Profit from the energy revolution

Blowing away the competition

The contracts for difference (CFD) scheme is the government’s mechanism for supporting investment in low-carbon electricity generation. Providing long-term protection from volatile wholesale electricity prices, developers are guaranteed a ‘strike price’ per megawatt hour (MWh) of electricity they produce over a typical 15-year period. If the wholesale market electricity price is less than the strike price, developers receive a top-up from the government to make up the difference. If it exceeds the strike price, developers must pay back the difference.

In the first CFD auction back in 2015, two offshore wind projects accounted for around 55 per cent of the total 2.1 gigawatts (GW) of capacity awarded to renewables developments. The average strike price was £117.14 per MWh in 2012 prices. The government’s aim back in 2012 was to reduce the cost of electricity from offshore wind to £100 per MWh by 2020. The results from the most recent CFD auction released in September suggest that target was wholly unambitious. The average strike price secured by six offshore wind farms was just £40.63 per MWh. This dropped to as low as £39.65 per MWh for projects due to be delivered from 2023.

Solar and onshore wind are no longer allowed to compete in CFD auctions, meaning offshore wind accounted for 95 per cent of the 5.8GW of new capacity awarded. With the strike price falling below the average 2019 wholesale price of electricity of £49 per MWh, this implies electricity generated from these new offshore wind projects will be subsidy-free. For Hugh McNeal, chief executive of trade association RenewableUK, these results mark “a new era of cheap power”, cementing offshore wind as the “backbone of the UK’s clean, modern energy system”. 

Benefiting from a mix of shallow waters and optimal wind speeds in the North Sea, the UK is a leader in offshore wind with the largest installed capacity in the world. With current capacity at 8.5GW, offshore wind provides around 8 per cent of the country’s annual electricity needs. As part of the government’s sector deal, the UK is targeting 30GW of offshore wind capacity by 2030. But with election policies flying around, this could yet increase further. Boris Johnson has pledged to extend this target to 40GW, while Labour is aiming to deliver 52GW through a majority state-owned venture that creates 37 new offshore wind farms.

According to analysis by climate research website Carbon Brief, the record-low auction prices mean the electricity generated from new offshore wind farms will be cheaper than existing gas-fired power stations (see chart). The rapid reduction in cost has come about through economies of scale and technological advancement. Seeing the industry as having reached an inflection point, Isabella Hervey-Bathurst, equity analyst at Schroders, believes “the growth potential for offshore wind could be huge”.

There are investment opportunities across the supply chain. Siemens Gamesa Renewable Energy (Sp:SGRE) is the world’s leading producer of offshore wind turbines. But despite confidence in its long-term outlook, the group has guided that industry pricing pressure could see its operating profit margin drop from 7.1 per cent to as low as 5.5 per cent in 2020. For Will Argent, lead adviser for the VT Gravis Clean Energy Income Fund (GB00BFN4H792), “it is likely that the most stable returns will come from investing in the operational assets responsible for the generation of renewable energy”. This is because these projects typically benefit from long-term contracted cash flows, often supported by government subsidies.

SSE (SSE) has been making a big push into offshore wind, with its generation capacity rising by over two-thirds to 579MW in the first half of the 2020 financial year. Its three proposed wind farms at Dogger Bank – a joint venture with Equinor (US:EQNR) – are on course to become the world’s largest offshore wind development, with 3.6GW of installed capacity. The group sees its renewables division as central to future growth and is aiming to treble its annual output of renewable electricity to 30 terrawatt hours by 2030. Accounting for 30 per cent of the group total, adjusted operating profit from the renewables business almost doubled to £150m in the first half. SSE looks well placed to capitalise on the increasing decarbonisation of the UK’s electricity generation. But be aware that from an income perspective, while its dividend cover is expected to improve this year, it will still be a thin 1.1 times adjusted earnings per share (EPS). 

Analysts at RBC Capital Markets believe now could be a good time to capitalise on the share price weakness of Ørsted (Den:ORSTED), the leading global offshore wind developer. Formerly the Danish Oil and Natural Gas group, it has transitioned “from a black to a green energy company”. Although the group reported stronger-than-anticipated results in the third quarter, it also warned it had underestimated the impact of the ‘blockage’ and ‘wake’ effects – which slow wind speeds – reducing the internal rate of return on its future projects by 0.5 percentage points. But even with the ensuing dip, its shares are up 44 per cent so far this year. With RBC describing the reaction as “overdone”, now could be an attractive entry point for a long-term growth opportunity.

Other runners in the race to zero

While offshore wind has been grabbing the headlines, it is still eclipsed by onshore wind, which has an installed capacity of 13.5MW. From 2015, onshore wind has consistently supplied 55-65 per cent of the UK’s wind power. While there are no current policy mechanisms supporting onshore wind in the UK, SSE believes some form of subsidy will need to be reintroduced to help deliver the volume of new onshore wind needed to meet the UK’s net zero emissions target. Greencoat UK Wind (UKW) is predominantly focused on onshore UK wind assets, which comprise 95 per cent of its operating portfolio by value. The 35 assets it holds equate to a generating capacity of 979MW and RBC Capital Markets believes the group can continue to deliver its target internal rate of return of 8-9 per cent (net of fees). Aiming to grow the dividend in line with retail price index (RPI) inflation, cover remains healthy with payments covered 1.7 times by net cash generated by operations during the first half of 2019.

A smaller part of the picture is solar power, which accounted for 12 per cent of the UK’s renewable electricity generation last year. Despite the removal of subsidies for new solar installations in 2017, new builds have continued as costs have declined (albeit at a gentler pace than offshore wind). Michael Bonte-Friedheim, chief executive of NextEnergy Solar Fund (NESF), says the UK has benefited from subsidy regimes in other global markets, which has led to increasing efficiencies. With assets spread across the UK and Italy, NESF is a more niche investment, but Mr Bonte-Friedheim believes “leading expertise in a particular technology allows you to outperform financially, technically and operationally versus the generalists”.

For those looking for broad exposure to the rise of renewables, The Renewables Infrastructure Group (TRIG) invests in a range of renewable energy infrastructure assets across the UK and Northern Europe. At the end of June, the trust had 73 per cent of its assets invested in onshore wind, 13 per cent in offshore wind and 13 per cent in solar. The proportion of its assets located in the UK is declining, having dropped from 82 per cent to 55 per cent since the beginning of 2018. Spying opportunities in Europe, the group recently amended its limit so that it can reduce UK exposure to a minimum of 35 per cent. Recently featured as one of the IC’s Top 100 Funds, its diversity helps smooth returns. Richard Crawford, director of infrastructure at the fund’s adviser, InfraRed Capital Partners, notes that “a stable revenue stream comes from the spread of assets across technologies and geographies”.

The intermittency factor

With the economics looking ever more attractive, can our electricity be derived solely from renewable sources? Critics point to ‘intermittency’, with renewable electricity generation dependent on whether the wind is blowing and the sun is shining. Wind output can vary from 2GW on one day to 12GW the next. In the first instance, this causes obvious challenges in matching demand with supply, suggesting that flexible, dispatchable sources of power will be needed to balance the fluctuating renewables output. But it is also problematic for a power network that needs to maintain a frequency of 50Hz – just a 1 per cent deviation from this can damage infrastructure and equipment.

Designed around the concept of large, centralised generators, the grid has yet to properly adapt to the rise of renewables. Conventional generation is still required to be able to maintain the system within its operational limits. Grid constraints mean that there are times when additional renewable generation is limited by network capacity, triggering these sources to be curtailed and energy lost. National Grid’s electricity systems operator (ESO) is aiming to be ready to operate a zero-carbon electricity system by 2025.

Finding the right balance – the nuclear option

For the near term^, at least, it appears renewables will need some form of back-up or balancing partner. For some, that role should be filled by nuclear power, which currently provides around a fifth of our electricity supply. The UK’s eight nuclear power plants are majority-owned and operated by EDF Energy (Fr:EDF), with Centrica (CNA) holding a 20 per cent stake it is trying to divest. But seven out of eight of these plants are due to come offline by 2030 as they reach the end of their operational lives. The coalition government laid out plans to build up to 16GW of new nuclear capacity by the mid-2020s, but so far only the 3.2GW Hinkley Point C project – the joint venture between EDF and China General Nuclear Power – is under construction. Toshiba withdrew from its Moorside project last year and Hitachi suspended development at Wylfa Newydd and Oldbury in January. There are only two further developments in the pipeline, Sizewell C and Bradwell B, and it is uncertain whether these will proceed. 

Given the green light in 2013, Hinkley was originally set to start producing electricity by 2023 and satisfy 7 per cent of the UK’s electricity demand. With that date already pushed back to 2025, EDF warned in September that it could be further delayed by 15 months with completion costs rising by up to £2.9bn to £22.5bn. The project’s internal rate of return has slipped from around 9 per cent to as low as 7.6 per cent. Set against the declining cost of renewables, particularly the recent benchmark set by offshore wind, nuclear power seems comparatively poor value for money – the 35-year strike price agreed for Hinkley in 2013 is £92.50 per MWh.

With the exorbitant upfront costs, few developers have a balance sheet that can accommodate the £15bn-£20bn cost of delivering a new nuclear facility. Investors are reluctant to dive in given that under the CFD scheme, revenue only starts to come through once electricity is being produced – with cost and schedule overruns, this could take more than a decade. The government is exploring the viability of using the ‘regulated asset base’ model. Rather than waiting until a plant is operational, developers would be able to charge electricity suppliers a regulated price in exchange for providing and operating the nuclear infrastructure that will ultimately materialise. This could bring down borrowing costs and allow investors to reap returns much sooner.

Rolls-Royce (RR) believes small modular nuclear reactors could “avoid the complexities, delays and overspends often associated with infrastructure projects”. Suggesting a 500-day build is possible, the group believes its design could lower the cost of electricity generated from nuclear, but this would still be in the region of £60-70 per MWh.

Powering past coal – another dash for gas?

In May, the UK reached another milestone by going two weeks without coal as part of its energy mix, the first time since before the Industrial Revolution. From that coal-free fortnight, the UK is looking to kick its coal habit forever on the back of the government’s commitment to close all remaining coal plants by 2025. Having been responsible for 30 per cent of our electricity generation in 2014, this dropped to just 5 per cent last year. Of the seven coal-fired power stations that were still operating at the beginning of this year, EDF’s Nottinghamshire Cottam plant ceased generation in September, while SSE’s Fiddler’s Ferry power station and RWE’s (Ger:RWE) Aberthaw plant will close by the end of March next year. Drax (DRX) has converted two-thirds of its Selby plant to biomass.

The ‘carbon price support’ – a tax paid by companies that generate electricity from fossil fuels – has weakened the economic viability of coal, tipping the scales in favour of natural gas, which provided two-fifths of our electricity last year. The oil and gas majors have bet big on the ostracisation of coal, fuelling an appetite for comparatively cleaner gas. But that gamble could end up being misplaced amid the burgeoning renewables revolution. More than just climate-change-led pressure against accepting gas as the ‘lesser of two evils’, falling costs are now challenging the economic case. Bob Dudley, outgoing chief executive of BP (BP.), has bemoaned that “gas is being increasingly marginalised. Even vilified and demonised”. He views natural gas as crucial both now and in the future, likening any effort to exclude gas as “an attempt to achieve the energy transition with one hand tied behind our back”.

So, what role will natural gas play in the future of the UK’s electricity mix? “We are already seeing combined cycle gas turbine (CCGT) margins and running patterns being impacted by the deployment of renewables,” says Steven Britton, senior analyst at Cornwall Insights. “This will undoubtedly continue in the future, making investment in new stations challenging.” According to BEIS’s 2018 energy and emissions projections, electricity generation from natural gas has peaked and is set to decline through to 2035 (see chart). But Mr Britton suggests natural gas will still be a feature of the most cost-effective decarbonisation scenarios. Gas plants will persist because they provide “valuable flexibility to balance intermittent renewables”. In light of different new roles, Cornwall Insights forecasts that installed capacity of gas-fired generation will probably increase, but that plants will run at much lower load factors.

Drax believes new-build gas generation is “a necessary transitional technology” as the UK seeks to meet its net zero carbon targets. It is developing options for four open cycle gas turbines and has received planning permission to convert its last two coal-fired units at Drax Power Station. With the suspension of the UK’s capacity market lifted – the mechanism that offers energy companies steady payments to supply power to the grid at times of stress – the group is looking to develop new gas generation with the support of these 15-year contracts. Drax offers investors exposure to the ongoing role of gas in our energy mix, whether that be as a ‘bridge’ to a zero-carbon future or as a more substantial player. At the same time it is also well-positioned to capitalise on increasing decarbonisation as it seeks to reduce the cost of its biomass generation to become subsidy-free beyond 2027.     

For natural gas to remain compatible with the UK’s decarbonisation aspirations, operations is likely to have to be accompanied by carbon capture, usage and storage (CCUS), a nascent technology that is yet to demonstrate large-scale economic feasibility. A near-term switch to burning hydrogen to eliminate carbon emissions seems similarly distant and would require a large overhaul of existing infrastructure. Until these methods become cost-competitive, natural gas will continue to come under pressure from low and zero-carbon sources.

Energy storage

Gas’s days could be numbered if another solution emerges for the intermittency dilemma. The current issue is that renewable technologies lack the readily dispatchable nature of conventional power sources. But energy storage holds the key to making renewables flexible, storing excess electricity at times when generation is abundant and releasing it later when needed. The emergence of widespread grid-scale battery storage could see renewables stand independently, without relying on balancing power sources.

That backdrop bodes well for Gresham House Energy Storage Fund (GRID), which invests in UK energy storage systems (ESSs). Having listed in November last year, the fund currently holds 124MW of capacity across seven utility-scale ESSs and is aiming to have 229MW in operation by the end of the first quarter of 2020. Revenue is primarily derived from ‘firm frequency response’ contracts – adding or removing power from the grid to maintain grid frequency – but this year will see a shift towards asset optimisation. Targeting a net asset value (NAV) total return of 8 per cent, the fund is aiming to reward shareholders with a 7p dividend in 2020, up from 4.5p this year.

Connecting the dots

While the rise of renewables is beneficial from both a cost and environmental perspective, the more volatile supply of energy does make it more difficult for the grid to balance demand and supply. Jon Butterworth, chief operating officer for global transmission at National Grid Ventures, believes interconnectors – underwater cables that join the UK’s electricity grid to neighbouring countries – are “in many ways the perfect technology”, providing the flexibility for multiple sources of low-carbon energy to be used efficiently. By linking national energy systems, interconnectors can smooth hourly variations in production from wind and solar farms. For example, when it is more overcast in the UK or wind speeds are low, we can fill the gap by importing decarbonised energy from Europe.

The UK currently has five interconnectors in operation providing 5GW of capacity. In the first six months of this year, almost two-thirds of electricity imported through these underwater cables was from zero-carbon sources. National Grid is investing over £2bn in a new suite of interconnectors, anticipating that they will add around £250m in cash profits (Ebitda) when they are fully operational by the early to mid-2020s. By 2030 it expects to be operating at least six interconnectors, through which 90 per cent of imported electricity will be from zero-carbon sources. Due to be completed in 2021, the group is currently constructing the world’s longest interconnector between Northumberland and the Blasjo reservoir in Kvilldal, which will plug the UK’s grid into Norway’s largest hydro-dam. 

The path ahead

Renewable energy is set to play a much more prominent role in the generation of the UK’s electricity, with offshore wind leading the charge. Conventional power sources are being forced to confront an uncomfortable reality in which their influence is being greatly diminished if not facing obsoletion. Ultimately, while the direction of travel may be clear, the precise future mix of energy is more obscure. Natural gas looks set to hang around for a while yet, but its fate is likely to be determined by who wins the technological race – carbon capture or energy storage. As we stand at the precipice and look back at the rapid progress that has brought us to this point, it’s worth bearing in mind that a zero-carbon future might come sooner than you think.