Demand growth creates new challenges for the power industry

One of the oldest insights of energy economics is the Jevons Paradox: the insight that increased energy efficiency can lead consumption to rise, not fall. It was first proposed in the 19^th century by the English economist William Stanley Jevons with respect to coal: as new technologies emerged for using coal more efficiently, consumption rose. It was, he wrote: “wholly a confusion of ideas to suppose that the economical use of fuel is equivalent to a diminished consumption”.

Today, we are seeing something similar with artificial intelligence. In effect, the recent advances in technologies such as generative AI promise huge gains in the productivity of the electricity used by data centres. Klarna, the Swedish financial services company, said recently that its AI assistant was able to do “the equivalent work of 700 full-time [human] agents”.

As Jevons would have predicted, those productivity gains will lead to increased use of AI applications, and a corresponding increase in demand for electricity to keep the data centres running. The potential implications for energy, and for power, in particular, are enormous. What the steam engine was for coal in the 19^th century, AI could be for electricity in the 21^st.

Already there is growing evidence that data centres for AI and other applications are transforming the outlook for electricity demand in the US. I have just been at the Distributech conference in Florida, where one of the hottest topics was the prospect of a return to demand growth after years of stagnation.

For more than a decade, power grids in the US have faced a series of mounting challenges. Variable renewable generation and distributed energy resources have been growing rapidly. Coal-fired power plants have been shutting down, driven in part by tighter regulations on pollution and low natural gas prices. Climate change is increasing the risk of extreme weather events. Customers, investors and policymakers are pushing companies to reduce emissions, and many have set net zero goals. Now utilities and grid operators are also having to plan for a new challenge: the prospect of significant growth in demand for power.

Total electricity demand in the US essentially flat-lined for about 15 years. Electricity sales to customers were 3,765 terawatt hours in 2007, and 3,806 TWh in 2021: an increase of just 1% over that entire period. Now, however, there are signs that the trend may be turning upwards again.

It is not just new data centres that are adding to electricity demand. There has been a resurgence in manufacturing investment in the US, driven in part by incentives for reshoring production of semiconductors and energy equipment.

Computer chip and battery factories are particularly power-hungry. The flagship chip plant that Taiwan Semiconductor (TSMC) is building in Arizona will initially need 200 megawatts of power. Battery plants need 20 to 37.5 kilowatt hours of electricity for every 1 KWh of storage of capacity they produce, a recent study showed. That means a typical factory producing 30 GWh of cells per year would need up to about 130 MW of power.

New energy facilities such as green hydrogen plants for electrolysing water, supported by government grants and tax credits, will also create large new sources of demand. Bitcoin mining has grown very rapidly in the US in recent years, and now accounts for an estimated 0.6% to 2.3% of national electricity consumption, according to the Energy Information Administration. And the rise of electric vehicles and heat pumps is putting upward pressure on residential electricity usage.

Even among all these other pressures, however, the increase in demand from data centres is particularly striking. Jensen Huang, chief executive of the chip company Nvidia, said last month that he expected the installed base of data centres to double over the next four to five years, from about US$1 trillion today to about US$2 trillion. The International Energy Agency expects their energy demand to grow in parallel: it forecast in January that electricity consumption from data centres, AI and cryptocurrency could double by 2026.

In a keynote speech at Distributech, Harry Sideris, Duke Energy’s executive vice-president for customer experience, solutions and services, noted that it used to be big news when the utility was notified of a new load of 10MW or 20MW. Now Duke sees planned chip factories needing hundreds of megawatts, and “several” planned data centres for AI need a gigawatt each.

Meeting that demand, he added, would mean a lot more renewables, more gas generation and, eventually, more nuclear power.

That rising trend in demand is already starting to show up in the data. The Southern region of the PJM grid covers Virginia, which advertises itself as the largest data centre market in the world. It has more than 35% of the world’s hyperscale data centres, thanks to its excellent fibre optic backbone, connections to transatlantic cables and helpful tax breaks. In that region, summer demand at off-peak hours grew almost 20% between 2019 and 2023.

Utilities and grid operators across the US are looking ahead at the prospect of similar growth. Phoenix-based Arizona Public Service, for example, last year published its updated Integrated Resource Plan, projecting that energy needs for electricity would rise at an average rate of 3.7% a year from 2023 to 2038. That represents an additional 23.7 TWh of annual electricity consumption by the end of that period. More than half of that increase – about 13 TWh – is expected to come from data centres.

APS notes that “while the dramatic influx of data center and large industrial customers can provide economic benefits to Arizona, the volume and total energy demand of these requests pose challenges during periods of time when generation resources are already limited”.

Meeting demand from data centres is further complicated by the fact that operators are typically looking for zero-emissions power. Amazon is aiming to use only renewable energy by 2025, and reach net zero carbon emissions by 2040. Microsoft has said that by 2030 it will be “carbon negative”, capturing more than it emits, and will have 100% of its electricity consumption, 100% of the time, matched by zero carbon energy purchases.

Utilities’ spending on technologies to help tackle the challenges of more complex grids has been soaring. The 50 largest investor-owned utilities in the US have raised their proposed spending on grid modernisation at an annual average rate of 72% since 2018, according to a Wood Mackenzie review of regulatory filings.

But at the same time, regulators are becoming increasingly concerned about the impact of grid investments on customers’ bills. As Wood Mackenzie’s analysts put it: “Grid modernisation is becoming a high-risk balancing act, between maintaining the grid’s reliability plus resilience and managing relationships with customers and regulators.”

The plunge in costs for wind and solar power and battery storage over the past two decades has meant that a low-carbon electricity system is no longer obviously the most expensive option. Solar and wind power dominate expected additions to generation capacity in the US for decades to come. But managing the growth in renewables, retirements of old plants, growing threats from extreme weather, opposition to building new infrastructure, changing relationships with customers and now rising demand – all at the same time – clearly makes the transition more difficult.

In climate and energy policy circles, people often talk about the “hard to abate” sectors, such as cement and aviation, where reducing emissions will be particularly challenging. It is now becoming clearer that even in the “easy to abate” sectors such as power, it is not a trivial exercise at all.

Warren Buffett raises concerns about the US utility business model

The mounting pressures on US utilities were also highlighted by Warren Buffett of Berkshire Hathaway in his latest shareholder letter, published last weekend. Operating earnings at Berkshire Hathaway’s utilities and energy business dropped 40% last year to US$2.33 billion, and Buffett argued that the fall was symptomatic of wider problems across the industry.

“The regulatory climate in a few states has raised the specter of zero profitability or even bankruptcy,” Buffett wrote. The standard model of utility regulation in the US for a century enabled electricity companies to earn a fixed return on equity. But now, Buffett argued “the fixed-but-satisfactory return pact has been broken in a few states, and investors are becoming apprehensive that such ruptures may spread”.

Oregon-based PacifiCorp, one of the electric utilities owned by Berkshire Hathway, reported an estimated charge in 2023 of US$1.7 billion from wildfires in 2020 and 2022. The company warned that it was “reasonably possible” that PacifiCorp would face significant additional wildfire losses, but warned it was “currently unable to reasonably estimate the range of possible additional losses that could be incurred.”

The threat to US power utilities from wildfires was underlined this week by Xcel Energy, which disclosed in a regulatory filing that it had received a letter from lawyers warning of its potential exposure for damages resulting from the wildfires in northern Texas. The lawyers’ letter called for the company to retain a fallen utility pole owned by Southwestern Public Service (SPS), an Xcel subsidiary, in the area where the fire may have started. Investigations into the fires in and near the SPS service territory are under way. Xcel’s shares fell sharply on Thursday and Friday.

Buffett noted in his letter that PG&E, based in California, was forced to file for bankruptcy in 2019 after devastating wildfires. “Whatever the case at Berkshire, the final result for the utility industry may be ominous: Certain utilities might no longer attract the savings of American citizens and will be forced to adopt the public-power model,” he wrote. “When the dust settles, America’s power needs and the consequent capital expenditure will be staggering.”

In brief

Fervo Energy, the innovative enhanced geothermal power company, has raised US$244 million in a new financing round led by Devon Energy, the oil and gas producer. The fund-raising represents a vote of confidence in Fervo’s technology, which has been showing promising results from its first large-scale project.

David Harris, chief corporate development officer at Devon, said Fervo’s approach to geothermal energy used cutting-edge subsurface, drilling and completions expertise and techniques that his company had been working on for decades. Devon pioneered the shale gas revolution in the early 2000s by combining horizontal drilling with hydraulic fracturing. Harris added that Devon aimed to deepen the partnership between the two companies “to capture the full value of Fervo’s first-mover advantage in geothermal”.

China’s National Bureau of Statistics published data confirming the scale of the country’s renewable energy boom last year. Grid-connected solar generation capacity rose by 55% to 609 GW, while grid-connected wind capacity rose 21% to 441 GW. However, the carbon intensity of the country’s economy remained unchanged: GDP and carbon dioxide emissions both rose by 5.2%.

The US House of Representatives passed a bill intended to expedite the licensing, regulation and deployment of new nuclear plants, by an overwhelming majority with bipartisan support.

The state of New York has selected two offshore wind projects to go ahead: Equinor’s Empire Wind 1, planned to be 810 MW, and Ørsted and Eversource’s Sunrise Wind, planned to be 924 MW. The weighted average all-in development cost of the awarded offshore wind projects over the life of the contracts is US$150.15 per megawatt hour, New York state said.

Uncertainty has been raised over Chevron’s agreed US$53 billion deal for Hess, as a result of ExxonMobil and CNOOC asserting a right of first refusal over Hess’s assets in Guyana. The Starbroek block in offshore Guyana is shared by Hess, ExxonMobil and CNOOC under a joint operating agreement. In an S-4 regulatory filing, Chevron revealed that ExxonMobil and CNOOC had asserted that that agreement gave them the right of first refusal to acquire the Hess assets, under a change of control provision. Chevron and Hess reject that assertion, and say the right of first refusal “does not apply to the merger due to the structure of the merger and the language of the Stabroek ROFR [right of first refusal] provisions”.

The Guyana assets are described by Wood Mackenzie analysts as “the crown jewel in Hess’s portfolio”. Chevron said it had been engaged in “constructive discussions” with Hess, ExxonMobil and CNOOC, and it believed the talks would “result in an outcome that will not delay, impede or prevent the consummation of the merger”.

If the discussions fail, it added, the disagreement could go to arbitration. If the talks fail and the arbitration does not result in an outcome acceptable to Chevron and Hess, then the deal would collapse.

Other views

Renewables costs in Asia reach an all-time low

Re-thinking energy transition supply chains – Simon Flowers, Gavin Thompson and Rory Mccarthy

Bioenergy: a US$500 billion market opportunity – Jom Madan

After hitting new highs in 2023, US lower 48 oil production growth will begin to slow considerably in 2024 and beyond

Cold weather impacts on US natural gas – Randall Collum and Amir Rejvani

Labour Party’s North Sea tax plans risk long-term pain for short-term gain

Reimagining the SPR – Daleep Singh and Arnab Datta

Pump the brakes on big transmission – Vincent Duane

Quote of the week

“Nothing that we are doing, nothing that President Biden has sought to do, has any political motivation or ideological rationale. It’s entirely a reaction to science, to the mathematics and physics that explain what is happening.”

John Kerry, President Joe Biden’s special presidential envoy for climate, rejected suggestions that political considerations were shaping the administration’s climate and energy policies. Kerry will step down from his climate role soon to work on President Biden’s re-election campaign, and will be replaced by John Podesta, currently an adviser at the White House.

Chart of the week

This comes from our latest analysis of the levelised cost of electricity (LCOE) in the Asia-Pacific region. There are several interesting aspects of this chart, but the one that I think is most noteworthy is the resumption of the downward trend in costs for solar and wind power and battery storage. Costs for these technologies rose in 2021 but have subsequently fallen back.

Meanwhile, costs for coal and gas-fired thermal generation have continued to increase. As a result, renewable energy is increasingly competitive with coal power. Utility-scale photovoltaic solar has emerged in 2023 as the cheapest power source in the Asia-Pacific region, while onshore wind is expected to become cheaper than coal after 2025. China is leading the way in reducing the cost of renewables, with wind and utility-scale solar 40% to 70% cheaper than in other Asia Pacific markets.

Get The Inside Track

Ed Crooks’ Energy Pulse is featured in our weekly newsletter, alongside more news and views from our global energy and natural resources experts. Sign up today to ensure you don’t miss a thing.