Questions From Institutional Investors About Energy Transition Are Revealing

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Recently, Jefferies Group, one of the United States largest investment banks, asked me to speak to a global group of their clients, institutional investors representing billions and possibly trillions in funds. The subject of the discussion was the future mix of electrical generation in our decarbonized world and the implications for transmission and distribution grids.

Questions at the end of the session were revealing.

Confidence Levels & Approaches

The first and very apt question was how certain I was of the percentages of future electrical generation would come from nuclear, wind, solar, and the like. What process did I follow, and how should investors approach their own projections?

As I frequently write in my projections and say in discussions, the error bars are big. I’m projecting scenarios decades into the future, when the great work of Philip Tetlock and his collaborators make it clear that 18 months is pretty much it for accuracy for most things. I also like to say that I think I’m less wrong than most.

I noted that for most investors, my global projections were informative, but not necessarily directly helpful. Their investments, by definition, would be much more local. As such, when considering a country or region, they need to consider a bunch of factors that are lost in the details of my longer range, global mix.

An example I called out was the country of France. It’s stuck on nuclear energy, but it’s best thought of not as supplying 75% of France’s demand, but as supplying 13% of Europe’s demand. Nuclear energy is inflexible due to a combination of technology and economics. It has to run at 90% or so capacity factors in order to make money, and most designs and technologies don’t like changing up or down in any event.

It’s a very different proposition investing in generation and transmission in France than in the North Sea. And it’s very different investing in either of those than in the Maghreb region of northern Africa where there’s a lot of sun and wind and not a lot of people. And it’s different yet again in jurisdictions like British Columbia, where all questions about energy immediately elicit suggestions for where the new hydro dam should go.

There are combinations of geography, energy history, regulatory structures, and the like where it’s just easier to do one thing than another. In BC, hydro electricity. In Maghreb, solar farms. In the North Sea, offshore wind.

If you go to a place with a lot of coal, they’re going to want to talk about building supercritical coal plants and bolting on carbon capture, which is something you should walk away from, as they make no economic sense.

For infrastructure investors, generation mixes are much more local than my global ones.

Hydrogen

One investor had been a couple of minutes late, and wondered if I had a hydrogen slide, and if so, what percentage of future electricity would come from the molecule.

I didn’t have a hydrogen slide because hydrogen isn’t a source of energy, it’s an industrial feedstock. It can be used for energy, but it’s not going to be because it’s such an inefficient store and source of energy. It’s expensive to manufacture, expensive to store, and expensive to distribute. And when used, it returns only a fraction of the energy that is used to make it.

At present, it’s a climate change problem of the same scale as all of aviation, and job number one is to fix that. Currently, the single biggest use, about a third of the 120 million tons or so we manufacture from fossil fuels annually, is to remove sulfur, water, and other impurities from crude oil, and to crack the crude into lighter and heavier fractions. That’s going away.

It’s always going to be more expensive than direct electrification. My assessments of importing hydrogen from Africa to the EU or making it offshore at wind farms and piping it ashore make it clear that it would be ten times the cost per unit of energy as liquid natural gas, which is currently the most expensive form of energy any country imports. That’s not an economically sound energy strategy for a country or continent, and it won’t be followed through on.

There will be no hydrogen for energy economy. It’s not suitable for heat, ground transportation, or air transportation. Synthetic fuels made from hydrogen will be even more expensive than hydrogen by itself and even less efficient.

Intermittency & Baseload

The follow-up question was about where we were going to get baseload energy from then, and how we were going to deal with the intermittency of renewables. Can storage be big enough?

We’ll be overbuilding renewables a bit, perhaps 25%, just as we have overbuilt every form of generation except nuclear, and run it at lower capacity factors than maximum. We’ll build lots of transmission in every direction to bring renewable electricity from where it happens to be prevalent to where it happens to be in demand at different times of the day and night. The sun is still shining three timezones to the west as the sun drops where you are, and we’ll do that timezone shifting.

We’ll be building lots of wind, solar, and storage in more remote areas and bringing firmed electricity to big demand centers. An example of that is the Xlink project, which will bring 3.6 GW of firmed electricity to the UK 20 hours every day over HVDC cables.

We’ve had pumped hydro storage in commercial operation since 1907. It’s by far the biggest energy store on the grid today, and the biggest form of energy storage under construction today, mostly in China. An Australian National University GIS study finds that we have 100 times the resource for storage as is required globally, and 200 times the requirement in North America. That was for pairs of small reservoirs separated by at least 400 meters vertically and not too many kilometers horizontally. It was off of protected land and near transmission.

A gigaliter of water in a pair of reservoirs separated by 500 meters is a GWh of 80%+ round trip electricity storage. The reservoirs would only be about a kilometer on a side, big ponds more than lakes. And they are 100+ year assets.

Demand management of the new electricity consumers is going to play a big role as well. All of the EVs will end up being plugged into smart chargers that automatically spread charging over lower demand periods as a major example.

Role Of Utilities & Technology

A different investor was interested in the role of utilities in bi-directional electricity flows, and what concrete examples of technologies I could share.

There are two levels to this. The first is the big interconnectors between grids. The first type of that is just plugging different side-by-side electricity grids together. Each grid is a running its own rhythm and the grid next door is either just off the beat or is running a different tempo entirely. North America has several grids. Japan has multiple grids and some run at different tempos for historical reasons.

HVDC is used in back-to-back mode to turn the synchronous electricity in one grid into asynchronous, beatless electricity and then convert it into the frequency of the other grid. Those are two-way connections so electricity can flow between the grids.

Longer interconnects between countries use HVDC as well, and increasingly it’s used within countries for longer transmission from renewables to demand centers. Those are increasingly bi-directional as well. There are several already in existence between the UK and European countries and more in construction, enabling the archipelago state to share electricity back and forth with the continent.

Lots of that is in construction. There’s the Moroccan example, a project to bring solar electricity from Australia to Singapore, a Black Sea connector to bring electricity from far eastern Europe to central Europe, and one to link Israel with Europe.

At the bottom end of the scale, it’s on the distribution grid. Commercial, industrial, and residential sites are plugged into the grid and used to get electricity solely from it. Now they have solar on their rooftops, car parks, and side fields, and push electrons back into the grid. That’s still pretty small scale, as we have to get up to light industrial and above to potentially reach MW-scale bi-directional flows. Net metering with utilities is required, and that’s increasingly requiring disaggregated services for energy, the distribution grid, frequency and voltage quality, and backup so that utilities are still compensated for the infrastructure that makes behind-the-meter generation relatively inexpensive.

HVDC has made some big strides in the past decade. In 2012, ABB delivered a breaker that was both fast enough and robust enough to allow HVDC to be used a lot more. Subsequently, line commutated converters (LCC) were displaced by voltage source converters (VSC), which are by far the dominant technology used today. They enable a high efficiency connection to be made between an HVDC source and an alternating current transmission line by artificially recreating the frequency sine wave in tiny digital increments, effectively pixelating the wave.

For investors interested in HVDC, it’s worth following RTE International, especially its monthly HVDC-VSC newsletter for information on new lines and technical and economic developments.

What’s Changing Where, & What Things Should Investors Look For?

The next question was a bit of a grab bag, looking for a few key takeaways. Where should investors be looking for opportunities amid the HVDC, transmission grid, distribution grid, transformers, and substations? How does the generation type impact this view (much of which was covered in the presentation and summary article)? And how should we look at specific changes in generation mixes in terms of what that might trigger for us?

The first observation I made was that on distribution grids there would be a migration of heavier duty transformers from further up the grid to further down. Demand at the end points of the grid was going up with things like EVs and heat pumps displacing things that burned fossil fuels. That’s a slow and gradual change, but it means more investment in transformers from the center of the network to the periphery. This process will take 20 or 30 years and be more of an accelerated maintenance program within utilities. Those entities are often challenged due to local politics constraining the price of electricity for reasons related to winning elections, so they may not be as well funded as necessary for the work.

Historical changes in grid, especially liberalization under specific types of governments, leads to some interesting problems. For example, both Australia and Alberta saw their transmission spun off under different structures that allowed very expensive upgrades of questionable necessity that has led to very high costs to connect generation to transmission. Regulated monopolies tend to include guaranteed profits for the utility, which is good for investors, but it can lead to some sub-optimal grid transformation decisions.

Another new thing in the mix is the EU’s carbon border adjustment mechanism (CBAM). That’s going to be pricing the embodied greenhouse gases of all imports to the region at the EU’s emission trading scheme price starting in 2026. It’s the third largest economy on the planet and a major importer, so this is effectively pricing carbon for every firm which exports to it, which is most of them.

The EU’s budgetary guidance for its carbon price in 2030 is US$203 per ton of carbon dioxide or equivalent, and close to $300 in 2040. Any geography which electrifies its economy and decarbonizes its electricity is going to have a baked-in competitive advantage over countries which don’t. The CBAM will give credit for local carbon pricing in the exporting countries, so Canada, a dozen US states including California, and China will all get discounts on CBAM pricing at various levels. All of those jurisdictions’ prices are below the EU’s at present, but all are going to be increasing.

US states that aren’t covered by a carbon price or still have a lot of coal and gas in the mix won’t be able to export things to the EU because they won’t be able to compete. That’s going to drive grid and green generation investments.

The Developing World

The final question was about what was going to happen in the poorest parts of the world, such as sub-Saharan Africa and parts of southeast Asia. How would these changing dynamics evolve in those places as opposed to the developed world and China?

One thread is that there is a transformation going on in the developing world that is mostly invisible to western eyes. Nigeria ordered 14,000 electric buses from Chinese e-bus giant Yutong, which is bigger than any order from a developed country. That’s a major expansion of bus numbers in the country. They are leapfrogging the west with electrification and transit, just as they leapfrogged with wireless phones. Similarly, two- and three-wheeled powered vehicles are an enormous part of transportation in those regions, and they are electrifying quickly. It’s much easier to build and fuel an electric scooter or bike than an electric car or truck, and expectations are much lower.

Another thread is China’s Belt & Road Initiative (BRI). Three-quarters of the countries in the world are part of that program, including many eastern European ones. As investors think about eastern European investments, they can see if they can engage with BRI projects. BRI is building a lot of roads, bridges, rail, transmission, and generation. And while there are still a lot of legacy coal projects in the BRI, as of two years ago, China committed to not adding any new ones.

For sub-Saharan Africa specifically, 44 of the 46 countries in the region are part of the BRI, and there are a lot of projects going on. A study published this year was particularly interesting from the perspective of grid and electrification investments. Chinese and African researchers using Europe-developed simulation tools modeled out multiple scenarios for a 12-country, 10,000-km HVDC supergrid connecting western Africa just below the Sahara, across to the east and then down to South Africa. The BRI penetration suggests this has the potential to be built, turning into one of the biggest infrastructure and decarbonization initiatives in the world,

As a note, a Johns Hopkins and Harvard Business School study in 2021 found that there was no evidence of any BRI Chinese debt trap, a dominant narrative in the west. China has been forgiving zero-interest loans and renegotiating terms as necessary, and only carries a bit over 10% of the debt of countries. Most foreign debt in economically challenged countries is carried by the west.

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And so, another interesting session with global investors ended. The questions are often the most interesting part for me, as I get a chance to see where their minds are at and what is resonant for them. Often questions are ones I haven’t thought through myself, and so make first approximations during Q&A sessions and then return to them.