1. On the Grid


    David McIntyre and Calum Holt, Multi Asset Team
  2. April 2021

    The value of an investment in the fund, and any income from it, can fall as well as rise and investors may not get back the amount invested.


    For many countries, the drive towards cleaner energy supply is much more than an aspiration. As new carbon targets are set, the political and economic agenda required to make it happen is becoming ever more real. Against this backdrop, David McIntyre and Calum Holt summarise their thoughts on the potential transformation of the European energy industry and how this is being embraced in our Multi Asset funds.



    The notion that the world needs much more renewable energy capacity is well-understood, but it is worth illustrating how significant the potential demand is, driven in large part by hugely ambitious carbon reduction targets.

    This is particularly the case in Europe, where in December 2019 the European Union (EU) Commission agreed a European Green Deal advocating a legally binding target for the EU of net zero carbon emissions by 2050. This also included a tightening of the goal for 2030 to reduce carbon emissions to 50-55 per cent of 1990 levels.

    If anything, the Covid-19 crisis has given additional impetus to these efforts: in May 2020, the EU Commission announced a €750bn recovery plan which placed green initiatives front and centre.

    The capital commitments that will be required to achieve a net zero outcome are staggering. The European economic think tank Bruegel estimates around €300bn per annum of additional investment is needed to meet the 2030 targets.  Much of this spending will be on renewable energy, because the power sector accounts for around a quarter of Europe’s carbon emissions. While alternatives to renewables are available theoretically, most notably nuclear and carbon capture and storage (CCS), these are relatively expensive and, in the former case, deeply unpopular.

    Estimates vary but point to a massive increase in renewable capacity. To take one example, Bernstein estimate that a 50-55 per cent emission reduction target by 2030 implies that around 65-75 per cent of power generation in Europe would have to be renewable in ten years’ time, against 35 per cent today.

    Allowing for assumed growth in electricity consumption over that time, that implies total renewable capacity could grow from around 300 gigawatt (GW) now, to 700-900GW by the end of the decade i.e. a compound annual growth rate of around 10 per cent.

    In monetary terms, this is huge: at an estimated €1bn per 1GW of capacity, perhaps €500bn or more invested in the next decade alone (although this does not take account of falling capital costs over time), which compares to a current market cap for the entire Euro Stoxx utility sector of around €460bn.


    EU Commissioners Frans Timmermans and Kadri Simson discuss the European Green Deal.
    © Getty Images Europe.



    Reaching Europe’s ambitious carbon targets will require substantial investment in renewable energy, but that will not be sufficient in itself. It will also require the broader displacement of fossil fuels by electricity. In a sense, this goes hand in hand with the growth of renewables: as generation becomes cleaner, so electricity becomes a desirable substitute for a range of carbon-emitting inputs.

    Naturally, this leads to the question of who the beneficiary of such a transformation might be?

    This remains an open question, hence our ongoing interest and continuing research on the subject. However, in the course of our work so far, there are two areas which we think look particularly interesting: most obviously perhaps, the utility companies capable of supplying the electricity, alongside those companies which can help facilitate the increasing reliance on the electricity grid and its related infrastructure.

    Let us briefly explain our thoughts on both areas, starting with the utility companies which might be best placed to benefit from an increased shift to electrification, before then addressing the opportunity in the transmission and distribution market.



    More renewables and greater electrification creates a huge growth opportunity.

    Simply extrapolating current market share in renewables by the extent of the growth opportunity implies huge potential capacity growth for many European utilities.

    The obvious question is why existing utilities should be the ultimate beneficiaries? After all, the shift from thermal generation in which these utilities traditionally specialised towards renewables marks a massive structural change which should create an opportunity for new entrants.

    This has, indeed, been the case. The market shares of traditional utilities in renewable energy are typically much smaller than their entrenched positions in ‘old’ generation: today, they rarely have much more than 10-15 per cent of renewable capacity in their home region and often much less.

    In our view, however, there are several important reasons why existing utility companies should at least maintain, and might even extend, their presence in the renewable energy market.

    With relatively low ongoing costs and no fuel inputs, the vast bulk of cost for a renewable asset is the up-front capital commitment where, on average, the development of 1GW of renewables costs around €1bn.

    This, in turn, implies significant advantages to scale via, for example: lower financing costs; cheaper procurement; stronger commercial relationships with suppliers; and in-sourcing of operating and maintenance, which can typically be delivered more cheaply than when outsourced to the manufacturers.

    Renewables and electricifcation are hugely beneficial for transmission networks, which utilities operate.

    Greater renewable energy capacity and electrification creates huge potential demand for transmission network spending: the International Energy Agency (IEA) estimates that, globally, each $1 spent on renewables requires $0.50 of investment in networks.

    There are several sources of potential demand:

    • Renewable capacity is typically built in different locations to those where thermal generation is based, and often far from the places where it is used (most obviously in the case of offshore wind). This means new capacity is needed to transport electricity.
    • The intermittency of renewable energy increases the need for a properly integrated grid. On days when there is less sunlight, for example, there may be more need to draw power from wind and vice versa. This also increases the need for more interconnection capacity to improve cross-border access to national energy grids, so that at any point in time power can be drawn from where it is most abundantly produced to where it is most needed (more on which to follow below).
    • As more electric vehicle (EV) charging points are installed, these will need connected to the grid. The European Federation for Transport and Environment estimate that nearly three million EV charging points will be needed by 2030 to meet EU emissions targets, or a twentyfold increase in current levels. It is very plausible that to incentivise the required investment, governments will include this in the capex budgets of regulated distribution companies.

    The scale of renewable energy roll-out required will only be achievable with substantial investment in electricity networks to offset the issue of intermittent availability. As much of this capex is likely to be undertaken by regulated transmission and distribution utilities, it follows that their regulated asset bases (RAB) will increase significantly, and those costs will be passed on to consumers through higher bills. This, in turn, might see regulators press down on returns in order to mitigate the impact.

    While this is a plausible risk, we think some of the concerns are overdone. First, as capital costs reduce, and equipment becomes more efficient, the cost of renewable power is dropping sharply. As the cost of renewable energy drops, it seems likely it will substantially, if not entirely, offset the impact of rising network costs. In other words, substantial investment in network capacity and storage facilitates the rapid growth of renewable energy.




    Investors often quip that during a gold rush, the smart money is invested in companies selling picks and shovels. If there is to be an analogy in the transmission and distribution market, our shovel-sellers are most probably cable manufacturers.

    If we focus solely on cables for energy transfer, then the market can be split between a commoditised and a non-commoditised segment.

    The commoditised part of the market currently includes mostly medium- and low-voltage cables for onshore distribution and transmission. There is a large number of players, low margins, and little technological differentiation. A cable that connects a coal power plant to a substation for instance, will just need to supply an AC current in one direction, at the same voltage, 24/7, and will probably involve a simple piece of copper wire insulated with paper, a design which has changed little since the 1950s.

    The non-commoditised side of the market includes most of the high-voltage cable market, international interconnectors, submarine cables, and inter-array cables for offshore windfarms, where there are greater demands placed on the cable. However, only a few manufacturers can supply what is needed, so margins and pricing power are much greater.

    In this regard, we would view the outlook for the high-voltage cable market as highly favourable. The European Commission estimates the continent will need 450GW of offshore wind generation alone by 2050, and 1GW currently requires $200-350m worth of cable, a figure which may indeed grow substantially.

    Our thesis is that the non-commoditised side of the industry will grow quickly, both proportionally and in absolute terms for the following reasons:

    • Interconnectors between grids and countries are being built with increasing pace. Part of the reason for this is that connecting grids together smooths out supply and demand of electricity, making them easier to match up, but they also help link geographies suited to renewable generation assets with those that are not.
    • Offshore wind capacity is growing extremely quickly. The above figure of 450GW in Europe by 2050 should make this clear, and this offshore capacity will, almost by definition, be built far away from those parts of the continent where the energy is needed.
    • On land and in interconnectors, there will be greater demand for cables that support a reversal in the direction of energy flow. For low voltage cables this is not a problem, but the higher the voltage, the harder this becomes to do, and the more specialised cables are required.
    • On a worldwide basis, the IEA estimates that there will need to be €1.3trn of investment in offshore wind by 2040, so if 30% of that spend goes on cables, then that’s a €390bn opportunity over the next 20 years, without considering interconnectors, replacement of current cables, and higher prices for dynamic offshore cables.

    In the future cables will need to be longer, better armoured, deeper, DC rather than AC, better able to handle changes in flow direction, and better integrated with monitors for data analytics purposes. This increased complexity is starting to result in higher margins than have previously been the case, but this trend has only just begun and it is one which we think should continue for some time.



    Could returns for renewable utility companies fall as more capacity is added? There are at least two plausible reasons why they might. First, there are fewer barriers to entry in the renewables sector, so competition should push down on returns. Second, the increasing efforts in some parts of Europe to wean renewable energy off subsidies and expose projects to merchant power risk.

    This is not an inevitable outcome, however. As things stand, requiring developers to take full exposure to merchant prices is almost certainly not compatible with the scale of the renewable energy commitment implicit in EU targets.

    Mechanisms, such as ‘contract for difference’ (CFD), which involve long-term contracts that provide a guaranteed minimum price for the output of renewable generation, create revenue certainty and thereby reduce funding costs. These make it possible to raise the project finance required to undertake large-scale construction. If cannibalisation becomes widespread, then as sources of finance are withdrawn, new construction will ultimately become uneconomic.

    Long-term subsidies will probably have to continue in some form if renewable ambitions are to be met. It is unlikely these subsidies will be as they were in the early years of renewable development. They are more likely to be implicit, such as price floors, which prevent the price falling to an unsustainable level. Any advantages gained in storage and electricity grid technology will make it easier to reduce subsidies: renewable operators will be able to better match supply and demand and so avoid prolonged periods of low prices. 

    In addition, it is possible that in the long-term public subsidy may be replaced partly by the growth of corporate power purchase agreements (PPAs). These are multi-year fixed-price supply agreements between companies and renewable developers, which help reduce the costs associated with planning or operating renewable energy plants.

    In the case of the cables companies, given a strong competitive position from several incumbents, alongside potential under-capacity and increasingly technologically complex cables, we think there’s a compelling case for higher margins in this industry in the coming decade. And while this may well be the case almost across the board, it should be especially evident in the interconnector, high voltage, DC and subsea segments.

    The scale of the demand for cables in the coming decades (and current backlogs) should provide a solid floor for revenues, and with only a small number of manufacturers capable of supplying what is needed, margins and pricing power are that much greater.





    With high expected margins, one could be forgiven for thinking that equity-like returns will carry equity-like risks. However, in this instance, we do not think this is necessarily the case.

    Throughout our experience of investing in infrastructure as an asset class, our investments have encompassed a wide range of underlying opportunities, from those more stable and lowlier correlated, through to those which have exhibited a materially higher equity beta.

    In this context, we recognise the opportunities presented here are likely to be closer to the economically sensitive end of the spectrum than some of our other infrastructure investments. However, their track record still suggests they offer reasonable diversification over the longer-term, a point we acknowledge in the context of the potential returns on offer, which remains crucial in determining their overall appeal.

    Indeed, if current margins can be sustained as capacity grows, there is the possibility of very attractive returns being generated, but for those returns to be achieved in a way which should also be beneficial within a diversified portfolio. 



    If Europe is to get anywhere close to meeting its aspirations for renewable energy over the next few decades, it will necessitate huge investment in both renewable generation and associated electricity transmission infrastructure.

    That creates a significant growth opportunity not only for established European utilities, but also for those companies best placed to facilitate the increasing transition to electrification, the increasingly important players in renewable development most likely to accrue economies of scale over time.

  3. Risk Factors

    The views expressed in this article are those of the Multi Asset team and should not be considered as advice or a recommendation to buy, sell or hold a particular investment. They reflect personal opinion and should not be taken as statements of fact nor should any reliance be placed on them when making investment decisions.

    This communication was produced and approved in February 2021 and has not been updated subsequently. It represents views held at the time of writing and may not reflect current thinking.

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  4. David McIntyre Investment Manager

    David is an Investment Manager in the Multi Asset Team and is a CFA Charterholder. He joined Baillie Gifford in 2008, initially working in our Fixed Income and European Equity Teams. David previously worked for KPMG and in 2007 qualified as a Chartered Accountant. He graduated BA in History and Politics from the University of Oxford in 2004.

  5. Calum Holt Investment Analyst

    Calum joined Baillie Gifford in 2019 as an Investment Analyst, first on the US Equities Team and now as a part of the Multi Asset Team. He graduated from Oxford University in 2018 with BA(Hons) in History.