The energy transition is already here – and becoming widely distributed

William Gibson is often quoted with the line “The future is already here — it’s just not very evenly distributed.”

It has become fashionable to deride this insight for various reasons – for example it sounds too passive – things will happen no matter what one does. But in terms of the energy transition, it has a very strong narrative and insightful power – and a precise analysis.

Consider.

In 1919, just over a century ago, and in living memory of a few of us today, only 6% of homes in the UK were lit by electric light – 94% were lit by gas, candles, or by those just willing to deal with the dark.

In 2023, and over 22,000 electricity pylons later or 220 per year, almost every UK home has not only electric lights, but electric appliances that range from the ability to boil water in a kettle to heat food via a microwave or induction hob, to the ability to charge the family car, or use a heat pump to warm the home.

From science fiction to humdrum in a generation or two – Gibson’s insight seems vindicated. And the move from non-fossil-fuel power for electricity is already on this curve of adoption.

So, the UK’s electricity grid has had to handle this constant tilt toward new demand for decades.

It has responded and used various technical solutions to out-think new demand requirements with clever supply options.

It has worked with new supply options such as hydroelectric, nuclear and wind and solar, and new demand-reducing technology innovations such as LED lightbulbs and demand management software.

Thus from 2008 until 2018 electricity demand in the UK actually declined by 12% (even as the population grew by 7%), and emissions declined by 62%, as coal was eradicated from the grid.

It’s next phase of development, as the latest UK Climate Change Committee report outlines, is to finish the UK power energy job: make sure almost all of the electricity produced is from cheap, sustainable energy sources, domestically produced e.g. from wind and solar and storage, and provide long-term stable, low-cost, low-emitting energy for the country.

In our latest report Gone with the wind , we note how the UK’s vast reserves of wind power serves this aim – but it is not wind technology that will slow its deployment (that is mostly solved) – it is the blockages of more mundane issues of transmission upgrades, permitting and governmental approvals.

This has significant real-time consequences for the UK consumer and for the energy transition in general: this transition will happen, but it needs to happen quickly. As we see later in the analysis of ENEL.

In both cases the incumbent bureaucracy or corporations are not grasping the opportunity of the new technology, and its scale and speed of development.

Let’s delve into this case of UK wind power.

Investments in the electricity grid are not keeping up with the rapid growth of wind resulting in record losses of green electricity and higher costs for British consumers.

In the report, we analyse the health of the UK’s electricity transmission grid – the backbone of the future decarbonised power system. We find that, as investments in transmission have stalled, the UK’s electricity grid has not kept pace with wind deployment and is currently not fit for purpose. As things stand, the grid cannot adequately deliver the UK Government’s vision of “affordable, homegrown, clean energy”.

Due to these shortcomings, the system is increasingly forced to curtail wind generation while requesting polluting gas plants to ramp up generation in so-called wind congestion events.

In summary:

The problem – (in the UK and worldwide)

The UK’s electricity grid is not yet fit for the purpose of renewable-dominated power. Since 2021, wind congestion costs have totalled £1.5 billion, repaid to grid suppliers from the operator, with the amount of wind power curtailed equating to the annual consumption of 1 million households.
Wind congestion on the Scotland-England bottleneck, responsible for 95% of today’s costs, is set to grow five-fold by 2030 as Scottish wind capacity is expected to grow five times faster than new transmission capacity. Wind congestion repayment costs from the operator to suppliers could reach £3.5 billion per year, with up to 20% of Scottish wind production at risk of being curtailed.
This is not just a UK problem – grids having to catch up with fast-growing renewables and connection issues are a US and Chinese issue too.

But there multiple (and increasing) solutions for the UK and elsewhere:

To start with, UK power oversight body Ofgem is looking to review these issues – but a quick resolution is required

Timely delivery of projects is critical, and delays in constructing transmission capacity would be extremely expensive. Our model shows that one year of delay could cost £3.6 billion while delivering new projects one year early could save a similar figure. Policymakers and regulators should prioritise project delivery as a matter of urgency.
Building new cables is key. Expanding further the connection between Scotland and England, despite the lengthy and complex permitting process, could prove extremely effective by reducing wind congestion costs by half. New cables could generate in one single year savings equivalent to half of their investment cost. However, urgent measures would be needed to deliver any additional cable on top of the existing pipeline by 2030.
Grid congestion can offer a business opportunity for flexibility providers. Accelerated deployment of storage can reduce wind curtailment by half without the need for new transmission infrastructure but at a higher cost. Battery storage, pumped hydroelectric and hydrogen can take advantage of negative electricity prices during wind congestion events while increasing the resilience of the grid.
Green hydrogen from wind surpluses. Scottish green hydrogen production could satisfy half of the UK’s projected hydrogen demand by 2030 and could be deployed for seasonal storage or for accelerating decarbonisation in hard-to-abate sectors.
Stronger locational price signals are needed to attract investments. The current electricity market lacks strong locational signals that can direct investments to the regions that need it the most. For this reason, we suggest a review of the Capacity Market and Contracts for Difference rules with an outlook for a deeper transition towards locational pricing beyond 2030.

To sum up – our electricity grid in the UK can handle our future electricity needs and is an engineering marvel.

This is what engineers would call a “good problem” – one that can be fixed and is due to a fast -growing new and better technology. The key will be to maximise the benefit of solving it.

If we optimise it now to handle new technologies of wind, solar, storage we secure value for the future and establish UK leadership in prized skills of wind installation, demand management and financial tools of grid efficiency.

However, in this moment of transition we may lose these key opportunities and the report outlines where we need to focus to ensure success, given our natural resources and industrial head start.

Energy Transition Plan Analysis

Enel’s possible backward step – but does it matter? Ex-boss Starace doesn’t think so.

Our latest transition analysis on major energy producers now covers Enel in this new report .

To set the scene – Enel is the largest global renewable private player, the biggest network operator by end users and retail operator by customer base.

The Group is the largest European utility by recurring EBITDA. It is an integrated power utility with 89GW of generation capacity, of which 31GW conventional, particularly CCGT. It has 72m end users, of which 32m are in Italy.

Enel’s 2023-25 Strategic Plan is aimed at accelerating sustainable electrification, streamlining Enel’s geographical presence to six countries (Italy, Spain, the US, Brazil, Chile and Colombia) and strengthening the balance sheet.

It tells a common story of incumbents.

Most of their emissions come from “Scope 3” activities (industrial and private consumers using their products: burning fuels, driving cars etc), and it is about how fast they can transform their business model to non-carbon production that determines their progress to Net Zero goals.

The recent up-tick in oil prices has made their traditional fossil fuel divisions more profitable, reducing the immediate fervour for change,

As we see here then, Enel whilst progressive in intent, has made little progress in engineering terms to the Paris goals – and with recent political changes in Italy, creating managerial and strategic changes, it is likely that the current momentum toward renewables may well slow-down or reverse

But ex-boss Francesco Starace believes that the transition is inevitable anyway.

We unpick the current situation here in our detailed analysis. And set out key questions for management to address given the current progress and recent changes to management.

To sum up:

Enel is Paris aligned, but has made little progress since 2020

Enel’s target to reduce 80% of scope 1 emissions over 2017-30 aligns with the goals of the Paris Agreement. However, Enel has made little progress in reducing scope 1 & 3 carbon intensity since 2020 and will likely struggle to hit 2023-24 targets. This will probably increase the cost of some emission linked debt. At 57% of total, Enel’s greatest challenge is Scope 3 emissions, mainly power & gas retail, where it has also made little progress since 2020. Nevertheless, Enel meets nine out of ten of the CA100+ criteria except for Just Transition, not assessed at October 2022.

Corporate governance conditioned by State ownership; changes to senior management

Enel holds strategic assets relevant to the national interest and is subject to the legal framework for special powers of the Government in strategic sectors. The state owns 23.6% and there is a cap on voting rights for other shareholders of 3%. Very recent changes to senior management, with Scaroni, ex CEO of ENI over 2005-14, as Chairman and Cattaneo replacing Starace as CEO, were opposed by some investors and may imply a change to the energy transition strategy.

Enel is closing fossil fuel capacity faster than most, but its fossil fuel portfolio remains substantial

Enel’s plans to exit coal by 2027 are ahead of peers RWE & EDF, while a planned exit from CCGT by 2040 is in line with RWE but ahead of Engie & EDF. Although it is planning to retire 16GW thermal assets by 2025, fossil fuel capacity today still accounts for 30% of total at 27.7GW.

Fossil fuel businesses more profitable than renewables in 2022

Enel coal and gas assets were highly profitable and cash generative (on EBITDA less capex) in 2022. For context, although the figures were affected by weak hydro, Enel renewables EBITDA in 2022 was around €4bn, well below fossil fuel EBITDA (including trading) of €6.7bn.

Large renewables pipeline, ambitious targets for 2025 & especially 2030 – achievable?

Renewables account for 50% of Group 2023-25 capex of €37bn. With a gross pipeline of 436GW, of which Enel defines 162GW (including 27GW battery storage) as mature and with 11GW in execution, Enel is targeting a capacity build over 2023-25 of 21GW. This takes renewables capacity to nearly 75GW by 2025 and 130GW by 2030. Based mainly on solar, this is a substantially faster build than peers, EDF, Engie & RWE. Despite recent delay, it implies Enel doubling the annual capacity build from 2025 onwards to an ambitious 11GW.

Key Questions for Management

Is Enel still on target to hit its emissions targets for 2023-25?
What are the chances that the new senior management team row back on Enel’s energy transition strategy?
Why is Enel reconverting some coal capacity to gas with implied stranding risk? Is new CCGT financially viable without capacity market contracts?
What measures does Enel need to take to overcome recent delay and achieve annual renewables build of 11GW from 2025?
What are the credit rating implications? How does Enel replace 30% of Group EBITDA from fossil fuels?

Relatedly we also cover recent attempts by integrated utilities in the US to re-order their traditional fossil fuel businesses with alternative renewable options – this time an attempt by Duke Energy to switch capital from fossil fuel energy assets into renewables.

It is clearly a busy market for swapping assets – key will be to assess how much traditional oil and gas is leaving the market rather than being merely traded.

Duke Energy – Sale process drawn out raises eyebrows on potential equity.

In our Transition Files vol 2piece, we noted that a key tenet of the energy transition is balance sheet integrity.
Duke’s commercial renewable business sale, optically to some, would send signals of unaligned net zero corporate strategy It is more so an attempt to protect balance sheet integrity to execute on recycling capital into the core utility business with an emphasis on utility owned renewable investments.
On the Q1 call Duke’s management alluded to a slowed sale process of the 3.5GW of Duke Commercial Renewables business, as the company took a $220m impairment charge on the assets. The prolonged sale process shines a light on a weakening M&A landscape, as a glut of renewable portfolios have recently transacted at peers Consolidated Edison (ED) and American Electric Power (AEP).
Based on our analysis we estimate an equity need of$1.1B before impact of sale and deferred fuel recoveries (See Within for Math). Balance sheet integrity is a crux for the company to execute on the ‘wind down and backfill’ strategy (run out fossil and build renewables) we reference this in our previous note.

To conclude – the energy transition is on course, but it is not a straight line from A to B: there will be technological mis-timings in grid infrastructure, and perhaps some reversals in corporate strategies as we have seen in Enel and Shell previously.

But the direction of travel is clear.

The latest and revamped edition of the BP-funded Statistical Review of World Energy notes yet again that oil consumption globally still remains below that of 2019 (which may turn out to be a peak given the growth rates of EVs – see our analysis here), and that 85% of global electricity demand increase came from renewables.

At their current growth rate of 15-20% pa this means that in this year renewables will likely provide over 100% of electricity demand growth – forcing fossil fuel demand into decline globally in the power sector, and along with it the decline in emissions.

For sure transmission, cable deployment and company strategies could help or hinder this transition – but the massive successes to date are piling up are setting the strategic direction.

The future is already here but is now becoming widely distributed.

References to CTI Research and related links (May / June 2023)

CTI

Cleantech – Gone with the Wind

https://carbontracker.org/reports/gone-with-the-wind/

Gas and Power – Enel overview

https://carbontracker.org/enel-for-something-completely-different-energy-transition-plan-analysis/

https://carbontracker.org/reports/enel-spa-all-change/

Corporate – Duke Energy / US Integrated Energy

https://carbontracker.org/reports/us-vertically-integrated-utilities/

UK Electricity Demand

https://www.theccc.org.uk/wp-content/uploads/2020/12/Sector-summary-Electricity-generation.pdf