750, and the Q323 cap at £3,192. These estimates observe prices up to and including 8th November. In formulating our estimates, we use pricing from Bloomberg. For gas we use ICE pricing, but for electricity we use Bloomberg BCFV analysis, given the lack of continuous pricing from other sources. As can be seen from Figure 4, the BCFV price (yellow line) has historically shown a close relationship with the Tullett Prebon price (green line), but since the start of October the relationship has broken down. The BCFV price since this date shows a volatility not present in the Tullett Prebon price, nor in Q123 gas prices (purple line). We have assessed the impact of this volatility, and after taking into account the number of observed days from October onwards, and weighting accordingly, we have applied a small uplift to our wholesale electricity price calculation for Q123. This adds c.£30 to our Q123 estimate. Next week’s fiscal statement may well bring clarity of sorts as far as government intervention in electricity generation is concerned, but as we head into winter, it is clear that for many visibility on enduring help with high energy bills is imperative for physical and mental wellbeing. This is very much an acid test as to whether the government “gets it”.
Over the weekend the UK government approved a deal between the special administrators of Bulb and Octopus Energy, in which the latter will acquire Bulb’s 1.5m customers. The sale will be implemented using the Energy Transfer Scheme (“ETS”), which will transfer the relevant assets of Bulb into a new separate entity. This entity will subsequently be sold to Octopus and will remain ringfenced from its core business for a defined period. The transfer is conditional upon approval of the BEIS Secretary and will take effect at a time ordered by the courts, likely 11 November 2022. According to Octopus, the transfer will “become effective likely on 23:59 15th November 2022.” BEIS suggest the transfer will “become effective likely on 17 November.” As Bulb is currently unhedged, the Government will provide financial support to the new entity to purchase energy for Bulb customers over the course of winter 2022, with this financial support to be repaid by the new entity in accordance with an agreed repayment plan schedule. Additionally, a profit-share agreement will be put in place for the ringfenced business until agreed funding is repaid by Octopus. Under this structure, payments to shareholders or the wider Octopus group, from the ringfenced entity, would be restricted until the repayable funding to government is repaid. The amount to be paid by Octopus for Bulb’s customer base has not been disclosed, although the BBC suggests that it is in the £100-200m range. According to Octopus the amount to be paid “will represent a higher amount per customer than suppliers typically paid to take on any of the 29 suppliers who have failed since September 2021.” Final Last Resort Supply Payment claims have not been made in respect of these failures, and the ‘acquisition’ costs per customer, if any, are not known, but we would not expect them to be significant. The detail of the profit share is also not known, but prima facie, an acquisition price of £33-67/account, assuming all customers are dual-fuel, strikes us as an attractive deal for Octopus. In our opinion, critical mass, efficiency, flexibility, and ability to manage risk are all key, and we would expect Octopus to leverage value from the acquired customer base as it migrates over to the Kraken platform. The cost to the government of Bulb’s SAR, which could still be recovered from consumers, is unknown at this juncture. The OBR put the cost at £1.2bn for 2021/22, and with day ahead commodity prices having fallen markedly in recent weeks, we expect the final cost will be well below the £4bn level quoted in various media sources over the weekend. Indeed, it is possible that the cost might be in the ballpark of the £1.28bn that GEMA (Ofgem) estimated, in its skeleton argument last year, that a SoLR process for Bulb would cost.
The Energy Prices Act received Royal Asset on 25th October, and we now await a consultation in respect of the ‘Cost-Plus-Revenue Limit’ (CPRL), a windfall tax in all bar name. We have been clear that the detail of such a mechanism will be important when considering the impact on GB’s investment attractiveness. We have also previously posed the question ‘Who’s driving the bus?’(here), HMT or BEIS, and with press reports suggesting that Rishi Sunak ‘plans to expand windfall tax grab’, uncertainty abounds. Will the existing energy profits levy be extended to renewable generators, and if so, does the idea of the CPRL get side-lined? Again, the detail is important, but we have previously expressed a clear view that a generator windfall tax is a bad idea. The need for ongoing support for many should not be questioned, and although there has been some moderation in forward electricity (Figure 4) & gas (Figure 5) prices, and consequently in our tariff cap estimates (Figure 1), the numbers will still be devastating for many. Judging who needs ongoing support, and administrating it, will not be easy. Support via the welfare system, support via suppliers, social tariffs, rising block tariffs, etc., all of these will undoubtedly be debated, and rightly so, but we cannot stress enough that we believe whatever transpires needs to go hand-in-hand with a significant push on energy efficiency, demand optimisation and reduction, and not work to the detriment of heat decarbonisation. The cost of such support is still likely to be significant, and present government with stark choices. Muddying the waters of the investment landscape, and, with it, the possible risks to the timing and quantum of new build, in turn potentially impacting energy security and the net zero pathway, cannot be the right answer. Early evidence from Wind Europe suggests interventionist measures on the continent are impacting wind turbine orders (Figure 6). Early days, but a possible indicator of the damage unilateral intervention can do to the attractiveness of the investment landscape. Hopefully, the spectre of intervention in the UK will bring the various parties back to the table to plot a pathway to voluntary CfDs, a far better solution, in our opinion. Now, more than ever, we need consistent, well considered, and fair policy making, allied with independent regulation. We are not convinced that, at this juncture, all of those are in place.
Rough gas storage facility opens in time for winter… Centrica has announced the reopening of the Rough gas storage facility, having completed significant engineering upgrades over the summer and commissioning over early autumn. First injection of gas into the site in over 5 years has been made and Centrica is in a position to store up to 30bcf over winter 2022/23. The work done so far means that Rough is operating at c.20% of its previous capacity this winter, making it the UK's largest gas storage site and adding 50% to the UK's gas storage volume. The long-term aim is to turn the Rough gas field into the largest long duration energy storage facility in Europe, capable of storing both natural gas and hydrogen. …Centrica injecting, and locking in a spread We understand that the site already holds 14bcf of reserves, and with Centrica able to inject c.2mmth/day, it would take 70 days to fill to current capacity. Centrica is operating Rough on a merchant basis, and the rate of injection will depend on near term gas prices remaining depressed vs. fowards, as Centrica locks in a spread. With forward gas >300p/th in 2023, we estimate that daily injection could be worth c.£5m/day, the timing of recognition depending on when withdrawals are made.
We are cognisant of a wide range of estimates for the tariff from April 2023 onwards. As the observation window for the April 2023 cap does not open until 17th November, this is only to be expected, as estimates are highly sensitive to wholesale prices (Figures 4 and 5), assumptions as to their development, and the point at which the estimates are made. Indeed, we have seen intraday swings that cause our own estimates to fluctuate widely. However, it is fair to say that, based on current forwards, and in the absence of receipt of targeted support post April, the typical household needs to brace itself for a significant jump in energy costs, to the equivalent of £4,000/year (Figure 1), although we do see a fall in July. These estimates are c.£100 higher than those we published on Monday. Our April estimate is 60% higher than the Energy Price Guarantee (EPG), and over three times the level of bills of a year ago. Our estimates continue to include policy costs of c.£150 for TDCV consumptions, costs which have been earmarked for absorption by the State, as flagged in the announcement of the EPG “…temporarily suspending environmental and social costs (including green levies) from being passed onto consumer bills. These costs will be transferred to the government…” Given that the EPG now only extends to March 2023, it is unclear as to whether consumers will face these costs from April, and if they do, where they will sit. Our estimates see the majority within electricity, although we note the intention, set out in last October’s Heat and Buildings Strategy to progressively move these onto gas. The EPG and tariff cap are not caps on what consumers pay, they inform caps on unit prices. The more you consume, the more you pay, and in Figure 2 we set out our estimates of the unit prices for electricity and gas through to September 2023. Figure 3 suggests how this translate into quarterly costs, including standing charges, and in Q223, we suggest c.£800 of energy will be consumed by the typical household given seasonality of consumption. The need for ongoing support for many should not be questioned, but judging who is of need, and then administrating the support will not be easy. Support via the welfare system, support via suppliers, social tariffs, rising block tariffs, etc., all of these will undoubtedly be debated, and rightly so, but we cannot stress enough that whatever transpires needs to go hand-in-hand with a significant push on energy efficiency, demand optimisation and reduction, and not work to the detriment of heat decarbonisation.
Ten months ago, we published a forecast of a £2,000 tariff cap for April 2022, and suggested that there would be “…implications for discretionary spend, inflation, and fuel poverty. An increase of this magnitude is likely to have political implications.” Clearly, each and every one of these has played out. The Energy Price Guarantee, unveiled by PM Liz Truss on 8th September, was set to “reduce the unit cost of electricity and gas so that a typical household in Great Britain pays, on average, around £2,500 a year on their energy bill, for the next 2 years, from 1 October 2022.” With this in place, our estimating of the energy price cap became more of an exercise in estimating the cost to government of what, in theory, was an open-ended liability. In yet another U-turn from the incumbent administration, the PM and the Chancellor have agreed that it would be irresponsible for the government to continue exposing the public finances to unlimited volatility in international gas prices. A Treasury-led review will be launched to consider how to support households and businesses with energy bills after April 2023. The objective of this review is to design a new approach to lower the cost to the taxpayer, whilst ensuring enough support for those in need. Estimating the level of the tariff cap once again becomes of significant relevance to the cost of energy, and the cost of living. It looks bleak, with our April 2023 estimate at around the £3,900 mark, and our July estimate around the £3,300 mark (Figure 1). As the observation windows for April and July 2023 have not opened, these estimates, which reflect forward wholesale prices, are likely to be very volatile. Ofgem has not published a price-cap model since 26th August, and these estimates include policy costs of c.£150 for TDCV consumptions, costs which have been earmarked for absorption by the State. We welcome the suggestion that there will be support for those in need beyond April, but judging who is of need, and then administrating the support will not be easy. There will be many who will be deeply concerned, the implications for discretionary spend are very much front and centre, and we probably haven’t seen the last political casualty.
13.2: “The Secretary of State may take such other steps as the Secretary of State considers appropriate in response to the energy crisis.” & 13.3.b: “acquiring, making available or otherwise enabling access to energy or relevant infrastructure…” 14.2: “Expenditure to be incurred by the Secretary of State… in connection with any one project, must not exceed £100 million…” & 14.3: “But subsection (2) does not apply if the Secretary of State is satisfied that the exercise of the power is urgent…” 16.2: The windfall tax, that isn’t a windfall tax according to the government, can be directed to suppliers “…for paying to electricity suppliers in connection with reducing the cost to customers of electricity”, or to government “…for meeting expenditure incurred or to be incurred by the Secretary of State in reducing the cost to customers of electricity.” 16.4: It would appear that, for technologies caught by the windfall tax, all generation output in period will be caught: “…periodic payment to be calculated by reference to the quantity of electricity generated during the period in question by the relevant generating station with which the electricity generator is concerned.” 21.2: “The Secretary of State may modify (a) an energy licence (including any conditions, standard or otherwise, of a licence);” Sch 6: In relation to the domestic electricity and gas price schemes, there is provision for possible extension, as there is for non-domestic customers. Support for the latter is initially for six months, but “…may provide for the reduction of charge for electricity supply that takes place during up to four such periods”, with similar provisions for gas supply.
Energy Prices Bill to be introduced: The Government is introducing an Energy Prices Bill, putting into law support to help households, businesses and others with energy costs this winter. Temporary ‘Cost-Plus-Revenue Limit’: The Bill includes powers to stop high gas prices dictating the cost of electricity generated by lower cost renewables and nuclear, to be effected via a temporary ‘Cost-Plus-Revenue Limit’. Non-CfD low-carbon assets in scope: The precise mechanics will be subject to a consultation to be launched shortly, and Government has been working closely with industry on the detail, ahead of it coming into force from the start of 2023. The full scope of coverage is still being determined, but it will apply to low-carbon generating assets not currently covered by a CfD. Applies in England and Wales, liaising with Scotland: The limit will apply in England and Wales, and the Government is liaising with the Scottish Government to confirm whether it will extend to Scotland. The legislation allows for a temporary revenue limit to apply in Northern Ireland. No indication of price; pre-crisis levels in the mix: The limit will allow generators to cover their costs and receive an appropriate revenue that reflects their operational output, investment commitment and risk profile. Pre-crisis expectations for wholesale prices is a factor being considered, and what a reasonable upper estimate for what those might be. % retention of revenue above the limit? An arrangement that allows generators to keep a proportion of their revenue above the limit is being considered, recognising a need to have appropriate signalling to incentivise dispatch at times of system need. Biomass and nuclear to be considered separately? The importance of dispatchable and baseload generation for security of supply, and the importance of continued investment in these supplies is recognised. The low-carbon technologies that can deliver these types of power tend to have higher input costs (biomass and nuclear specifically mentioned) and this is being considered as part of the detailed policy design. ROCs stay in place: Generators will continue to receive their existing revenue support or subsidy payments, such as ROCs. Voluntary CfDs still on the table: Government is also legislating for powers that would allow it to consider running a voluntary CfD process for existing generators to take place in 2023. Subject to an appropriate strike price, we see advantages to both generators, from longer-term revenue certainty, and consumers, who could benefit from strike prices below wholesale prices. Splitting hairs: The press release states that “this intervention differs from a windfall tax as it will be applied to excess revenues generators are receiving, as opposed to applying to all profits.” Let’s leave that as a matter of interpretation.
The FT reports that talks to move merchant renewable generation to voluntary CfDs have collapsed, and that the government is seeking to press ahead with revenue caps, backed by legislation which could be unveiled this week. A price of £50-60/MWh is a starting point, but we understand that this has not yet been set, and that negotiations are ongoing. The article is quiet on whether ROCs remain in-situ, but we suggest that it is the wholesale price component that is being discussed. It is also not clear how such a cap, if implemented, would work. Capping the revenues of renewable generation, does not necessarily impact the wholesale price, and wholesale price indices feed through to the tariff cap. However, if structured as a CfD, strike prices below wholesale prices would impact the cap. It is possible to suggest that merely capping prices for certain technologies at this level is effectively akin to a windfall tax of 100% on revenues above a certain level, and hence a revenue raising exercise. Noting that Liz Truss previously ruled out a windfall tax on energy companies (Bloomberg 7th September), this smacks of a U-turn. It is also not clear whether this potential cap extends to Drax’s RO biomass units. If it does, we suggest it would be economically sensible for Drax to look at the merits of scaling back output at Drax Power Station, and selling biomass pellets on the open market. At a time where National Grid ESO’s concerns about security of supply have been laid bare, and the clear need to bring forward significant investment in the electricity value chain, the possibility of unilateral intervention is deeply worrying and a negative signal to investment. Pulling back from a public campaign to promote energy saving, and, possibly, now this. Clear cause for concern.
Lights stay on in Base Case: The Base Case assumes that interconnectors meet Capacity Market commitments, no disruption to gas supplies, no material demand response to price, and excludes coal contract and Demand Flexibility Service mitigation. It sees a de-rated margin in line with last winter (Figure 1), with the system tightest in December (Figure 3), but the ESO is confident that its standard operational tools will suffice. Tight if Europe looks after its own: The reduced import scenario assumes no import from Belgium, France and the Netherlands, 1.2GW import from Norway, and 0.4GW export to Ireland. Coal contracts (2GW) and Demand Flexibility Service (2GW) deployed. There is risk of demand interruptions on cold days with low wind levels (Figure 4), but mitigation measures are expected to be effective. Gas shortage and it’s rolling blackouts: A more aggressive scenario of reduced imports, and 10GW of CCGT assumed unavailable for a two-week period in January due to insufficient gas supply. Coal contracts (2GW) and Demand Flexibility Service (2GW) deployed. The deficit is of magnitude where the market response is insufficient, and it may be necessary to initiate the planned, controlled and temporary rota load shedding scheme under the Electricity Supply Emergency Code (ESEC). Some customers could be without power for pre-defined periods during a day (assumed 3-hour blocks). Banking on French nuclear: The Base Case assumes interconnectors deliver in line with their CM obligations (Figure 6), with risks and uncertainties of reduced imports included, and challenged present French nuclear availability is assumed to improve markedly (Figure 7). Prices expected to remain above last winter (Figure 9), with spikes in the Balancing Mechanism in times of scarcity. LNG and high gas prices: Despite price-driven demand response from domestic and non-domestic consumers, winter gas demand is forecast to be the highest since 2017/18 (Figure 9), driven by power and exports. Infrastructure sufficient, and LNG anticipated as primary source of supply flexibility, attracted by high prices. Tools, including a Gas Supply Emergency, to manage the imbalance. Tricky winter for government: Rolling blackouts could prove very tricky for the government, and we believe it is not unreasonable to suggest that there could be significant political fallout, including individuals taking responsibility, or even a change in administration. Flexibility a likely winner: A key strand of both the electricity and gas outlooks is the need for the market to respond, and generally we would expect a response if appropriate incentives are in place. This is likely to be a source of value to those which have flexible thermal assets (Drax, SSE), pumped storage (Drax, SSE), batteries (SMS), gas storage (SSE), can aggregate and offer consumer demand side response (Centrica, Good Energy), or have material trading operations (Centrica).
CNA DRX GOOD NG/ SMS SSE
Eligibility – everyone on a non-domestic contract, including businesses, the voluntary sector/charities, and public sector organisations, who are on fixed-prices contracts agreed on/after 1st April 2022, signing new fixed price contracts, on deemed/out-of-contract tariffs, or flexible purchase contracts. Exclusions – limited, but includes generators (power stations, pumped storage, grid connected batteries). For contracts signed before 1st April 2022, there is no eligibility for support. Discount on unit prices – the government will provide a discount on unit prices. This will be calculated by comparing the estimated wholesale price a business will be paying over winter to a baseline ‘government supported price’ (£211/MWh electricity, £75/MWh gas). The supported prices for gas and electricity have been set so that the wholesale prices faced by non-domestic consumers are aligned to wholesale prices in the domestic scheme. Fixed contracts – the discount will reflect the difference between the government supported price and the relevant wholesale price for the day the contract was agreed. Government will publish the wholesale price to be used in the calculation for each day from 1st April 2022. Variable/deemed contracts – the discount will reflect the difference between the government supported price and relevant wholesale price, but subject to a ‘maximum discount’ that will be determined at the beginning of the scheme. Maximum discount – the maximum discount will be calculated by comparing the government supported price with the average of expected wholesale prices for delivery across the six months of the scheme, and will be confirmed on 30th September. An indication of c.£405/MWh for electricity and c.£115/MWh for gas has been provided. Automatic application – support will be provided automatically with no need to apply. For fixed price contracts based on wholesale prices below the government supported price, there will be no eligibility for support. Reviewing the scheme – a review into the operation of the scheme will be published in 3 months’ time, to inform decisions on future support after March 2023. Continuing support to those deemed eligible would begin at the end of the initial 6-month support scheme, without a gap. Legislation required – legislation to enable the implementation of the scheme will be introduced in Parliament in October. What could it cost? – the announcement suggests that winter wholesale prices are expected to be £600/MWh for electricity and £180/MWh for gas. Winter gas is trading around this level, although baseload electricity is c.10% below. Average prices since 1st April are £393/MWh (electricity) and £127/MWh (gas). The likely cost depends on contract mix/date, but for six months support, we suggest a range of £22bn-£48bn.
Elevated commodity prices see our quarterly tariff cap estimates remain above the October 2022 level for the duration of our estimation, with the January level well over 3x that of October 2021 (Figure 1). As we have argued repeatedly, these are levels that are devastating for many, necessitating intervention by government. This will come in the form of the Energy Price Guarantee, which will see a typical GB household pay an average of £2,500 a year from 1st October 2022 for two years. The average unit price (there will be regional differences) for electricity will be limited to 34p/kWh (electricity) and 10.3p/kWh (gas), with average standing charges at 46p/day (electricity) and 28p/day (gas). It is not clear how often these will be updated, but with £61 of SOLR costs set to roll off at end March, our estimates suggest a small move in unit rates in April (Figure 2). For those on fixed tariffs, there will be a discount of 17p/kWh (electricity) and 4.2p/kWh (gas), albeit a discount that we understand will be scaled back so as not to reduce prices below the level of the guarantee. At this stage, the prepayment meter uplift looks set to remain, but we suggest that on social fairness grounds, and gaining political capital, it is a likely element for review. The £400 Energy Bills Support Scheme remains in place, and will be paid in six instalments from 1st October. Despite this, absent direct debit smoothing, seasonality would still point to higher cash outflows in winter (Figure 3), although we would expect suppliers to smooth the payment profile. Our updated estimates as to the cost of the government support is c.£80bn for the two years it is set to be in place. The business market is more difficult to cost, not least because of the absence of a reference price that the tariff cap provides in the domestic market. For this reason, a p/kWh discount for business consumption has its merits from a costing point of view, and likely easier to administer. The fiscal statement expected next week could set out the support at a high level, though the mechanics are likely to take longer, albeit with the possibility of backdating. Reforming the power market is also en train, although this only addresses part of the problem. Over 22m households use gas for heating, and the UK has some of the worst housing stock in Europe from a thermal efficiency perspective (Figures 4 and 5). The UK has a policy to have a policy when it comes to the decarbonisation of heat, but with the best molecule of gas being the molecule not used, it is imperative that not only does the government push ahead with a no regrets approach to heat decarbonisation, but also backs an industrialised approach to improving energy efficiency.
Government has announced an energy price guarantee for households lasting two years at £2,500. The guarantee also includes a temporary suspension of green levies. Existing renewable support schemes will be funded by government, as will the wider support. The previously announced support of £400 and other targeted measures will remain in place. We understand that Ofgem will calculate unit prices for each region, although it is not clear whether the removal of green levies will see a rebalancing from electricity to gas. It is also not clear whether the price differentials for payment methodologies will be removed. For the first year, this means a typical household will face £2,100 energy costs, rising to £2,500 in the second year. For some, this will still be a devastating level of cost, and two times the October 2021 level. We forecast price caps out to September 2023, and estimate that the cost of one year's support for households (including the equivalence fund for non-gas heated homes) is in the region of c.£48bn. Wholesale gas prices for Q4/23 to Q3/24 are a little lower than those in our 22/23 cap estimates, and we suggest the second year of support could cost c.£41bn. Businesses & other non-domestic energy users will be given six months of support at an equivalent level, with a potential extension for certain vulnerable industries beyond that. There will be a review in three months’ time to consider where this support should be targeted. We understand that discussions with the business retailers commenced yesterday. Estimating the cost of business support is extremely difficult given the absence of a price cap in this market, but using the domestic price cap as a reference, and assumptions as to seasonality, six months of support could cost c.£25bn. A new Energy Supply Taskforce has begun negotiations with domestic and international suppliers to agree long-term contracts that reduce the price they charge for energy and increase the security of its supply. The Taskforce and BEIS will negotiate with renewable producers to reduce the prices they charge as well. Nuclear was also mentioned. We believe that this could take the form of a move to voluntary CfDs, but there is no indication of process, whether it will be technology specific, strike prices, or duration. This should help bring the overall cost of electricity down. A windfall tax on the generation sector has been ruled out. Continued overleaf
Before Xmas, we were the first to predict a £2k energy cap level (see here) and we spoke of the implications for discretionary spend, inflation, difficulty in paying bills, and political consequences. It is clear that each one of those has played out. When we introduced a £4,200+ estimate (see here), press comments quoted Ofgem as saying our estimate was "a long way off". Since then, estimates have ground upwards, and there has been a significant reaction from across the stakeholder spectrum, and the resignation of a GEMA board member. We question whether Ofgem was fully aware at the time of the backlash that would ensue from January cap estimates. It is possible that Ofgem could come under scrutiny once a new PM moves into No 10, and potentially Ofwat too, given the growing furore around sewage spills and leakage levels in the face of drought conditions. Keir Starmer might have pushed back on nationalisation, but the actions, legitimacy, and potentially ownership of the energy and water companies will be increasingly in the spotlight, bringing investment implications. We will update our January cap estimate in due course, but as we have commented many times before, a greater level of support, particularly targeted support, is urgently required. The fact that, hitherto, the level of support has been insufficient is a clear failure of the current administration, in our view. We acknowledge that both Sunak and Truss have their own views on bill help packages, but the anxiety felt by many will be huge, and the continued failure to act falls way short of what is needed…and could well have political consequences down the line.
Ofgem published a number of decisions this morning in relation to the energy tariff cap, a number of which have a material impact on our estimates. Unexpected SVT demand costs incurred in cap period eight will be recovered through the adjustment allowance in the amounts of £15.57 for electricity and £23.38 for gas. Backwardation costs for cap period seven (April 2022) were revisited, and an uplift of £6 per customer will be applied via the adjustment allowance. As expected, Ofgem has decided to move to quarterly updates, with the price cap for October 2022 to be announced on 26th August, and the price cap for January 2023 to be announced on 24th November. In May, Ofgem consulted on updating the wholesale methodology to include backwardation costs, with a proposal to model these ex-ante, and recover these over a twelve-month period. The decision taken is to model ex-ante, but to recover over a six-month period. Based on 19th July prices, Ofgem has estimated a £271 backwardation cost per dual fuel customer over winter, and indicated that moving to a six-month recovery period increases the backwardation costs in the cap by approximately 60% in cap period 9a (October) and 75% in cap period 9b (January). Ofgem’s view is that the “shorter recovery period reduces the risk of supplier failure and the potential irrecoverable supplier exit costs that customers would pay if we saw further exit over winter.” Our updated modelling, based on prices as of 4th August, is that backwardation costs (post deadband) are slightly higher at c.£296 per dual fuel customer, which given the aforementioned comment as to the cap impact of six-month recovery, we believe will have a material impact on the level of the cap, particularly in January 2023. Within our cap estimates, we include backwardation components of c.£131 for October, and c.£504 for January. We suggest that the latter is not inconsistent with Ofgem’s indication that a six-month recovery would push up backwardation costs in the cap period 9b by approximately 75%. Although ultimately a cashflow timing change, it is a material contributor to our higher cap estimates, which now stand at £3,523 for October, and £4,210 for January (see Figure 1). Comparing our estimates with our previous position, the increased backwardation component alone accounts for c.£350 (pre-VAT). At c.£427 per month for winter consumption, the pressure on stretched households will only intensify, and the calls for support will get ever louder. It is blatantly obvious that what is on the table is not enough. Things have changed. Rishi Sunak and Liz Truss need to get together and agree a common position, and communicate it before the month is out.
A 412% jump in adjusted operating profit at 1H22, and the reinstatement of the dividend, with a 1p/share interim, at the time of a cost of energy crisis, triggered a degree of media hysteria. Having long argued for additional directed help for those who could face a devastating ‘eat or heat’ dilemma, we understand why a furore has ensued, but we believe a dose of realism is necessary. Indeed, as far as the dividend is concerned, our pre-results narrative had been ‘if not now, when?’. We argue that our thesis of there being a much improved landscape for domestic energy supply remains intact, but what is patently obvious is that the UK energy system, indeed the global energy system, is changing. More capacity is needed, more flexibility is needed, innovation in tariffs is needed, routes to market are needed, decarbonised heat sources are needed, and much, much more. Significant investment is needed, and risk needs to be rewarded. Those who argue otherwise and rail against profit, are unfortunately missing the point, and could plunge us into darkness. We welcome Centrica’s outlining of the growth opportunities from the energy transition, but we would welcome more visibility on how Centrica envisages this translating into earnings growth, and value accretion. A material uplift in our estimate for EMT profitability drives a c.36% increase in our FY22E EPS to 18p/share, with negligible changes to FY23E and FY24E (Figure 1). We suggest that consensus needs to move up for FY22E. Higher values of upstream (nuclear, E&P) and EMT more than offset a lower valuation for BG Services (Figure 4), and see our target price move up to 160p/share. We look through the noise and disproportionate scrutiny. BUY.
This week has seen a great deal of media attention on a price cap estimate for January in excess of £3,800. Our updated estimates are not at these levels, but have moved upwards from our 21st July estimates. For October, we now stand at £3,409 (vs. £3,307 on 21st July), and for January we are at £3,605 (vs. £3,366). The greater movement in the January estimate is due to the fact that the observation window for the January cap (assuming Ofgem adopts quarterly updates) does not reopen until 19th August, and our January estimate is therefore highly exposed to wholesale price movements. On the other hand, there are now only 14 days left in the observation window for the October cap, and hence the range of outcomes is narrowing. A £3,400 dual-fuel bill for the typical household is fast becoming a reality. Taking into account seasonal consumption patterns, the average household looks set to be racking up energy bills of c.£390 per month over winter, a truly overwhelming amount for many. dreadful We have long advocated the need for bill support, and more importantly, targeted support, and we are pleased to see that this call has become increasingly widespread. Indeed, both candidates for Tory leader, and the next Prime Minister, have put forward measures. Rishi Sunak has U-turned on VAT, moving from “I know that some in this House have argued for a cut in VAT on energy. However, that policy would disproportionately benefit wealthier households”, to a temporary removal of VAT from energy bills. Liz Truss has promised a temporary moratorium on what she terms ‘green levies’, although, as we have pointed out before, the correct terminology is ‘policy costs’. These include mechanisms such as the Warm Home Discount, and the ECO scheme, both of benefit to those on lower incomes. Both proposals, however, fall well short of what is needed, and both are regressive. On our estimates, Rishi’s measure offers a £167 saving, and Liz’s a £152 saving, but should be viewed against an average winter cap that could be £700 higher than the £2,800 estimate that prompted the package unveiled in May, details of which have been updated today (LINK). The ‘eat or heat’ dilemma reflects a dreadful choice, and we suggest that the energy price crisis is of such magnitude that it warrants a cross-party solution, and one that is brought forward before the new Prime Minister is anointed.
Centrica released a strong set of results with material year-on-year improvements. As expected, earnings were supported by high and volatile commodity prices, in particular for E&P and nuclear. Operating profit reached £857m (+512%). More importantly, the group resumed shareholder distribution with a £1 interim dividend and a further £2 expected by the end of the year. Bullish view confirmed… also our cautiousness about windfall taxes.
We said ‘if not now, when’. It’s ‘now’ with the dividend returning Centrica has reported 1H22 results this morning. Adjusted operating profit including Norwegian E&P was £1,342m, up 412% vs. 1H21A, above our estimate of £1,314m. Excluding Norway, adjusted operating profit was £857m, up 512% vs. 1H21A, and well above our estimate of £676m. Including Norway, EPS was 11.0p, up 547% vs. 1H21A (INVe 10.2p), and excluding Norway, EPS was 10.2p, up 685% vs. 1H21A (INVe 8.5p). Divisionally, contributors of note to operating profit were British Gas Energy Supply at £98m (INVe £116m), British Gas Services & Solutions at £7m (INVe £28m), EMT at £278m (INVe £136m), and nuclear at £286m (INVe £211m). The 1H outturn of the latter two suggests that our FY estimates for each look light. As we suggested previously, it was as a case of ‘if not now, when?’ for the dividend, and Centrica has reinstated it, declaring an interim of 1.0p (INVe 0.75p). Centrica has indicated that it intends to retain its historic policy of the interim being 1/3rd of the total. The policy will be progressive, moving to 2x cover over time. The net cash position at 30th June was £316m compared to our estimate of £750m. A presentation will take place at 9:30am (LINK). Guiding up on FY EPS expectations Centrica has stated that if forward commodity prices were to stay around current levels and asset performance remains strong, then it expects FY adjusted EPS to be at, or even above the top end of the range of current sell side analyst expectations, currently 10.1p-15.0p based on the 12 forecasts published since the 10th May trading update. Energy transition investment opportunities Centrica has alluded to opportunities to invest in the energy transition with a focus on battery storage, gas-peaking plants, solar farms, hydrogen and Carbon Capture, Utilisation and Storage (CCUS).
Cost of energy crisis – more help needed. We have been very clear since last year that higher energy costs would have significant implications. As the Chancellor, Rishi Sunak in February announced a repayable rebate of £200 on electricity bills. We were clear that this wasn’t enough, denouncing it as a political conjuring trick. An enhanced package, announced in May, was greater in quantum, and importantly targeted at those with greater need. However, this came at a time when Ofgem was suggesting that the tariff cap would be around £2,800 in October. Our estimates are higher than this, with £3,307 for October and £3,366 for January (Figure 1), and last week, Ofgem’s CEO indicated an expectation that the £2,800 level looked too low. It is clear that more help is needed, particularly for lower income households. Liz Truss has promised a temporary moratorium on what she terms ‘green levies’, an amount of £152 in the current tariff cap. These policy costs are wider than support mechanisms for renewables, so to badge them as green levies is not correct. The Warm Home Discount, and the ECO scheme are component parts, and of benefit to those on lower incomes, and represent c.37% of policy costs. However, the question as to whether to remove policy costs from energy bills and fund by general taxation is very valid, in our opinion Windfall tax, buried or paused? In his speech on 26th May, Rishi Sunak hinted at the possibility of a windfall tax on electricity generation. We have been very clear that we view this as poor policy, and a move that would jeopardise much needed investment in UK electricity, at a time when an acceleration of investment is needed to address security of supply, and to move forward on the commitment to decarbonise the power sector by 2035. With Downing Street indicating last week that “we will continue to evaluate the scale of the profits and consider appropriate steps, but there’s no plans to introduce or extend to that group”, we are cautiously optimistic that common sense has prevailed, and the idea of a windfall tax dropped. The incoming PM might hold a different view, although we note press commentary (FT, 18th May) quoting Liz Truss as opposing a windfall tax: “The problem with a windfall tax is it makes it difficult to attract future investment into our country”. The FT also suggested on 28th June that Rishi Sunak was cooling on the idea of windfall tax on electricity generators, something we view as investment positive Will we have a net zero hero? In a week where the devastating consequences of global warming have been laid bare, we need a net zero hero. Rishi Sunak has committed to net zero 2050, but reversing plans set out in April’s Energy Security Strategy to bring forward more onshore wind would be a mistake, in our opinion. Liz Truss has committed to the net zero target, but has said that Britain needed to “find better ways to deliver net zero” that won’t “harm people and businesses” (Reuters, 20th July).
Change needed. With a commitment to fully decarbonise the electricity system by 2035, the electricity system of tomorrow will be vastly different to todays, and vastly different to the one that existed when the last major piece of electricity market reform took place ten years ago. REMA consultation published. The government made a commitment in the British Energy Security Strategy to undertake a review of electricity market design, with the aim of ensuring that it delivers energy security, and is affordable as the electricity sector decarbonises. On Monday, it published a consultation document “Review of Electricity Market Arrangements” (REMA). Lengthy with many options, and will take time to implement. At 130 pages, it is a lengthy document, and one that is wide ranging, putting forward many options. These options will be developed over 2022/23, moving to a full delivery plan, and implementation from the mid-2020s. Those who had hoped for material near-term changes will be disappointed, but those who had feared knee-jerk rushed changes should be cheered. Maintaining investor confidence seen as key. Reforms to marginal pricing, time-of-use of tariffs, and locational pricing, possibly for both demand and supply, will be the headline grabbers. As far as pricing is concerned, we take comfort in statements such as “…we need to maintain the confidence of investors…”. We see significant benefits in time-of-use tariffs, but consider that significant regional price differentials in end user prices will be difficult politically. Flexibility growing in importance. We have long argued that flexibility is increasingly important, and the consultation concurs: “Flexibility – the ability to shift the consumption or generation in time or location – is critical for balancing supply and demand, enabling the integration of low carbon power, heat and transport, and maintaining the stability of the system.” Replacement firm capacity needed. As the system becomes increasingly dominated by renewables, firm capacity will be pushed out of merit, challenging the economics of such capacity, leading to capacity retirements. Significant investment is needed to provide replacement firm capacity. REMA recognises this with a number of possible options. A need for low carbon ancillary services. Fossil fuel generators currently provide most ancillary services, a cohort that will contract over time. At the same time, there is an expectation that the need for ancillary services will grow. Investment in low carbon ancillary services is required, and REMA puts forward a number of options.
National Grid ESO’s Future Energy Scenarios (FES) are produced annually, and set out four credible pathways for the future of energy between now and 2050. Used widely by many stakeholders, they are an important voice in the energy sector. Four scenarios are set out, but only three deliver net zero by 2050. We focus on the three that deliver net zero, all of which see less energy demand in 2050, but significant electrification. We reiterate our view that it is no longer appropriate to think and operate in silos. Policy and regulatory developments must take the whole system into account, with markets developing along similar lines. With 2050 only 28 years away, there is a clear need for immediate implementation, and quick decisions. All three net zero scenarios model negative emissions and BECCS power is a key feature, but biomass has to be sustainable. We suggest a positive read- across to Drax. Residential consumers need to play their part. Gas heating is on the way out, more PV is likely, and a greater amount of smart appliances. We see a clear direction of travel for energy-as-a-service, but we need to see more time-of-use tariffs (TOUTs), an opportunity for the likes of Centrica and Good Energy. Improving energy efficiency is imperative. The highway is electric for cars and vans, as well as HGVs, although hydrogen has a role to play in the latter. In the industrial & commercial space, the net zero scenarios see the end of gas, with a trade-off between electricity and hydrogen. This points to an uncertain future for gas networks. A clear role for hydrogen in hard-to-abate sectors, but uncertainties as to how prominent it will be in heating. More renewables, more interconnection, and more storage are three clear directions of travel. Flexibility is essential and will take many forms, from hydrogen storage, pumped storage (Drax, SSE exposed), electrolysis, battery storage, demand side response, V2G, etc.. Appropriate policies and price signals via a demand side strategy are needed.
Much has been said about the likely level of the energy price cap for October and January, and continued elevated wholesale prices have pushed up our estimates yet again. We now stand at £3,285 for October, and £3,359 for January. There are only 28 days left in the observation window for October, albeit weighted with a 15% uplift, but as time ticks by, the range of outcomes for October is narrowing. With the second part of the observation window for January commencing on 19th August, January cap estimates will be more volatile. Less is said about how consumption patterns vary over the year, and what that means for the average household. Gas use in particular is highly seasonal, and Ofgem’s tariff cap methodology suggests that c.76% of annual gas consumption occurs in the winter (October – March) period. For electricity, the figure is lower at c.57%. Our analysis suggests that should our tariff cap estimates be correct, the average household will face energy bills of £1,007 for Q422, and £1,194 for Q123. This is equivalent to c.£367 per month over the winter period, a truly devastating level for many. We have spoken in the past about ‘heat or eat’. The situation is getting worse, not better, and with our price cap estimates now over £500 more than the £2,800 level that forced the ex-Chancellor to act, it is clear that more needs to be done. It is also worth reflecting on the impact of gas prices on electricity prices, and the consequent impact on the tariff cap. Our estimates suggest that electricity prices account for c.29% of the tariff cap. Weakening the link between electricity and gas prices might not be the cure that many hope for. We continue to stress the need for investment across the energy value chain, the commitment to fully decarbonise the electricity system by 2035, and the net zero 2050 target. It is essential that any changes proposed under REMA are well thought-out, and considered from a whole systems perspective. Knee-jerk changes, perhaps triggered by short-term politics, are likely to be damaging in the longer-term.
Centrica reports 1H22 results on 28th July. Our 1H22 estimates included Spirit Energy’s Norwegian assets, the sale of which was completed on 30th May. Our detailed estimates are shown in Figure 1. We look for adjusted operating profit of £1,314m, and adjusted EPS estimate of 10.2p/share, and net cash of £750m. We understand that Centrica will present a set of numbers that include Norway, and a set of numbers that exclude Norway. Excluding Norway, our 1H22 estimate for adjusted operating profit is £676m, and our adjusted EPS estimate is 8.5p/share. FY performance is subject to a number of uncertainties, including weather, the timing of cost recovery through the tariff cap, bad debt risk, and the challenges in the service business. With high power prices, if Centrica delivers £200m+ in nuclear in 1H, we suggest that our £302m FY forecast looks hugely cautious, while the positive noises made in the 10th May trading statement regarding EMT’s performance may also render us overly prudent for this activity. The reinstatement of the dividend is a hotly debated topic and, notwithstanding the fact that the triennial pension negotiations are still ongoing, and the broader political backdrop, we believe it is very much a case of ‘if not now, when’ as far as the dividend is concerned. We forecast a 0.75p interim, 30% of our FY estimate of 2.5p. We also look for Centrica to set out its business priorities and financial framework. The energy transition offers a host of investment opportunities, and a number of these will clearly appeal to Centrica. With this in mind, we think that a near-term return of capital is unlikely.
BEIS has announced the results of CfD Allocation Round 4 (AR4). Unlike the previous round, there were three pots. Pot 1 contained Onshore Wind (>5MW), Solar Photovoltaic (PV) (>5MW), Energy from Waste with CHP, Hydro (>5MW and <50MW), Landfill Gas and Sewage Gas. This compares to a budget of £10m (2011/12 prices) in each of the two delivery years, and a 5,000MW cap, inclusive of 3,500MW caps for each of Onshore Wind and Solar PV. 251MW of Solar PV capacity has cleared for delivery year 2023/24 at a price of £45.99/MWh, 1,988MW of capacity (Solar PV/EfW) has cleared for delivery year 2024/25 at a price of £45.99/MWh, and 888MW of Onshore Wind capacity has cleared for delivery year 2024/25 at a price of £42.47/MWh all in 2011/12 prices. 888MW of Onshore Wind, and 2,209MW of Solar PV cleared in total. Pot 2 contained ACT, AD (>5MW), Dedicated Biomass with CHP, Floating Offshore Wind, Geothermal, Remote Island Wind (>5MW), Tidal Stream, Wave. This compares to a budget of £75m (2011/12 prices) in each of the two delivery years, inclusive of £24m and £20m minima in each year for Floating Offshore Wind and Tidal Stream respectively. 6MW of Tidal Stream capacity has cleared for delivery year 2025/26 at a price of £178.54/MWh, 35MW of Tidal Stream capacity has cleared for delivery year 2026/27 at a price of £178.54/MWh, 32MW of Floating Offshore Wind capacity has cleared for delivery year 2026/27 at a price of £87.30/MWh, and 598MW of Remote Island Wind capacity has cleared for delivery year 2026/27 at a price of £46.39/MWh, all in 2011/12 prices. 32MW of Floating Offshore Wind, and 41MW of Tidal Stream cleared, including 28MW at MeyGen (Simec Atlantis). 220MW at SSE’s Viking project (Remote Island Wind) also cleared. Pot 3 was reserved for Offshore Wind, with a £200m (2011/12 prices) budget in each year. 6,994MW of capacity cleared for delivery year 2026/27 at a price of £37.35/MWh, in 2011/12 prices. This is a new record low for offshore wind in GB. In the previous round (AR3) concluded in September 2019, 5,775MW cleared. Offshore wind was the dominant technology with 5,466MW, with 2,612MW at £39.65/MWh (2011/12 prices) for delivery year 2023/24, and 2,854MW at £41.611/MWh (2011/12 prices) for delivery year 2024/25. With the same prices, Remote Island Wind saw 226MW (2023/24), and 50MW (2024/25), with Advanced Conversion Technologies at 28MW (2023/24), and 6MW (2024/25).
Draft Determinations – Ofgem has published RIIO-2 draft determinations (DD) for electricity distribution (ED) this morning, and will host a presentation this afternoon. There is a forest of paper to work through, a process that will take a while, but we set out an initial high-level view below. Totex – as expected, baseline totex has moved up. For NG, the DD proposes £5.6bn, slightly below our modelled assumption of £5.9bn, while for SSE the DD proposes £3.3bn, below our modelled assumption of £3.6bn. We suggest that this could impact by c.6p on our NG sum-of-the-parts, and by c.9p on our SSE sum-of-the-parts. Allowed returns – proposed allowed returns have moved downwards vs. RIIO-ED1, with the WACC at 3.26% CPIH real (3.29% for three DNOs incl. WPD’s South Wales). This compares to 3.04% RPI real for SSE in FY23, and 2.49% RPI real for the fast-tracked WPD (NG) based on the final year of RIIO-ED1 (22/23). The returns are based on April data, and rolling forward to last Friday would have been 12bp higher. Allowed return on equity – the proposed allowed return on equity at 60% gearing is 4.75% (vs.6.0% RPI real in RIIO-ED1 for SSE, 6.4% RPI real for the fast tracked WPD (NG)). There is no outperformance wedge. Returns above consensus – Ofgem-collated consensus published earlier this week pointed to a range for the allowed return on equity of 4.05%-4.91%, with a mid-point of 4.48% and an average of 4.66%. In today’s communication, Ofgem now refers to a mean of 4.61% and median of 4.75%. If we adjust our estimate for Ofgem’s risk free rate of -0.74%, we would be in line with Ofgem’s DD position. The range for the allowed return was 2.34%-3.30%, with a midpoint of 2.82%, and an average of 2.98%. In the round, no major impact – We are at the high end of the cost of equity range at 4.91%, but with an allowed return of 3.01%, broadly in line with the consensus average. The allowed return proposed by Ofgem suggests a minor positive sensitivity to our valuations for both NG and SSE, by c.3p and c.8p respectively. Together with the aforementioned totex impact, our initial reaction is that taken in the round, there is little valuation impact. National Grid response – “We are working through the detail of these draft determinations, in particular the proposed reduction in totex across each operating company. As we move towards final determinations, we will work hard with Ofgem to ensure we agree a price control that meets the outcomes our customers have asked of us, including resilient and reliable networks, as well as enabling the transition to net zero.” SSE response – “Ofgem's initial determination is tough and stretching…”, “SSEN Distribution also notes the proposed allowed cost of capital which it will continue to review against the context of prevailing market conditions.”
Ofgem is proposing that customer credit balances and RO payments are protected, so they are available to the customers’ new supplier if and when a supplier fails. Ofgem’s view is that this will reduce the mutualisation costs directly associated with credit balances and RO payments, and mean that suppliers do not have access to free, risk-free working capital that incentivises excessive risk and risky business models. Ofgem is proposing that suppliers insure or otherwise protect an amount of money using an ‘Approved Protection Mechanism’, acknowledging that some of these mechanisms protect an amount equivalent to consumer credit balances, rather than formally ring-fencing them. For the RO, Ofgem proposes a policy that requires suppliers either to ring-fence or otherwise protect funds equivalent to their liability under the RO or, alternatively, to discharge (partially or in full) their obligation to protect funds by demonstrating that they hold ROCs in their account on the Register. For both of the above, Ofgem is proposing that suppliers use measures selected from a ‘menu’ of mechanisms, these being trust accounts, escrow accounts, third party guarantees, parent company guarantees, or standby letters of credit. There are references in the consultation to there being additional costs in providing such protection, more so for smaller suppliers. Ofgem has set out options for preserving the value of an insolvent supplier’s hedge for the benefit of their customers. The aim is to reduce mutualised costs following a supplier’s failure and/or to ensure that owners of failed energy supply companies cannot extract value from hedges at the expense of future bill payers in instances of insolvency, or winding-up. In respect of capital adequacy, Ofgem’s view is that more specific requirements and a greater level of regulatory oversight will be needed to increase supplier resilience and incentivise more robust risk management. Ofgem’s current thinking is that suppliers should be expected to maintain a minimum capital buffer, with the possibility of additional, bespoke capital requirements for higher risk suppliers that do not take appropriate steps to manage risk. An initial cost associated with raising capital, if necessary, is anticipated, and one which likely will be borne by consumers, but Ofgem’s view is that in the long run, financial resilience measures will result in lower costs of capital overall for suppliers due to better creditworthiness, together with fewer failures and associated mutualisation costs. We have also taken this opportunity to update our tariff cap estimates for the October 2022, and January 2023 quarters, with these now at £2,986 and £2,904, respectively. The spectre of a £3,000 bill looms large.
Earlier today, the Chancellor outlined a temporary new Energy Profits levy on oil and gas companies, albeit with an investment allowance built in. The levy will be charged at 25%, and will be phased out if oil and gas prices return to more normal levels. The legislation will include a sunset clause, effective end December 2025. The Levy does not apply to the electricity generation sector, with HMT’s statement stating that “The Levy does not apply to the electricity generation sector – where extraordinary profits are also being made due to the impact that rising gas prices have on the price paid for electricity in the UK market.” As set out in the Energy Security Strategy, the government is consulting with the power generation sector and investors to drive forward energy market reforms and ensure that the price paid for electricity is more reflective of the costs of production. The Chancellor announced today that “the Treasury will urgently evaluate the scale of these extraordinary profits and the appropriate steps to take”. The above brings little clarity to the generation sector, something we suggest is detrimental to the pathway to net zero, arguably raising the cost of deploying capital in GB. We acknowledge the investment incentives offered to the oil & gas sector, but even if these are offered to the generation sector, the glacial pace of the planning process would point to final investment decisions for many projects being someway off, and potentially not eligible for relief if a mechanism with a sunset clause is imposed on the generation sector. We also see significant difficulties in defining excess profitability as wholesale prices have been driven by more than gas prices, with the implications of asset retirements, the carbon price, and events on the continent all contributing. We suggest that hedging would need to be taken into account, and it is also possible to argue that thermal assets have also benefitted from the volatility which high gas prices have brought to the wholesale market. Designing a mechanism that is workable, fair and proportionate will be extremely difficult, and most likely be subject to legal challenge if implemented. We have been suggesting for many months that more needed to be done for consumers, and this needed to be distributionally fair. Finally we have action, but the possibility of a windfall tax on generation is something we firmly believe is a negative step for the pathway to net zero, and if implemented will cost consumers through higher returns being required for investment. We hope that common sense will prevail.
Hitherto, the windfall tax narrative appeared to be directed at oil and gas companies, but the FT carries an article suggesting that Rishi Sunak has ordered officials to draw up plans for a possible windfall tax on electricity generators. We have made it clear since before Christmas that there is a cost of energy crisis: “…with implications for discretionary spend, inflation, and fuel poverty. An increase of this magnitude is likely to have political implications”, and we have previously expressed disappointment at the level of government intervention so far. There are huge investment needs in electricity (offshore wind, nuclear, networks, pumped storage, BECCS), as well as hydrogen storage. Other countries face similar needs, so there is global competition for capital, and if the perception of risk goes up in the UK, then return requirements might too, ultimately to the detriment of consumers. Some of the areas requiring investment in the UK need remuneration frameworks (BECCS CfD, pumped storage cap and floor), and the government should be pushing hard to get these in place to unlock investment. At a simple level, generation plant that has zero or negligible marginal cost, or a cost that isn’t exposed to global commodity markets, and which isn’t under a ‘fixed’ price regime, is the type of plant that benefits from high prices. This includes nuclear, plant under the RO (wind, solar, biomass, landfill gas, hydro), merchant renewables, EfWs, etc. CfD generation doesn’t benefit, save for the inflation benefits of index-linked contracts. Companies will also have hedged forward to varying degrees, so measuring perceived excess profitability is not as simple as comparing the outturn wholesale prices less some arbitrary view of a more normalised level. SSE has big investment ambition, Drax does, EDF does, RWE does, and so on, and looking at the investments they wish to make, and as suggested above, you could argue that the hurdles that need to be jumped are planning, remuneration frameworks, etc. Government should be focussing on removing these barriers, not building new ones Given these huge investment needs, a windfall tax on generation could possibly jeopardise much needed investment, and could see higher returns demanded. Longer-term, neither would be good for the consumer or the net zero pathway. Cost of energy crisis? Yes. Insufficient action so far by government? Yes. A windfall tax on generators the right answer? No. Be careful what you wish for.
CNA GLO DRX GOOD NG/ SSE
On Monday, Ofgem published a number of price cap documents, including a consultation to move to quarterly updates, and to extend the MSC to March ‘23. Ofgem also published a number of draft models that form part of the suite of price cap models. We have used these to set out an estimate for the cap level in the October 2022 - December 2022 and January 2023 - March 2023 periods (Figure 1), as opposed to the previous October 2022 - March 2023 (Figure 2). Our newly presented estimates include an amount for unexpected SVT demand (we assume 50% of the £42 dual-fuel estimate in the consultation), and backwardation costs of £40. The latter is towards the lower end of Ofgem observations, although we are also cognisant of the fact that Ofgem has indicated Q123 could see higher backwardation costs. Adjusting our previous estimate by adding the aggregate £62 of these two components would imply a cap level of £2,827, slightly above the simple average of the Q422 and Q123 periods in our new estimate. On an underlying basis, this suggests a marginal benefit to consumers over the upcoming winter period of a shift to quarterly updates. We are aware that part of what Ofgem set out has attracted some criticism, some of it quite robust. Indeed, we have previously been critical of the lack of nimbleness in the price cap methodology, with the view that light touch oversight of the supply market has burdened consumers with the cost of failure. In this instance, ire directed at Ofgem strikes us as unfair. Ofgem sets the cap with reference to the Domestic Gas and Electricity (Tariff Cap) Act 2018, an Act brought in by a Conservative government, albeit Labour, in opposition, had previously proposed a cap if it won the 2015 general election. The Act requires Ofgem to have regard to four matters, with an objective of protecting current and future default tariff customers. Ofgem’s view is that this means prices reflect underlying efficient costs. In our view, this does not equate to the cap being the cheapest source of electricity and gas, although in the current environment, for many it is. We are of the opinion that recognising efficient costs is both appropriate and fair. Ofgem is also very clear on the need for innovation on the road to net zero, and that the market needs to be suitably attractive: “If the risks of participating in the market are too high, it is unlikely that there will be the investment needed for the net zero transition, in turn leading to higher costs in the future”. We see this as supportive of our view that the energy supply landscape is improved. Our estimates show that the cost of energy crisis shows little sign of abating. The Government has not done enough to help, in our view, and needs to act quickly. In the longer-term, reducing exposure to commodity prices via renewables build-out, and perhaps, wholesale market reform strike us as possible solutions.
CNA’s recent trading statement highlighted a strong performance in UK gas, nuclear, and Energy Marketing & Trading (EM&T), with ongoing challenges in British Gas Services & Solutions. British Gas Energy remains exposed to the impact of the weather, commodity price risk, bad debt risk, and the timing of recovery of unexpected costs via the tariff cap. Ofgem published a number of consultations yesterday relating to the tariff cap, with a very clear message regarding the recovery of efficiently incurred costs: “…unless changes are made to the methodology and suppliers are able to recover the efficient costs they face in providing this tariff to customers”. The consultation documents make specific reference to unexpected SVT costs, and backwardation costs, but our view is that bad debt costs above a reasonable level will ultimately be recoverable, with Ofgem aiming to address this “in separate, ongoing, consultations”. Ofgem is also very clear on the need for innovation on the road to net zero, and that the market needs to be suitably attractive: “If the risks of participating in the market are too high, it is unlikely that there will be the investment needed for the net zero transition, in turn leading to higher costs in the future”. We see this as supportive of our view that the energy supply landscape is improved. Updated estimates see EPS rise by 22%/33%/19% (FY22/23/24E). A higher contribution from upstream and EM&T is offset in part by a trimming of British Gas Services, and timing in British Gas Energy. Ex Norway E&P, our FY22E EPS is 11.5p/share. We maintain our 2.5p FY22E dividend and, despite the political backdrop, suggest that CNA should not kick the can down the road. Target price up to 140p/share. CNA’s high profile brings disproportionate scrutiny, but we see substantial upside on offer. BUY.
On Friday, Ofgem released the independent review that it had commissioned into the root causes of the recent supplier failures, and how regulation of the industry played a part. Parts of the report make for uncomfortable reading for Ofgem and its Board, but in many respects, the report merely tells us what we already knew, or suspected. In November 2020, we wrote “It is also possible to argue that the SOLR regime, whilst protecting consumer’s credit balances, created moral hazard, exacerbated by Ofgem actively promoting switching by highlighting marked differentials in pricing across the market”, and comments in the report are consistent with this viewpoint. “…we find that Ofgem’s approach to regulating the market created the opportunity for suppliers to enter the market and grow to a considerable scale while committing minimal levels of their own equity capital. This was justified largely on the grounds of increasing the degree of competition in the market, and created the opportunity for prospective suppliers to enter the market on the basis of a ‘free bet’.” “In the pursuit of higher levels of competition, Ofgem did not seek evidence on trade-offs on an ongoing basis… Nor did Ofgem sufficiently test whether the economic incentives at the point of entry and exit were aligned with the protection of the consumer interest, through promoting effective competition. For example, Ofgem did not fully analyse systemic risks that might arise.” The nimbleness of the price cap is discussed, as are the business models of new entrants which exposed them to supply or demand shocks, risks exacerbated by a lack of financial strength, poor liquidity, over-reliance on customer credit balances, and non-existent/low levels of hedging. Assessing Ofgem’s role and effectiveness in monitoring the market, Oxera comment: “Overall, Ofgem’s approach to assessing financial resilience in the sector has been reactive rather than proactive. Ofgem did identify risks to the sector that could have been addressed with earlier intervention, but in some cases was slow to design new policies.” Six overarching recommendations are made, and from these we highlight that policy trade-offs should be evidence-based taking into account consumer interest and the competitive landscape, as well as clear suggestions that communication and information flows need to be improved. Ofgem’s Board has fully accepted the review’s findings, and has stated it is: “…focused on ensuring that action is taken to learn lessons and strengthen the regulatory regime going forward, building on work already in hand.” It remains to be seen what changes, both regulatory and organisational will ensue.
In November 2020, we wrote: “In our view, the low barriers to entry and level of regulatory oversight were contributory factors to the growth in the number of suppliers in the market, and the subsequent failure of many which found out that operating a supply business was a complex task. It is also possible to argue that the SOLR regime, whilst protecting consumer’s credit balances, created moral hazard, exacerbated by Ofgem actively promoting switching by highlighting marked differentials in pricing across the market.” Skip forward to April 2022, and in an open letter, Ofgem writes: “On failure, customer credit balances and payments due under the RO scheme are effectively insured through mutualisation, and so a moral hazard (Investec highlight) exists as the failed supplier is not exposed to this downside risk.” Continuing: “…this moral hazard (Investec highlight) can give rise to very poor outcomes for consumers and systemic risks to the retail supply market, even in circumstances where the majority of suppliers do not rely on such unsustainable business models.” Against this backdrop, Ofgem is considering introducing a principle that suppliers should not use customer credit balances for working capital at all. Of the options considered: “Our preference, in order to ensure that a supplier is able to pay its customer credit balances on failure and therefore fix the moral hazard (Investec highlight) that exists, is option (ii), i.e. that suppliers should protect an amount equal to gross credit balances net of unbilled consumption.” Ofgem’s currently favoured approach to implementation is to use “a methodology, based on gross credit balances net of unbilled consumption, to calculate an amount to be protected each month or each quarter.” Ofgem appears open to the protection mechanisms that could be used, with escrow accounts, trust accounts, letters of credit, 3rd party guarantees, and parent company guarantees highlighted, albeit that its thinking is likely to develop on the pathway to statutory consultation. Ofgem has recognised that the new rules, if enacted, could require some suppliers to strengthen balance sheets, albeit with a transition period: “To the extent that any of these proposals result in the need to re-capitalise efficiently run suppliers, we are open to allowing a suitable transition period that aligns with any necessary reform to the price cap.” In a separate consultation, Ofgem is consulting on amending the methodology for setting the Contract for Difference allowance. Ofgem’s minded to position is to replace the LCCC published Interim Levy Rate with an expected levy payment based payment based on LCCC data from the October tariff cap reset onwards. This could be a negative number, and Ofgem is suggesting that this could be a benefit of £12.51. Our approach to estimating the tariff cap (Figure 1) already includes an adjustment of this ilk, albeit at a higher level (c.£31).
Last December we suggested the April 2021 tariff cap could reach £2,000, and that “...this will still come as a shock to many, with implications for discretionary spend, inflation, and fuel poverty. An increase of this magnitude is likely to have political implications.” In February, when the government outlined a number of measures to address the cost of living crisis, we suggested that “…a repayable £200 rebate on electricity bills is arguably a political conjuring trick.” With our October tariff cap estimate still in the region of c.£2,800, we have been consistent in our view that this will be devastating for UK households, with increasing numbers of them facing the unacceptable choice of ‘eat or heat’ in the winter season. In our view, there has been missed opportunity after missed opportunity to go further in addressing the crippling energy costs, with it now a fully blown political crisis. We would not be surprised to see casualties. Government has now consulted on the £200 rebate, or to give it its correct title, the “Energy Bills Support Scheme”. However, we prefer to view this as the mechanics of not enough. We remain firmly of the view that more needs to be done, both in respect of financial quantum, and distributional fairness. As far as the mechanics are concerned, the proposals will see suppliers funded by government to provide a £200 reduction to domestic electricity customers’ bills as soon as possible from October 2022 (Figure 1). BEIS proposes using 23:59 GMT on 3 October 2022 to establish which supplier should provide the reduction to which customer. To recover the £200, the government intends to introduce a new levy to recover the full nominal amount paid out by government from all domestic electricity customers over a five-year period, from financial year 2023/24 to 2027/28. Recovery via both an energy supplier approach and a network charges approach are considered. Following engagement with suppliers and DNOs, BEIS considers that obliging DNOs to recoup the levy through network charges (Figure 2) represents the least burdensome approach for achieving this, as limited new processes will have to be created and managed. The levy rate will be calculated as £40 (the amount to be collected from meter point per year) divided by the number of days in the year to give a pence per meter day rate. The £200 grant is not subject to VAT, but the levy amount will be adjusted down to allow for the VAT on top. BEIS expects that the reasonable costs of delivering the scheme will be incorporated into any future default tariff cap levels set by Ofgem.
CNA GLO DRX GOOD NG/ SAE SSE
Nuclear: A significant acceleration of nuclear, with an ambition of up to 24GW by 2050, representing up c.25% of projected electricity demand. Subject to technology readiness from industry, Small Modular Reactors will form a key part of the nuclear project pipeline. A new government body, Great British Nuclear, will be set up immediately to bring forward new projects, backed by substantial funding, with a £120m Future Nuclear Enabling Fund to be launched this month. We acknowledge that nuclear is capable of providing clean baseload power, but it is an industry with a legacy of cost overruns and delays, while an RAB based remuneration framework will add to customer bills before electrons are produced. We are far from convinced. Offshore wind: Ambition of up to 50GW by 2030, a 10GW increase from the current 40GW target, of which up to 5GW could come from floating offshore wind in deeper seas. This will be underpinned by new planning reforms to cut the approval times for new offshore wind farms from four years to one year, and an overall streamlining that will radically reduce the time it takes for new projects to reach construction stages. We view the increased ambition as positive for the likes of SSE (renewables, transmission) and National Grid (transmission). Onshore wind: Partnerships with a limited number of supportive communities who wish to host new onshore wind infrastructure in return for guaranteed lower energy bills. In our view, this is a halfway house, a missed opportunity, showing a distinct lack of ambition, and it arguably discriminates against those living in large cities. Solar: The rules for solar projects will be consulted on, with the possibility of capacity growing by up to five times by 2035, from the current 14GW. Increased solar could have positive implications for distribution companies (National Grid, SSE), and suppliers (Centrica, Good Energy). Heat pump manufacturing: A Heat Pump Investment Accelerator Competition will be run this year, worth up to £30m to make British heat pumps. Decarbonisation of heat is imperative, and we view heat pumps as key to this, yet what we have seen so far leaves us begging the question, “is that it?”, with no targets to radically improve energy efficiency of the housing stock. Oil and gas: Seen as transition fuels, a licensing round for new North Sea oil and gas projects is planned to launch in the autumn, with a new taskforce providing bespoke support to new developments. Hydrogen: An aim to double the existing ambition to up to 10GW of low carbon hydrogen production capacity by 2030, with at least half coming from green hydrogen and utilising excess offshore wind power to bring down costs. Industry is seen as the principal user, but power, transport and potentially heat also mentioned.
Last July, BEIS and Ofgem launched the Future System Operator (FSO) consultation, setting out proposals for an expert, impartial body with responsibilities across both the electricity and gas systems to drive progress towards net zero while maintaining energy security and minimising costs for consumers. In a response document published today, a commitment has been set out to proceed with the creation of the FSO as an expert, impartial body in public ownership, making it truly independent from asset ownership and commercial interests, but also from day-to-day operational ownership of government. Creating the FSO will require primary legislation, as well as secondary legislation, new and updated licencing arrangements, as well as amendments to industry codes. All these will take time. The FSO will take on all the main existing roles and responsibilities of NGESO and the longer-term planning, forecasting, and market strategy functions in respect of gas. This recognises the interactions between electricity and gas in the energy system, and brings us a little closer to whole systems thinking. The FSO is intended to have a statutory advisory duty to provide expert advice, analysis, and information to Ofgem and government, and an increasingly significant role in shaping the energy system and driving forward competition. We suggest that this will build on the forward-looking work we have seen from the ESO over the past couple of years, with independence from NG being a facilitator of expanding this role. The future could see a further expansion of the FSO’s role to include DSO, data, heat, transport, hydrogen, and CCUS. Government will set out its policy package through regular iterations of its energy plan, which in turn will be subject to scrutiny by a new panel of independent energy experts. There will be a phased approach to implementation of the FSO, with a need for primary legislation, secondary legislation, licensing and code amendments, discussions with NG, NGESO, and NGG, as well as engagement with the wider energy industry. Transactions between government and NG, and any other relevant parties (noting the NGG sale recently announced) will be required, with the parties being appropriately compensated for the elements of their businesses that are transferred into the FSO. There is a reasonably long timeline as both primary and secondary legislation. It is expected that the FSO could be established by, or in 2024. NG’s ownership of the ESO has been open for debate for some time, even after separation of the activity within the group on 1st April 2019. Kwasi Kwarteng (now Secretary of State for BEIS) questioned NG’s ownership in September 2019, and we are not surprised to see independence as the chosen route.
On 16th February, Ofgem published a decision to introduce two measures: (i) a requirement for suppliers to make all tariffs available to new and existing customers; and (ii) a requirement for suppliers to pay a Market Stabilisation Charge (MSC) when acquiring new customers, triggered if prices fall significantly. These measures come into effect on 14th April on a temporary basis (to end-September 2022), in advance of enduring reforms coming in later this year. The MSC, as currently set out, will be payable by suppliers gaining new customers to suppliers losing them, but will only take effect if wholesale prices fall 30% below the indices used to set the price cap, includes a 75% de-rating factor, and a consumption weighting factor to account for seasonality in demand patterns, and hence hedging. This morning, Ofgem has decided to re-visit the MSC, via consultation, stating: “The higher and more volatile wholesale energy prices currently being observed mean that a well-managed and prudent supplier is exposed to potentially large losses if prices fall, despite the MSC. In this environment, the MSC, with its current parameters, does not appear likely to have the effect that we intended, of allowing a nominal supplier to recover a sufficient proportion of its hedging losses.” Ofgem is proposing new parameters: “We have therefore re-assessed the parameters, taking account of the consequential impact on the nominal supplier’s hedging strategy of the Indexation Guidance Letter, and propose that they should be altered to a threshold of 10-20% and a de-rating factor of 80-90%.” If adopted, these will be effective from 27th April. Our view is that Ofgem is increasingly attuned to the clear risk of significant potential losses to well hedged suppliers if wholesale prices fall quickly and markedly, from a mass reversion to fixed-term tariffs when such tariffs price below the default tariff cap. In turn, this could see suppliers hold back on hedging, which would give rise to an elevated risk if wholesale prices were to rise significantly. Consumers are already footing the bill for past regulatory shortcomings, and we welcome moves to limit the likelihood of further burdens. We also welcome the references to the investibility of the domestic energy sector. We reiterate our view that innovation is needed, and investment is more likely to be forthcoming if investors can have confidence in the retail energy market. It does appear that Ofgem now ‘gets it’, something we consider positive for the likes of Centrica and Good Energy. With the tariff cap at TDCV rising to £1,971 tomorrow, we have updated our estimate for the October cap (Figure 1), and it remains around the £3k level. The cost of energy crisis is real, the political environment febrile. Has government done enough to help? The answer is clearly no, in our view.
This week Ofgem published guidance “that, absent any other policy decisions on the cap mechanism, the price observation window would be from 1st March to 31st August for the winter period, one month later than the current observation window”. However, Ofgem has also stated: “Based on our previous guidance, prices observed from 1st February 2022 will be used to calculate the cap for period nine. We committed not to retrospectively change this guidance, so to move to a later observation period we need to make a forward-looking change to the price observation profile.” In order to facilitate the shift, Ofgem’s guidance indicates: “To delay the price observation window by one month we will apply a 50% weighting to prices observed over a two-month window, from 16th March to 19th May inclusive. Absent of any other changes, we would then resume a 100% weighting for prices observed between 20th May and 31st August inclusive.” Pending publication of the updated wholesale cost allowance model, we have made changes to our model to reflect our interpretation of the guidance. Updating for current wholesale prices (Figures 3 & 4), our tariff cap estimate using the new observation window stands at £2,841 (Figure 1). A comparison to the legacy observation window (Figure 2) shows no meaningful difference. We are also cognisant that current high wholesale prices are above CfD strike prices, resulting in payments from generators. The current tariff cap methodology floors the CfD allowance at zero, arguably penalising consumers. Ofgem will publish a consultation on CfD costs/benefits, but we suggest the October cap could see a downwards adjustment allowance. Although our latest estimate is below our previous published iteration, it still represents a c.44% increase vs. April’s level, and more than double the October 2021 cap. For those still lucky enough to be on fixed price deals, the expiry of those deals is set to be even more painful. Clearly, the cost of energy crisis and the cost of living crisis, already issues, will only get worse, with many plunged into fuel poverty and increasing numbers facing the unacceptable choice of ‘eat or heat’ in the winter season. We maintain our view that the measures hitherto put forward by the government are insufficient in quantum, and fail to address distributional fairness. Wednesday’s spring statement gives the Chancellor an opportunity to offer appropriate support to those that need it. If such support is not forthcoming, it is inconceivable that energy will not develop into a fully blown political crisis. Higher tariffs are also likely to see bad debt risks increase for suppliers and, to the extent that suppliers are unhedged, the sharp jump in wholesale prices could be a solvency risk for some. Price volatility may also see variation margin calls, a possible liquidity risk for some.
The regulatory failures of a supply market structure that encouraged moral hazard, and the burden that consumers have to bear as a consequence are clear and, should Bulb’s administrators have failed or been unable to hedge in line with the tariff cap methodology, the pain could yet get greater. Ofgem has woken up to the issue, and we view decisions already taken, and the broader direction of travel, as positive for well-capitalised incumbents, and by implication, Centrica. We reflect this in higher forecasts for British Gas’ energy supply business (Figure 5). We are absolutely convinced that energy supply has a key role in helping to deliver net zero, and the developing narrative around energy independence intensifies the need for a shift away from gas, energy efficiency, and improving the UK’s housing stock. There is a clear opportunity for British Gas Services in this respect. Management has alluded to the challenges facing the services business, and fixing this will take time, impacting both FY22 and FY23 earnings from this business line, but what is missing is a clear pathway of how Centrica will leverage its army of engineers to benefit from the net zero journey. We urge Centrica to reschedule last November’s postponed CMD, and detail the significant opportunities that we believe exist. Our earnings estimates are raised significantly across our forecast period, positioning us above consensus in all years. Ex the Norwegian E&P assets (disposal completion expected in Q2), our FY22E EPS is 9.3p/share. Our target price is raised to 130p (from 105p), reflecting higher valuations of supply (+6p), EMT (+9p), business supply (+4p), and the nuclear portfolio (+13p), offset by a lower value of services (-11p) (see Figure 4).
Centrica’s FY21 results beat expectations as the E&P subsidiary Spirit Energy benefited from surging commodity prices for oil and gas. Even if the group remains confident regarding the 2022 outlook, the current markets’ volatility enlarge the range of possible outcomes and reduce visibility. Despite the strong figures and an impressive net cash position, no dividend will be proposed for 2021. Instead, Centrica is paving the way for a dividend in respect of 2022 and possible share repurchase programmes.
Electricity (Figure 2) and gas (Figure 3) prices have risen markedly over the past couple of days for all periods captured in the commodity price component of the tariff cap calculations. This could have serious implications for the level of the default tariff cap for October, with our ‘marked to market’ estimate having risen to over £3,000 for dual-fuel at TDCV. This is based on the existing Ofgem approach that takes into account forward commodity prices in a six-month observation window that runs from 1st February to 31st July. As such, our estimate assumes that forward prices remain at current levels for five months, which in turn makes it an extremely volatile estimate as wholesale prices move, but we are already approaching a month’s worth of observed prices that are already baked in. With the April price cap factoring in electricity wholesale costs at £131/MWh and gas at 126p/therm, absent a significant drop in wholesale prices, we consider it inevitable that the October tariff cap will rise significantly from April’s £1,971 level. A significant jump in the tariff cap will exacerbate the cost of energy crisis, the cost of living crisis, and plunge many people into fuel poverty, with many facing an ‘eat or heat’ dilemma in the winter season. There will be knock-on ramifications for inflation, and for businesses exposed to energy input costs, and discretionary consumer spend. With this direction of travel, measures put forward by the government, of which the repayable £200 rebate on electricity bills is little more than a poorly disguised loan, are insufficient in quantum, and most definitely fall short of addressing distributional fairness. Energy is likely to intensify as a political crisis for the government. We suggest that a return to the drawing board is necessary to ensure support is there for those that need it, and if this means tough decisions for the Chancellor then these decisions must be made. Higher tariffs are also likely to see bad debt risks increase for suppliers and, to the extent that suppliers are unhedged, the sharp jump in wholesale prices could be a solvency risk for some. Whilst it is possible to argue that some of the criteria for an in-period price cap adjustment could be met, it is not clear that all five tests would be satisfied.
Numbers beat, no dividend Centrica has reported FY21 results this morning. Adjusted operating profit was £948m, up 112% vs. FY20A, well above our estimate of £584m, and consensus of £649m. EPS of 4.1p, up 46% vs. FY20A (INVe 3.3p, consensus 3.7p). No dividend was declared. Net cash of £660m compared to our estimate of net debt at £117m. Divisionally, the biggest contributors to operating profit were British Gas Energy Supply at £118m, below our estimate of £142m, British Gas Services & Solutions at £121m, below our estimate of £166m, and E&P at £701m, double our estimate of £346m, albeit that E&P is heavily taxed. British Gas residential customer numbers were up 5% vs. 2020, boosted by a number of SOLR appointees in 2H21. A pre-recorded presentation will be available at 8am (LINK), with a Q&A session following at 9am. Broadly positive outlook for 2022, but wide range of outcomes Centrica has suggested that the 2022 outlook is broadly positive, pointing to a strong balance sheet and leading energy procurement and risk management capabilities that it believes leave it well placed to handle the energy market crisis. However, it adds that high and volatile wholesale commodity prices and a changing regulatory environment create a wider range of outcomes than normal for 2022.
The T-4 Capacity Market auction for delivery year 2025/26 cleared yesterday at £30.59/kw/year, a record level for what is the larger and more important of the two Capacity Market auctions (Figure 1). Gas continues to dominate, with 27,632MW of awarded capacity, broadly commensurate with volumes awarded in recent years. Interconnectors represent the second largest technology with 6,966MW of awarded capacity. Nuclear continues to decline with only two Sizewell B units in receipt of contracts for delivery year 2025/26, with combined capacity of 990MW. Pumped storage was awarded contracts for 2,528MW, up from 2,072MW awarded in last year’s T-4 auction for delivery year 2024/25. New build generation was awarded 1,919MW of capacity, up from 1,736MW awarded in last year’s T-4 auction for delivery year 2024/25. There was a marked growth in the capacity awarded to battery storage, at 1,094MW, up from 252MW awarded in last year’s T-4 auction for delivery year 2024/25. Demand side response at 988MW was slightly down from 1,066MW awarded in last year’s T-4 auction for delivery year 2024/25. Centrica was awarded contracts for 229MW of capacity. Drax was awarded contracts for 586MW of capacity, but did not secure a 15-year new build contract for the Abergelli OCGT. SSE was awarded contracts for 4,146MW of capacity (including SSE’s Seabank share), but did not secure contracts for 758MW (three units), including the Medway CCGT. All capacity figures are in de-rated terms.
Centrica reports its FY21 on 24th February, with the presentation available at 8am (www.centrica.com). We look for adjusted operating profit of £584m, up c.31% yoy, but below Factset consensus of £649m. Granular detail is set out in Figure 1. Our FY21E do not assume any change in the accounting treatment of the Norwegian E&P assets following the disposal announced in December. Centrica postponed a Capital Markets Event scheduled for November, and we now look for some of the content of that event, which would have provided detail on Centrica’s longer-term strategy and financial framework, to be addressed next week. The multiple supplier failures in 2021, the acquisition of c.673k customers in the SOLR processes of 2H, changes enacted or proposed by Ofgem, and the inclusion of £59 in tariff cap periods eight and nine to cover the costs incurred by suppliers in cap period seven to cover unexpected SVT demand, backwardation, shaping and imbalance costs, lead to an improved market backdrop for Centrica, and other well capitalised suppliers. Centrica has previously indicated that it intends to recommence dividends when it is prudent to do so, and we argue that despite wholesale price volatility, financially Centrica should be in a place to pay a dividend, and our estimates assume a 2p/share final dividend. Politically it might be harder to do so given the cost of living crisis, and we might not see a resumption at this stage. More importantly, we view Ofgem as now being more attuned to the fact that the challenges of achieving net zero requires a healthy energy supply industry, that innovation is needed, and that investment is more likely to be forthcoming if investors can have confidence in the retail energy market. We consider this direction of travel as a positive for Centrica.
In December, Ofgem consulted on potential short-term interventions to address risks to consumers from market volatility, putting forward three potential interventions to enable suppliers to better manage the risks created by the current wholesale market volatility. In its decision document, published on 16th February, Ofgem has decided to introduce two measures: (i) a requirement for suppliers to make all tariffs available to new and existing customers; and (ii) a requirement for suppliers to pay a Market Stabilisation Charge (MSC) when acquiring new customers, triggered if prices fall significantly. These measures will come into effect on 13th April on a temporary basis (to end of Sep 2022), in advance of enduring reforms coming in later this year. Without intervention there is a clear risk of significant potential losses to well hedged suppliers if wholesale prices fall quickly and markedly, from a mass reversion to fixed-term tariffs when such tariffs price below the default tariff cap. In turn, this could see suppliers hold back on hedging, which would give rise to an elevated risk if wholesale prices were to rise significantly. Having previously inhabited a world of switching for switching’s sake, and presided over a framework that encouraged moral hazard, a somewhat chastened Ofgem is seemingly more attuned to the fact that the challenges of achieving net zero requires a healthy energy supply industry. Innovation is needed, and investment is more likely to be forthcoming if investors can have confidence in the retail energy market. With numerous references of this ilk throughout the decision document, we are tentatively prepared to say that Ofgem now ‘gets it’, something we consider positive for the likes of Centrica and Good Energy. A requirement for suppliers to offer all their tariffs to existing as well as new customers will help to reduce the risk of unsustainable competition between suppliers, and help mitigate to some extent against major supplier financial losses leading to significant costs for consumers from disorderly supplier exits. The MSC will be payable by suppliers gaining new customers to suppliers losing them, but will only take effect if wholesale prices fall 30% below the indices used to set the price cap, includes a 75% derating factor, and a consumption weighting factor to account for seasonality in demand patterns, and hence hedging (see Figure 1). Both interventions are designed to be temporary, falling away this autumn as soon as the risks they are protecting consumers from are adequately addressed by reforms to the price cap. Nevertheless, Ofgem has reserved the ability to extend each measure through next winter if significant risks remain.
Ofgem has decided to allow suppliers to recover £59 over cap periods eight and nine, in respect of the extra costs they have incurred in cap period seven relating to unexpected SVT demand, backwardation, and shaping and imbalance costs. We included £17.50 in our cap estimate, suggesting that this could account for the majority of the difference between the announced cap level and our estimate. Ofgem is introducing the ability to amend the cap outside of its routine six-monthly cycle, to help to manage the risk of the cap allowances materially deviating from efficient costs in exceptional circumstances, albeit with a high threshold for making such an adjustment. Ofgem has published a consultation on Medium Term Changes to the Price Cap Methodology following on from its call for input in December. The consultation covers three further ways that Ofgem might reduce systemic risk in the current market. changing the cap methodology to either a quarterly update (Ofgem’s currently preferred option), a price cap contract (previously called the fixed term default contract), or strengthening the current six-monthly update with other protections. adding a backwardation allowance to allow suppliers to recover any exceptional costs of the seasonal basis risk inherent in the current cap methodology. reducing the implementation period of the cap from two months to one. Making the cap more nimble should help suppliers as pricing should be more reflective of the prevailing wholesale environment, with consumers also less likely to face significant movements in pricing. Ofgem has announced its decision on measures to strengthen its milestone assessment framework and increase scrutiny around significant commercial developments and personnel changes, and launched a consultation on proposed changes to ensure that new suppliers in particular have sustainable and resilient business models and the capacity to manage significant financial risks, without passing inappropriate risks to consumers. These measures are arguably a positive for well-capitalised incumbent suppliers with efficient cost bases, and innovative product offerings.
The energy price cap for the summer 2022 period will rise by 54% to £1,971, a record level. This is 2% above our final estimate of £1,924 (Figure 1), albeit slightly below the £1,995 estimate we published in December. The differences are largely in commodity costs, where Ofgem has indicated that the wholesale cost uplift will be adjusted. An announcement will be made at 7am tomorrow. We suggest that a higher wholesale cost adjustment is a positive for energy suppliers. Network costs include Supplier of Last Resort recovery costs of £68, broadly in line with our estimate of £72. Consumers may understandably feel aggrieved that a regulatory framework that created moral hazard, coupled with light touch monitoring, has given rise to a situation where they are hit with significant costs of supplier failure. Additional measures to be announced tomorrow will include changing licence conditions to give Ofgem the more flexibility to change the price cap level if needed in between the regular six-monthly cap updates (which could move to quarterly updates). Ofgem has indicated that it has set five tests that mean it only expects to use the power in exceptional circumstances. A consultation on further reforms to the price cap from October will published tomorrow morning. In December, Ofgem set out three options to make the price cap more robust to high and volatile wholesale energy costs while preserving as far as possible the benefits of the price cap for consumers. The consultation will include all three options, with quarterly updates Ofgem’s preferred option. The devil will be in the detail, but we have previously argued that the price cap methodology was not nimble enough, and we cautiously welcome the change. The magnitude of the increase in the tariff cap is likely to painful for many, with those currently on fixed price deals likely to see much larger percentage increases when those deals expire. For some, this could mean a ‘heat or eat’ decision, and we suggest that fuel poverty is likely to increase. We acknowledge the measures announced by the Chancellor, including a £200 rebate (albeit repayable) on electricity bills, a £150 Council Tax rebate for properties in Bands A to D, and expansion of Warm Home Discount eligibility, but it strikes us that this doesn’t go far enough to help those facing a cost of living crisis. With forward gas prices above 180p/th throughout 2022, and above the level in the April 2022 cap (Figure 3), the cap is likely to rise again in October, and based on the current methodology, to around £2,300. The cost of living of crisis shows no sign of abating, and the £200 rebate could well be swallowed up by a further increase. Being repayable, it’s arguably a political conjuring trick.
The wholesale price observation window that feeds into the tariff cap for April 2022 – September 2022 now has two weeks left to run, and the cap will be updated on 7th February. Our estimates continue to incorporate a number of simplifying assumptions, including extrapolating current wholesale prices through to end-January, £72 per dual-fuel to cover the cost of supplier failure, and £17.50 to represent the midpoint of the three possible costs outlined by Ofgem in its 19th November consultation. We continue to assume no structural changes to the tariff cap methodology, noting Ofgem's suggestion that these will not be consulted on until early 2022. With both gas (Figure 1) and electricity (Figure 2) prices having moderated since we published our £2k tariff cap estimate in December, the inclusion of a further month’s observed commodity prices, and extrapolation at a lower level, gives rise to a tariff cap of £1,907 (Figure 3) for the summer 2022 period. This is still a 49% jump vs. current levels, with likely higher increases for those currently on fixed tariffs. By way of indication, we suggest that if we use today’s forward prices to estimate the winter 2022 cap level, there would be a further increase to c.£2,100. The implications for fuel poverty, discretionary spend and inflation remain. It is clear that some political or regulatory intervention is needed, as a failure to act could spell trouble for a government already fighting many other fires. With commodity costs accounting for £480 of the increase ex VAT, scope for intervention could be somewhat limited, but we note that our assumed recovery of supplier failure costs, policy costs, and VAT account for c.£300 of our cap estimate. Despite some suggestions that some options have already been dismissed, setting VAT to zero, moving policy costs to general taxation, and spreading the recovery of supplier failure costs across multiple cap periods are potential mitigating tools that would arguably be less regressive in nature. Whatever the government elects to do, it is imperative that in engineering a solution for the here and now, it doesn’t merely defer the problem to another day, or worse still, create a new problem. Solutions have to be workable, not act as a disincentive to investment, and be consistent with the crucial part that energy has to play in delivering net zero. For suppliers, the winter months remain uncertain, although a c.£20 (c.£23 in our previous analysis) increase in the absolute level of EBIT and headroom in the cap suggested by our analysis will help from April. We maintain our view that we are moving to a more sustainable supply market, and one that will help facilitate the journey to net zero, something that should be a positive for the likes of Centrica.
CNA GLO DRX GOOD IBE IBE NG/ SAE SSE
In a consultation published earlier today, Ofgem has indicated that it expects that the tariff cap will rise ‘significantly’ in April, and that it is exploring options for reducing the impact on consumers. Although wholesale prices are the primary driver of the significant increase in the cap, paying for the price of a flawed market framework is another, with Ofgem approving £1.83bn of supplier of last resort (SoLR) claims last week. As things stand, these will be recovered through network charges (levy payments) from April, and passed through to SoLR suppliers. The implication of this is that suppliers are financing the working capital requirements of procuring the underlying commodities, until they can recover these through SoLR claim payments, while consumers will be hit to the tune of c.£69/household next year. To address both of these, the consultation proposes a ‘securitisation’ style approach, where a third-party financier ‘buys’ any and all rights the SoLR has to future levy payments. The third -party financier (or special purpose vehicle (SPV) which it creates for the purpose) then receives the SoLR Levy payments from the network licensees, instead of the SoLR. The value of those payments would be adjusted to take account of a) the decrease in SoLR working capital costs caused by the shorter payback period for the SoLR; and b) the likely increase to reflect the additional financing costs. The timing of the payments could also be altered, spreading the impact on customer bills in any one year. Not only could this ease the burden of the impending cost of living crisis, although only by c.10% of the c.£700 jump we forecast for the tariff cap in April, but it would have positive working capital implications for suppliers too.
In a letter dated 29th October, Ofgem set out proposals to speed up the supplier of last resort (SoLR) claims process, stating that “providing claims are made, decided upon and received by networks prior to the end of 2021 then payments to the SoLR should commence from April 2022”. The letter outlined a proposal for a two claim process, an initial claim and then a later “true-up” claim, with Ofgem stating that “the initial claim would include costs that a SoLR incurs and can be fully evidenced in the period immediately after appointment, in particular commodity costs”. The suggestion that the initial claim would be primarily composed of commodity costs was reinforced by Ofgem stating “to support this and mitigate the risk of overpayment, we expect the initial claim to only include costs that have actually been incurred, and so be primarily comprised of wholesale costs”. Ofgem published its decision on the proposals on 1st December, and invited SoLR appointees since 1st September to submit initial claims by 6th December. Ofgem has today published its consents for these claims, with the total amount of the initial claims totalling £1.8bn, equivalent to £851/customer of the failed suppliers (Figure 1 overleaf). We highlight Avro Energy where the initial SoLR claim is a staggering £1,175/customer. The claims will impact UK domestic energy consumers by £69/household. We previously suggested an amount of £72/household, split £49 commodity costs, £16 credit balances, and £7 Renewable Obligation Mutualisation costs. Given Ofgem’s suggestions that initial claims would largely comprise commodity costs, this suggests our previous estimate of the impact could be c.£20/household light. The impact on our tariff cap estimate of £1,995 for the next cap period is negligible as we have already included £72, but it does suggest that consumers will be paying for supplier failure beyond next year, once “true-up” claims are submitted and agreed. Ofgem’s website states that “We work to protect energy consumers, especially vulnerable people, by ensuring they are treated fairly and benefit from a cleaner, greener environment”. In our opinion, it cannot be right that consumers pay for a regime that created moral hazard, and apparent light touch oversight. We invite GEMA’s chair, and Ofgem’s CEO to explain to UK energy consumers how paying for the price of failure is fair. The energy affordability storm looks set to become a hurricane that will hit land early next year. We acknowledge the government’s call for views on retail, but our question to Kwasi Kwarteng is “what does the government intend to do to ease consumer pain today, not tomorrow?”
The wholesale price observation window that feeds into the tariff cap for April 2022 – September 2022 has 6 weeks left to run, and the cap will be updated on 7th February. We expect that the tariff cap will rise significantly, possibly to the £2,000 level for TDCV (typical domestic consumption value) consumption paying by direct debit (Figure 1). This would represent a c.56% increase on the £1,277 cap for the October 2021 – March 2022 period. Our estimates incorporate a number of simplifying assumptions, including extrapolating current wholesale prices through until end-January, £72 per dual-fuel to cover the cost of supplier failure, and £17.50 to represent the midpoint of the three possible costs outlined by Ofgem in its 19th November consultation. We have not assumed any structural changes to the tariff cap methodology, noting Ofgem’s suggestion that these will not be consulted on until early 2022. To the extent that there is a fixed price market, quotes for a London DNO/SGN GNO at TDCV have also moved up significantly since we last undertook an exercise three weeks ago (Figure 2), suggesting that staying on, or rolling onto SVTs (standard variable tariffs) will be the choice of many. Although energy price increases have been well trailed, the magnitude of the increase is still likely to be a shock to many, with implications for inflation, discretionary spend, and fuel poverty. All of these are also likely to have political implications in what is already a febrile political environment. In 2020, UK households spent £30.5bn (£18.4bn electricity, £12.1bn gas) on energy. We suggest that the incremental spend for UK households of the analysis we have outlined above will be in the region of £18bn. With commodity costs accounting for £560 of the increase ex VAT, scope for political or regulatory intervention appears somewhat limited, but we note that our assumed recovery of supplier failure costs, policy costs, and VAT account for c.£300 of our cap estimate. Setting VAT to zero, moving policy costs to general taxation, and spreading the recovery of supplier failure costs across multiple cap periods are potential mitigating tools that would arguably be less regressive in nature. For suppliers, the winter months remain uncertain, although a c.£23 increase in the absolute level of EBIT and headroom in the cap suggested by our analysis will help from April. We maintain our view that we are moving to a more sustainable supply market, and one that will help facilitate the journey to net zero, something that should be a positive for the likes of Centrica.
Retail financial resilience: There is a clear recognition that Ofgem needs to have a more comprehensive understanding of the retail market, that it needs to go further and faster than under the current rules of the road, and that it has witnessed practices that fell short of the minimum standard necessary to protect consumers. In our opinion, this suggests that the oversight of the retail market was not tough enough, and interventions by Ofgem were insufficient. We welcome the step change proposed, but it strikes us as shutting the stable door after the horse has bolted, with consumers set to foot the bill for failures to date. We view the action plan as a positive for well-capitalised suppliers with more to their commercial offerings than endeavouring to sell cheap electrons and molecules, and consider it positive for Centrica. Milestone assessments: Unsustainable practices in the supply market have been found out, and measures to oversee business models and business practices should clearly have been in place many years ago. Proposals to pause customer acquisitions at 50,000 and 200,000 consumers, if introduced, would likely support a more resilient supply market, and be a positive for suppliers already above these thresholds. Adapting the price cap: Three options to reduce volume risk for suppliers, albeit only partially in respect of two options. As we have suggested before, the commodity element of the price cap has not been nimble enough to respond to the volatility we have witnessed in the commodity markets. We believe that it is right that this element is being looked at to mitigate the risk of facing more SVT (Standard Variable Tariff) customers than expected, and vice versa. Short-term intervention: The potential measures above should reduce the likelihood of a repetition of unsustainable business models being pursued, but there is clearly a risk that if the commodity curve rolls over early next year, switching could yet expose suppliers to risk, and consequently influence hedging strategies. If this manifests itself as a reduced level of hedging, suppliers could be then be exposed to the risk of higher prices. By consulting on potential options to mitigate the impact, Ofgem has shown that is cognisant of the potential risk, even if these options are better described as contingency measures.
The Business, Energy and Industrial Strategy Committee has launched an inquiry into “energy pricing and the future of the energy market”. The inquiry “will examine the extent to which the policy and regulatory environment has contributed to the current issues affecting the energy market, the impact on consumers of rising energy prices, and the operation of the energy price cap”. The full terms of reference for the inquiry are listed below, and submissions are welcomed until the closing date of 31st January 2022: The regulatory requirements companies must meet in order to trade as a regulated entity in the retail energy market. The mandate, role and performance of Ofgem in setting regulation and supervising regulated entities. The performance of previous policies introduced to stimulate effective competition within the retail energy market, and an assessment of the impact on competition of proposed future regulatory frameworks. The functioning and performance of the ‘energy price cap’ and an assessment of its use in the future, and an assessment of the role of auto-switching. The future of Bulb and the recovery of public funds and the cost to consumers of other energy supplier failures. The role of retail market reform in the context of the UK’s net zero transition and domestic energy security requirements. The comparison of UK wholesale prices and additional costs with the wholesale prices and additional costs across Europe We have been very clear that not only should an inquiry be held, but that one was inevitable. The BEIS Committee should be praised for moving so quickly to get the ball rolling. The terms of reference, we echo some of the questions that we put to Ofgem in a recent note, and we once again reiterate our view that households should not pay for failure. We expect Ofgem to be heavily scrutinised in the inquiry, and rightfully so, given that warning signs about the risks had existed for some time. This view is shared by Citizens Advice who this morning have published a report, with the accompanying press release opening with a damning conclusion that makes for uncomfortable reading for Ofgem: “Ofgem allowed unfit and unsustainable energy companies to trade with little penalty. Despite knowing about widespread problems in the market, it failed to take meaningful action”. Winter working from home could pile more commodity price risk on domestic suppliers, but we continue to opine that the future market will be a better place.
Spirit’s Norwegian assets to be sold, Centrica share of proceeds c.£560m Headline consideration of $1,076m million (c.£800m) in cash, plus deferred commodity price linked contingent payment. The sales are on a debt free, cash free basis, with a commercial effective date of 1st January 2021, with consideration reduced by net cash flows subsequently generated by the assets. Decommissioning liabilities will be transferred to the buyers. Centrica expects to receive c.£560m, broadly in line with the implied value of the Norwegian assets in our SOP, but closing hedges will cost c.£180 pre-tax, equivalent to 3p/share of value pre-tax. Contingent consideration could partially offset this. Sval Energi AS will acquire the Norwegian oil and gas business, held by Spirit Energy Norway AS (“SEN”), excluding the Statfjord field, for $1,026m, while Equinor Energy AS and Equinor UK Limited will respectively acquire SEN’s Norwegian interests in the Statfjord field, and Spirit Energy Resources Limited’s UK interests in the Statfjord field, for $50m. Rump of Spirit (UK/NL) in run-off, energy transition investments possible The businesses to be sold contributed 52% of Spirit’s 2020 production, and 63% of its 2P reserves at 31st December 2020. The remaining Spirit business, in which Centrica holds 69%, will focus on realising value from its assets in the UK, while minimising future investment in E&P. Capex will reduce to £10-50m from 2023 onwards. That said, Spirit will seek to pursue potential energy transition investments. The Spirit shareholders agreement has been amended. Likely to dilute, but strategically sensible, eyes towards FY21 results and a financial framework The earnings impact of the proposed transaction is complicated. We understand that the assets will not be reclassified as held for sale until after the shareholder vote, and will then benefit from no depreciation until completion. It is also likely that the UK assets will be written up. We expect dilution from FY22E onwards of 10%+, excluding the impact of a write-up. Given the ongoing triennial pensions valuation, and the current commodity price backdrop, Centrica will retain the proceeds as balance sheet cash, and we look to FY21 results in February for a financial framework that should outline options for longer-term deployment. Centrica has reiterated that it intends to recommence dividends when it is prudent to do so.
Ofgem has been forced to make public court documents relating to GEMA’s application for a special administration order in respect of Bulb Energy Ltd, and to say that they make interesting reading is an understatement, in our view. Given our recent analysis (see here) suggesting that the wave of failures since the beginning of August could cost each household c.£120, including Bulb, we found Ofgem’s suggestion in the skeleton argument of 23rd November, that the failures, excluding Bulb, will amount to £200 additional cost per consumer in 2022/23, eye watering. It appears that Ofgem arrived at this view too, with an accompanying note dated 2nd December pointing out that the figure of £200 was incorrect, and replacing it with a corrected estimated range of £80-85. Big difference, but still a significant amount for consumers to shoulder. The amount of £120/household in our recent analysis was split c.£55(SOLR)/c.£65(Bulb), but only for included commodity costs and RO mutualisation. As Ofgem points out in the skeleton argument, there are multiple environmental and social schemes that suppliers have to pay into, and where shortfalls are made up by other scheme participants. There are also the costs of honouring the credit balances of the failed suppliers, to the extent they are not met by the SOLR appointee, to be factored in. Our updated analysis (Figures 1 and 2) now includes an assumption around mutualisation of credit balances, noting that level monthly payments and seasonality of consumption will likely give rise to credit balance levels well above a single month’s advance payment. Excluding Bulb, we now suggest a failure burden of £72/household, again with the possibility of additional costs from other environmental/social schemes. The timing of these, and industry levy claims, will also see additional costs likely to fall to households in 2023/24. The skeleton argument also estimates that a SOLR process for Bulb would cost in the region of £1.28bn, but this route was not chosen. This is below the £1.69bn loan set aside by the government for the special administration process, although it is possible that the final cost to households could be mitigated by Bulb’s trading, and/or sale proceeds. For now, we include £1.69bn in our analysis, suggesting that the cost of the supply market meltdown could reach c.£135/household. In our opinion, it is unfair and unjust that households have to bear the cost of supplier failures, given our misgivings around the creation of moral hazard, entry requirements, and monitoring. An inquiry appears inevitable, and will trigger change and consequences, which we believe will result in a sustainable supply market. For now, the focus should be on consumers, and whether some of the energy bill burden can be shifted elsewhere. As suggested by E.ON UK’s CEO (see The Times), supplier failure costs are one such cost. We concur.
We have commented extensively on the supply market disorder, and whilst we are convinced that the meltdown will ultimately result in a better landscape for the survivors, we still have winter to get through, and the possibility of elevated switching levels given the inevitable significant jump in the tariff cap on 1st April. Add uncertainties on industry levy payments, and mooted changes to the tariff cap, and visibility for energy supply in FY22 is somewhat limited. We lower our energy supply operating forecasts by £24m in FY21E, leaving FY22E largely unchanged, electing to factor in our view of an improved operating environment from FY23E. Higher commodity prices boost our upstream forecasts, with FY21E consolidated adjusted operating profit moving up by 3.4% (Figure 4), and FY22E by 19.5%, although a mix shift to higher taxed E&P limits the impact at the EPS level to 3.9% and 5.1% respectively. Having long merely applied a per customer value to British Gas’ supply and energy services activities, we are now of the view that a DCF approach is more appropriate to capture our view that there should be greater stability and visibility in the medium-term. This revised approach accounts for the majority of a higher valuation (Figure 7), and a target price we lift to 105p (prev. 65p). The FY21 results on 24th Feb are the next scheduled catalyst. We expect Centrica to outline the longer-term strategy and financial framework, including a dividend framework, and a progress update on the triennial pensions valuation. Ahead of this, we would not rule out news flow on the E&P sale process, given recent newswire commentary. Assuming that Norway represents c.50% of Spirit, a sale at this value could trim c.6p/share from our valuation, but would need to be viewed in the context of executing on the strategy to refocus the Group.
The meltdown in the supply market is likely to see substantial additional costs land on every GB household, hardly welcome when fuel poverty is an issue, inflation is an issue, and commodity costs look set to push energy bills up. Trying to pinpoint the cost that will fall to the industry level, or, in the case of Bulb, arise from the special administration process, is akin to attempting to nail jelly to a wall, but we suggest that the cost to purchase the commodity needs of SOLR customers is c.£600/customer (Figure 1). Add in the £1.69bn widely mentioned as being set aside by the government to allow Bulb to trade through the winter, as well as RO mutualisation costs, and we suggest that the cost to the domestic consumer is c.£3.2bn, equivalent to £120/household (Figure 2). Indeed, there could well be additional costs. In a letter to the Former COO of PFP Energy (in administration) dated 17th November 2021, Ofgem wrote: “Our licence conditions require suppliers to have adequate financial arrangements and operational capability and systems in place.” Given the number of supplier failures, we ask Ofgem whether the requirements were tough enough, and whether the level of monitoring and oversight undertaken by Ofgem was sufficient. The same letter also contained the following sentence: “Were suppliers to have made a commercial decision to adopt a hedging or risk management strategy that is not consistent with the wholesale cost allowance methodology provided for in the price cap, or not hedge at all and have not secured sufficient capital to manage scenarios where losses occurred then the risk and commercial consequences of such a decision should be borne by the supplier.” This may well be given the case, given supplier failure, yet there is likely to be considerable cost to every household in the land to pick up the pieces of failure. We ask Ofgem whether it is right that consumers ultimately bear this price, and whether the system as structured created moral hazard. We now have a considerably smaller pool of suppliers, and we continue to argue that this should ultimately lead to a stronger supply market, hopefully supported by a regulatory backdrop that drops an obsession with switching for switching’s sake, and is supportive of the role that suppliers need to play in facilitating the journey to net zero. In the meanwhile, it appears that not all of the remaining suppliers are prepared to take on board new customers (Figure 3). Yet, Supplier Licence Condition 22.2 of the electricity supply licence states: “Within a reasonable period of time after receiving a request from a Domestic Customer for a supply of electricity to Domestic Premises, the licensee must offer to enter into a Domestic Supply Contract with that customer.” We ask Ofgem whether licenced suppliers not offering tariffs are compliant with the supply licence, and if not, what action will be taken.
Bulb has issued a statement indicating that it has accepted being put into special administration “We’ve made the difficult decision to support Bulb being placed into special administration. This process is designed to protect Bulb members, ensuring there’s no change to your supply and your credit balance is protected.” Energy supply company administration is intended as a backstop to the Supplier of Last Resort process, and is to ensure that if a large gas or electricity supply company is in financial difficulty, arrangements are in place to allow the company to continue operating until it is either rescued, sold, or its customers transferred to other suppliers. The aim is to reduce the risk of financial failure spreading across the energy market, to maintain market stability, and therefore to protect consumers. It has not been used before. Bulb’s failure takes the number of customers impacted by supplier failure to an astounding c.3.8m since the beginning of August, c.13% of the market. We have long commented on various unsustainable business models, but the pace at which the supply market has melted down has surprised us. An energy administrator will be appointed, and will be under a duty to ensure that energy continues to be supplied at the lowest cost that it is reasonably practicable to incur, and to conclude the energy supply company administration as quickly and as efficiently as is reasonably practicable. The energy administrator must first seek to rescue the company, and only if that is not possible can the energy administrator seek to sell the company as a going concern, and then only if this is not possible can the energy administrator transfer the assets to more than one company. The impact assessment (IA) that accompanied the 2013 consultation on energy supply company administration suggests the possibility of government funding to facilitate the continuation of activities, with an intention that any funding provided by the government will be recovered from the company if rescued, or its successor(s) if sold. If not all the loans can be repaid, the IA indicates that the Secretary of State can allow licence modification to recover the shortfall. The financial impact of failure on consumers looks set to grow ever larger. Ofgem analysis in last week’s consultations suggests a £700 cost per unhedged customer supplied at the tariff cap. We suggest this could point to an out-of-the money commodity price exposure of £1.45bn for the 2,079k SOLR customers since the beginning of August. The RO shortfall for 2020/21 is £277m, there will most likely be a RO shortfall for 2021/22, and Bulb’s failure could well see the need for further recoveries. It is entirely reasonable to suggest that tab that domestic consumers will have to pick up will be above £2bn, or £75/dual-fuel customer. It is not hard to see why consumers might be hugely aggrieved.
Ofgem indicated in late October that it would consult on whether the existing mechanisms in the price cap methodology that allow suppliers to recover uncertain costs should be adjusted. Today, Ofgem has published five consultations to address some of the challenges. Ofgem’s initial view is that there are material costs, risks and uncertainties facing suppliers that are not appropriately accounted for within the existing cap methodology due to increased wholesale prices, and that its minded to position is to introduce an upward revision to the wholesale additional risk allowance as an interim solution. An initial estimate is that the impact of higher costs faced by suppliers could be in the range of £10-25 per customer per year at TDCV. The estimate includes higher shaping costs, higher customer numbers on SVTs, and lower CfD costs. It also accommodates an Ofgem view that elevated levels of customers defaulting from FTCs to SVTs should have in part been foreseen, and hedging strategies adapted. Any prospective adjustment will be an interim solution, with the decision reviewed no later than 12 months after its implementation. Ofgem is proposing to modify the supply licence to allow it to amend the methodologies that set the allowances under the cap, and recalculate the cap level within a cap period in exceptional circumstances. It is clear that such adjustments would not replace the need for suppliers to manage risk proactively, with Ofgem specifically mentioning wholesale costs for suppliers who had not effectively hedged their expected demand. This would not be a get out of jail free card for suppliers who haven’t managed risk. The consultations close on 17th December, with a decision expected by February 2022. Ofgem will also consult shortly on possible broader reforms to the price cap as a part of a wider ranging review. This will include how the current design and operation of the price cap might evolve, given increased volatility of energy prices, and will consider reform of the price cap structure. The review will include whether the current eight month lag between wholesale prices and their reflection in the price cap is optimal and whether this, and the price cap’s use of 12-month forward contract prices, exposes suppliers to costs and risks that are hard to manage at times of price volatility. This tallies with our view that the price cap lacks nimbleness. Our take is that this is a stepping stone to addressing some of the shortcomings of the tariff cap, which should have been foreseen, but weren’t. Although we don’t expect Ofgem to be generous in increasing the wholesale additional risk allowance, it should be helpful to well-run efficient suppliers, whilst not bailing out those who failed to manage risk.
Five energy suppliers have failed this week. These are Bluegreen Energy Services (c. 5,900 domestic customers), Omni Energy (c. 6,000 domestic pre-payment customers), MA Energy (c. 300 non-domestic customers), Zebra Power (c. 14,800 domestic customers), and Ampoweruk (c. 600 domestic customers and c. 2,000 non-domestic customers). Ampoweruk (final) and MA Energy (provisional) were the subject of orders from Ofgem to pay RO obligations, and Omni Energy had been issued with notice of expulsion from the BSC. It does not come as a surprise that these companies have failed. This takes the number of failures on the domestic side to 18 since the beginning of August, with 2.04m customers entering the SOLR process (Figure 1). The failure of a framework that supported a race to the bottom is all too clear to see. Last Friday, Ofgem indicated that it will consult on whether there should be adjustments to the price cap methodology to allow mechanisms to recover uncertain costs to be adjusted. We expect the consultation to land in the second part of the month, and it may well consider changes that can be made in the near-term, and also those that require more thought, and are hence longer-term in their delivery. Recovery of mutualised RO costs strikes us as a change that could be implemented in April. Ofgem has, however, made public a letter to suppliers setting out changes it is proposing to the Last Resort Supply Payment (“levy claim”) that SOLR appointees can submit. In particular, Ofgem is exploring how levy claims can be temporarily sped up, from a current position of 15-30 months post SOLR appointment. Measures include reducing the length of time it takes a SOLR to submit a claim, and how long it takes Ofgem to make a decision. Ofgem’s proposal is that a SOLR submits two claims per SOLR: an initial claim, and then a “true-up” claim. The expectation is that the initial claim would only include costs actually incurred, and primarily comprise wholesale costs, for which the SOLR appointees are providing significant working capital under the current framework (Figure 2). The indication is that if claims are made, decided upon, and received by networks prior to the end of 2021, payments to the SOLR could commence from April 2022. This would be of clear cash flow benefit to SOLR appointees such as Centrica. As we have indicated before, the price of supplier failure will be borne by us all, and it is entirely reasonable that there will be many disgruntled consumers frustrated that a framework was put in place which has allowed this to happen. Ofgem has acknowledged the upwards pressure: “We are aware that this would mean network charges are likely to rise significantly from April next year…”, and “…we appreciate the negative impact this will have on consumers…”, indicating that it is exploring how to mitigate this impact.
Against a backdrop of increased risk and uncertainty, Ofgem is to consult on whether existing mechanisms in the price cap methodology that allow suppliers to recover uncertain costs should be adjusted. Ofgem expects to publish the consultation in November, setting out the options it is considering and its minded-to position. This would lead to a decision in February 2022, with any changes implemented in the next price cap period from 1st April 2022. Protecting vulnerable consumers and addressing fuel poverty are imperative, and attempts in some quarters to blame the existence of the price cap for the sector’s woes are unfair. Indeed, one benefit of the cap has been to force suppliers to be more efficient. However, it would appear that the methodology was not sufficiently stress-tested against high wholesale price levels, and that the current methodology is not sufficiently nimble. A review is a positive step. Ofgem will shortly be publishing a letter setting out the steps it is proposing to take to expedite the process for SOLRs making a Last Resort Supply Payment claim. Faster payments will be beneficial to Centrica and other SOLR appointees in the recent tsunami of failures. Ofgem’s approach to supplier monitoring is also to be tightened, with increased scrutiny of supplier financing and operational capacity, although this is clearly a case of shutting the stable door after the horse has bolted, in our view. Looking longer-term, Ofgem has indicated that it will develop its regulatory approach to risk in the retail market, including examining how the current design and operation of the price cap might evolve given increased volatility of energy prices. Ofgem also intends to work with government and the sector to build a retail market that will support the longer-term transition to net zero, with retailers and other market participants playing an active role to support a smarter, more flexible low carbon system. This is aligned with our view that innovative, financially strong suppliers are a necessity on the road to net zero, and we see this as positive for the likes of Centrica and Good Energy. In our opinion, misguided proposals for opt-in, opt-out switching should be dropped immediately. Seven active suppliers have not paid or provided adequate assurances that they will make their Renewables Obligation payments by the late payment deadline of 31 October 2021. Ofgem has issued the suppliers with final and provisional orders compelling them to pay £17.9m in unpaid RO amounts. Failure to pay could trigger further enforcement action. The final orders have been issued to Ampower (£3.59m) and Whoop Energy (£0.06m), with the provisional orders issued to Delta Gas and Power (£0.38m), Entice Energy (£0.17m), MA Energy (£0.94m), Neon Reef (£0.35m), and Together Energy (£12.4m). Ampower and Whoop Energy had previously been issued with provisional orders. Further supplier failures appear inevitable.
What if the best solution for the energy transition were … nuclear power? Nuke is back at the heart of political debates in the context of the current energy crisis and massive but insufficient investments in renewables. This short review provides an overview of nuclear power in Europe and speculates on options. This ‘nuke optionality’, hinging on a favourable green taxonomy, is a game-changer for EDF, Centrica, Fortum but also Engie, Iberdrola, Enel and EDP.
Heat in buildings is one of the largest sources of UK carbon emissions, accounting for 21% of the total, and the urgent need to deliver a mix of new, low-carbon heating solutions to help deliver net zero by 2050 is clear. Government has finally set out its plan to incentivise people to install low-carbon heating systems with the publication of the Heat and Buildings Strategy, and a confirmed ambition for all new heating systems installed in UK homes from 2035 to be low carbon. At the time of writing, only a press release with high level detail was available. Our initial thoughts are based on the press release, and we will revert with more colour once in receipt of the full document. New grants of £5,000 will be available from April next year to encourage homeowners to install more efficient, low carbon heating systems – like heat pumps that do not emit carbon when used – through a new £450m 3-year Boiler Upgrade Scheme. However, this only equates to 90,000 homes, which, given a previously communicated target of 600,000 heat pump installations a year by 2028, appears decidedly short on ambition. Government and industry will also work together to help meet the aim of heat pumps costing the same to buy and run as fossil fuel boilers by 2030, aiming for cost reductions of between a quarter and a half by 2025 as the market expands and technology develops. To support this, a new £60m Heat Pump Ready innovation programme has been announced. This tallies with our view that we need to see industrialisation of heat manufacture and installation, but it is also imperative that system design in the home is addressed. There is an intention to reduce the price of electricity over the next decade by shifting levies away from electricity to gas. A call for evidence is to be published, with decisions made in 2022. The disincentives to shift away from gas to electricity have been clear for some time, and in our opinion, deferring the decision to next year shows a lack of courage on the part of the policy setters. A decision on the potential role for hydrogen in heating buildings will taken by 2026, but we contend that the role of hydrogen is more likely in decarbonising other areas. There are a variety of quotes in the press release (here), mostly from larger energy suppliers, and we see this as supportive of our view that the days of financially weak suppliers selling only cheap molecules and electrons are over, as evidenced by the supply market meltdown. Innovation and a wider product suite are required. This is a step along that road.
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Pure Planet, a gas and electricity supplier with around 235,000 domestic customers, and Colorado Energy, a gas and electricity supplier with around 15,000 domestic customers are ceasing to trade. Colorado Energy was already the subject of an Ofgem consultation to issue a final order to compel it to make outstanding RO payments. BP has a c.24% stake in Pure Planet’s ultimate parent company. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of the failed suppliers. These failures represents the 32nd and 33rd SOLR processes since January 2018, amounting to over 3.6m customers, c.13% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. The final bill for industry levy claims will not be known until after the winter period, but assuming that a SOLR appointee prices its deemed contract at the level of the tariff cap, there will be claims for the additional costs that the SOLR appointee incurs in procuring the commodity. There is also the likely mutualisation of the RO given the £15.4m threshold for 2020/21. Ultimately, consumers will foot the bill. We reiterate our view that there are clearly questions that Ofgem needs to answer as to its role in facilitating a market where some business models have proved to be unsustainable, as we suggested last November (here). We have previously made it very clear that we expected to see more supplier failures, previously suggesting that the supply market is in meltdown, so this again very much aligns with our thesis of ongoing consolidation in the GB supply market. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, exacerbated by high wholesale prices, but also given the likely shift in customer demands as the energy transition gathers pace. We consider these failures as supportive of a direction of travel that is increasingly positive for stronger players in the market, such as Centrica (Buy, TP 65p).
National Grid ESO has released its Winter Outlook for 2020/21 (LINK). The headline is that the ESO expects sufficient margins over the winter and the system is within the reliability standard. The lights will stay on. A sister publication for gas has also been published (LINK), although not the subject of this paper, a key message from this publication is that the gas supply margin is expected to be sufficient in all supply and demand scenarios, with supply from diverse sources, and at a level comparable to last winter. Margins on the electricity system are seen as lower than last winter, but well within the national Reliability Standard. Updated base case margin of 6.6% (Figures 1-4), 0.7% lower than the 2021/22 early view base case. Plant closures and the IFA interconnector outage are drivers, but margins are seen as being above 2015/16 and in line with 2016/17. The ESO states: “while it may be possible to stack multiple downside risks, such that the Reliability Standard would not be met, we do not consider this in our credible range. GB has a well-functioning electricity market and so we would expect a market response driven through higher prices to mean such an outcome would be less likely”. Weather corrected peak demand for winter 2021/22 is expected to be higher than the previous winter (Figure 9), largely due to COVID-19 restrictions being lifted, and broadly in line with winter 2019/20. Minimum operational surplus projected to be throughout December to mid-January (Figure 5). The ESO issued six Electricity Margin Notices (EMNs) last winter (Figure 7), and expects to issue a broadly similar number of EMNs this winter (Figure 8). If 2GW of capacity near its end of life were to close permanently, then the number of EMNs could double. Sufficient levels of generation and interconnector imports to meet demand throughout the winter are expected, with slightly more available generator capacity than last year (more CCGT/biomass, Figure 10). Generator reliability to be broadly in line with recent winters, albeit with a higher assumed breakdown rate for thermal capacity. Price effects could see more coal generation. Forward prices in GB are expected to be higher than last year across the winter period due to the gas price. Days with tight margins expected to see spikes in the balancing mechanism, particularly when EMNs are issued. Balancing costs are likely to rise even if the volumes of system actions remains consistent with previous winters. This is likely to benefit providers of flexibility, including Drax (BUY, TP 615p) and SSE (BUY, TP 1,800p).
Ofgem is consulting on issuing five suppliers with final orders to compel them to make £7m in outstanding payments to comply with the Renewable Obligations (RO) scheme. The suppliers are Ampoweruk, Whoop Energy, Goto Energy, Home Energy Trading and Colorado Energy. We do not have customer numbers for these suppliers, but it is reasonable to expect that there is a relationship between the amounts owed and the size of the customer base. On this basis, Ampoweruk and Goto Energy are likely to be materially larger than the other three. We have endeavoured to ascertain whether new business is being quoted, setting out our findings below. Ampower is not quoting or accepting any new customers until further notice. (see Figure 2 of full report). It is also in default of the BSC. Whoop Energy is a business only supplier, and is in default of the BSC. goto.energy has a single offer for a London postcode, but is pricing at c.50% the level of the tariff cap (Figure 3). We have not been able to locate a website for Home Energy Trading, but the company’s last filed accounts show negative capital and reserves (Figure 4). Colorado Energy operates in the tenanted property space, working with selected letting agents. The website lists tariffs by region (Figure 5), but given the business model, there is no direct sign up on the website. The two directors (Mooktakim Ahmed, Olatunde Algebe) are also directors of Lawdeck Limited, Colorado Energy’s parent company. Lawdeck Limited is listed as the registered company on the website of Homeshift (Figure 6), where it is possible to get a quote (Figure 7). We continue to expect more failures in a supply market that is in meltdown, an environment that is positive for stronger players in the market, such as Centrica (Buy, TP 65p).
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Ofgem is consulting on issuing five suppliers with final orders to compel them to make £7m in outstanding payments to comply with the Renewable Obligations (RO) scheme. The suppliers are Ampoweruk, Whoop Energy, Goto Energy, Home Energy Trading and Colorado Energy. We do not have customer numbers for these suppliers, but it is reasonable to expect that there is a relationship between the amounts owed and the size of the customer base. On this basis, Ampoweruk and Goto Energy are likely to be materially larger than the other three. We have endeavoured to ascertain whether new business is being quoted, setting out our findings below. Ampower is not quoting or accepting any new customers until further notice. (see Figure 2). It is also in default of the BSC. Whoop Energy is a business only supplier, and is in default of the BSC. goto.energy has a single offer for a London postcode, but is pricing at c.50% the level of the tariff cap (Figure 3). We have not been able to locate a website for Home Energy Trading, but the company’s last filed accounts show negative capital and reserves (Figure 4). Colorado Energy operates in the tenanted property space, working with selected letting agents. The website lists tariffs by region (Figure 5), but given the business model, there is no direct sign up on the website. The two directors (Mooktakim Ahmed, Olatunde Algebe) are also directors of Lawdeck Limited, Colorado Energy’s parent company. Lawdeck Limited is listed as the registered company on the website of Homeshift (Figure 6), where it is possible to get a quote (Figure 7). We continue to expect more failures in a supply market that is in meltdown, an environment that is positive for stronger players in the market, such as Centrica (Buy, TP 65p).
ENSTROGA, a gas and electricity supplier with around 6,000 domestic customers, Igloo Energy, a gas and electricity supplier with around 179,000 domestic customers, and Symbio Energy, a gas and electricity supplier with around 48,000 domestic customers and a small number of non-domestic customers, are ceasing to trade. Igloo Energy and Symbio were already the subject of provisional orders in respect of FiT payments. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of the failed suppliers. These failures represent the 29th, 30th and 31st SOLR processes since January 2018, amounting to over 3.4m customers, c.12% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. In a press release, Ofgem has pointed to the fact that the three suppliers account for less than 1% of the market. This is true, but we are more concerned about the consequences of the accumulation of failures over recent weeks. In a note earlier this week (Supplier consolidation continues), we suggested that September’s failures (prior to these) could see mutualisation costs of c.£30 per dual-fuel customer. We now suggest that for September alone that figure could be in the region of c.£36/dual-fuel customer. Consumers will undoubtedly be aggrieved at this knock-on impact. With Ofgem’s former CEO suggesting that Ofgem should have tightened the rules sooner (FT, 28th September), there are clearly questions that Ofgem needs to answer as to its role in facilitating a market where some business models have proved to be unsustainable, as we suggested last November (Supply - Empowered, engaged, valuable). We have previously made it very clear that we expected to see more supplier failures, previously suggesting that the supply market is in meltdown, so this very much aligns with our thesis of ongoing consolidation in the GB supply market. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, exacerbated by high wholesale prices, but also given the likely shift in customer demands as the energy transition gathers pace. We consider these failures as supportive of a direction of travel that is increasingly positive for stronger players in the market, such as Centrica (Buy, TP 65p).
Octopus Energy has been appointed the Supplier of Last Resort (SOLR) for Avro Energy’s 580,000 customers. Ofgem has indicated that Avro’s customers will be protected by the price cap, which suggests that a sizeable claim could be made by Octopus Energy for the additional cost of purchasing the electricity and gas to supply Avro’s customers, over and above that allowed by the cap. The level of the cap from 1st October includes electricity at £69.75/MWh and gas at 62.69p/therm. However, 1st winter baseload electricity and NBP gas are trading at £186/MWh, and 180p/therm respectively. This suggests that the excess costs that are likely fall to the industry level could be significant. Although taking the spot price for a single contract is a huge simplification, and could understate, we believe it shines a light on the eye-watering amount that could be mutualised across all suppliers. Using Ofgem’s seasonality estimates of 57% of electricity consumption taking place in winter, and 75% of gas, we suggest that for the winter period alone, the excess cost could be at least c£550/dual-fuel customer. Applied to the c1.5m customers of the suppliers that have failed in September alone, this suggests that in excess of £826m might need to be mutualised, equivalent to c.£30/dual-fuel customer. It is not hard to imagine that customers of stronger suppliers who now find themselves having to foot the bill for market failures are going to be somewhat aggrieved, and looking to apportion blame. Suggestions that regulation is not to blame are wide of the mark, in our opinion. Granted, gas prices have triggered a domino-like collapse, but it’s not as if the unsustainability of the situation was not foreseen. Indeed, in a report last November (here) we wrote that “In our view, the low barriers to entry and level of regulatory oversight were contributory factors to the growth in the number of suppliers in the market, and the subsequent failure of many which found out that operating a supply business was a complex task. It is also possible to argue that the SOLR regime, whilst protecting consumers’’ credit balances, created moral hazard, exacerbated by Ofgem actively promoting switching by highlighting marked differentials in pricing across the market. As our analysis shows, many of these tariff offers are loss-making, and in our view, ultimately unsustainable”. We continue to expect more failures in a supply market that is in meltdown, and we note that Sky News reported on 24th September that CNG Group, a wholesale energy trader, has appointed advisers to undertake a strategic review. This may further add to the difficulties faced by smaller suppliers. We continue to expect the supply market to consolidate.
CNA GLO DRX TUNE IBE IBE MGP NG/ RR/ SAE SSE UU/
Avro Energy, a gas and electricity supplier with around 580,000 domestic customers, and Green Supplier Limited, a gas and electricity supplier with around 255,000 domestic customers, and a small number of non-domestic customers, are ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of the failed suppliers. These failures represents the 27th and 28th SOLR processes since January 2018, amounting to c.3.1m customers, c.11% of the market, with Avro Energy (c.2% market share) the largest supplier failure to date. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. We have previously made it very clear that we expected to see more supplier failures, previously suggesting that the supply market is in meltdown, so this very much aligns with our thesis of ongoing consolidation in the GB supply market. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, exacerbated by high wholesale prices, but also given the likely shift in customer demands as the energy transition gathers pace. These are significant failures, and we consider them as supportive of a direction of travel that is increasingly positive for stronger players in the market, such as Centrica (Buy, TP 65p).
British Gas takes on the customers of People’s Energy Ofgem has appointed British Gas to take on supplying People’s Energy c.350,000 domestic customers, following its failure last week. The appointment of British Gas follows a competitive process run by Ofgem that considers the customers of the failed supplier, and the cost to the wider system. Notably, unlike British Gas’ two recent SOLR appointments, Ofgem has not stated that British Gas is offering customers a competitive tariff. However, outstanding credit balances owed to both existing and former customers of People’s Energy will be honoured. Ofgem has stated that “the supplier of last resort process will allow British Gas to recover the additional costs of taking on People's Energy's customers, where appropriate. British Gas has committed that it will do everything it can to minimise those costs”. In its own statement, Centrica has stated that “it has been agreed that all costs incurred by British Gas that it is not able to recover as a result of taking on the customers, including additional costs of buying energy, the refund of credit balances, and other operating costs, will be recoverable through the established industry levy in a timely manner”. In our opinion, this should protect value, although there could be timing mismatches on cash flow. In line with Centrica’s strategy to stabilise, then grow customer numbers For Centrica, the acquisition of the customers via the SOLR process is likely to be cheaper than customer acquisition via PCWs, etc., and is in line with Centrica’s stated ambition to stabilise, then grow, customer numbers. The 350,000 residential customers gained through this process, and the 91,000 added last week, more than offset the 114,000 lost in 1H21. More importantly, however, the failings of the supply market, and some of the framework that governs it, have been laid bare. If we want net zero, we need strong suppliers that can innovate, and industrialise the decarbonisation of heat. Government/Ofgem need to realise this, and abandon the idea of switching for switching’s sake.
Five suppliers have failed in recent weeks, with People’s Energy (c.350k domestic customers) the 2nd largest to date. Nearly 2.5m customers have now been through the supplier of last resort (SOLR) process, c.9% of the market. EDF Energy appointed the SOLR for Utility Point. We continue to wait for the appointee for People’s Energy, but the trend of consolidation is continuing. Smaller suppliers find it more difficult to hedge, and some may have chosen not to. Current high wholesale prices have pushed suppliers into failure. Previous light touch entry requirements from Ofgem, and a narrative that actively encouraged consumers to switch to cheap deals, despite these being unsustainably priced, have exacerbated this. Ofgem has tightened up licensing and monitoring, but the fox is already in hen house, and the supply market is in meltdown. Some price comparison websites have suspended their energy offer (Figure 2), or indicated that they can’t help (Figure 3). Ofgem has issued a provisional order to Avro Energy, a supplier with a c.2% market share; if Avro fails, it would be the largest failure to date. Elexon has published a circular indicating that Symbio Energy is in default, having not paid amounts in full on three or more occasions over a 30 calendar day period, in respect of trading charges due for payment under the BSC. The Times (17/09) cited research from Baringa that projects that 39 suppliers could fail in the next 12 months, leaving only 10 in the market, the BBC (18/09) suggested that 4 suppliers are expected to fail this week, and the FT reported (19/09) that Bulb (c.1.7m customers) is seeking a bailout. SOLR appointees might be prepared to fund all/part of credit balances, but we would be surprised if they would fund out-of-the-money unhedged positions, with it unclear as to whether the tariff cap constrains the level of the deemed tariff a SOLR could offer. Costs will need to be mutualised, further adding to the problem. Energy Supply Company Administration is an alternative. SVTs could well be the best option for consumers for now, given the tariff cap does not fully reflect current market conditions, although out-of-the-money for new sign-ups. We note that although British Gas’ T&Cs (Figure 4) state that the SVT is open to new signs, we couldn’t generate an online quote (Figure 5). Kwasi Kwarteng, Business and Energy Secretary, held a series of individual meetings with senior executives from the energy industry on 18/09 and met with Ofgem on 19/09, with an industry roundtable to be convened today. In our opinion, the unsustainable pricing of some participants has come to a head. We need a stable and profitable supply market that can fully support the energy transition. Opt-in, opt-out switching proposals should be dropped. Ultimately, we view the likely shake-out as positive for Centrica.
CNA CHRT GLO DRX IBE IBE NG/ SAE SSE
People’s Energy, a gas and electricity supplier with around 350,000 domestic customers, and around 1,000 non-domestic customers, and Utility Point, a gas and electricity supplier with around 220,000 domestic customers, are ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of the failed suppliers. The failure represents the 25th and 26th SOLR processes since January 2018, amounting to c.2.3m customers, c.8% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. We have previously made it very clear that we expected to see more supplier failures (for example, Predictably, more supplier failures (Jan’21) and Two more failures, we expect more (Sep’21)), so this very much aligns with our thesis of ongoing consolidation in the GB supply market. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, exacerbated by high wholesale prices, but also given the likely shift in customer demands as the energy transition gathers pace. These are significant failures, and we consider them as supportive of a direction of travel that is positive for stronger players in the market, such as Centrica (Buy, TP 65p).
The government has announced the draft budget for CfD Allocation Round 4, providing up to £265m per year in support via the CfD framework (Figure 1). Pot 1 for established technologies (includes Onshore wind, Solar and Hydropower) has a £10m budget, a capacity cap of 5GW, and caps of 3.5GW imposed on both onshore wind and solar PV. Pot 2 for less-established technologies (includes Floating Offshore Wind, Tidal Stream, Geothermal and Wave) has a £55m budget, but with no capacity cap, and £24m of ring-fenced support for floating offshore wind projects Pot 3 for offshore wind has a £200m pot budget, but no capacity cap. Pot 1 has delivery years of 2023/24 and 2024/25, while Pots 2 and 3 have delivery years of 2025/26 and 2026/2027. The separate maxima of 3,500MW each applied to onshore wind and solar PV will operate as ‘hard’ constraints. In the event that maximum only auctions need to be run for both technologies, the solar PV auction will be run first. A final Budget Notice will be issued no later than 10 working days before the commencement date of the Allocation Round on the 13th of December. We consider the absence of a capacity cap for offshore wind to be a positive for those such as SSE who are bringing forward projects. However, unlike AR3 where the budget cap was not reached, it is possible that financial caps could come into play given the downward trajectory of reference prices (Figure 4) over the delivery/valuation year period. Consideration of the case for introducing additional minima is ongoing, with any additional minima to be set out ahead of, or in, the final budget notice. This would appear to keep the door ajar for the possibility of technology-specific minima for wave and tidal stream, an outcome which if it came to pass, we would view a positive for Simec Atlantis, and its MeyGen project.
British Gas takes on the customers of PfP Energy and MoneyPlus Energy Ofgem has appointed British Gas to take on supplying PfP Energy’s c.82,000 domestic customers and c.5,600 non-domestic customers, and MoneyPlus Energy's c.9,000 domestic customers, following the failure of both last week. The appointment of British Gas follows a competitive process run by Ofgem that considers both the customers of the failed suppliers, and the cost to the wider system. According to Ofgem, British Gas are offering customers a competitive tariff. Outstanding credit balances, including money owed to both existing and former customers of PfP Energy and MoneyPlus Energy, will also be honoured, with British Gas also absorbing some of the costs of honouring customers’ credit balances and the migration of customers. We expect more failures, with the bigger suppliers likely to be the SOLR suppliers Analysis of the 25 SOLR processes (Figure 1 overleaf) that Ofgem has run shows that the successful SOLR supplier is highly likely to be one of the larger players in the market, underscoring our view that we will see further consolidation in the market. We expect more supplier failures, noting that 76% of SOLR processes have taken place in the months of September to January, most likely due to the cash flow pressures of settling any ROC obligations, direct debit mismatches, and covering short commodity positions in the higher consumption winter months. In line with Centrica’s strategy to stabilise, then grow customer numbers For Centrica, the acquisition of the customers via the SOLR process is likely to be cheaper than customer acquisition via PCWs, etc., and is in line with Centrica’s stated ambition to stabilise, then grow, customers numbers. The 91,000 residential customers gained through the process almost offset the 114,000 lost in 1H21. As failing suppliers often seek a buyer before entering the SOLR process, we would expect that Centrica had knowledge of the two suppliers, and that ‘due diligence’ on both had been carried out before and after their failure, hence mitigating the risk of this form of customer acquisition.
PfP Energy, a gas and electricity supplier with around 80,000 domestic customers, and 5,000 non-domestic customers, and MoneyPlus Energy, a gas and electricity supplier with around 9,000 domestic customers, are ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of the failed suppliers. The two failures represent the 23rd and 24th SOLR processes since January 2018, amounting to c.1.75m customers, c.6% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. We have previously made it clear that we expected to see more supplier failures, so this very much aligns with our thesis of consolidation in the GB supply market continuing to play out. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, exacerbated by high wholesale prices, but also given the likely shift in customer demands as the energy transition gathers pace. Although small, we consider these latest failures as supportive of a direction of travel that is positive for stronger players in the market, such as Centrica (Buy, TP 65p).
The CMA has published a summary of its provisional decision in the appeals brought by nine energy firms against changes made to their licences by Ofgem in the RIIO-2. Twelve different grounds of appeal were considered, and the CMA has only provisionally found that GEMA (Ofgem’s governing body) were wrong, or partially wrong, on five grounds. The CMA has upheld Ofgem’s decisions to reduce the future returns allowed to equity (“we have provisionally determined that GEMA’s allowed cost of equity of 4.55% was not wrong”). The CMA has “provisionally concluded that GEMA’s decision not to aim up on the cost of equity was not wrong”. The CMA has also provisionally sided with Ofgem on the cost of debt, albeit that only one company, WWU, appealed the cost of debt (“we have provisionally determined that GEMA was not wrong in its approach to or estimate of its cost of debt allowance”). The CMA has provisionally determined that Ofgem did not provide sufficient evidence to justify the introduction of two new adjustments, namely the outperformance wedge (“we have therefore provisionally determined that GEMA was wrong”) and the innovation uplift. It also found three other errors. We have consistently suggested that the outperformance wedge lacked validity, and are not surprised to see that the CMA has provisionally ruled against it. We have also been consistent in our view that energy is deserving of a higher return than water, and at 4.55% CPIH real we note that the cost of equity for energy is higher than the 4.53% CPIH real in the CMA’s final determinations in the water PR19 appeals. However, the finding in favour of Ofgem is likely to come as a negative surprise, and we note that consensus expectations for the cost of equity were 4.76% CPHI real. Our modelling assumes the returns in Ofgem’s final determinations including the outperformance wedge, suggesting minor upside from removing the outperformance wedge if the CMA’s final determination of the cost of equity lands at 4.55% CPIH real. However, we suggest that the initial reaction will be tilted towards the downside. The full provisional determination, including the CMA’s reasoning, has been issued to the companies and Ofgem, which now has three weeks to respond with its representations. The CMA will consider responses and then issue its final determination, including directions to correct any errors found in Ofgem’s decisions, no later than 30 October 2021. A non-sensitive version of the full final determination will subsequently be published on the CMA’s case page.
Hub Energy, a gas and electricity supplier with around 6,000 domestic customers, and c.9,000 non-domestic customers is ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on Hub Energy’s customers. Hub Energy is the first supplier to fail since January, but represents the 22nd SOLR processes since January 2018, amounting to c.1.65m customers, c.6% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. We have previously made it clear that we expected to see more supplier failures, so this very much aligns with our thesis of consolidation in the GB supply market continuing to play out. We believe that the trend will continue, both due to the financial challenges facing loss-making suppliers, but also given the likely shift in customer demands as the energy transition gathers pace. Although small, we consider this latest failure as supportive of a direction of travel that is positive for stronger players in the market, such as Centrica (Buy, TP 65p).
We have been consistent in our view that the outperformance wedge in Ofgem’s RIIO-2 final determinations for transmission and gas distribution lacks validity, and that energy is deserving of a higher return than water. Every transmission and gas distribution company appealed the outperformance wedge, and the cost of equity to the CMA, and the latter is set to publish provisional determinations next week. The CMA found in favour of the four appellants in the water PR19 appeals, and awarded a higher cost of equity than that set by Ofwat at final determinations, including ‘aiming-up’ by 25bp (Figure 1). We view this as supportive of our view that the outperformance wedge will be removed, and suggest that the CMA should put forward a cost of equity that is at/above the 4.53% CPIH real in its PR19 final determinations. The allowed return on equity of 4.30% CPIH real in RIIO-2 final determinations reflects a 25bp outperformance wedge adjustment to Ofgem’s 4.55% cost of equity at 60% gearing, the latter being the midpoint of Ofgem’s range. Removing the outperformance wedge, aiming-up by 25bp, and assuming no changes to other parameters would point to a cost of equity of 4.80% CPIH real. Ofgem has circulated consensus expectations. Formed from 12 contributions, 11 expect no outperformance wedge, with a cost of equity range of 4.40-5.10% CPIH real. The mean is 4.76% CPIH real. We base our modelling for National Grid and SSE on RIIO-2 final determinations, including the outperformance wedge. A higher cost of equity, including removing the outperformance wedge would have positive valuation implications for each. By way of sensitivity, a 4.80% CPIH real cost of equity applied to both transmission and electricity distribution would add c.28p/share to our valuation of National Grid, and c.18p/share to our valuation of SSE. We suggest that the provisional determinations could be a positive catalyst for National Grid and SSE, both of which we rate as Buy. Both have delivered a total return of 20% since 26th February, but have lagged the water companies over the same period. National Grid also trades at a lower RAV/RCV premium than both Pennon and Severn Trent (Figure 2). Given the magnitude of the energy transition opportunity, the relative underperformance strikes us as a trigger point to revisit both stocks.
The net-zero narrative has accelerated in 2021, and customers have a key and essential role to play through behavioural change. We will not get there by merely building windmills, and criss-crossing the country with more wires and cables. We consider this view is supported by a raft of recent government publications. The Government’s vision for retail, elaborated in ‘Energy Retail Market – Strategy for the 2020s’ envisages engaged customers, and innovative, competitive and profitable companies. Actions such as removing market distortions, improving information, adoption of EVs and heat pumps, and supporting new business models are sensible, and are likely positive for energy supply. This leads us to suggest that there is a significant opportunity for suppliers who can score the hat-trick of competitive positioning, product offering, and customer service. On the other hand, proposals to introduce opt-in switching, and trial opt-out switching from 2024 are not smart, represent a barrier to innovation, and are another headwind the industry has to negotiate. Fairness of price can be addressed via a proposal to retain the price cap post 2023, and we hope that common sense will prevail, albeit that we acknowledge that the consultation could provide a big nudge factor for suppliers to up their game. We remain of the view that there will be further consolidation over the upcoming months, through supplier failures and/or distressed sales as liabilities have to be settled, and high wholesale costs begin to bite. Speculative M&A is also a possibility as suppliers may well choose to expand/re-position portfolios for the energy transition. The forthcoming call for evidence to consider whether to regulate third party intermediaries (TPIs), such as price comparison websites (PCWs) and brokers, could also usher in a period of uncertainty for participants in this space.
Cash flow coming through Centrica reduced net debt organically by ca. GBP300m in H1. There were tailwinds - GBP266m FCF from the EandP business the group is still looking to exit, net tax repayments, positive variation margin and collateral movements - but this was done against tough operating conditions - industrial action and ongoing COVID restrictions - and post the contribution of GBP243m towards pension liabilities. Still, this needs to be put in the context of the absence of dividend outflow. Earnings not there yet While Upstream, Supply and Services were broadly as expected, normalised profitability from LNG and route to market businesses is lower than our or market expectations. The legacy gas contract is now guided to lose GBP100m or more this year vs previous guidance of -GBP50-100m. One-off adjustments to deferred taxes of ca. GBP40m helped keep H1 EPS in line, but this will be offset by a GBP40m increase in Upstream DandA in H2 after valuation write-up. We cut our 2021 estimates to reflect the moving drivers, but the impact on 2022 earnings onwards is muted on a net basis. Strategy questions Centrica appears to have walked away from an exit from nuclear and although that was linked to its Net Zero ambitions, we suspect it is just as much a function of the lack of a market for that asset. Offers have been received for Spirit Energy but none that satisfy management, so alternative routes are now being examined although a listing was stated as ''highly unlikely''. Management appears committed to turning around the performance of the rest of the portfolio. We therefore believe that the market hopes of significant asset sales and capital return now looks remote. Upgrade to Neutral. We raise our price target to 49p (from 46p) Risks remain both from government energy policy (e.g. collective switching) and execution (inability to become cost competitive or to smoothly migrate customers to the new platform). But we believe the market''s...
Flat but unsurprising results from Centrica in the first half of the year, as favourable weather conditions and commodity prices were offset by the COVID-19 impact, British Gas engineer strikes and sharp trading conditions. On the positive side, the sale process of Spirit Energy has made progress, and a CMD will be held on 16 November 2021. However, nothing new on the dividend side. Neutral view confirmed due to so many uncertainties surrounding the stock.
Consolidated numbers in line with expectations Centrica has reported 1H21 results this morning. Adjusted operating profit of £262m was broadly in line with our estimate (£273m), EPS of 1.7p was in line with our estimate (1.7p), and net debt of £0.1bn was in line with our estimate (£50m). As expected, no interim dividend was declared. Differences at the business lines At an individual business line, we highlight (i) Energy Supply where adjusted operating profit came in at £172m (vs. INVe £130m) benefiting from price cap impacts (bad debt allowance, Judicial Review, offset by a 2% drop in customer numbers), colder weather, cost reduction, absence of Direct Energy cost allocations; (ii) Services with adjusted operating profit of £60m (vs. INVe £90m) reflecting the strike impact; (iii) EMT with an adjusted operating profit of £(40)m (vs. INVe £30m) impacted by higher losses on the legacy gas contract; and (iv) Nuclear with adjusted operating profit of £(38)m (vs. INVe £(19)m) impacted by lower output and lower prices. These suggest that our FY forecasts for these business lines need revisiting, and we will do so in due course. Looking to the CMD on 16th November Centrica is making process on alternative Spirit Energy sale options. The triennial pensions valuation process is underway, with the technical deficit at 30th June in the region of £1.5bn, reduced from £1.9bn at 31st December. Centrica now indicates that the nuclear stake might be retained given its low carbon nature. Consolidated FY guidance has not been provided, although there is refinement of the narrative outlined at FY20, which we will reflect in our revisions. However Centrica has indicated that the 2021 outlook is broadly unchanged. We suggest that catalysts for Centrica are likely to be post summer, notably a Capital Markets Day scheduled for 16th November.
Draft business plans for RIIO-ED2 were submitted to Ofgem on 1 July. With the exception of UKPN, which has only published a brief executive summary, all DNOs have made their draft business plans public. Some have also published the supporting annexes. We have analysed the published information, and summarised our findings in Figure 1 overleaf. The three ‘R’s of reinforcement, resilience and reliability are key themes, with significant investment needs to facilitate the energy transition, and beef-up information/operational technology, cyber security, and protect asset health. There is an increased demand for flexibility services as an alternative to reinforcement. All six DNOs are seeking totex increases versus ED1 in their base case submissions. ENWL is seeking the biggest jump at 53%, followed by SSEN (SSE) at 45%. At the other end of the spectrum, UKPN has only factored a 7% increase into the base case. A number of DNOs have put figures on uncertainty totex, pointing to possible higher spend. EVs and heat pumps are key drivers. In aggregate, base case plans see c.7.2m EVs by March 2028, although there are significant differences in penetration from DNO to DNO. Those with the UK’s largest conurbations, UKPN (London) and National Grid’s WPD (Birmingham), forecast markedly lower penetration/customer than other DNOs, possibly reflecting access to public transport. Heat pumps installed could reach c.2.6-2.7m by March 2028 according to base cases, a level that appears to be consistent with the government ambition to see 600,000 annual installations by 2028, though arguably still a challenge. SSEN has the highest predicated penetration of heat pumps, a likely consequence of the rural nature of its SHEPD licence area. The five DNOs which have published their cost of capital assumptions all disagree with Ofgem’s working assumptions of an allowed return on equity of 4.40%, and a WACC of 3.01%. SSE has put forward the highest cost of equity at 6.75% CPIH real, and is an outlier for this variable. ENWL has put forward the highest cost of debt at 3.21% CPIH real, and the highest WACC at 4.25%. The male/female composition of the Customer Engagement Groups is mixed, with SPEN (Iberdrola), UKPN, and NPG all male dominated. Ethnic diversity across these groups and Ofgem’s Challenge Group is poor, and in aggregate arguably not reflective of the ethnic mix of the UK. Final business plans are to be submitted on 1 December, with Draft Determinations next June. Ahead of this, we suggest that the CMA’s provisional determinations in the RIIO-2 appeals process, expected in early August, should be watched closely, and are a potential catalyst for National Grid and SSE.
SSE’s FY21 guidance for adjusted EPS of 85-90p was based on assumptions about weather conditions and the impact of Covid. As we suggested earlier this week, weather conditions have not clawed back the renewables shortfall vs. plan, and have actually gone the other way, with a 9% shortfall at 23rd March. However, SSE now expects the impact of Covid on adjusted operating profit to be c.£180m for FY21, compared to a previously forecast £150-250m range. Taken together, SSE has confirmed the 85-90p EPS guidance (we have 90p). Net debt is expected to be c.£9bn at 31st March, fractionally better than our £9.3bn forecast. The FY21 dividend of 80p plus RPI for FY21 (we have 81.2p) has been confirmed, and the growth policy of RPI growth to FY23 reiterated. SSE is progressing options for divestment of all its equity stake in SGN. Consideration is being given to recent market developments (we see this as a reference to the premium paid by National Grid for WPD), as well as the potential impact of the referral of certain elements of the RIIO-GD2 price control process to the CMA. SSE expects to update the market further on its approach and timings at its results presentation in May. SSE has confirmed an intention to sell 10% of Dogger Bank C in FY22. Pennon has commented that the COVID-19 financial impact is in line with expectations, and that South West Water is on track to deliver strong totex and financing outperformance, anticipating a doubling of RORE of 3.9%. Circa 80% of ODIs are on/ahead of target, but a penalty position in pollution is likely to see a net penalty position in FY21, no change from the direction outlined at 1H21. There is another holding statement on the deployment of the Viridor proceeds. “Pennon believes there is significant value potential from the reinvestment of the Viridor sale proceeds in the UK water sector and continues to narrow down its review of potential growth opportunities. In the event a major value accretive investment opportunity is not available, Pennon expects to make a substantial return of capital to shareholders. The Group expects to provide clarity on this position by the time of its full year results on 3 June 2021.” Good Energy has issued a trading statement ahead of FY20 results on 13th April. The company has alluded to good performance in 4Q, with the y/e cash balance of £18.1m in line with the June 30th position of £18.2m. Customer numbers have remained stable since September 2020, with strong cash collection and a healthy working capital position. The implementation of the Kraken technology platform and the smart meter roll-out remain on track, two drivers that we consider important in positioning Good Energy to bring forward innovative products to leverage its customer base as the energy transition gathers pace. We consider comments around vigilance on the potential impacts later this year of the withdrawal of various government support schemes from individuals and businesses as prudent, and consistent with the narrative disseminated by others.
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Centrica announced on Friday that it has acquired Nabuh Energy, a small supplier with 36,000 largely prepayment residential customers. No financial details were given. Nabuh Energy was issued with a final order by Ofgem (see Supplier Warning Signs) in October for non-payment of its Renewables Obligation, and in acquiring the Nabuh Energy brand and certain IT assets, we believe it is unlikely that Centrica will have taken on these liabilities. This transaction, although small, is consistent with Centrica’s ambition to grow its GB presence after years of customer losses, and supports our view that we will see consolidation of the market through both trade sales, and supplier failure. According to Bloomberg, SSE and Equinor plan to sell 10% each in their Dogger Bank C offshore wind farm JV. This is not a surprise given SSE’s stated intention of holding 30-40% in its offshore wind farms, and follows on from last December’s sale by SSE of a 10% stake in Dogger Bank A and B for £202.5m to Eni, which also made a similar purchase from Equinor. We would expect the sale to realise c.£100m for SSE. United Utilities is set to issue a pre-close trading statement on Thursday. Given the recent Capital Markets Event, where UU indicated that it expects to deliver ODI outperformance of up to £20m, we are expecting no surprises on the ODI front. At 1H21 UU guided to a volume impact, including Covid-19, of £10-60m at the wholesale level, and FY21 revenue of £1.75-1.8bn. We expect that this number will be updated, and additionally there to be a negative impact from Covid-19 on Water Plus, its equity accounted business supply JV with Severn Trent. We expect reiteration of the dividend policy of CPIH growth, and our year-end net debt estimate is £7.5bn.
The CMA has published its final determinations in respect of the four appellants against Ofwat’s PR19 determinations. In each instance the determinations allow for higher totex, while the appointee level WACC has been set at 3.20% based on a cost of equity of 4.73% and a cost of debt of 2.18%. The CMA has set a retail margin of 8bp, pointing to a WACC at the wholesale level of 3.12%, and a wholesale cost of equity of 4.53%. This is above the wholesale WACC of 2.92% in Ofwat’s PR19 determinations, and the implied wholesale cost of equity of 4.09%. The CMA’s last communicated position, in January had a cost of equity of 4.83%, or 4.63% when adjusted for a 20bp retail margin. There is no immediate financial benefit for the listed water companies, as each accepted Ofwat’s determinations, but we see the ruling as a positive for the PR24 regulatory review in respect of the AMP8 regulatory period commencing in April 2025. Applying the CMA’s WACC to our models for AMP8 onwards would add 2.6% to our valuation of Pennon, 6.1% to our valuation of Severn Trent, and 5.5% to our valuation of United Utilities. A potential impediment in Pennon’s ambition to acquire a regulated water company has also been removed. There is also a read-across to the energy networks as every transmission and gas distribution company is seeking to appeal to the CMA, the cost of equity and outperformance wedge element of Ofgem’s RIIO-2 final determinations. At 60% gearing, Ofgem’s allowed return on equity is 4.30%, or 4.02% at 55% gearing. We have been consistent in our view that the outperformance wedge lacks validity, and that energy is deserving of a higher return than water. However, if we apply the CMA’s wholesale cost of equity to National Grid (NGET and NGGT) and SSE (SHET), this would suggest a WACC of 2.9% for NGET (vs. 2.81%), a WACC of 2.9% for NGGT (vs. 2.81%), and WACC of 2.78% for SHET (vs. 2.69%). This would add 1.2% to our valuation of National Grid, and 1.4% to our valuation of SSE.
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Little incremental from the FY results Fundamental drivers do not appear to have materially altered in recent months for Centrica''s core businesses. We note that the COVID-related pressures in 2020 on the Business Energy Supply division were larger than we anticipated, causing us to assume a bigger reversal y-o-y in 2021. The higher ECO costs highlighted by management are a larger headwind than we assumed and cost reduction in the British Gas Energy Supply business is also slower than we were factoring in. However, we can infer very little from these movements with regards to Centrica''s ability to operate profitably and sustainably and return to a growth path in the future. Customer migration the big bet Management highlighted that it plans to migrate customers from its legacy ''not fit for the future'' IT system into software that reflects the realities of the market environment much better. This will be a multi-year process. Although the end result should be lower costs and better customer experience, putting the company on the path to being competitive, we remain concerned as to whether a) the process will be executed smoothly given the track record of the industry on such migrations and b) that the process will be executed fast enough for Centrica to catch up with the competition. Balance sheet on better footing The increase in gilt rates has reduced the technical pension deficit ahead of the triennial review and ongoing negotiations with trustees relating to its funding. The completion of the Direct Energy disposal in January and the resumption of the Spirit Energy disposal - which, however, appears to be progressing slowly - should give further comfort on the balance sheet. Still, we do not expect dividend payments to resume until next year. Reiterate Underperform. SOTP PT 46p. As we showed in CENTRICA: Finding it difficult to fit we believe that the portfolio, cost structure and top-line profile that this management team has...
Affected by volumes which were lower than their long-term average and weak commodity prices for the upstream division, the group published a disappointing set of FY20 figures. Although the group’s efforts on its cost structure are notable, we maintain a cautious view on inventory due to the economic uncertainty that could erode cash generation (due to an increase in working capital requirements, among other things).
Announced and pending management change at Good Energy, and its Zap-Map subsidiary, offer an opportune moment to revisit the equity story. The energy supply market is changing, decarbonisation of transport and heat are likely to see a significant shift towards electrification, and we expect service-based offerings to become more prevalent. Good Energy has outlined a strategy to evolve in this direction, and a customer base that is likely to be more engaged, and/or more affluent, than the national average provides an excellent platform from which to leverage. However, the current offering is somewhat lacking in innovation, particularly in the domestic segment, and we suggest Good Energy needs to launch new products in 2021 if it aspires to niche leadership. Zap-Map and Zap-Pay pique our interest, and both inhabit a space where the government is keen to improve the consumer experience. Monetisation of what is currently a free-to-use app is a challenge, and we look to Zap-Map’s new management to set out a strategy for growth. Our rebuilt model provides segmental granularity, and we shift our valuation to a sum-of-the-parts approach. We take a conservative approach to valuing Zap-Map, but suggest that the current equity value is more than covered by generation and supply alone. Our target price is increased to 280p from 225p, pointing to a potential total return of c.48%. In our opinion, Good Energy offers an interesting play on the consumer end of the energy transition, and we re-iterate our Buy rating.
Centrica plc Good Energy Group PLC
Centrica reports FY20 on Thursday 25th February, and presentation slides will be available from 8am (LINK). We have previously commented on the positive trading statement issued on January 14th, but did not amend our estimates for the cessation of depreciation on the now disposed Direct Energy, nor continued strong trading and optimisation performance. Accordingly, we expect Centrica to report adjusted EPS ahead of our published 4.6p, and most likely above 5p/share. Looking forward into FY21, we see the evolution of customer numbers as important, as Centrica endeavours to get on a growth footing, but the current Covid-19 restrictions, and further down the line, rolling back of economic support measures, and possible tax rises, suggest the narrative on FY21 could be cautious. We also look for visibility as to the impact of the recent cold snap and high prices in the balancing market on Centrica’s supply business, an update on discussions with the pension trustees, and a view on when the dividend might be reinstated. Drax also reports FY20 on Thursday 25th February, and presentation slides will be available from 7am (LINK). Drax’s most recent trading statement was on 15th December, and consequently we expect little by way of surprise for FY20 (our EBITDA estimate is £399m), but we see initial guidance for FY21 as important. We expect Drax to announce that it will no longer progress plans for a CCGT at the Drax site, and we look for an update on the recently announced Pinnacle Renewable Energy acquisition. Comment on the possible positive benefit to Drax’s flexibility earnings as a consequence of the high balancing market prices seen during the recent cold snap and system tightness may also be forthcoming, although fuel and carbon cost will eat into the benefit. What is not now going to happen this week, is final determinations from the CMA in the PR19 appeals process, as the CMA has pushed the target date back to the week commencing 8th March. This has ramifications for the timing of any acquisitive move Pennon might seek to make in the regulated water space, but also the decisions to be made by energy companies as to whether to accept Ofgem’s RIIO-2 final determinations. The network companies have 20 working days from 3rd February to accept, or seek a CMA referral, so decisions will need to be taken by the middle of next week at the latest. We might yet see news flow this week. A crucial data point (the CMA’s view on the cost of equity) will now be absent, suggesting that the decision-making process is now even more difficult. However, we remain of the opinion that settling a number of issues via a CMA referral might well be the best course of action, for net zero and shareholders alike.
Where does supply fit in a net zero world The UK aims for net zero GHG emissions by 2050 and as part of its 10-point plan the government has also published a series of interim targets/ambitions. The focus so far has been on the implications for networks and generation but there should also be implications for energy supply. We conclude that Centrica would need to grow its market share (electricity and gas) in order just to maintain gross margins flat. We estimate that the group would need additional cost-cutting, beyond the 2020 measures, in order to remain profitable. Centrica''s customer offering and tech interface also need improvement and we therefore would expect some of the cost savings to be reinvested. Lessons from Spain? The UK supply market has been a leading indicator of developments for the rest of Europe. However, the substantial reduction in renewable LCOEs and the government''s more favourable approach towards renewables, leave the market open for new business models. The renewables plus customers approach has been favoured by a number of players in Spain and is yielding superior returns to renewables-only or customers-only models. The auction for new renewables capacity due in the UK late this year will give us a good indication of whether a similar model could be profitable in the country, disrupting customers-only incumbents such as Centrica. A services company? We believe cash flow and value for Centrica will be predominantly driven by the Home Services business rather than energy supply. The ongoing dispute with the GMB union is unhelpful in that regard, and could create headwinds to customer retention for 2021-22. We model a sustained margin improvement towards the 20% level but a flat top line beyond 2021 with risks to market disruption, for the time being, not taken into consideration. Reiterate Underperform We update our estimates for the group''s trading statement (lower debt than anticipated), our net zero...
Green Network Energy, a gas and electricity supplier with around 360,000 customers, and a small number of non-domestic customers, and Simplicity Energy, a domestic supplier with around 50,000 customers are ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose new suppliers to take on the customers of each. Green Network Energy is the largest supplier failure to date, and the two represent the 20th and 21st SOLR processes since January 2018, amounting to c.1.65m customers, c.6% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss-making entities. We have previously made it clear that we expected to see more supplier failures, so this is very much our thesis of consolidation in the GB supply market continuing to play out. We still believe that the trend will continue, both due to the financial challenges facing those suppliers which are loss-making, but also given the likely shift in customer demands as the energy transition gathers pace. The requirement for the 18 suppliers which took advantage of £65m of network deferrals to repay the amount by end March, could trigger further failures. Once again, we consider this latest shake out a positive for stronger players in the market, such as Centrica (Buy, TP 65p), and also for price comparison websites which are likely to see increased traffic as an enforced change of supplier is a clear trigger for a domestic consumer to review his/her supply arrangements.
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CMA consulting on specific elements of cost of capital – following submissions pursuant to the water PR19 appeal provisional determinations, the CMA is consulting on its updated thinking outlined in two working papers on specific elements of the cost of capital: the Cost of Debt and Choosing a point estimate for the Cost of Capital (LINK). Cost of debt – the CMA has updated its thinking on the cost of debt. For embedded debt, the CMA is now provisionally proposing a 15-year collapsing average approach suggesting a cost of embedded debt allowance estimate of 4.52% nominal (vs. 2.76% CPIH real in the provisional determinations). For new debt, the nominal estimate of the debt cost has been updated to 2.19% from 2.38% in the provisional determinations, with a point estimate of 20% weighting of new debt vs. 17% in the provisional determinations. Taken together and expressed in CPIH terms, this implies a cost of debt allowance of 2.12% vs. 2.45% in the provisional determinations. Cost of equity – the CMA has not updated on the cost of equity save for an updated judgement on where it believes it should land in the range: “…our updated judgement is to use a cost of equity of around 0.25% above the middle of our range. The final figure for the cost of equity will take account of our updated analysis of the risk-free rate, beta and the total market return as well as consideration of the responses to this consultation.” The CMA’s range in provisional determinations was 3.56%-5.60%, suggesting a point estimate of 4.83%, all other things being equal. WACC – the CMA has pointed to a c.0.3% reduction in WACC vs. provisional determinations, this being consistent with a 4.83% CPIH real cost of equity referred to above. RIIO-2 read across – Ofgem has previously alluded to a 20bp adjustment to headline water cost of equity numbers to account for the equity component of the 8bp retail margin deduction from the appointee level WACC. This would position the wholesale cost of equity for water at 4.63%, still higher than Ofgem’s 4.55% in final determinations. Furthermore, a cost of equity 25bp above the midpoint of Ofgem’s 3.85%-5.24% range would point to a cost of equity of 4.80%. So what now? – our focus continues to be on the cost of equity, and we continue to believe that energy should attract a higher return than water. Some of the gap has reduced given the CMA’s updated thinking, but we see updated estimates of the risk-free rate, beta and the total market return as being crucial factors as to whether there are CMA referrals from the energy networks. The CMA is still aiming to report of final determinations in mid-Feb.
Opt-in switching – a simple method of switching for customers at the end of a contract, presumably via a collective switch. Opt-out switching – unless customers choose not to, they are automatically switched to a new cheap tariff after their initial contract has ended. We need to see the detail of the testing that looks likely to be proposed, but our initial thoughts are: We could see an end or a reduction in ‘tease and squeeze’ tariffs => likely to make it difficult for small suppliers who initially price low and hope to raise prices. We expect more failures and further consolidation. The price point at the bottom of the market could move up as suppliers seek to price on a sustainable basis. It is likely that traffic to price comparison websites will reduce as a push factor is reduced as customers are more likely to think they are on a good deal. A challenge to the established suppliers with disengaged customers such as the legacy Big 5, as certain parts of the book could see lower prices. This will further the need to be smarter and more efficient. Ultimately, we continue to see the emergence of a market which moves away from the plain vanilla supply of electrons and molecules, and to innovative tariffs and bundled service offers. Centrica (Buy, TP 65p) has a broad foundation to deliver this, but we could well see further volatility in the share price until clear details of the trials are set out.
Final Determinations – Ofgem has published RIIO-2 final determinations (FD) for electricity transmission (ET), gas transmission (GT), gas distribution (GD), and the ESO this morning. There is a forest of paper to work through, a process that will take days, but we set out an initial high level view. Totex – as expected, baseline totex has moved up for ET, GT and GD (Figures 1-3 overleaf), and for NGET, the FD is £0.8bn above our modelled assumption; for GT it is £0.4bn above, although for SHET (SSE) it is £0.2bn below. We suggest that this could be worth c25p on our NG sum-of-the-parts. TIM – TIM % have moved higher in most instances, although, notably, for NGET it has fallen. Relief at a higher totex allowance is likely to be tempered by a blunt level of incentive (Figure 4). Business Plan Penalties – SHET and SPT (Iberdrola) have moved from a penalty to reward position, leaving NGET and NGGT as standout on the penalty side. We imagine that there will be a high level of anger at National Grid at this outcome (Figures 5 & 6). Allowed returns – allowed returns have moved upwards with the NGET/NGGT WACC at 2.81% CPIH real (vs. 2.63% at DD), and the SHET WACC at 2.69% vs. 2.47%. The allowed return on equity at 60% gearing has moved up to 4.3% (vs. 3.95%), but the flawed outperformance wedge of 25bps remains. At 55% gearing the allowed return is 4.02% (Figures 7 & 8). In line with our National Grid modelling – Our National Grid model assumes 4.04% at 55% gearing (equivalent to 4.33% at 60% gearing), and a WACC of 2.78%. Consensus WACC was 2.86%. Re-openers and Net Zero – we had expressed concern that the re-opener process was not sufficiently responsive, but Ofgem has brought forward additional mechanisms, and lowered the materiality threshold from 1% of baseline revenue to 0.5% (Figures 9-11). SSE’s strongly worded response – both National Grid and SSE issued brief statements this morning, with SSE’s more strongly worded: “…SSEN Transmission is very disappointed that Ofgem has not fully reflected the robust evidence – particularly that from the Competition and Markets Authority (CMA) provisional findings of the PR19 water price control appeal – in setting the financial parameters for RIIO‐T2, which SSEN Transmission expected to be at least in line with the CMA's provisional findings.” CMA referral a distinct possibility – we have long maintained that energy requires a higher return than water. Versus PR19, it does, but if the CMA outturns above (and the provisional determination was at 5.08%), then Ofgem has a problem, and we would expect that at least one network would appeal to the CMA. In turn, this could impede a fast start to RIIO-2 investment.
Ofgem tightens supplier rules Ofgem has published its decision for the ‘Supplier Licensing Review: Ongoing and exit arrangements’ consultation that closed in August. The aim of the consultation was to ensure that ‘appropriate protections are in place against poor customer service and financial instability’, and it sought to tighten up on ongoing monitoring and engagement, and arrangements for managing supplier failure and market exit. Measures to promote more responsible risk management, improve governance and increase accountability, increase market oversight, and new rules concerning exit arrangements when suppliers fail will be brought in on 22nd January, with Customer Supply Continuity Plans being effective from 18th March. We believe that these tougher requirements are supportive of our view that we are likely to see more market consolidation in the short to medium term. Is LNG on the block? A sale would be a further de-risking Bloomberg, citing the WSJ, has reported that Centrica is looking to sell its LNG portfolio. This business forms part of Centrica’s ET&M business, and includes various LNG contracts, such as the Cheniere contract, and other asset positions. The activity is not separately reported, and while some of the LNG contracts are out of the money, in the round, we believe that the LNG business is a negligible contributor to group financials. Given the refocussing of the group following the announced disposal of Direct Energy, the liquidity in the GB gas market, and basis risk from procuring $ denominated Henry Hub indexed gas and selling it into a NBP market, we argue that the rationale of Centrica being present in this activity has weakened with the passage of time. A disposal would help with de-risking, and would, subject to value, be something we would welcome. We also note that at FY19, Centrica’s CFO, now the CEO, when asked about non-core disposals replied “…we always keep our assets under review, so if there are assets in the portfolio that we either think somebody else would be a better owner of, or somebody approaches us and gives us a bid where we can't get that value from them, then we certainly have that conversation. We're not allergic to selling other things.” We see a sale as possibility.
Yesterday’s National Infrastructure Strategy is yet another step in the UK’s infrastructure-led green recovery. We are well and truly living in a green infrastructure age, which should in turn drive multi-year growth and investment opportunities. The clear message is that bold action is needed to transform the UK’s infrastructure to meet net zero by 2050 and climate change commitments. An Energy White Paper is to follow shortly, aimed at providing investors with clarity over the government’s plans. The Government is pursuing large-scale nuclear projects, subject to clear value for money. Further details to follow in the Energy White Paper, but again, no explicit mention of Sizewell C. A revenue mechanism for CCUS and hydrogen projects via new business models will be outlined next year. The Government has asked the National Infrastructure Commission to provide recommendations on the technologies and policies that should be deployed for greenhouse gas removal and the delivery of negative emissions. The Energy White Paper will include plans to legislate to introduce competition in onshore networks. The Government is to review the right long-term role and organisational structure for the Electricity System Operator. Is independence on the cards? A huge challenge for industry is to deliver 1.7m net zero ready heating systems per year by the early 2030s. A UK infrastructure bank is to be set up. The bank will co-invest alongside the private sector. There is a huge opportunity for pension funds to support UK infrastructure ambitions. Measures are being considered on removing barriers to infrastructure investment. Support is there for strong independent economic regulation, but with the possibility of some change, in order to deliver regulation fit for the 21st century. Plenty of publications in the 12-month pipeline, but the long awaited Energy White Paper could be the next stop on this long and exciting journey.
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More flesh has been put on the bones of the initial press release regarding The Ten Point Plan for a Green Industrial Revolution, with the publication of a more expansive document (link). The publication is still very broad brush, and we look to the Energy White Paper due to be published after next week’s spending review, but before the end of the year, for further granularity. The aim is to put the UK at the forefront of global markets for clean technology, which for electricity is likely to lead to significant investment needs over a multi-year period given suggestions that globally 83% of the $13.3tr of investment in electricity systems by 2050 could be in zero-carbon technologies. A Climate Ambition Summit will be held in December and, in addition to the White Paper, next year will see the development of multiple sectoral plans (Figure 2) to meet carbon budgets and the target of net zero by 2050. A Task Force Net Zero will be established, putting a systems approach at the heart of government thinking. We believe there are significant opportunities for those companies that are aligned with the direction of travel, and can deliver. The 40GW offshore wind target is supportive of the ambitions of the likes of SSE, Iberdrola, and others in respect of the GW themselves, but there are also positive implications for the likes of National Grid, Iberdrola, and SSE in respect of transmission connection and reinforcement requirements. Networks, including distribution (SSE, Iberdrola), will benefit from the acceleration of the rollout of charging infrastructure. Hydrogen will touch many parts, but we consider the direction of travel to be hugely beneficial to the likes of ITM Power, while a revenue model for CCUS might be a catalyst for Drax to advance its plans in this sphere, increasing post 2027 visibility. Energy supply is also set to benefit with the seismic shift in heat pump rollout offering Centrica tariff/home service opportunities, also fitting firmly with Good Energy’s strategy.
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1. Offshore wind – as previously announced, a 40GW offshore wind target by 2030. 2. Hydrogen – aim to generate 5GW of “low-carbon” hydrogen by 2030, with up to £500m invested to create a hydrogen neighbourhood in 2023, a hydrogen village by 2025, followed by a hydrogen town. 3. Nuclear – backing for nuclear power, including large scale, and £525m to develop small and advanced nuclear reactors, although, at this stage, no explicit backing for EDF’s Sizewell C project. 4. Electric Vehicles – investing £2.8bn in EVs, with £1.3bn to accelerate the roll-out of charging infrastructure, £0.6bn in grants to incentivise EV purchasing, and £500m to develop UK gigafactories. As widely trailed, the ban on the sales of new petrol and diesel cars will be brought forward to 2030, although the sale of hybrid cars will be allowed until 2035. 5. Public transport, cycling and walking – incentivising cycling and walking, and investing in low-carbon buses, with up to £5bn expected to be invested. 6. Jet Zero aviation and greener shipping – supporting difficult to decarbonise industries, with research projects for zero-emission planes and ships. £20m has been set aside for clean maritime innovations at sites including Orkney and Teesside. 7. Homes & public buildings – investing £1bn next year to make homes, schools and hospitals greener, warmer and more energy efficient, with a target to install 600,000 heat pumps every year by 2028. 8. Carbon capture – becoming a world-leader in CCUS, with a target to remove 10mt of carbon dioxide by 2030, backed by £1bn of government investment for clusters across the North, Wales & Scotland. 9. Nature – one year on from manifesto pledges from many political parties, tree planting is once again centre stage, with a commitment to plant 30,000 hectares of trees every year. 10. Innovation and finance – an ambition to make the City of London the global centre of green finance, and a £1bn energy innovation fund to help commercialise new-low carbon technologies.
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Ofwat has hit back hard at the CMA in response to the latter’s provisional determinations in the PR19 appeals process, suggesting that they undermine Ofwat’s ability to regulate effectively, and cause wider uncertainty across regulated industries. Most ire has been reserved for the CMA’s approach to setting WACC, in particular the cost of debt, upwards bias in the individual components of the cost of equity formation, and the ‘aiming up’ of the overall return. High gearing, leakage, incentives for efficient business plans, and the standard of evidence required for funding are the four other elements that give Ofwat the most concern, although we note that the summary overview has not pushed back against all the incremental totex provisionally allowed by the CMA. We do not expect the three listed water companies to seek interim determinations, but the CMA’s final determinations are still of huge importance to PR24 and beyond. If the CMA does not budge, applying its findings on WACC would add 7% to our Pennon valuation, 15% to our Severn Trent valuation, and 14% to our United Utilities valuation. Using Ofwat’s cost of debt, and the CMA’s cost of equity would point to value additions of 4%, 10%, and 9% respectively. We suggest that the balance of risk has an upwards skew to the PR19 position. In energy, the RIIO-2 open hearings have flagged the CMA report as an important contributor to the regulatory process, and in the interests of consistency across sectors, we therefore urge the CMA not to acquiesce to Ofwat’s request for an extension to the current timetable. Notwithstanding the success of Ofwat’s counterpunching, we continue to argue that energy is higher risk than water, something that Ofwat arguably alludes to in expressing a view on ‘aiming up’, “…‘aiming up’ on the WACC may be relevant in other sectors…where there is greater demand uncertainty and in order to provide stronger incentives for investors to accelerate discretionary investment”. We view our assumed cost of equity for RIIO-2 of 4.33% CPIH real at 60% gearing as prudent, and maintain our stance that Ofgem will have to move upwards on the cost of equity at December’s final determinations. On totex, our take from the open hearings is that movement on totex allowances is now a foregone conclusion.
Tonik Energy, a gas and electricity supplier with around 130,000 customers, is ceasing to trade. Ofgem is stepping in, and will now run the supplier of last resort (SOLR) process to choose a new supplier to take on all of Tonik’s customers. This latest failure is the 18th SOLR process since January 2018, amounting to c.1.2m customers, c4% of the market. Additionally, there have been trade sales, a number of which involved the customer books of loss making entities. Tonik Energy was one of the seven companies with outstanding RO & FIT obligations that were served by Ofgem last week with a Notice of Proposal to issue a Final Order. Of the others, the customers of Co-operative Energy & Flow Energy are with Octopus Energy, although the liability sits with the Co-op. Likewise, the customers of Robin Hood Energy were acquired by British Gas, with the liability sitting with Nottingham City Council. This leaves Nabuh Energy, Symbio Energy & MA Energy, albeit MA Energy is a non-domestic supplier. We note that Nabuh Energy & Symbio Energy both have low Trust Pilot scores at 1.5/5 and 2.7/5 respectively, and suggest that a low score could be indicative of operational issues. Ofgem’s review as to whether COVID-19 has materially impacted suppliers’ costs is ongoing, and, in our view, their view on cost direction suggests that the dark winter is coming. The tariff cap mechanism and any tweaks will protect the default market, but higher costs in the active market will need to be recovered through price rises, or borne by suppliers. For some, this might be too much to bear. We continue to believe that the GB supply market will consolidate, both due to the financial challenges facing those suppliers who are loss-making, but also given the likely shift in customer demands as the energy transition gathers. We consider this shake out a positive for stronger players in the market such as Centrica (Buy, TP 55p), and also for price comparison websites which are likely to see increased tariff as an enforced change of supplier is a clear trigger for a domestic consumer to review his/her supply arrangements.
CNA DRX GOOD IBE IBE NG/ SSE
Ofgem is undertaking a review to assess whether COVID-19 has materially impacted suppliers’ costs (Figure 1) and, if so, how it might adjust the tariff cap methodology. Its initial view is that the only material costs that might need to be adjusted for are additional debt related costs. Ofgem is seeking to publish a decision at the end of January 2021, so that any changes will have effect from 1 April 2021 (the sixth cap period), with an intention for at least one further review as COVID-19 impacts evolve. Review limited to efficient COVID-19 related costs incurred supplying domestic default tariff customers, with most of the impacts of COVID-19 excl. debt-related costs largely addressed within the existing cap methodology. COVID-19 related costs of supplying prepayment meter (PPM) customers on default tariffs will be included in the review. The initial view is that COVID-19 related cost adjustments can be placed ‘on top’ of the existing cap level, rather than amending individual cap allowance methodologies. The proposal is for an initial adjustment via an Adjustment Allowance in April 2021, informed by data to September 2021, and most likely calculated ex-post, or float/true-up, but with a preference for the latter. Potential debt cost increases from late payment impact on working capital, non-payment, and additional admin costs, with the initial view that some additional allowance would be required for costs incurred in cap periods four, five and six (April 2020 to September 2021), and set using a lower quartile benchmark. This recognises the risk that more severe COVID-19 impacts will be seen as government support schemes roll off. Less likely to be ongoing additional costs in respect of PPM customers, but the proposal is to treat additional one-off costs specific to lock-down months via an ex-post adjustment in cap period six. Policy costs impacted by COVID-19, but viewed as temporary and sufficiently accounted for by the existing cap methodology (Figure 2). The initial view is that no adjustments are necessary for any of the other cost allowances in the cap, although there are costs on which Ofgem has not formed a view. Ofgem intends to continue to monitor the impacts of COVID-19 on these costs and may revisit them in subsequent reviews. The reference to additional gross margin from increased domestic supply volumes could be interpreted as an intention to look at any ultimate adjustments in the round. On balance, we consider these proposals as positive for suppliers, which may well be facing elevated bad debt risk in the domestic segment as government support schemes roll off. Centrica is most exposed to GB domestic supply under our coverage.
Historically, regulation was arguably a ‘negotiation’ between the regulator and the regulated entities, but for RIIO-2, Ofgem introduced a new dimension of enhanced engagement, which for transmission involved companies establishing independent User Groups, with Customer Engagement Groups in distribution. Although Ofgem retains ultimate decision-making responsibility, it has previously stated that “evidence from enhanced engagement will be one of the key inputs”. It is clear from the network company comments post July’s draft determinations that there is a wide chasm between the companies and Ofgem, but in any negotiation process, a divergence of views at this stage between parties with differing vested interests is not unexpected. The User Groups are, however, independent, and therefore a very important voice if Ofgem stands behind its desire to see enhanced stakeholder engagement. If this is no longer the case, then all the time and effort put in by these groups will have been wasted. National Grid’s Independent User Groups for electricity and gas transmission have published a joint response to Ofgem’s RIIO-2 draft determinations, and we are struck by the degree of dissatisfaction emanating from the document; “…we can only emphasise that, in the DD, the clear lack of recognition of stakeholder insights and priorities, and of the role of enhanced engagement, does not reflect the good practice that Ofgem has required the network companies to demonstrate.” Other areas of pushback include cost justification, an area where an axe was taken to totex in business plan submissions: “…we are disappointed with the general approach taken in the DD which seems overly engineering-focused, short-term in some cases, siloed and often lacking in context and/or the impact and consequences of Ofgem’s decisions.” …the needs of future consumers: “The DD is also not clear on the extent and thoroughness of Ofgem’s insights into the needs of future consumers, leaving us to question the longer-term consumer bill impacts and therefore the real value to consumers rather than the value at the end of the five years”; and… …Net Zero: “…without answering the questions and concerns that we, and others, are raising, and setting out a clear delivery plan, again as a matter of urgency, we would be concerned that RIIO-2 becomes a blocker, rather than an enabler, for achieving the 2050 Net Zero position.”
British Gas to buy customer book of Robin Hood Energy Centrica has announced that British Gas is to acquire the energy supply customers of Robin Hood Energy for an undisclosed sum. Robin Hood Energy, Nottingham City Council’s energy company, has been struggling for a while, and a meeting of the council was held last week to decide on the next steps for the energy company following a critical external auditor’s report. The transaction is expected to complete on 16 September. Supportive of our view that there will be failures and/or consolidation in the supply market A sale does not therefore come as a surprise and is supportive of our view that we will see failures and consolidation in the supply space, and ultimately the emergence of a more ‘sensible’ market. Cheap way to acquire customers if they stay It is clearly unhelpful that no price is disclosed, but in theory, it’s a cheap way to acquire customers (if they stay), and fits with Centrica’s desire to grow customer numbers, albeit small in the context of British Gas. According to media reports, 250 employees of Robin Hood Energy are being made redundant, supportive of the benefits of acquiring customers is this way. Robin Hood Energy has 112,000 domestic and 2,600 non-domestic customers across 10,000 sites.
Wholesale cost allowance adjustments: Following British Gas’ successful challenge, the High Court (Nov 19) concluded that Ofgem should reconsider the wholesale allowance for the first cap period of the default tariff cap. Following a consultation, Ofgem has decided to include an adjustment allowance of £7.98 (gas) and £2.64 (electricity) per customer with benchmark consumption in the fifth cap period (between 1 October 2020 and 31 March 2021). In annualised terms, the adjustment will increase the published cap levels for gas and electricity by £10.71 and £4.56 respectively. In contrast to its May 2020 proposal, Ofgem has decided to set the adjustment allowance on a collective basis to reflect the lower numbers on default tariffs. The adjustments are 35% (gas) and 51% (electricity) higher than those proposed in May, in what we view as a minor victory for suppliers. Prepayment meter (PPM) cap: The PPM cap covers c.4m customers, and was due to expire at year-end. Ofgem is extending protection by including a new cap level within the default tariff cap. For cap periods 5 and 6 (1 October 2020 to 31 March 2021 and 1 April 2021 to 30 September 2021 respectively), the PPM cap will be set at the same level that would have been calculated by the current PPM cap methodology, effected via the PPM uplift, and the non-pass-through Smart Metering Net Cost Change (SMNCC) for PPM customers. The indication of a PPM cap through to September 2021 at the earliest is a clear indication that Ofgem will be recommending that the default tariff cap is extended beyond year-end, with the recommendation most likely on Friday, alongside the cap level. Smart metering costs: There is an allowance in the default tariff cap to account for the net financial impact of the smart meter rollout on suppliers: the non-pass-through Smart Metering Net Cost Change (“SMNCC”) allowance. The SMNCC has been set at £17.12 on a dual fuel basis for the fifth cap period, including an amount for potentially sunk installation costs due to COVID-19. The SNMCC for the sixth cap period has been frozen at the same level as the fifth cap period. This delays a reduction in the SMNCC, providing time for Ofgem to consider the outcome of BEIS’ autumn consultation on the tolerance levels for its new rollout framework, the effects on rollout performance of basing the SMNCC on an average rollout profile, and the impact on customers if some suppliers reduced their rollout as a result of the SMNCC level. The freeze in cap period six vs. a reduction is a minor respite for suppliers.
Action Team In less than 4 months and in the middle of a global recession and a pandemic, the new Centrica management team has announced an acceleration of the cost-cutting program, a simplification of the business and an exit from the US. Such swift and shareholder-friendly action marks in our view the start of a new era, with Centrica focused on execution and performance rather than size. But pressures remain on the business Although H1 results were above our expectations, this was on better prop trading and lower DandA run rate in upstream. The exit from the US, although at a price 10% above our SOTP, has the drawback of leaving the group fully exposed to what we view as a tougher UK market. Customer numbers were down y-o-y and slightly below our expectations on all divisions. With the real economic impact on domestic and business customers yet to be felt (September is usually a key month for switching) and the bulk of the restructuring yet to be done, there remains material execution risk. The GBP2.4bn pension question In CENTRICA: Point of maximum uncertainty we highlighted the risk of a GBP900m increase in the pension deficit at the 2021 triennial review. Management confirmed that the roll-forward size of the deficit stands today at GBP2.4bn vs GBP1.4bn previously. Although we do not presume to know what the agreement with the trustees will involve, the fact that post the US disposal FCF will be ca. 20% lower all else equal, leads us to expect an increase in upfront payment. In line with practice for UK companies, we assume the GBP2.4bn in our SOTP, instead of the lower IFRS16 figure. Time to think beyond Utilities? Centrica did not provide any guidance for the FY, is not paying a dividend, is looking to exit Upstream energy and ~40% of adj. Op. Profit comes from services / solutions. Perhaps it should be seen as a Business Service for longer term investors to be attracted to the equity story. We value the non-Upstream business on...
1H20 likely to be significantly impacted by Covid-19, with a likely spill into 2H as the impact of the ending of furlough support feeds through into the broader economy. We look for a c.41% fall in adjusted operating profit, and a c.45% drop in EPS. We look for Centrica Business (to be disbanded) to be loss-making, hit by volume declines, bad debts, and hedge position unwinding, although the trading business should have benefitted from market volatility. Centrica Consumer (also to be disbanded) could post profit growth, but with 1H19 hit by a £70m one-off, the underlying direction looks to be negative, with potential challenges in 2H. Upstream activities are for sale, but for now, are a volatile contributor to earnings. Hedging should offer some protection in 1H, which we expect to be in positive territory, with 2H loss-making despite prices bouncing off lows earlier in the year. Extended outages at the nuclear fleet are a 2H negative. July 24th is about more than 1H numbers, or indeed 2H expectations. We view 2020 as a lost year, but Centrica has accelerated cost reduction/restructuring, and we look for flesh to be put on the bones, as well as an elaboration of the strategic rationale of British Gas X, an update on the upstream disposal processes, and a pathway to restoring dividends.
Major restructuring could be positive for FY21E earnings Centrica has announced plans for a significant restructuring of the business that will see fewer customer-facing business units, all reporting to the CEO, and an accelerated cost reduction plan that will see a headcount reduction of c5,000, of which over half will be from management levels. The senior leadership team will be halved from the current level of 40. The majority of the restructuring will take place in 2020, and we suggest that efficiency savings in FY21 could top £400m, up from a previously communicated c£300m. Restructuring spend will be accelerated relative to previous expectations, but should fall within the previously communicated envelope, with Centrica confident this can be funded. Purging of the old guard continues, new CFO appointed Sarwijt Sambhi (Chief Executive, Centrica Consumer), and Richard Hookway (Chief Executive, Centrica Business) have stepped down from the Board today, and will leave Centrica at the end of July. Johnathan Ford has joined today as CFO, his most recent role having been COO and CFO of Homeserve plc, a position he held up to December 2018. Johnathan brings with him experience of home services, while the departure of Sarwijt, with 19 years of experience at Centrica, continues the purging of the old guard. Significant change was needed, and under the leadership of Chris O’Shea, recently appointed as CEO, this is now beginning to come through. Beefing up British Gas makes sense on the energy transition journey A business reorganisation sees Centrica Consumer and Centrica Business disbanded as divisions. Home Solutions and SMEs will be bundled into British Gas in a move that we believe makes sense given our view of what customers might want as the energy transition accelerates. It is clear that British Gas is the core of Centrica’s strategy, and by leaving the North American businesses in their current form, a disposal of these activities would arguably be easier to execute. Establishing a digital only challenger brand takes the fight to the smaller suppliers, some of whom, might not have sustainable business models, but the risk of cannibalisation of the existing customer base cannot be discounted. Continued overleaf
The issue of suppliers being exposed to the double whammy of volume declines and heightened bad debt risk is something we have discussed at length, repeatedly suggesting that a solution is needed. In UK Utilities, ‘Dividends at risk’ (2nd April), we commented; “Be under no illusion, all actors across the value chain will be impacted, irrespective of their regulatory and remuneration frameworks, and government/Ofgem/Ofwat/industry need to work together urgently to find a solution that ensures continued provision of essential services to all, but one that, to the best of their ability, preserves regulatory integrity.” …and in UK Electric Utilities, ‘CV19 impacts the whole value chain’ (20 April), we offered some suggestions as to how help could be structured; “As we have repeatedly said, government/Ofgem/industry will need to work together to find a solution that ensures continuity of vital service provision, protects the vulnerable, and maintains regulatory integrity. A loan to suppliers has been mentioned as one possible solution, but in our opinion, delaying or re-phasing certain costs could be another.” Industry has responded, with SSE proposing a MOD (currently under discussion) that would see additional BSUOS costs arising from Covid-19 (c£500m) deferred to charging year 2021/22, while BEIS is consulting on deferring certain supplier obligations for CfD payments until 1Q21. Ofgem asked the network companies to develop schemes to provide relief to suppliers, and has published an open letter setting out the common features of what has been agreed by way of the network companies providing liquidity to certain electricity suppliers and gas shippers. The key points are set out overleaf, but seemingly do not apply to electricity transmission charges at the moment, and with repayment of any deferrals to be made by March 2021, this should not impact National Grid and SSE’s earnings, unless a supplier defaults on the deferral. Ofgem will be monitoring to guard against abuse. Ofgem has indicated that it does not have sufficient evidence to justify amending the price cap to reflect increased bad debts for the next six-month cap period starting in October 2020, but has held open the prospect of changes further out, if there is a material change in suppliers’ costs as a result of COVID-19. We view the form of words as indicating that Ofgem is unlikely to recommend that the cap is removed at year-end, but even the possibility of there being flex to address elevated bad debt levels is a minor positive for the likes of Centrica.
The EC has put forward its proposal for a major recovery plan, which includes a proposal to create a €750bn recovery instrument, Next Generation EU, for measures over the period 2021-2024. The largest part of the Next Generation EU will be directed towards a Recovery and Resilience Facility of €560bn, which will have green and digital transitions at its heart, with these seen as the defining challenges of this generation. The budget document states “Investing in a large scale renovation wave, in renewable energies and clean hydrogen solutions, clean transport, sustainable food and a smart circular economy has enormous potential to get Europe’s economy growing.” Recovery and Resilience Facility money will be channelled through programmes such as the European Green Deal, with (i) A massive renovation wave of buildings and infrastructure and a more circular economy, bringing local jobs; (ii) Rolling out renewable energy projects, especially wind, solar and kick-starting a clean hydrogen economy in Europe; and (iii) Cleaner transport and logistics, including the installation of one million charging points for electric vehicles and a boost for rail travel and clean mobility in cities and regions. Sustainable management of the repayment of funds raised under Next Generation EU is seen as strengthening the case for fundamental reform of EU budget financing, and proposals put forward in the budget document include carbon taxes and taxes on non-recycled plastics packaging waste. The European Commission is looking to reach a political agreement at the level of the European Council by July. We consider that today’s package is clearly supportive of renewables, the energy transition and the circular economy, themes which we expect will also be central to rebuilding the UK economy. Companies with significant renewables exposure include EDP, Enel, Iberdrola, Orsted, RWE, and SSE. National Grid could benefit from increased investment requirements from greening the energy system, with Centrica well placed to benefit from an increased need for energy solutions as buildings are renovated, while Renewi’s strategy is predicated on the circular economy.
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Electralink has published switching data for electricity change of supplier (CoS) events in April, the first full month of switching data since Covid-19 lockdown was imposed. 481k switches completed in April (Figure 1), 19% less than in March 2020, and 28% below the all-time record of 670k in April 2019. With 712k switches started in March, and with daily CoS events raised in March trending down over the months, it may well be the case that switches are taking longer to complete given workforce disruption due to Covid-19. 498k CoS were started in April (Figure 2), 30% less than in March 2020, and 26% down on the corresponding last year. This is the lowest number of switches started since December 2018, and the lowest for April since 2017. We are not surprised to see switching levels falling given the absence of doorstep selling, and a drop in telesales as a consequence of Covid-19. A £17 reduction in the default tariff cap in April 2020 vs. a £117 increase in April 2019 also represents a considerably reduced push factor for switching. Looked at on a weekly basis (Figure 3), switching levels in the last three years have only been this low, or lower, during the run up to Christmas, and those sunny days of late June/early July 2018 during the Football World Cup. It appears that consumer behaviour is focussed on matters other than the household utilities. Analysed by switching behaviour (Figure 4), switches away from the Big 6 to challenger brands, or from challenger brand to challenger brand fell by more than the falls in switching levels between the Big 6, and from challenger brands to the Big 6. Net gains by challenger brands were 88k, below the 110k level seen in the previous two months, and considerably below the 252k seen in April 2019. This appears supportive of our view that big supplier customer haemorrhaging is slowing, a potential benefit to Centrica, although we note that switches to the sub 250k customer group actually went up.
The Chairman of the Committee on Climate Change (CCC), and the Chair of the CCC’s Adaptation Committee have written to Boris Johnson and a host of ministers to set out how effective climate policy can, and should, play a part in rebuilding the economy after the Covid-19 crisis. The full letter can be accessed via this link, but we highlight a number of suggestions that have relevance for the UK utility space, referencing stocks under our coverage where appropriate. Investments in low-carbon and climate-resilient infrastructure – the CCC has previously suggested investments to reduce emissions, and is calling upon government to act to bring these forward without direct public funding, or with co-financing. We suggest that renewables, network and EV infrastructure could form part of this, and it is clear that the energy industry is part of the solution. Indeed, the CCC specifically references significantly strengthening electricity networks (National Grid, SSE, Iberdrola), co-operative onshoring of offshore wind energy (possible onshore transmission reinforcement needs – National Grid), hydrogen and CCS infrastructure (Drax, National Grid). Shifting long-term behaviours – Government could encourage more home working, something we believe will be necessary in big cities given the inability to socially distance on public transport. We see this as a medium-term driver for energy services, and innovative tariff offerings, with a move away from the commoditised provision of electrons and molecules. We suggest that this will favour better capitalised suppliers (Centrica) which can invest in new offerings, and have the bandwidth to do so. Fairness – we expect that we will see an expanded definition of vulnerability going forward, and fairness will need to be embedded in future policy. The CCC suggests that the benefits of acting on climate change must be shared widely, and the costs must not burden those who are least able to pay. In our opinion, paying for many environmental policies via the electricity bill might have to be reviewed, and alternative collection mechanisms considered. Strengthened incentives – particular mention has been made of the UK’s future carbon pricing mechanism, and the need for a well-designed floor price. Clarity in this respect would be positive for renewables obligation generation (Drax, SSE).
We hosted a call last week on the GB retail energy market with Mary Starks. the Executive Director of Consumers and Markets at Ofgem. Mary outlined the backdrop which has seen significant new entry in the retail market, but also supplier failure, albeit with the benefits of increased competition falling unequally, and a two-tier market continuing to exist, even in a price cap world. Ofgem is concerned about the sustainability of some pricing models, and the financial stability of some suppliers, and has already moved to tighten entry requirements. The consultation on ongoing requirements and exit arrangements has closed, but due to Covid-19 the statutory consultation has been delayed until stakeholders have the capacity to engage. Regarding the impact of Covid-19, Ofgem is in the process of making clear to suppliers what its key priorities are, and those which are of lesser importance at the moment; clearly there is an expectation of providing assistance to the most vulnerable customers. In terms of intervention into energy markets, Ofgem believe the government’s first preference is to encourage usage of its general economic measures to protect businesses and consumers, with sector-specific interventions only considered by way of fall back if needed. That said, the financial health of suppliers is being monitored closely given the disruption of Covid-19, and a number of options have been worked up if Ofgem needs to act, although the trigger points have not yet been met to pull the levers. The SOLR process has been well tested over the past two years, and while there is no specific threshold, the special administration regime exists in cases where SOLR is not practicable. This has never been used, but has been rehearsed. There is no evidence on the impact of Covid-19 on switching levels, but in our opinion, in April these will be below what would have been likely under normal course of business as doorstep sales have ceased, and direct selling via telesales will have dropped as suppliers focus on servicing existing customers. Ofgem’s consultation on reconsidering the wholesale allowance in the first period of the tariff cap closed in February. This is not work that has been rescheduled due to Covid-19, and proposals for statutory consultation are expected to be published at the end of May. Ofgem sees its role as making it easier for customers to switch, it is keen to see nudge thinking around decarbonisation, but wants to see companies come up with innovative solutions and good value proposals to drive this. EVs, smart heating, demand side management, and storage were all mentioned, and this tallies with our view that the supply needs to, and will, move away from a model based on the commoditised provision of electrons and molecules.
Industrial and commercial demand for electricity and gas has fallen markedly in lockdown, and the exit strategy will define the annualised impact – we suggest declines of c8% for both in 2020. Power prices have broadly rebounded to pre-lockdown levels, but remain restrained by subdued gas prices, particularly at the short-end of the curve. Suppliers are most exposed to the impact of volume declines and bad debt risk. We could see more supplier failures, and suggest that a collaborative approach from government/Ofgem/industry is needed to find a solution that protects the vulnerable, and preserves regulatory integrity. Networks are exposed to volume risk, and across both electricity and gas the impact could be c£0.5bn, albeit recovered two years later if current regulatory arrangements hold firm. FY20 looks set to be cataclysmic for Centrica’s EPS, and we cut our DPS estimate to 3p/share, with the previous 5p/share level not reached until FY24E. Our target price falls to 55p, but we consider the damage is already in the share price, and maintain our Buy rating. Generation is the driver of value for Drax, but B2B supply exposure could hit FY20 EPS, which we have cut by 23%. Our target price is lowered to 320p, but we continue to see Drax as well positioned in a world that will need flexible generation. Buy rating reiterated. National Grid’s definition of underlying EPS excludes timing differences, suggesting volume shortfalls are an issue of cash flow phasing, although the risk of bad debts in the US see our FY20E and FY21E EPS fall by c4%. Our target price is nudged down to 980p, and we maintain our Buy rating. SSE may have exited GB domestic retail, but it remains exposed on the business side. We bring down our FY21E EPS by 10%, and with payout ratios looking uncomfortably high under the communicated dividend policy, now assume a flat 80p/share dividend through FY23E. Our target price lowered to 1,300p, and Hold rating reiterated.
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CNA DRX NG/ SSE
We have previously commented that the double whammy of falling volumes and rising bad debts will see an under-recovery of revenues at an industry level, and that all actors on the value chain will be impacted, irrespective of their regulatory and remuneration frameworks. We called upon government/regulators/industry to urgently work together to find a solution that not only provides continuity of essential service provision, but also preserves regulatory integrity. We also questioned whether dividends could be at risk. We hear and understand clearly that in network utilities, a sizeable part of the shareholder base comprises pension funds, charities, and individuals, many of whom are attracted by the dividend paying credentials of the individual stocks. But, according to the Sunday Times, the water companies, through the trade body Water UK, have lobbied Ofwat for a financial bailout in the form of a higher return, and leniency on ODI penalties. This follows a request from the energy industry for a £100m a month loan scheme, which according to The Daily Telegraph has been rebuffed by ministers. These are unprecedented times, but one word continually springs to mind, and that is legitimacy. With Labour’s new leader, Sir Keir Starmer, supportive of common ownership of energy and water, the nationalisation debate will raise its head at some stage, and sustaining legitimacy today and legitimacy tomorrow, is paramount for the longer-term positioning of private utilities. There will be tough decisions for boards to take, and the viewpoints of all stakeholders will need to be heard, but if there are industry-specific bailouts, we struggle to see business as usual for dividends. Legitimacy, legitimacy, legitimacy.
Suppliers in energy and water are in part collection agents for the wider value chain, and if volumes are falling (business) and bad debts rising (household and business), cash collection is falling, and there will be under-recovery of revenues at an industry level. Spreading fixed costs across a reduced volume base exacerbates the problem. Be under no illusion, all actors across the value chain will be impacted, irrespective of their regulatory and remuneration frameworks, and government/Ofgem/Ofwat/industry need to work together urgently to find a solution that ensures continued provision of essential services to all, but one that, to the best of their ability, preserves regulatory integrity. For example, would it be possible for Ofgem to immediately cut RIIO-1 allowed returns, with a guarantee that the foregone revenue would be recovered over the five-year RIIO-2 period? Ofgem could dust off work on the cash flow floor if there are financeability challenges. Centrica has announced the cancellation of its 3.5p final dividend for FY19, and National Grid has warned that, in respect of the final dividend, it will “take into account expected business performance and regulatory developments, including an assessment of the impact of COVID-19”. SSE indicated last Friday that although the Board still intends to recommend a full-year dividend of 80p, the timing could be reconsidered. We now question whether the 56p will be paid in full, if indeed at all. Drax’s final dividend of 9.5p is due to be paid on 15th May, and is subject to approval at the AGM on 22nd April. We question whether it will now be paid in full, if indeed at all. In water, Severn Trent and United Utilities have already set out AMP7 dividend policies, with Pennon due to elaborate on 4th June. In a recent note, we suggested that the right balance was needed when the time comes. We now suggest that this time will come a lot sooner, and that each company will need to think very carefully about the level of its final dividend, at the very least from a legitimacy point of view.
Ofwat’s CEO wrote to all water company CEOs yesterday setting out expectations for the industry response to Covid-19, and we highlight three sentences from the letter. “I would also like to see all companies consider whether they can go further to ease the financial burden on households, including by considering opportunities to increase financial assistance and by adopting suitably supportive and flexible payment and debt collections practices.” “We will consider the need for any ex post adjustments to our regulatory system following an in-the-round assessment as part of our normal reconciliation process.” “A reasonable and pragmatic approach to the collection of wholesale charges from retailers who may be facing difficulties in obtaining payment from their customers.” The message on prioritising the delivery of core services in these unprecedented times was echoed by Ofgem’s CEO who made it clear a pragmatic approach to regulatory compliance will be taken; “Where companies can demonstrate that any compliance issues have resulted from prioritising efforts to protect customers and security of supply, we will take full account of this in any decisions we take.” Ofgem’s message followed on from an agreement between BEIS and the domestic energy suppliers to provide a broader range of payment options for prepayment customers, a suspension of credit meter disconnections, putting in place support measures for the vulnerable, as well as for any energy customer in financial distress. The suppliers and network companies occupy a unique place in the economy, and are arguably public/private crossovers. There is no doubt that collectively they will step up and deliver. In practical terms, we would not be surprised to see a tick up in bad debt levels, with the pressure being felt more acutely by thinly capitalised new entrants. We expect more market exits through both Ofgem’s SoLR process and trade sales. Switching levels could fall, as consumers stick with what they know, and suppliers use staff to focus on priority customers. This may well see less pricing pressure for the likes of Centrica who have been competing to retain customers. Activities that require human proximity such as smart meter installations will be impacted. Installation rates could fall, albeit with lower risk of regulatory issues. For those seeking safe havens, network utilities (NG.L, PNN.L, SVT.L, UU.L) should be best placed given volume true-ups.
Uncertainty sweeps the nation, commodities/currency are extremely volatile; we flag moving parts for Centrica, and will revisit earnings in due course. It is too early for meaningful data on changing demand patterns, but we would expect upwards pressure on residential demand, and downwards on I&C, particularly in SMEs where Centrica has most of its UK business exposure. Buying additional volumes at low prices to service additional residential demand is earnings positive, although direct debit payments point to limited short-term cash flow impact. Centrica hedges 90-95% of expected demand in the business segment, and volume drops of magnitude could trigger a need to place volume back on the market, working in the opposite direction to residential. Bad debts could rise, but this is an industry-wide issue, and government measures to support businesses are a driver of the balance between timing impacts and possible non-payment. Most of energy services is on contract, so we see little immediate impact, but with Centrica having to prioritise work, the risk is that annual servicing is delayed, which in turn might impact the customer experience and influence renewal decisions. Switching levels could fall as customers stick with what they know, fearful of difficulties in the switching process at a time of workforce disruption. Earnings risk from lower oil. Without recovery, the c$30/bbl drop since February could hit FY20E EPS by c.0.6p, and FY21E by 1.5p. We expect Spirit to trim capex. Power (nuclear) and gas prices have moved less markedly since mid-Feb, albeit downwards. Potential exposure here looks less marked for now. We see little by way of refinancing needs in near-term (see Figure 1).
Infrastructure: National Infrastructure Strategy to be published in spring. Innovation/R&D: Investing over £900m to ensure UK businesses are leading the way in high-potential technologies including commercialising nuclear fusion technology. A portion of this funding contributes to a wider investment of up to £1bn to develop UK supply chains for the large-scale production of electric vehicles, as announced in September. Greener economy: HMT will publish two reviews this year, one into the economic costs and opportunities of reaching net zero, the other into the economics of biodiversity. CCS: CCS is important to decarbonising both power and industry, and can provide flexible low carbon power and decarbonise many industrial processes, whilst also offering the option for negative emissions at scale. A CCS Infrastructure Fund of least £800m will establish CCS in at least two UK sites, one by the mid-2020s, a second by 2030. Consumer subsidies to support the construction of the UK’s first CCS power plant could benefit Drax. Decarbonising heat: Accelerating the greening of the gas grid with a new support scheme for biomethane, funded by a Green Gas Levy. Support for the installation of heat pumps and biomass boilers by introducing a Low Carbon Heat Support Scheme backed by £100m of new Exchequer funding. Funding for the Heat Networks Investment Project extended for a further year to 2022, with £270m of new funding to enable new and existing heat networks to adopt low carbon heat sources. Electrification of industry: Climate Change Levy on gas raised in 2022-23 and 2023-24 (whilst freezing the rate on electricity). EV charging: £500m over the next five years to support the rollout of a fast-charging network for EVs, with drivers <30 miles from a rapid charging station. This will include a Rapid Charging Fund to help businesses with the cost of connecting fast charge points to the electricity grid. OLEV to complete a comprehensive electric vehicle charging infrastructure review. Carbon price support (CPS) rate: The government will freeze the rate of the CPS at £18/t CO2 in 2021-22. Alongside wider carbon pricing policies, this will continue to encourage decarbonisation of the power sector, and is consistent with our modelling. Plastics tax :The government will introduce a new Plastic Packaging Tax from April 2022 set at £200/t of plastic packaging with less than 30% recycled plastic. Economic regulation: Commitment to maintaining strong, independent regulation. NIC ‘Strategic investment and public confidence’ report welcomed, but a view that regulation may need updating in some areas to address 21st century challenges. The government will respond in full later this year.
The T-4 Capacity Market (CM) for delivery year 2023/24 cleared at £15.97/kW/year (2018/19 money). This is markedly higher than our assumption of a £7.50/kW/year clearing price, and a clearing price of £6.44 (2017/18 money) for delivery year 2022/23 in the recent T-3 auction. A breakdown by technology is shown in Figure 2, and it can be seen that coal clings on (three units at Uniper’s Ratcliffe plant), four nuclear units (two at Hunterston and two at Heysham) owned by EDF (80%)/Centrica (20%) failed to secure contracts, and one CCGT (SSE’s Keadby plant) secured a 15-year new build CM agreement. c.7GW exited the auction in round 11, and is possible that the nuclear plant was bid in such a way to sacrifice capacity to maximise revenue. This provides mitigation for EDF/Centrica in the ongoing nuclear sale process. The real winners of such a strategy are those who received contracts for a significant proportion of entered capacity. We highlight Drax which received CM contracts for 2,333MW of capacity, slightly above the 2,246MW assumed in our model. As we expected, Drax did not secure new build contracts for its OCGT projects, but we do not consider these plants to be key to the investment case. Should this level of CM pricing be maintained in real terms in future auctions, then theoretically it could be worth 68p/share on our valuation, but more importantly, we consider the CM to be a hedge against power price pressure for capacity with high de-rating factors, such as Drax’s CCGTs, the Cruachan pumped storage, and from 2027, the biomass units at Drax. This hedge is not present for renewable technologies such as onshore wind, which has a low de-rating factor. SSE is exposed in this latter respect, but the new build contract for Keadby, already under construction, is a positive, and provides multi-year revenue visibility for this project.
We cut EPS by 9.6% and 7.9% for FY20E and FY21E respectively, but weak commodities are the driver, not the underlying consumer business, which is showing signs of moving in the right direction. With customer numbers stabilising in UK supply, we see per account margins growing in UK Home, driven by growth in services and cost reduction. We expect the UK supply market to slowly evolve from the provision of electrons and molecules to the service provision of heat, light and mobility. Centrica’s broader offering should confer it an advantage. Turning North American Business around is a key part of Centrica’s strategy. There are signs of recovery, which we expect should continue into 2020. Commodity exposure represents an uncertainty, but the risk is largely within businesses that are for sale. Progress towards the disposals of Spirit and nuclear should de-risk underlying earnings through accounting reclassification, with possible accretion once the disposals are completed. The CEO search rumbles on, and is a hindrance given an element of strategic uncertainty, but we struggle to see a new CEO wanting to retain the upstream presence. We forecast a flat dividend in FY20E, with moderate growth thereafter, and view the prospective 6.8% yield as attractive. For the first time, we believe that the positives outweigh the negatives and, with an unchanged 90p target price, we upgrade to Buy.
CNA GAMA GHH RECKIT RKT
Four companies, Anglian Water, Bristol Water, Northumbrian Water, and Yorkshire Water have rejected Ofwat’s PR19 package, and have asked Ofwat to refer final determinations to the CMA. Bill reductions for each company were greater than company proposals, and totex allowances were below asked for levels. In the case of Anglian Water and Yorkshire Water, Ofwat has observed that plans to maintain financial resilience are necessary. Ofwat’s initial response was robust: “Some investors have accepted this scale of ambition and change, but others need to face up to the new reality. We are ready to fully engage with the CMA, setting out our analysis and why we are confident this is the right settlement for customers, the environment, and companies.” The CMA process is likely to take six months, and the CMA’s decision binds the appellant, and not the sector. We argue that the PR19 appeals, the ongoing CMA review of the CAA’s RP3 decision, and Ofgem’s RIIO-2 process are all entwined, and suggest that investors pay attention to all three processes. Provisional findings of the RP3 review are expected in early/mid-March, and could have cost of capital implications given cross regulator consistency on total market returns. Ofgem “it is possible that we could set a TMR lower than our current working assumption of 6.5%”, and Ofwat “any statements the CMA might make in the context of the NERL price control could potentially impact on expectations for the appropriate return on capital for water companies, with consequent implications for water company appeals” have already fired warning shots in the CMA’s direction, and we believe both will vigorously defend their positions. For totex, there is arguably less of a ‘one size fits all’ read-across from the CMA process, although should the CMA conclude that Ofwat has been harsh and revise totex allowances upwards, there would be potential positive implications for the water sector in the PR24 process, something that could also extend to energy networks.
Disappointing full-year results after a 9m trading statement that had seemed encouraging. Adjusted operating profit came in short at £901m, however the adjusted EPS came in perfectly in line with the consensus. On the positive side, adjusted operating cash flow came in slightly above our expectations. However, despite a good level of cost reductions targeted for FY20 (c. £350m), the group expects the FY20 adjusted operating cash flow to be lower than in FY19 (£1.6-1.8bn versus FY19: £1.8bn). We confirm our cautious view.
FY19 short at adjusted operating profit, slightly above at EPS Centrica reported FY19 adjusted operating profit of £901m (vs INVe £976m, consensus £974m), adjusted EPS of £7.3p (vs INVe 7.0p, consensus 7.1p), DPS of 5p (vs INVe 5p, consensus 5p), net debt of £3.2bn (vs INVe £3.3bn, consensus £3.4bn). At a divisional level there were two marked differences to our estimates, Energy Market & Trading was a beat helped by a deferral of gas volumes under a legacy contract from FY19 to FY20 (will be a negative in FY20), and a shortfall in E&P due to lower gas prices, lower volumes, higher depreciations, and write-offs. Guiding down on FY20 A tough commodity outlook in 2020, the subject of our recent note, was alluded to as a drag on earnings momentum in 2020, with Centrica stating that “As a result, we would expect the positive earnings momentum from our core customer-facing businesses to be broadly offset by the negative earnings impact from the legacy gas contract and the Upstream portfolio”. Our interpretation of this statement is that whilst there might be EPS growth in FY20, it is likely to be <10%, pointing to the possibility of marked cuts in consensus EPS (currently 8.9p), and to a lesser extent our FY20E forecast of 8.2p. Centrica has guided to AOCF of £1.6-1.8bn in FY20 (INVe £1.9bn) and net debt of £3.2-3.6bn (INVe £3.3bn), although Centrica’s guidance includes an extra £0.2bn of lease liabilities, and the receipt of the £0.1bn Kings Lynn CCGT disposal proceeds which we had included in FY19. CEO search continues, selling nuclear a tough task Our previous concerns on the risk to offloading nuclear in FY20 have been confirmed by Centrica indicating that it might still hold a stake in nuclear at end-2020, but initial bids for Spirit are expected at end-Q120. The search for a new CEO goes on.
Ofgem issued a letter on Friday regarding its intention to consult on three significant potential modifications to the tariff cap: (i) the non-pass-through Smart Metering Net Cost Charge; (ii) reassessing the wholesale allowance in the first cap period; and (iii) prepaying the cap for prepayment customers on default on the expiry of the PPM cap. Statutory consultations on each are expected to be published in mid-May, with decisions expected at end-July. The consultation on the wholesale allowance in the first period is a consequence of Centrica’s successful judicial review, and it is this consultation that is the subject of this brief note. There are three overarching questions: (i) what were suppliers’ wholesale costs for the relevant periods?; (ii) what would an appropriate level of costs have been?; and (iii) how should future cap periods be adjusted? Ofgem intends to estimate wholesale costs for large suppliers (the Big 6, and possibly Bulb) separately, based on their hedging strategies for winter 2018/19, and focussing on the first cap period, although the possibility of an impact in cap period two could also be considered. Bilateral discussions will take place. Ofgem will then consider whether the wholesale allowance in the first cap period was appropriate, or whether it should have been set at a different level. Ofgem intends to use average costs, as the cap is one size fits all. If the conclusion is that the allowance for the first cap period should have been different, then there will be a standalone correction for a limited number of future periods. Ofgem has indicated that it is likely to propose a 12-month adjustment period covering cap periods five and six from 1 October 2020 to 30 September 2021. This appears to support our view that Ofgem’s August review of the cap will see it recommend that the cap is extended beyond December 2020. No indication of the possible impact has been published, but Centrica which had a 36.6% market share of gas default tariffs in the first cap period, and 22% of the electricity market, has previously indicated a detriment of £70m, suggesting that the industry detriment could be in the region of £250m. Changes in customer numbers and the one size fits all approach mean that there might be winners and losers from any additional allowance, but at this stage, it is impossible to offer any granularity. However, on the assumption that Centrica recovers £70m, spread over a year and taking into account seasonality, we suggest that pre-tax Centrica could recover c.£20m in FY20, and £50m in FY21. This would be 4% EPS enhancing in FY20E, and 7% enhancing in FY21E.
CNA CBG DRX GOOD IBE IBE IMB MER NG/ SNR SSE VMUK WYN
The National Audit Office (NAO) report (link to 9pp summary) examines Ofgem’s use of RIIO regulation of electricity networks to protect the interests of consumers and achieve the government’s climate change goals. Returns in RIIO-1 are seen as high vs comparable companies and Ofgem’s expectations, with Ofgem erring by placing too much weight on consistency with previous regulatory decisions. Ofgem has previously acknowledged the generosity of RIIO-1 returns, and an intention to cross-check the CAPM implied cost of equity in RIIO-2 should introduce market evidence into rate setting. Performance targets were set too far in advance, and were easily exceeded. Acknowledged by Ofgem, with RIIO-2 set to have safeguards via higher sharing factors with consumers and the use of returns adjustment mechanisms. Ofgem lacks robust evidence that it can use to determine whether making changes during a price control would save customers money. We view retrospective changes as harmful to the stability of a regulatory regime, and caution against such interventions. A reversion to a five-year regulatory period should reduce the risk of consumer harm vs RIIO-1. Ofgem needs to do more to show in clear and simple terms that the overall cost-effectiveness of networks has improved over price control periods. Imperative for ensuring the longer-term legitimacy of the regulatory regime. Ensuring networks undergo a transformation to a low-cost, low-carbon energy system in a timely way will be a challenge for BEIS and Ofgem because it will not necessarily be in the economic interests of the network companies to do so, as alternatives to network build are likely to be key to the energy transition. BEIS and Ofgem will need to improve co-ordination significantly in the energy system if it is going to reach net zero emissions at least cost. In our view, this is crucial to ensure alignment of policy and regulation. To maximise electricity networks’ value for money in future, Ofgem must ensure it sets stretching targets for network companies in the next regulatory period, while building enough flexibility into the price controls to respond to unexpected developments. The government must help to clarify future network requirements by bringing forward further policies for decarbonising heat and transport. We agree. In summary, the NAO underpins our view that legitimacy of the regulatory regime is paramount. Returns need to come down, and past generosity must be avoided. We view the 6.5% cost of equity proposed by National Grid and SSE as too high, and expect Ofgem will land at a level that is considerably lower. We factor in 4.8% CPIH real for RIIO-2.
CNA DGE DRX GOOD IBE IBE ICP NG/ OSB PAG RSW SSE ULVR
A week late, last Friday the RIIO-2 Challenge Group published its independent view of network Business Plans for RIIO-2 submitted on 9th December. This was a planned step ahead of open hearings to be held in late March/early April (Figure 1). We will be attending. Iberdrola’s SPT’s plan scored as one of the better plans, but those of National Grid’s NGET and SSE’s SHET are positioned as least convincing (Figure 2). Adjusting for load, network companies are asking for an additional £4bn totex (Figure 5) vs. RIIO-1. The Challenge Group doesn’t “think an increase of this size has been, or indeed can be, justified.” NGET, SHET and NGGT have the largest changes vs. RIIO-1, and it is this trio for which the Challenge Group has the least confidence on cost forecasts. The Challenge Group expressed disappointment “that no company, apart from the ESO, has been genuinely proactive in shaping the path to Net Zero”, and “that Ofgem will have to fill a large space in order to ensure that RIIO-2 outcomes are consistent with the progress needed to achieve net zero.” Nobody has persuaded the Challenge Group that Ofgem’s working assumptions for WACC make their business unfinanceable, with plans showing “little focus on achieving financeability at low cost to the consumer.” We stick with 4.8% CPIH real for cost of equity, well below plan submissions (Figure 6). “Little evidence to support universal rejection of the 0.5% outperformance assumption”, although this is an area where we side with the networks, as we consider the wedge to be arbitrary, and something that should be captured via totex allowances and sharing mechanisms. The Challenge Group was blunt with its view that on finance, NGET and NGGT’s plans do not provide value for money for the consumer, while SHET’s is viewed as having “little evidence of a focus on achieving financeability on the basis of lowest cost to the consumer.” The Challenge Group was not “convinced that the companies' Consumer Value Propositions demonstrate significant additional value for consumers overall.” The ESO role is critical, but “it is still unclear precisely what that role is, and in particular the relative responsibilities of the ESO and the Transmission Operators.” The Challenge Group is of opinion “that there may be further scope for competition in new connections for both gas and electricity companies”, and that none of the companies have been particularly ambitious on efficiency. The report is only one of a multitude of variables feeding into the RIIO-2 process, but we suggest that investors are alive to the WACC and totex pushback.
CNA CBG DRX GOOD HLMA IBE IBE ITM NG/ OSB SSE STEM
Gas prices have legged down since Centrica’s 3Q19 trading update, and the ageing nuclear fleet continues to creak. We have cut FY20E earnings by 13% to reflect these headwinds, positioning us 11% below consensus, which we believe needs to come down. Lower gas and power price assumptions also impact further out, as the tariff cap and a competitive supply market limit the ability to offset via UK Home. Our FY21E EPS and FY22E EPS are cut by 9% and 8% respectively. Nuclear and Spirit (E&P) are up for sale, and the impact on pro-forma EPS, more representative of Centrica’s ongoing business activities, is lower, at 7% and 4% for FY21E and FY22E. Our approach to valuation is unchanged, but we have rolled our valuation point to end 2020E, and revisited our valuations of Spirit and nuclear, which we value at estimated disposal proceeds. Our valuation nudges up from 85p/share to 89p/share. Previously, we applied a 10p/share discount in setting our target price to reflect strategic uncertainties and the prolonged CEO departure process. We have no knowledge of the timing of an announcement of a new CEO, but surely it must be imminent, and with positive noises in the 3Q19 trading update regarding North America Business, we have decided to remove the discount. Our target price rises to 90p/share from 75p/share. Trading slightly above our target price, Centrica looks fairly valued. HOLD retained.
The Times reports that Octopus Energy has agreed to acquire 70,000 household customers from Engie, with the latter making “a strategic exit from the UK domestic energy market”. Octopus Energy supplies energy to c.1.2m UK homes, a little over 4% of the GB domestic market. With Ofgem data indicating that Octopus had a 3% (electricity) and 2% (gas) market share at Q2 2019, Octopus’ position as a fast growing supplier is clear to see. Overall switching levels remain high, but net gains by small/medium suppliers have retreated from highs, while larger suppliers (the so-called Big 6) have fought back (Figure 3, Figure 4). Centrica clearly elaborated a stabilise, then grow strategy at its 1H19 results. Given Ovo’s acquisition of SSE Energy Services, the migration of npower customers onto E.ON’s platform, and the market shares of the likes of Shell, Bulb, and Octopus, Ofgem and the industry need to urgently revisit the market segmentation definition, but there is clear evidence of a trend towards large/mid-sized suppliers. Ofgem’s belated review of supplier licencing has and will contribute towards a levelling of the playing field, and recent SOLR processes have seen the larger companies successful (Figure 5). As the industry slowly shifts towards the provision of heat/light/mobility and away from plain vanilla retail of electrons and molecules, we believe that the trend towards better capitalised medium and large suppliers will continue. Consequently we expect more market exits.
After the 2019 hiatus, a number of Capacity Market auctions are imminent, with relevance for a number of stocks in our coverage universe. The auctions start on 30th January with the T-3 auction for delivery year 2022/23, followed by a T-1 auction (delivery year 2020/21) in early February, and finally the T-4 auction (delivery year 2023/24) in early March. The T-3 and T-4 auctions are the two that are relevant, and our estimates are based on clearing prices of £8.6/kW/year (2017/18 money) and £8.7/kW/year (2018/19 money) respectively. These are below the central case forecasts of industry consultants Aurora, who forecast £10.9/kW/year and £16.1/kW/year respectively. Clearing prices at our forecast levels would see the auctions clear on day two of the process, namely 31st January and 6th March, with the results published on the Delivery Body website at 19:00 the same day. The previous T-4 auction cleared at £8.4/kW/year, and saw only 767MW awarded in respect of new build ex new build interconnectors. A low clearing price in the upcoming auctions might give rise to directionally the same outcome. This is of particular relevance to Drax who have pre-qualified four 299MW OCGTs and the 1.8GW Damhead Creek project in the T-3 auction, complemented in the T-4 auction by a 1.8GW coal to CCGT conversion at Drax. Given the ongoing judicial review, we expect the latter to be bid in high, and exit the process early, but should no capacity contacts be secured by Drax’s other new build projects, questions about the strategic direction outside well communicated biomass plans will persist. Drax coal unit 6 has not pre-qualified for the T-4 auction, and with unabated coal capacity having to close by end 2025, this may well be a precursor to closure of this unit, in our opinion. For SSE, we note that Keadby 2 CCGT has pre-qualified for a 15-year new build contract. Construction is already underway, and this may well see SSE being prepared to bid into the auction at a lower price to secure a contract. Centrica’s exposure is principally through its 20% stake in the EDF nuclear fleet, a stake which is for sale. Clarity will arguably help the sale process, but we note that Hinkley Point B did not pre-qualify for the T-4 auction.
CNA CWK DVO DRX GOOD HSBA IBE IBE MGAM NG/ OSB PAG SNN SSE
The Times reports that EDF is in a race against time to secure a funding deal for the Sizewell C nuclear project, and that it wants a definitive way forward this year, so that construction can begin in 2022. The article suggests that delays to funding would erode any savings that can be gained from transferring workers and equipment across from the Hinkley Point C project, with a senior executive at Sizewell reported to have said “outside an acceptable price range for the government, then the project probably won’t go ahead — it’s as simple as that.” The UK government consulted last year on a RAB model for new nuclear projects, as a way of lowering the cost to consumers of new nuclear, with the consultation having closed in mid-October. It is not clear as to when BEIS will publish its findings, but should the government decide to introduce a RAB model, it is likely that there will be further consultations on the design features of the model. The net zero by 2050 commitment, a likely shift to increased electrification, and the need to replace to capacity lost with the closure of the remaining coal stations and the existing ageing nuclear fleet, points to a need for new low carbon capacity, but is far from clear cut as to the exact nature of this capacity. Given the low prices achieved in last year’s CfD Allocation Round 3, offshore wind will clearly be a major source of new capacity. We would also expect to see more storage and other forms of flexibility, and BECCS is a possibility. There is clearly an opportunity for nuclear, but its pricing would need to be legitimate in the eyes of the general public, and clearly this would mean a price point considerably below the £92.50/MWh (2012 money, CPI linked) granted to Hinkley Point C. If new nuclear can’t pass the cost effectiveness test, then we suggest that government and Ofgem should leave well alone.
Orsted and RWE have agreed to make voluntary payments of £4.5m each as they did not remain connected after the lightning strike. UKPN began reconnecting customers ahead of being instructed to do so by the ESO, and will make a voluntary payment of £1.5m. Ofgem has also closed its investigation into National Grid Electricity Transmission (NGET), and all five other DNO groups, without enforcement action. Ofgem did not identify any failures by the ESO to meet its requirements which contributed to the outage, but will continue to review the ESO’s current application of the security standards it is required to meet alongside reviewing the standards themselves, with enforcement action not ruled out. Updating the Security and Quality of Supply Standard (SQSS) could see increased levels of frequency response, reserve capacity and inertia being held, a possible benefit to the likes of Drax. Ofgem’s strategic system operation review could ultimately see a move to an independent ESO, but we suggest that the impact on National Grid would be limited. A tightening of the licencing regime for embedded generation could increase compliance costs for this asset class, possibly benefitting large scale incumbent generators. Given the electrification of the broader economy, a fundamental review of the Low Frequency Demand Disconnection (LFDD) obligations is a much needed step as reliability and security of the electric system will be even more important going forward. Continued overleaf
Current predictions point to a Conservative majority of c. 80. We view a Conservative majority as the best outcome for the UK utilities, and with the spectre of nationalisation lifted, at least for now, we expect the space to move ahead in trading today, led by the networks. We would, however, caution against over-exuberance. On our estimates (Figure 1 overleaf), the networks are trading at 8-24% premia to FY21E RAV/RCV, and although we would be comfortable with 15-30%, we suggest that alarm bells should ring at higher levels. National Grid may also be held back by sterling strengthening given its material US presence. We view tough but fair regulation as the answer to ensure legitimacy, and the focus can now turn to Ofwat’s announcement of PR19 final determinations on Monday. Now is not the time for Ofwat to flinch. We look for a 5% nominal WACC (2.94% CPHI real), with a 4.47% CPIH real cost of equity. Should Ofwat land at this level, it would raise legitimacy issues in respect of the 6.5% CPIH real requested by National Grid and SSE in their RIIO-2 business plans, in our view. Diving into the granularity of the manifesto commitments, we highlight that Drax could benefit from support for a fully deployed carbon capture cluster, and the possible reopening of the Skipton-Colne rail line; National Grid from support for an EV fast charging network; and Pennon from increased plastics recycling. Centrica, however, would face uncertainties from a promise to keep the existing energy tariff cap in place, and to introduce new measures to lower bills.
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A divergent cycle with much further to run. Despite the gloomy rhetoric, macro leading indicators remain broadly conducive to fee growth; notwithstanding a weaker UK and ‘soggy’ parts of the Eurozone, the near-term outlook for key, high-potential markets (e.g. Asia and Latin America) remains relatively buoyant, particularly amidst a backdrop of global skills shortages and tight labour markets. Far from a one-size-fits-all. The level of exposure to different (i) geographies; (ii) verticals; and (iii) candidate types varies dramatically between firms; we posit the extent to which a constituent of our coverage universe will under/outperform is likely to be predicated on these idiosyncrasies. In our view, Robert Walters and PageGroup are optimally positioned; offering investors the highest exposure to structural growth markets, whilst maintaining a bias towards Perm/white-collar - attributes that are likely to outperform near-term given the above macro. Not a UK macro proxy play. Given sustained levels of uncertainty surrounding Brexit/the UK’s impending general election, domestic LFL fee growth has trended down 2019 YTD. Recruiters are inherently momentum driven and therefore a (temporary) downtick in the UK has weighed heavily on investor sentiment. We think this is unjustified; across our coverage universe, the level of reliance on UK fees has reduced markedly over the course of the current cycle (from c60% FY06 to <20% FY18) with investment in international headcount continuing apace. Scope for earnings upgrades. Our scenario analysis examines the effect of the sector’s high operational gearing on improvements in consultant productivity; given staff salaries represent c70% of a recruiter’s total cost base, productivity (or lack thereof) is arguably the main driver of operating margin. Robert Walters stands best to benefit; a mere 5% improvement would add c300 bps to its conversion ratio in FY20E (equivalent to £14.7m of incremental EBIT). High quality returns. Our coverage universe continues to screen well, exhibiting cash conversion and ROIC metrics well-above that of the wider UK mid-cap index. Attractive dividend/buyback programs drive an average FY20E yield of c5%, with distributions typically well-underpinned by both net cash and earnings. Disruptive technology creates an economic moat. The candidate database is becoming increasingly democratised by social media (e.g. LinkedIn); firms are increasingly leveraging technology to improve the breath of offering and speed to candidate - attributes that are now seen as core differentiators when pitching for new mandates, in addition to improving consultant productivity. Whilst new, disruptive entrants continue to enter the market, we believe that scale and cost to play will prove a long-term effective barrier.
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RIIO-2 business plans were submitted to Ofgem on 9th December by network companies in electricity transmission, gas transmission, and gas distribution. With the exception of Cadent (gas distribution), we have been able to locate all of the business plans, and have undertaken a review of each, with a focus on totex, financing, and customer cost. Totex: the biggest increases vs. RIIO-1 have been proposed by National Grid, both in electricity and gas. SSE and Scottish Power propose significant totex reductions in their base cases, but there are significant projects that are included within uncertainty mechanisms. Each of the three gas groups whose plans that we have reviewed propose increased levels of totex, albeit in the 5-10% range. Financing assumptions: push back against Ofgem working assumptions for cost of equity and debt, with each group offering alternative financial parameters. Cost of debt: proposals arguably reflect individual circumstances, but on balance proposals are for a longer trailing indexation period than the 11-15 year working assumptions for business plans put forward by Ofgem. Cost of equity: cost of equity remains highly contentious, and each of the transmission companies, both electricity and gas, have countered with 6.5% CPIH real vs. Ofgem’s 4.8%. Gas distribution is different, with a range of proposals from 5% to 6.1% CPIH real at 60% gearing. NGN is the marked outlier at 5% and in our opinion, the only company to embrace legitimacy when it comes to cost of equity. NGN’s plan states: ‘Based on this assessment and without prejudice to the industry-endorsed range for the cost of equity, we believe that an equity return of 5.00% for NGN strikes an appropriate balance of interests between our customers and investors in RIIO-2.’ Higher cost of company proposals: company financial parameters would push the cost to consumers up. Transmission would cost an additional c£4/average household/year, while for the two gas companies who have provided the analysis, the additional cost would be £9-£19/average household/year. Given the knock-on implications for RIIO-ED2, and previous Ofgem media activity re potential consumer savings in RIIO-2, we would expect strong push-back from a regulatory body that needs to deliver on its tough but fair narrative. .
Zero VAT rating of domestic electricity and gas in a post-Brexit world, energy efficiency programmes, and zero rating for new EVs for domestic use. Cancel HS2, but build a third runway at Heathrow. We question the environmental merits of pushing back against an electrified rail corridor, and supporting an infrastructure project that could result in higher aviation emissions, and localised emission increases during and beyond the build process. A strong interconnection strategy including a link to Iceland, and the possibility of it making landfall in Northern Ireland. We note that the project is in the feasibility stage, and hitherto has failed to find support from the UK government. A new agricultural policy including reforestation, tree planting, and making agro-forestry a realistic and viable option. Commitment to UK’s net zero emissions by 2050 target, but noting the CCC’s recommendation for a Northern Irish target of a 78-80% reduction by 2050, support a Northern Ireland Executive request for a formal recommendation from the CCC on a CO2 2050 target, and then adoption of that target. ‘Tree’ word count of one.
Our review of election manifestos highlights a broad consensus that we face a climate emergency that needs to be tackled, but Labour is alone in advocating nationalisation of large parts of the utility value chain. Nationalisation for the few, not the many: we consider nationalisation as a policy borne out of blinkered ideology. In our view, renewable build needs, public sector labour dispute risk, high levels of employee participation in equity, and minority public support, are reasons why the current ownership model should be retained. Regulation, however, has to be tough, fair and legitimate. Opinion polls point to a Conservative majority, but polls have been wrong in the past: the latest opinion polls point to a Conservative majority on 12th December, but a hung parliament cannot be ruled out. We suggest that a Conservative majority could see UK network utilities build on recent strong performance, while an unlikely Labour majority could see stocks tumble to RAV/RCV valuation levels. For Pennon and Severn Trent, this would suggest falls of >20%. The reaction to a hung parliament is harder to gauge, but we would expect it to be negative. Ofwat final determinations on 16th December, RIIO-2 business plans submitted on 9th December: The election is not the only major event in December impacting the networks. RIIO-2 business plans are to be submitted on 9th December, and Ofwat publishes final determinations on 16th December. In water, we look for a 5% nominal WACC (2.94% CPHI real), with a 4.47% CPHI real cost of equity. Should Ofwat land at this level, it would raise legitimacy issues in respect of the 6%+ we expect that National Grid and SSE will request in their business plans. However, the CMA investigation into the CAA’s RP3 decision for air traffic control could well have a relevance and needs to be watched.
innogy & E.ON have announced proposals to restructure npower, one of the Big 6 GB energy suppliers. npower’s domestic and small business customers will be migrated onto the E.ON UK customer service platform, a move which should create substantial synergies. The intention is to carve out npower’s profitable industrial and commercial business. The restructuring would include the closure of the majority of npower’s sites and corresponding staff reduction. E.ON’s UK CEO will take over joint leadership for both E.ON UK and npower, and npower’s CEO and CFO will leave the company. The UK energy supply landscape is changing, and the price cap has laid bare the cost efficiency challenges faced by the Big 6, where the perennial loss-making npower was a significant outlier. The merger with SSE’s retail business fell through, and it was clear there was a risk to npower’s longevity as a standalone entity. Today’s proposals, whilst hard for those affected, are a step along the road to reducing the cost to serve. Migration of customers is not without risk, and arguably presents an opportunity for those such as Centrica, Bulb, Ovo, Octopus, etc. which wish to grow customer numbers, as change itself is a trigger point for customers to consider their choice of supplier. This could be exacerbated if there are glitches in migration. Figure 1: E.ON – proposed solution for npower Source: E.ON
Reform of the energy supply market: introduction of an Ofgem database of people who haven’t switched supplier, a free whole of the market switching service, and the possibility of collective switching. Hardly radical given that Ofgem has already trialled and/or proposed each of these, but of greater potential impact is an openness to new legislation to cap the most expensive tariffs. The latter is a potential negative for suppliers with high levels of SVT/default tariff customers, of which Centrica is most exposed under our coverage. Net zero: a 75% reduction in emissions by 2035, net zero carbon emissions by 2040, and net zero of all emissions by 2045. Accelerated deployment of fully operational carbon capture utilisation and storage suggests the SNP would back Scotland competing for the £800m funding proposed by the Conservatives, potentially pitting it against Drax’s Humber cluster proposal. Renewables yes, new nuclear no: SNP opposition to new nuclear maintained, but extension of contract for difference support to onshore wind and solar, as well as floating offshore wind and tidal generation. Beneficial to all those companies with renewables ambition, notably Iberdrola and SSE given their geographic footprints. Networks: reform of zonal transmission charging that penalises generation location in Scotland, and a clear timescale for the delivery of interconnectors to Scotland’s islands. Greener taxes: tax incentives to enable people to make the switch to low-carbon heating systems more affordable, and a reduction in the VAT rate on energy efficiency measures. Possible benefit for the likes of Centrica with sizeable energy services businesses. Electric vehicles: campaigning for the UK government to bring forward plans to sales of diesel/petrol vehicles to match Scotland’s 2032 target, although we noted no promises related to EV charging. Independence: intention to offer an independence referendum next year. With energy regulated on a GB basis, Scottish independence would create regulatory uncertainty at a crucial moment in the energy transition. Unhelpful in the short-term for the entire industry, with SSE most impacted given its material presence north of the border relative to its size. Longer-term, any enhanced policy support for renewables rollout and network investment to better connect the islands could be a positive. Tree word count: disappointingly, only one.
Tariff cap: keeping the existing energy cap in place, and introducing new measures to lower bills. Although we believe it is extremely unlikely Ofgem will decide in August 2020 that conditions for effective competition exist, a precursor to the removal of the cap, this policy hints at longer-term existence of the cap, a clear negative for the likes of Centrica. There is no information on what the new measures could entail, but this could cause alarm bells to ring across the value chain, particularly for those in receipt of generous renewables support. The CMA will also be given enhanced powers. South West water rebate: worth £50 to household customers, this would be extended, but on examination of the costing document, only for a single year (2020/21). Funded by government, one could argue that at the margins it assists with customer perception of South West Water (Pennon). EV fast charging: investment of £1bn in completing a fast-charging network to ensure everyone is within 30 miles of a rapid charging station. We believe it is reasonable to suggest this is supportive of National Grid’s proposal to build network infrastructure to support the locating of fast chargers at motorway service stations. Beeching lines: restoration of many of the rail lines removed due to the Beeching cuts. The 12 mile Skipton-Colne line is one such line and, if restored, could benefit Drax as the journey time of biomass pellets landed at the Port of Liverpool could be reduced from 11 hours to three, with clear cost benefits. Plastics: boost domestic recycling and ban the export of plastic waste to non-OECD countries. Such policies are supportive of the strategic direction of the likes of Viridor (Pennon). Scottish independence referendum: Conservative opposition is positive for SSE. Net zero by 2050: 40GW of offshore wind by 2030 (SSE, RWE, Iberdrola, Orsted are among those that could benefit), and £800m to build the first fully deployed carbon capture storage cluster by the mid-2020s (if the Humber cluster is chosen, it would benefit Drax and National Grid). Support for nuclear needs to be justified on affordability grounds, in our view. Tree word count: tying for lead with two when the final whistle was blown, victory achieved with the golden goal of a tree logo on the final page.
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Green transition: 100% self-sufficient in renewable energy by 2030, including tidal lagoons for Swansea Bay, Cardiff and Colwyn Bay, a windfarm on Ynys Môn, and an Usk barrage, complemented by local energy grids. The Swansea Bay lagoon has previously failed to find support on value for money grounds, and although we can see the merits from an environmental standpoint, in line with our view on nuclear new build, for it to be viable, it has to meet affordability criteria, and the bar is being set at a high level by offshore wind. National Energy Agency: to be known as Ynni Cymru, this organisation would be charged with realising Wales’ green energy potential, with an ‘Energy Atlas for Wales’ identifying areas where development would have the least ecological impact. Given previous pushback against onshore wind farms, the latter is highly relevant, while a policy to oppose pylons in National Parks and AONB could benefit National Grid through higher investment requirements. Oppose new sites for nuclear: an interesting choice of words as while Plaid oppose nuclear on principle, nuclear brings employment and local economic benefits. The language could be interpreted as keeping the door ajar for nuclear new build at Wylfa. Electric vehicles: investment in a national electric vehicle charging network across Wales. Housing: all new build housing to be insulated to the highest standards, and equipped with photovoltaics for electricity generation and solar water-heating. Although it will not happen overnight, this direction of travel, combined with Ofgem’s supplier hub reform, could see energy supply move away from paying for electrons and molecules, and towards paying for heat, light, and mobility. Plastics: a ban on single-use plastics, increasing recycling targets and an emphasis on the circular economy. This could benefit the likes of Pennon who could examine the possibility of co-location of a plastic recycling facility at its Cardiff Energy Recovery Facility. ‘Tree’ word count: tied for the lead with Labour and Liberal Democrats at a whopping two mentions.
Environment: The Brexit Party propose planting millions of trees to capture CO2, and the promotion of a global initiative at the UN. On the tree word count scale, we count one reference in the Brexit Party contract, and two each in the Labour and Liberal Democrat manifestos. It is not unreasonable to suggest that the Brexit Party could and should be doing more on the tree front. Recycling: emphasis on increased recycling, making it illegal for waste to be exported across the world to be burnt, buried or dumped at sea. Supportive for the likes of Pennon which has a recycling strategy. Energy: zero VAT on domestic fuel (not allowed under EU rules) to reduce energy bills, but no mention of the renewables. In our opinion, this would help with the affordability challenge of the energy trilemma, but little else.
Green revolution: Labour’s aim is to achieve the substantial majority of emissions reductions by 2030 and create one million jobs. Costs of the green transition are to fall fairly, but mostly be borne by the wealthy. Investment: launch of a £400bn National Transformation Fund, with £250bn of this to directly fund the transition through a Green Transformation Fund, as well as a National Investment Bank to provide £250bn of lending for enterprise, infrastructure and innovation. Renewable energy: delivery of 90% of electricity and 50% of heat from renewable and low-carbon sources by 2030, with 7,000 new offshore wind turbines, 2,000 onshore wind turbines, more solar and new nuclear. There is no mention of how nuclear new build, which is currently far from successful, both in respect of cost and delivery, can be delivered at an acceptable price point vs. other technologies, and, in our view, big numbers on turbines are not what matters, it is all about GWs, load factor and location. Heat: roll-out of technologies like heat pumps, solar hot water and hydrogen, as well as district heating. More power storage and interconnectors. A sensible direction of travel, we believe, but as domestic heat sources become more technologically advanced, maintenance costs could rise. We see no assessment of the cost implications of ongoing maintenance on the consumer. Nationalisation: bringing energy and water systems into public ownership. A new UK National Energy Agency would own and operate the national grid infrastructure, 14 Regional Energy Agencies would replace the DNOs, with the supply arms of the Big Six also nationalised. In our opinion, it is unfathomable and discriminatory to target part of the wider supply company base, and the absence of costing of nationalisation appears fiscally irresponsible. On balance, we argue that energy networks have delivered, with issues of legitimacy more a case of the historic generosity of returns. The latter can, and we expect will, be addressed by a tougher approach to regulation. Water: somewhat strangely, the word ‘water’ only appears six times in the manifesto, four of which are in the context of ownership, and even those lack detail on how a nationalised water industry would be structured. The chapter on the environment is brief, with no reference to water quality and efficient usage. Waste and Recycling: three short paragraphs, with an indication to increase recycling rates, albeit without defined targets.
Full-year outlook unchanged Centrica's trading statement indicates that the full year outlook for cash flow and earnings remains unchanged. Centrica continues to expect adjusted operating cash flow to be in the lower half of the targeted £1.8-£2.0bn range (INVe £1.8bn) and year end net debt to be within the targeted £3.0-£3.5bn range (INVe £3.4bn). Capex now expected at around £800m, £100m down vs. previous guidance. In-year efficiency savings of around £300m are set to beat the previous £250m target. Positives in the US, UK supply still tough Centrica has delivered growth in total customer accounts, with increases in both the UK and US, although the UK is a mix effect (services up, supply down, albeit with the decline rate slowing). Centrica has pointed to higher margins and returns in business energy supply in North America, a positive given this business’ recent troubled past, and strong trading and optimisation performance in Europe. These have offset the impact of further extensions to outages at the non-operated Dungeness B and Hunterston B nuclear power stations. Lower near-term European wholesale gas prices are also likely to have impacted, although 2019 E&P earnings are largely protected by forward hedging. Staying on the sidelines Comments around the US and cost reduction are positive, as is reiteration of guidance following a tough recent history. However, it is clear that the UK supply market remains challenging, with customer numbers yet to stabilise. With no mention of progress on disposals, and a new CEO still to be appointed, we prefer to maintain our neutral stance.
Stronger economy: the Liberal Democrats propose investing £130bn in infrastructure including upgrading energy systems and an emergency ten-year programme to reduce energy consumption, cut emissions and reduce fuel bills, with corporation tax increased to 20%. Infrastructure spending would benefit network companies, which would also be immune to tax increases through regulatory true-up mechanisms. Those with non-network activities, such as Centrica, Drax, Pennon, and SSE, could see earnings impacted by higher taxes. Insulate all Britain’s homes by 2030: retrofits and a shift to renewable zero-carbon generation on-site could accelerate a shift in the way that gas and electricity are paid for, with consumers paying for heat, light, mobility, and services. Somewhat a leap of faith, but the evolution of the market in this direction could benefit Centrica, given its extensive Home Services business. Legally binding target to reduce net greenhouse gas emissions to zero by 2045 at the latest: given that some sectors will be unable to reach zero emissions, technologies such as BECCS, currently being explored by Drax, National Grid and Equinor, could be given a boost if the policy were supported by a fair regulatory framework. 80% of UK electricity from renewables by 2030, with aim to decarbonise power completely: a removal of restrictions on solar and wind would benefit the likes of Iberdrola and SSE, with increased interconnector build beneficial to National Grid. Banning non-recyclable single-use plastics: we see this as supportive of Pennon’s ambitions to develop its plastic recycling activities in its Viridor subsidiary, although a desire to reduce waste sent for incineration could lower opportunities for future EfW development. Electrification of transport: cutting VAT on EVs to 5% and increasing the roll-out of charging points, including those at service stations would require increased infrastructure investment, benefitting the electricity distribution and transmission companies. Increased electrification of rail would drive a need for additional sources of renewable generation, benefitting companies such as SSE, Iberdrola, Orsted and RWE, all material players in UK renewables. Long-term targets for improving water quality: with an indication of funding streams being made available, such a policy could work its way into the evolution of regulation in the water sector, while higher water efficiency standards could be part of ODIs. Together, these could offer greater incentives for high performing water companies, in our opinion.
Update on expectations for FY19. At 1H, Centrica guided to AOCF in the bottom half of a £1.8-2.0bn range, £250m of efficiency savings, capex of £0.9bn, and net debt of £3.0-3.5bn. Our estimates are at the lower end of the AOCF range at £1.8bn, and the upper end of the net debt range at £3.4bn. We expect confirmation of the intention to pay a 5p dividend for FY19. Standing and fighting in UK Home is a key part of Centrica’s strategy. It is possible that, given the growth in UK energy supply customers in May and June, Centrica is finally able to indicate that UK customer numbers have stabilised. If this outturns, it is possible that Centrica also flags that the mix has changed, and efficiencies are being used to fund competitive offers. We have previously suggested that the North American Business in is the last chance saloon. Centrica appears to be committed to turning around this business, and an indication that management actions are working, and 2H19 adjusted operating profit will better 2H18 is a necessity to reassure investors in our opinion. Centrica has two big ticket disposals planned: its 69% stake in Spirit (E&P) and the 20% stake in EDF’s UK nuclear fleet. We expect an update on each, and indications that both are likely to be 2020 disposals, albeit with the nuclear disposal being more challenging given a smaller pool of potential buyers, and the operational challenges which are impacting 2019. As far as 2019’s £500m small scale disposal plan is concerned, we expect Centrica to come up short. We believe that Centrica could announce a new CEO by year-end, with it possible the announcement could be as soon as next week, particularly if the successful candidate is internal.
The EC has approved under EU State aid rules the British CM scheme. The investigation confirmed that the scheme is necessary to guarantee security of electricity supply in GB, is in line with EU energy policy objectives, and does not distort competition in the Single Market. The EC did not find any evidence that the scheme would put demand response operators or any other capacity providers at a disadvantage with respect to their participation in the scheme. The UK has committed to implementing certain improvements to the scheme for the future. In particular, these improvements concern: (i) the lowering of the minimum capacity threshold for participating in the auctions; (ii) the direct participation of foreign capacity; (iii) the participation rules for new types of capacity; (iv) the access to long-term contracts; (v) the volume in the year-ahead auction and (vi) the compliance with the new Electricity Regulation. BEIS has issued a statement indicating the UK Government will: (i) restart the mechanism for making payments to capacity providers, including the c.£1bn of deferred payments that have been suspended because of the standstill period; (ii) invoice suppliers for the standstill collection period supplier charge which will be used to fund the deferred capacity payments; (iii) confirm that the conditional capacity agreements awarded in the replacement T-1 auction, held in July 2019, have become full capacity agreements; (iv) confirm the three capacity auctions scheduled for early 2020 will take place. Drax (Buy, TP 420p) – As expected, with reinstatement in our estimates, but this significantly de-risks the company in the eyes of investors. Drax will be able to push ahead with seeking CM contracts and advancing development of permitted growth assets (Drax repower, OCGTs, Damhead Creek CCGT). Focus is now on the 19th November CMD. 9.4x FY20E P/E, 5.4% FY20E div yield (at 316p). Centrica (Hold, TP 75p) – £46m of exposure (c.5% FY19E adjusted operating profit) and reinstatement is in our estimates. Clarity is a potential positive for Centrica’s ongoing sale process of its nuclear stake. 7.9x FY20E P/E, 6.7% FY20E dividend yield (at 74p). SSE (Hold, TP 1,340p) - £148m of exposure (c.10% of FY20E adjusted operating profit), including £60m relating to FY19A. Reinstatement is in our estimates. 13.8x FY21E P/E, 6.4% FY21E dividend yield (at 1322p). Reinstatement means that suppliers will be required to make payments to the EMR delivery body. Some may have paid the amounts into escrow, but some will have not, suggesting heightened risk of further supplier failure if adequate funds are not available. Possible benefit to better capitalised suppliers.
National Grid SO’s 2019/20 Winter Outlook published today takes a whole system view, albeit that granularity is at individual gas and electricity levels. Gas – Supplies are diverse, flexible, and expected to be sufficient to meet winter demand (Figures 1 and 2), itself expected to be higher than 2018/19 weather corrected demand. Gas demand for electricity forecast to be lower than last year, but dependent on renewable generation output, and the coal stock depletion strategies of coal plants close to decommissioning. High levels of LNG imports are forecast (Figure 3), though subject to pricing uncertainties (Asian prices, shipping costs). Electricity – Expectation that there will be sufficient generation and interconnector imports to meet winter 2019/20 demand, with de-rated margins higher than last year (Figures 4 and 5), and with loss of load expectation within the government set Reliability Standard. Demand can be met with a full range of interconnector scenarios. Merit order and pricing – Gas is expected to be in merit over coal through the winter (Figure 6), with gas prices driving electricity prices. Ofgem highlighted an expectation of weak near-term fundamentals, but Q120 uncertainties have driven high seasonal spreads. UK power price exposed companies (Centrica, SSE, Drax, Iberdrola) are largely hedged on outright power in the near-term and longer-term fundamentals are more important. Brexit – The SO’s analysis in relation to Brexit shows gas margins that are sufficient even in a scenario with no interconnector flows between GB and continental Europe, although the market would need to attract regular LNG supplies to the UK. For electricity, margins are seen to be sufficient even if there is no interconnector flow. Capacity Market confidence – The SO considers “that the Capacity Market has met its core objective to ensure electricity security of supply at the lowest cost to consumers. As such, we believe there is a need to continue the Capacity Market, and that this is the correct mechanism to promote long-term stable investment in capacity by providing a stable and reliable longer-term price signal. We are confident that the Capacity Market will be restored and will evolve to continue to be a key pillar of the transition to a low-carbon energy future.” Ofgem also appeared confident on reinstatement, indicating an expectation of an October decision. This would benefit Centrica, Drax, and SSE. However, should there be no decision by end October, and a no-deal Brexit, the pathway to reinstatement could be complicated.
National Grid’s full technical report into the 9 August power cut was published on 10 September, and we have previously highlighted the key findings. Ofgem’s investigation is ongoing, and we expect this to be concluded by early November. E3C’s review sits alongside this, and has identified a series of measures that warrant further investigation to make the electricity system more resilient. E3C will build on these, providing a set of recommendations to the Secretary of State in the final report expected to be released alongside Ofgem’s investigation. Key initial findings: 1. Communications need to improve, and communication policies and protocols across the industry should be reviewed to understand whether these support timely and effective communication for future events. 2. More work needs to be done on the compliance process, most notably for embedded generation, with a review of the timescales for delivery of the Accelerated Loss of Mains Change Programme. Further work is required from the electricity sector to ensure a continual balance between system security, resilience and the generation mix. 3. A review of the reserve and response holding policy of the Electricity System Operator, and whether it is fit for purpose going forward. This should explore the single largest loss criterion, the increased volatility of frequency deviations, and the level of inertia. 4. A review into the performance of the Low Frequency Demand Disconnection scheme, and a suggestion that minimum standards for essential services/critical infrastructure should be established to ensure that their internal systems and business continuity plans are fit for purpose for such situations. The recommendations tally with those in the National Grid report, and should come as no surprise. However, the report serves to keep the electricity industry under considerable political and regulatory scrutiny, and we await the outcome of Ofgem’s investigation to see if structural changes are suggested or required. Financial penalties are also a possibility.
Key objectives addressed – Ofgem’s chairman addressed Ofgem’s three key objectives in a speech earlier today. Decarbonisation – Decarbonisation might see a bigger role for Ofgem, and there was a clear message to networks to address decarbonisation in RIIO-2 business plans, or see these rejected. Anticipatory investment mechanisms for EV charging infrastructure and heat decarbonisation are being considered, but there will be no blank cheques. Drive for retail competition – Ofgem intends to double down on competition and do everything it can to empower consumers to get a better deal, but with a tightening of the licencing regime to drive up standards. For financially stable suppliers delivering good customer services, this part of a tougher Ofgem might well be a positive. Protecting consumers – although the price cap is a temporary measure, certain customer groups may well need enduring protection. The future of the price cap – price cap legislation requires Ofgem to assess whether the conditions are in place for effective competition in the domestic retail market and to recommend to the Secretary of State whether or not the price cap should be lifted. Ofgem’s framework for doing so was published today, and is based on three conditions that would need to exist to make this conclusion. Structural changes – changes that are facilitating or can be expected to facilitate the competitive process, including those from the government, Ofgem, and the wider market. Well-functioning competitive process – competition should be expected to work well in the absence of the cap, with no significant barriers to consumers accessing the market, sufficient commercial opportunities for well-prepared prospective suppliers to enter the market, and the existence of a level playing field. Fair outcomes for consumers – competition should be expected to deliver fair outcomes for consumers in terms of what matters to them, including prices, range of tariffs to suit needs, good quality of service, and ease and reliability of switching. We struggle to see the cap being lifted at end 2020 – Ofgem has made it clear that there will be no pre-judging, but given the visibility needed on a number of structural changes that are playing through, we would consider the removal of the price cap at the end of 2020 as highly unlikely.
Government bans on new fossil fueled vehicles in many major economies are likely to drive significant growth in electric vehicles (“EVs”) over the next twenty years. This will create growth in electricity demand from EV charging. The volume of energy to be supplied creates opportunities for both supply companies and generators and the provision of charge points is already creating a new industry. However, the timing of this demand puts pressure on local distribution infrastructure. While smart charging and vehicle to grid technology offer solutions, we believe these will only be partial given likely charging behaviour and as a result there will be demand for additional grid capacity and for other solutions. These other solutions include charger located storage and distributed generation.
CNA NG/ YU/ DRX GOOD RED SMS IKA AFGYF
Following the completion of the nuclear island “common raft” for the first unit of Hinkley Point C (HPC) in June 2019, EDF has undertaken a detailed review of the project’s costs, schedule and organisation. The review has concluded that: (1) The next milestone of completing the common raft for Unit 2 in June 2020, announced earlier this year, is confirmed; (2) The previously communicated risk of commercial operations delay of unit one and two (of 15 months and nine months respectively) has increased; (3) The project completion cost (in £2015) is now estimated between £21.5bn and £22.5bn, an increase of £1.9bn to £2.9bn compared to the previous estimate. The cost increases reflect challenging ground conditions which made earthworks more expensive than anticipated, revised action plan targets and extra costs needed to implement the completed functional design, which has been adapted for a first-of-a-kind application in the UK context Under the terms of the Contract for Difference, there is no impact for UK consumers or taxpayers, but EDF’s project rate of return (IRR) for HPC is now estimated between 7.6% and 7.8%, versus a previous expectation of around 8.2% with the previously communicated delay risk.
The report follows on from the interim report delivered and published in mid-August. Transmission system protection operated in line with the design and in compliance with the Grid Code requirements on fault clearance, with associated voltage and current disturbance on the network within expected limits. A weak internal network environment at Hornsea was a contributory factor to the rapid de-load of Hornsea 1, and turbine controllers also reacted incorrectly. Orsted has taken remedial action. RWE’s review of the Little Barford trip is continuing, with inspections and resilience testing to take place during a September outage. The Lower Frequency Demand Disconnection (LFDD) scheme worked largely as expected. There was some underperformance in the delivery of frequency response and is being followed up with specific providers. The train system did not operate as specified, and the event should not have caused a permanent lockout fault on a number of Govia Thameslink Railway’s fleet. Recommendations include a review of the facilities connected to the LFDD, a review of security standards regarding the level of system resilience, assessing whether standards for critical infrastructure are required, and whether the timescales for the delivery of a programme to reduce the risk of inadvertent tripping and disconnection of embedded generation are appropriate. We expect Ofgem’s investigation to be concluded around the end of October, and that the electricity industry will be the subject of much political and regulatory scrutiny over the coming months.
The Times article suggests that a lightning strike caused Orsted’s Hornsea One (800MW) to drop off the system, with at least part of RWE’s Little Barford CCGT (730MW) tripping almost instantaneously. It is also possible that embedded generation also tripped. The Times article also suggests that frequency fell, and that it appears that the initial efforts to keep frequency above 49.5Hz proved insufficient, with subsequent falls in frequency to the point at which the system started automatically disconnecting demand to prevent wider blackouts. The blame game over the past week has been unedifying for the electricity industry, and consumers/rail passengers who were affected by the power cut will most likely not share the ESO’s view that the systems “worked well”. Perhaps not the best choice of words under the circumstances. There are serious questions that need to be answered, including: Why did the ESO not have sufficient backup capacity, particularly given that the cost of doing so would be inconsequential in the context of the dual fuel bill? To what extent did the changing generation mix, and location thereof, play a role in all of this, and are the industry rules fit for the electric industry of today and tomorrow? Who cut the power to the railways and why was power cut to the railways ahead of other demand? Why, when power was restored relatively quickly, did certain parts of the affected railway industry take so long to restore services? Clearly this goes wider than any single part of the value chain, with serious questions for Ofgem/BEIS too, as to whether the balance of incentives and penalties in the broader remuneration framework are appropriate, and delivering the desired outcome. Remuneration in RIIO-1 has been generous, many offshore wind farms are earning triple digit £/MWh, and we have a capacity market (albeit currently suspended), yet resilience was challenged, and in the eyes of the consumer, voter, and wider British public, legitimacy too. We would not be surprised to see Ofgem’s resolve toughened, with others seeking to make political capital too. Helpful for the electricity industry? Far from it!
CNA DRX GOOD IBE IBE IRES NG/ SAFE SSE
SSE in discussions with Ovo over the possible sale of SSE Energy Services The Sunday Times reported yesterday that Ovo Energy is in advance talks to acquire SSE’s retail business for an upfront payment of £250m, with a promise of further payments. SSE has confirmed it is discussions with Ovo and that the discussions are ongoing: “These discussions are continuing, however no final decisions have been taken and no agreements regarding the terms of any transaction have been entered into.” SSE has declined to answer further questions: “SSE will provide no further comment on the discussions until a conclusion to them has been reached.” Many unknowns, but the hypothetical extreme is £40/account The possibility that a deal might not come to fruition, coupled with the lack of visibility, make it hard to draw concrete conclusions at this juncture. The level of debt that SSE Energy Services will be spun off with is not known, nor is there any visibility on the magnitude of the future payments that might be forthcoming. On one hand, we would view a disposal ahead of the previously communicated timeline as a positive, but the extreme scenario of a £250m price tag would be a giveaway, in our opinion, equivalent to c.£40/account (services included). At this price, the impact on our SOTP would be 67p, 6% of our target price. SSE excludes SSE Energy Services from its definition of adjusted EPS, so on this metric, the interest cost saving would suggest slight earnings accretion. However, our reported EPS would see dilution of c.8% in FY21E, assuming a full-year impact. We do, however, stress that this analysis is hypothetical given the multitude of unknowns. Anti-trust issues unlikely, challenge to smaller members of the Big 6 A combined Ovo & SSE would be #2 in both electricity (c.18% market share versus British Gas c.19% market share) and gas (c.15% market share vs British Gas c.28% market share), and given that the terminated SSE/npower received CMA clearance, we would not expect anti-trust issues. Given Centrica’s more aggressive stance on cost cutting, and the benefits that can be gained from the home services, our initial reaction is that a SSE/Ovo tie-up would be more problematic for the other members of the Big 6. The aforementioned hypothetical extreme of using £40/customer limits the ability of an immediate read to Centrica, where we suggest that current trading levels imply a valuation of c.£100/account. Meaningful weakness in Centrica’s share price off the back of this news would be an over-reaction, in our view.
Centrica plc SSE plc
Default tariff cap cut by £75: Ofgem has announced the levels of the tariff caps (default and prepayment) for the winter (October-March) period, effective 1 October. The default tariff cap, covering c11m customers will fall from £1,254 to £1,179, while the prepayment meter cap, impacting c4m customers, will fall from £1,242 to £1,217. Wholesale costs the driver: The principal driver of the reduction in the default tariff cap is a £75 reduction in the wholesale cost component (measured in a six month window to end July), with small movements elsewhere summing to zero. The prepayment meter cap methodology has been aligned with the default tariff cap methodology following the recent decision by the CMA. The approach to the Capacity Market (full allowance) and Smart Metering Net Cost Change (retention of model used in the first two tariff cap periods) remains unchanged. Reduction in line with expectations: The £75 reduction in the default cap is broadly in line with market expectations of an £80 reduction, while the underlying reduction in the prepayment cap is of the same magnitude as that in the default cap, given previous indications that the prepayment cap would have been £49 higher in the current April-September period had the methodology been aligned with that of the default tariff cap in this period. No change in view on supplier profitability: We expect that the larger suppliers hedge in line with the way that the commodity component of the default tariff cap is built up, suggesting that the commodity costs are, in effect, a pass-through, and that the lower cap should not have a negative impact on profitability. However, given the increased churn that followed the increase in the cap announced in February, this reduction may well see lower customer churn, supportive of Centrica’s strategy to stabilise/grow customer numbers. We see no reason to change our view of EBIT margins around 3% in the medium-term for the UK energy supply market.
Starting gun fired on RIIO-ED2 process – Ofgem has published an Open Letter Consultation on the approach to setting the next electricity distribution price control (RIIO-ED2). There is considerable flow through from prior RIIO-2 documents, but the letter is the first major stand-alone ED2 publication ahead of the start of the next regulatory period in April 2023. Tough but fair narrative repeated – Ofgem has made it clear that it intends RIIO-ED2 to be a tough but fair settlement, continuing the narrative underpinning the RIIO-2 journey for ET, GT and GD, but has identified priorities to facilitate the energy transition that could inform its approach. Distribution could be where the action is – There is clear recognition that the energy transition will have an impact on the activities that distribution network operators (DNOs) are expected to undertake, with knock-on implications for the amount and type of funding that network companies require. Distribution is likely to be where the action in the regulated space is as the energy transition plays out. Early days in the process – it is difficult to draw firm conclusions at this juncture, but most proposals appear unsurprising and unlikely to trigger a change in investor sentiment. However, as the RIIO-ED2 process progresses, we suggest that the DNOs will use asset security and an environmentally sustainable network to push for higher levels of totex, whilst seek to lever uncertainty as the basis for pushing back against Ofgem’s current stance on cost of equity. We view the proposal not to use an anchoring for distribution as positive. Stocks with the greatest exposure to UK electricity distribution include SSE (SSE.L), Iberdrola (IBE.MC), and PPL (PPL.N).
Clarity of UK strategy, but execution risk – A strong multi-channel offering in UK retail and ambitious cost reduction targets should give Centrica a fighting chance of arresting declining account numbers, but we would like to see tangible evidence of delivery before we become more bullish on margins. We continue to struggle with merits of the geographic mix – North America Business struggled again in 1H19, but management is determined to turn the business around. We continue to struggle to see the attractions of a UK/North American mix, and would not rule out further strategic change once a new CEO arrives. Earnings cut, disposals likely to dilute – Updated estimates post 1H19 results see adjusted EPS cut by 12% in FY19E, 15% in FY20E, and 6% in FY21E. Planned disposals of E&P and nuclear are likely to be dilutive to the tune of 9% based on our pro forma numbers for FY21E. Target price cut to 75p, upgrade to Hold – Our SOTP is broadly unchanged, but we suggest that a discount is warranted given the lingering strategic and execution risks. At current levels, Centrica is trading on a dividend yield of 6.6% in FY20E, a level that does not strike us as unreasonable relative to UK peers. We cut our target price to 75p, but with this suggesting a 12-month total return of 5%, we upgrade to Hold.
Dividend cut to 5p Centrica has reported a 49% reduction in adjusted operating profit to £399m (INVe £435m), a 63% reduction in adjusted EPS to 2.4p (INVe 2.6p), and a 58% reduction in the interim dividend to 1.5p (INVe 1.8p). Net debt of £3.4bn was slightly below our estimate of £3.5bn. UK Home, North America Business, and E&P accounted for the majority of the reduction in adjusted operating profit. CEO to depart, E&P exit, more cost cutting The strategic update sees CEO Iain Conn stepping down in 2020, although he will remain until AGM at least. Centrica plans to exit E&P with a trade sale targeted, Connected Home is renamed Centrica Home Solutions and refocused on UK and Ireland, the cost reduction programme over 2019-22 is increased by £250m to £1bn, but with costs to deliver of £1.25bn, and a progressive dividend policy instituted from the 5p rebase, linked to earnings & cash flow, with target cover of 1.5-2.0x. The presentation will be at 9:00am – LINK Evidence of delivery needed; UK/US mix to struggle to resonate with investors With the plan to exit E&P well trailed, Centrica will have a business that is asset light and exposed to significant competitive pressures. We continue to struggle to see the UK/US mix resonating with investors, and despite moves to be best in class on costs, our initial reaction is that the market will want to see tangible evidence of delivery before ascribing value. Our estimates and price target are placed under review. Continued overleaf
FY18 had raised concerns about the sustainability of the dividend, and Centrica has finally cut it by nearly 60% after the catastrophic figures for H1. The group has announced its intention to exit from oil and gas production in order to refocus its activities on services around the transition to low-carbon. The group tried to reassure about the outlook for H2, confirming its cash flow and net debt full-year targets.
BEIS and Ofgem have published a joint consultation Flexible and Responsive Energy Retail Markets that follows on from the November 2018 joint review to investigate what policy, legal and regulatory changes might be needed to make sure the retail market framework can meet the demands of the coming decades. The consultation, which closes on 16th September, is the mid-point of the review, and sets out emerging thinking. Innovation and choice are seen as key, with competitive pricing for all consumers, and protection for vulnerable consumers. There is an expectation of greater diversity of the types of companies participating in the energy value chain, and BEIS/Ofgem are considering additional reforms, on top of those already in train, to facilitate this change. Longer-term, more fundamental reforms have not been ruled out. We see both routes as a challenge to ‘business as usual’ supply models. The current retail market has a number of embedded distortions, notably the delivery of policy obligations which are based on size, and the distribution of high cost-to-serve and bad debt customers, who are more likely to be customers of the larger incumbent suppliers. Reforming the approach to both would arguably be a positive for the Big 6 and other medium-sized suppliers. In its work on loyalty penalties in other sectors, the CMA set out a number of measures to protect consumers, including targeted interventions, collective switching, actively helping people to move to a better deal, and enforcement. The consultation invites views on how any of these measures could be adapted to benefit energy consumers, but the message that persistent overcharging cannot be allowed to return to the retail market is clear. We see this as supportive of our view that supply margins will not return to historic levels. We see an EBIT margin of c.3% as the likely new norm. Continued overleaf
Earnings drop, dividend cut – At a consolidated level, we look for a 44% reduction in adjusted operating profit to £435m, a 59% reduction in adjusted EPS to 2.6p, and a halving of the interim dividend to 1.8p. In absolute terms, our expected fall in adjusted operating profit is £347m, and largely comes from three business lines: UK Home (tariff cap, customer loss, competition), North America Business (warm weather, tough 1H18 comp), and E&P (impact of lower UK gas prices on unhedged position). Our full-year estimates are arguably looking aggressive, with downside risk. Challenges abound, tough task – The challenges facing Centrica are many, and, in our opinion, management has a tough task in persuading investors of the merits of the strategy, and why the business mix adds value. In particular, we look for a view on how Centrica will respond to a retail market which Ofgem envisages will see more competition and innovation, when/whether Connected Home will break-even, and when North American Business will deliver the promised recovery. It will also be necessary to demonstrate sustainability of the repositioned dividend. We remain sellers – Absent significant change, we continue to see a business that will struggle to strike a chime with investors, and a tough backdrop that looks set to persist. We remain sellers.
CNA GBG JLG PURP
In our last model update we affirmed that, in the long run, a recovery was still possible, but that we preferred to remain cautious for the time being and wait for some news flow positive enough to cause an inflection point. Unfortunately, in the absence of a positive element, we have now decided to review our approaches and adopt a more conservative view.
Centrica delivered a mixed set of results FY18, adjusted operating cash flow and net debt were within the target ranges, but EPS is 2.6% lower than expected. Due to the UK default tariff cap the low volumes in E&P and nuclear, group downgraded AOCF guidance for 2019 is 1.8-2.0, or 13.6% lower than the required average pace of growth to reach the 2018-20 target.
Centrica released a weak trading statement. Competition remained intense in the UK during the four months to October. The company lost 372k accounts in its Home business, while the E&P business suffered from unplanned outages forcing Spirit Energy to cut its 2018 production target by 5%. However, the group confirmed its 12p dividend target for 2018, ensuring a comfy 8.8% yield at today’s price, thus limiting the downside risk.
Centrica released a rather weak set of H1 results. EBITDA was broadly flat while adjusted operating profit was down 4% as profit recovery in E&P was more than offset by tough market conditions in the Retail segment. The group confirmed its FY18 objectives and expects to pay a stable dividend in 2018 (12p).
Centrica released a short Q1 trading update. Centrica’s management said that the overall performance has been good in the year to date, driven by higher demand for gas following the colder weather and confirmed its set of FY targets (including the 12p dividend), with revenue growth expected to be weighted towards the second half of the year.
• The Centrica Business division hammers the group’s results. • The company lost 5.2% of its clients (-1.4m) in the customer segment and -7.1% in the Business one (-100k). • Price cap should hurt 2019 margins (and earnings), but impact unknown. • Reassurance on the dividend side and OCF guidance (£2.1-2.3bn) is a positive.
The group has stated in its trading update that it expects adjusted EPS for 2017 to be close to 12.5p, which is 17% below the 15.2p we previously expected. It confirmed its adjusted net debt target at £2.5-3bn and operating cash flows to be above £2bn. It has also raised its cost-cutting target for the year to £300m, from the previous £250m. It maintains its capex target at close to £1bn (with £500m for E&P). Moreover, driven by the group’s exposure to the retail market, it confirmed that the company lost 823k customers in the last three months. In addition to this, the group has stated that during the transition phase towards greater customer exposure and diversification to improve margins, Centrica would be forced to have a dividend cover below its historic levels.
Centrica’s solid H1 numbers and 12.5% electricity tariff increase announced yesterday morning were both in line with market expectations. Operationally, the business was resilient given this year’s warm weather and challenging competitive dynamics. The political impact of the tariff hike was mitigated by protecting 200,000 vulnerable customers, a move we view as sensible given especially high levels of political risk in UK retail energy currently. The bigger story for Centrica shareholders remains the long-term shift away from upstream ‘asset businesses’ to tech-enabled customer businesses. Yesterday’s announcements do not change that strategy and the reality is that Centrica is very early in its strategic change of direction.
Centrica reported a mixed set of results for the first half. The company achieved higher revenue (+7% to £14.29bn) and EBITDA (+2% to £1,293m) despite unfavourable weather conditions and competitive pressures. However, the group saw an 11% contraction in adjusted net earnings to £449m. As a direct consequence, it announced a 12.5% increase in the price of electricity on the British Gas standard tariff, effective from mid-September onwards. This is the first increase in four years, while gas prices will remain the same. Adjusted operating cash flow (AOCF) fell by 9% to £1,242m, reflecting a one-off working capital inflow in 2016. However, net debt has improved to £2,941m (a 22% reduction), on the back of the portfolio rotation strategy. Moreover, the group confirmed its full-year guidance as its strategic transformation and efficiency programme are well on track: adjusted operating cash flow >£2bn net debt in the £2.5-3bn range by year-end a further £250m efficiency savings The company proposed a flat interim dividend of £3.6p/share (30% of the FY2016 dividend), in line with historical practices.
The group has provided strong results given the conditions, beating forecasts across the board on its 2016 performance. Revenue decreased by 3% yoy to £27.1bn, but the contraction is less dramatic than expected. Adjusted operating profit, on the other hand, increased by 3.8% yoy and is 6% above market consensus, with adjusted net income on the same path with 3.8% yoy growth to €895m. EPS decreased by 2% yoy due to the issued shares and the diluting effect of the capital increase made last year to finance the acquisition in the retail business. On a reported basis, the company had an operating profit of £2,486m and £1,672m in net income, a strong performance. The best part came from the operating cash flow, the main objective of the company, as this grew by 19% yoy to £2,686m. The E&P business is in positive territory with a positive free cash flow. As a result, net debt decreased by 27% to £3.5bn, far better than previously expected. The dividend payment will be 12p/share, in line with last year’s, but below expectations given that the expected improvement on cash flows should have benefited shareholder remuneration, but it didn’t. Operating cash flows are expected to be above £2bn, which implies a contraction in the performance achieved over the year. Investments will be limited to £1bn for 2017.
Centrica has published its Q3 16 trading update, raising its guidance expectations for 2016 with operating cash flows now expected in the £2.4-2.6bn range (+20%) rather than the £2bn earlier. Moreover, due to the gas assets’ better performance, benefits from the cost-cutting programme, and a strong performance in energy marketing and trading, the group expects the full-year EPS to be around 16.5p, whereas the market estimates something close to 15.4p (+7.1%). Nonetheless, the new expectations imply that EPS is expected to decrease by 4% yoy, although this is less than previously expected (-10.5%), which represents a substantial improvement.
Results fell 13% yoy to £13.38bn. However, £969m from the re-measurement of energy contracts has positively affected the reported results leading to a 31.5% yoy increase in operating profit to £1.76bn and net income to have a 9.3% yoy increase to £1.15bn, translating into an EPS of 22.2p. As a result, the company has increased the interim dividend by 1% to 3.6p. Nevertheless, on an adjusted basis the results show a different story as operating profit fell 12% yoy to £853m, net income decreased 14% yoy to £507m with EPS reaching 9.8p. Although, on an adjusted basis, operating cash flows increased by 19%yoy to £1.37bn. The strong cash flow performance in the first quarter has allowed the group to increase capex by 16% yoy to £444m which, added to the £694m capital increase performed earlier in the year, has allowed the company to have a comfortable net increase in cash of £1.28bn at the half year mark. This has allowed the company to achieve a 23% yoy decrease in net debt, to reach £3.8bn. Concerning guidance, the 2016 full-year expectation on operating cash flows above £2bn is expected to be exceeded. Moreover, as strong progress has been achieved in cost-cutting measures, as £141m has been achieved in the first half, the 2016 cost cutting target has been raised to £300m. Headcounts are expected to be reduced by around 3,000 FTEs.
Centrica has published an operational update with no revenue or profit numbers but confirms its full-year objectives: adjusted operating cash flows above £2bn, capex should not exceed £1bn (in which £500m would be focused on E&P) and a £200m efficiency programme is still expected to be achieved in 2016, as part of the £750m/year cost reduction programme. Moreover, the group expects to add to the direct headcount reduction expected in 2016 of 3,000 employees, of which 800 have been already been achieved in the first three months. Nevertheless, the group continues to lose clients as its home energy supply accounts have been reduced by a further 1.5% in the first quarter (an additional 224,000 customers lost, compared to 119,000 customers lost in Q1 15). Due to this, a more aggressive strategy will be applied from Q2 16 to stop the loss of customers. The negative effect may be offset by North American home accounts (although not quantified). As previously announced, the group is to close the Killingholme power station after it has served the National Grid for 2015’s winter supplemental balancing reserve.
Uncertainty ahead of the United Kingdom's EU referendum has begun to dampen investor appetite for UK equities. However the dislocation of UK equities from their global peers are rare occurrences with the cross-correlation (100DMA) having only dropped below 0.5 on four occasions since the turn of the millennium:Dot.com bust: April 2000Foot and Mouth crisis: February 2001London terrorist attacks: July 2005Scottish Referendum: September 2014We expect a further dislocation in the run up to the referendum on June 23. In this note we use these four recent dislocation episodes, the sensitivity of UK equity valuations with sterling, and European Union revenues to establish a risk profile for the largest UK-listed companies. Based on this framework we provide our preferred picks to navigate the coming months of political uncertainty – Table 1.
CNA PSON RR/ PRU AHT SGE CCL EZJ HMSO
Mixed results as sales reached £27.97bn, representing a 4.9% yoy decrease and falling short of expectations due to the decrease in customer accounts, and gas and electricity consumption. Operating profit finished in negative territory at -£857m due to £2.35bn of impairments and provisions, while on an adjusted basis it reached £1.38bn, which represents a 20% yoy decrease and missing forecasts. Bottom line, the group has performed better than expected due to lower financial expenses and taxes, as on an adjusted basis it has reached £863m which represents a 10% yoy decrease, but the fall is less than expected. Adjusted EPS reached 17.2p; however, on a reported basis the group booked again a net loss reaching -£747m that translates into a -14.9p EPS. Moreover, net debt was reduced by 9% yoy to £4.74bn. Adjusted operating cash flows improved by 2% yoy reaching £2,253m and the group expects to deliver 3-5% growth per annum, which is a positive. Free cash flow finished in positive territory after dividends and debt repayment. The dividend payment has been reduced by 10% yoy to 12p/share, but management expects it to steadily increase from this point forward. Guidance is focused on cash flow as lower commodity prices would continue to impact the group’s results especially the E&P and power generation business: the group expects to bring adjusted operating cash flow to £2bn in addition to a £750m/year cost efficiency programme, out of which a £200m/year reduction has already been achieved.
The group published today a trading update, reinstating its earnings objective as the decrease in prices has been offset by across the board expense reductions.
Despite the increase in residential consumption due to colder weather than in the previous year, the 10% decrease in household tariffs puts some pressure on margins. Revenue decreased by 2% yoy to £15.45bn, adjusted operating profit decreased by 3% yoy to £1bn. Adjusted for one offs, net income increased by 15% to £611m.
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