Tester testy with Haaland. Shale won’t derail. Energy Efficiency Ignored.

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Court finds environmentalists’ challenge to Trump NEPA rule too early in process
Maya Weber, Richard Rubin, S & P Global Platts, June 21, 2021

Sees path for challenges after agencies make project decisions.

Other cases stayed as Biden CEQ revises regulation.

Streamlining rule was backed by gas pipelines.

A US district court judge June 21 tossed one of multiple environmental challenges to the Trump-era changes to the National Environmental Policy Act that have implications for energy infrastructure including natural gas pipelines.

But the ruling’s practical implication for projects is muted because the Biden administration already is backing away from implementation of the Trump-era regulation. Interstate natural gas pipeline projects often face challenges from environmental groups under NEPA, leading to assertions from developers of a need to rein in procedural delays.

Judge James Jones of the US District Court for the Western District Court of Virginia, Charlottesville Division, found that the challenge filed by a coalition of environmental groups including Wild Virginia was not justiciable, and the court therefore lacked jurisdiction.

“Delaying judicial review of the 2020 rule until it can be considered in an as-applied challenge will not create a significant hardship for the plaintiffs,” Jones wrote. “When a particular agency renders a decision on a particular project following a procedure that, in the plaintiffs’ view, does not meet the requirements of NEPA, the plaintiffs will then be able to pursue a legal challenge.”

The judge also pointed to the government’s assertions that following the change in administrations, CEQ has directed agencies not to devote resources to establishing their own NEPA procedures implementing the rule, and its statements that CEQ is actively reconsidering the regulation.

Concern about interference

“I am therefore concerned that judicial review of the plaintiffs’ claims at this juncture could interfere with further administrative action,” Jones wrote (Wild Virginia, et al., v. Council on Environmental Quality, et al., 3:20CV00045).

Even if he were to conclude the claims were ripe, he added, the environmental groups lacked standing because they did not establish the rule has caused or would imminently cause them concrete injury, and he found claims of such harms were too speculative.

“Here, the plaintiffs may have valid concerns about how the 2020 rule will impact projects in their areas, but they simply do not know how each agency will interpret the 2020 rule, taking into account any applicable CEQ guidance, or whether the 2020 rule will be applied to pending NEPA reviews,” the judge wrote.

The court also dismissed CEQ’s motion to have the case remanded without vacating the regulation. The decision to dismiss the case was without prejudice.

Hurdles for environmental groups

ClearView Energy Partners in a research note said the case illustrates the challenges environmental groups face in successfully appealing the NEPA rules themselves in order to effect changes.

The case is not end of the road for battles over the regulation. The rulemaking is being challenged in four other district courts, where it has been stayed as the Biden administration has stated it was reviewing the regulation.

The Trump administration regulation issued in July 2020 codified steps to streamline NEPA reviews, rein in their scope and limit the public comment process, as well as narrowing climate change considerations and allowing for more categorical exclusions.

Environmental groups contended CEQ cut corners and rushed through the rulemaking process in violation of the Administrative Procedure Act.

Business trade groups, including the Interstate Natural Gas Association of America argued the rule would allow NEPA to live up to Congress’ original purpose. “If plaintiffs here obtain a vacatur of the rule, CEQ’s reform of the NEPA review system would be undone, and the business associations’ members would once again be subject to an uncertain and overly burdensome regulatory scheme that invites obstructive litigation and needlessly delays important projects and operations,” they argued in an intervenor brief filed in Aug. 21, 2020.


Why U.S. Shale Won’t Derail The Oil Rally
Tsvetana Paraskova, OilPrice.Com, June 21, 2021

For the first time in nearly a decade, OPEC has solid reasons to believe that its control over the global oil supply will not be ruined by a surge in U.S. crude oil production.  The ongoing restraint in drilling activity in the shale patch would make the efforts of OPEC and its allies in the OPEC+ group to manage supply to the market this year a much easier task. 

Last week, OPEC+ was reportedly told by major international forecasters—including the Energy Information Administration (EIA), the International Energy Agency (IEA), Wood Mackenzie, IHS, Argus Media, Energy Intelligence, and Energy Aspects—that U.S. crude oil production would grow by just 200,000 barrels per day (bpd) this year, OPEC sources told Reuters at the end of meetings of OPEC’s economic and technical think-tank, the Economic Commission Board. 

For 2022, the views range from production growth of between 500,000 bpd and 1.3 million bpd.  

All in all, the general view among external forecasters was that the shale patch would not be rushing into accelerating activity and production rates despite the high oil prices. That’s so unlike the previous behavior of U.S. oil producers, which used to prioritize production over profits, contributing to market oversupply and lower oil prices.

But after the second major oil price downturn in half a decade, the shale patch put the brakes on drilling activity in 2020 and continues to be careful with capital spending, prioritizing returns to shareholders to production records. 

Related: Is China Finally Moving Away From Coal?

U.S. production has been hovering at around 11 million bpd in recent months, down by 2 million bpd from the record highs early in 2020, before the pandemic slammed demand and crashed oil prices.

The first-quarter earnings and conference calls of U.S. producers highlighted a previously unheard-of restraint from public shale firms. Listed producers generated record cash flows, but they are not reinvesting most of those back to drilling. Instead, shale operators are now channeling cash flow toward reducing debts and rewarding investors.

OPEC itself sees average U.S. crude oil production this year at 11.2 million bpd, down by 120,000 bpd year over year, the cartel said in its latest Monthly Oil Market Report (MOMR) for June. 

“Despite the current recovering trend in US crude oil production, particularly in the Permian Basin, and the expected exit rate at 11.6 mb/d in December 2021, average US crude production in 2021, will remain lower by 0.12 mb/d, y-o-y, at 11.2 mb/d,” according to OPEC’s estimates. 

The EIA expects American crude oil production to average 11.1 million bpd in 2021, as per the latest Short-Term Energy Outlook (STEO) for June. 

Next year, U.S. oil production is set to grow by 700,000 bpd to an average of 11.8 million bpd.  

“Because prices of West Texas Intermediate crude oil remain above $60/b during 2021 in the current forecast, we expect that producers will drill and complete enough wells to raise 2022 production from 2021 levels,” the EIA said. 

Related: China Reports Major Oil And Gas Find At Record Depths

Even the EIA forecast for next year’s production growth is moderate, especially compared to the growth rates between 2017 and 2019. 

The 1.3 million bpd expected growth at the top end of the external forecasters OPEC heard last week may be overly optimistic as producers continue to be under pressure to deliver in terms of returns instead of in plowing every available cash, and more, back into drilling, Texas-based energy analyst and consultant David Blackmon notes in Forbes.

Slow growth rates in the U.S. shale patch—if forecasts materialize—would give OPEC+ more clarity about near-term supply outside the alliance. Restraint in U.S. drilling gives more control to OPEC to manage the market with its ongoing production cuts. 

The OPEC+ group is currently easing those cuts, but it still keeps around 5.7 million bpd off the market. 

“What is clear, however, is that OPEC+ remains firmly in control while global demand continues to recover. At least until a time when non-OPEC+ producers react to increased revenues and profitability by boosting output,” Ole Hansen, Head of Commodity Strategy at Saxo Bank, said on Friday.

The OPEC+ meeting on July 1 is set to decide the policy course from next month. The decisions at that meeting would “send a clear signal” whether the alliance will seek even higher prices by keeping supply artificially tight, or whether it prioritizes stability through increased production, Hansen noted. 


The Economics of Big U.S. LNG Export Facilities
Marcellus Drilling News, June 18, 2021

We spotted a fascinating article on the Forbes magazine website about Freeport LNG, which is fed (in part) by Marcellus/Utica molecules traveling through the Williams Transco Gulf Connector pipeline (see Williams Gulf Connector Goes Online – M-U Gas to Corpus Christi?). The article is about Freeport’s founder/builder/CEO, Michael S. Smith. However, it is some of the ancillary information woven into the article revealing the economics of the facility that caught our attention. How much money does it cost to build these plants? How much money do they make? And how long does it take to begin turning a profit?

All of those questions and more are answered in the article below.

How Michael S. Smith salvaged a wrong-way bet on fracking by building a $14 billion plant in Texas to ship gas around the globe.

Quintana Island is a 7-mile speck of land off Freeport, Texas, tucked in where the Brazos River empties into the Gulf of Mexico. Over the past 200 years, the island has been home to a Mexican fort, then a busy seaport for early Texas farmers, who shipped out cotton. Union ships later bombarded Confederate troops stationed there. In 1900 came the Great Galveston Hurricane, which killed 11,000 in the immediate vicinity and wiped Quintana clean. By the time Michael S. Smith set foot on the island in 2002, it was languishing: a few dozen dilapidated homes, a migratory bird sanctuary and beach, and a brownfield of storage tanks built on fill dredged from navigation channels. “We’d be sinking in the mud if we were standing here then,” Smith says.

Smith has made his own historic mark on the island. Having spent $14 billion, he now owns a controlling interest in Freeport LNG, which chills and exports 2 billion cubic feet of natural gas per day, most of it so-called shale gas, horizontally drilled, hydraulically fracked. At current market prices that daily output is worth some $14 million, on which Freeport collects about $5 million a day in tolling revenue. “We are taking clean American natural gas, adding tremendous value and exporting it to countries that do not have enough energy and would otherwise be burning dirty coal,” he says.

Since becoming operational in September 2019, Freeport LNG has loaded 200 cargoes destined for Japan, South Korea, and Croatia, where a single shipment can meet the annual energy needs of tens of thousands. Freeport will export about 15 million tons of LNG this year—the energy equivalent of 130 million barrels of oil—and is on track to book nearly $2.5 billion in revenue. Smith’s 63% ownership in the limited partnership is worth in excess of $1 billion.

Liquefying gas involves chilling methane down into a -260-degree liquid that can be pumped into thermos-bottle tankers and then shipped around the world. To do so economically, Freeport LNG has erected some of the world’s biggest LNG machines, called “trains.” It started by hammering 36,000 pilings 100 feet into mushy Quintana ground. Atop that now stands enough steel to build six Eiffel Towers and 192 miles of gleaming pipe, all anchored in 496,000 tons of concrete. What’s truly extraordinary is that all this was built not by some multinational energy giant but instead by one individual: the stubborn, Bronx-born Smith.

He admits he initially got his bet wrong. Back in 2002, when he got his start on Quintana Island, Smith’s strategy was not to export LNG at all, but to import it. He believed at the time that the U.S. would soon run short of affordable supplies of domestic gas. Indeed, he first raised $800 million to build an import terminal that by 2008 was obsolete before it was even completed.

Having been the first mover in a failed strategy, though, put Smith in prime position to reverse course and export, rather than import, LNG. All he had to do was manage a few risks: raising $14 billion, jumping through regulatory hoops and completing one of the world’s biggest construction projects. “Our capital costs were off by more than two times,” he says. “We just didn’t know.” A decade later, thanks to the fracking revolution, the U.S. now exports a record 10 billion cubic feet of gas per day, about one tenth of domestic production.

Smith is a large man, who at age 66 is still skiing and scuba diving despite some replacement joints. He has a lopsided nose and plenty of “da Bronx” still in his voice. His father ran a business involved in turning garbage into fuel. Smith studied premed at Colorado State University, but his senior year he “realized I was going to be a doctor for all the wrong reasons. I didn’t know what I wanted to do.” So he dropped out and became a Vail ski bum.

To earn a living, Smith got his real estate license in Colorado in 1978, selling commercial properties out of Fort Collins. Vital to his later success was learning all the paperwork—deals, contracts, plans, permits. Real estate provided a natural pivot into oil and gas; in the late 1970s, when oil prices spiked, he got into leasing land for drilling near where more experienced operators had just hit big wells. “When I started drilling wells, I would sit the wells myself,” he says, meaning he’d stay on-site alongside the roughnecks. “I found out that I had the fundamentals to understand the technical side of the business.” Rather than pay engineers, Smith used a calculator: “I did it on my HP 12c.”

“I had eternal optimism,” he continues, “but I was always afraid there was so much I didn’t know.” Such as oil prices’ tendency toward volatility. When oil plunged in the late 1980s, Smith bought out his partner for little more than the assumption of liabilities. To save cash, he paid service providers Halliburton and Maverick Tube with interests in new wells. Smith took Basin Exploration public in 1992. Big finds grew elusive, so in 1995 he transformed Basin, sold the Rockies assets, cut staff and shifted operations to Houston to drill in the Gulf of Mexico. That got frustrating, too, leaving Smith convinced that domestic supplies of natural gas were drying up. In 2000, he sold Basin for $410 million to Stone Energy, pocketing about $60 million.

Just 45, Smith had a fortune, but he wasn’t ready to hit the slopes full time. In 2001, at the Brown Palace Hotel in Denver, he met Charif Souki, a former investment banker and restaurateur with a small gas company called Cheniere Energy. They both believed the United States would soon need to import gas. Souki had scoured the Gulf Coast for prime LNG locations and had options on three sites, including Freeport. Smith could have thrown in his lot with Souki, but he wanted to run his own show. He put up $14 million for 60% of the Freeport site.

The project united his real estate and energy skills. Smith recouped his initial investment by getting big potential customers like Dow Chemical and ConocoPhillips to put down deposits and eventually sign 20-year contracts securing the right (but not the obligation) to turn LNG back into usable gas at Freeport. With those anchor tenants in place, ConocoPhillips put up more than $500 million to build the import terminal, including insulated tanks big enough to stack Boeing 747s in. “If I had known the costs would become so high, I would’ve just looked at Charif’s proposal, shut it and kept on going,” Smith says.

By 2008 it was clear the boom in shale gas had made their import terminal dead on arrival. But thanks to those 20-year contracts, Freeport LNG was still making $25 million a year . . . for doing nothing. Says Smith: “We had built this facility, and it literally never got used.”

He therefore made a bet that it was more lucrative to reverse the flow and export America’s natural-gas bonanza (up 74% in two decades, thanks to fracking some 33 trillion cubic feet per year). As Jason Feer, of the consultancy Poten & Partners, says, “These guys were quick to understand the value of these stranded assets just waiting for repurpose.” Smith again raised money by selling 20-year contracts for services to liquefy natural gas to BP and Japanese giants such as Osaka Gas and Jera. He also sold equity stakes in specific aspects of the project: The two Japanese companies put up $1.25 billion to own 50% of train 1. Australian private equity firm IFM Investors injected $1.3 billion for 56% of train 2. In 2014, private equity giant GIP bought 25% of the limited partnership for $850 million. With solid backing, Smith’s team borrowed massive amounts.

Most Nimby conflicts were resolved when Freeport LNG bought and demolished some 60 homes on the island. The biggest frustration was Hurricane Harvey, which dumped 2 feet of rain in 2017 and ruined equipment. Finally, in late 2019, Freeport LNG was operational. “He built it. It’s finished. He has accomplished something remarkable and done a phenomenal job,” says Souki, a friendly rival, who in 2015 left Cheniere to start LNG developer Tellurian Energy. “Any kind of construction risk is out of the way. It’s the safest business model possible—just a tolling business impossible to replicate today.”

Today Freeport LNG carries $13 billion in debt. That’s manageable. With customers locked in to paying $2.5 billion a year for the next two decades, there will be enough to pay off debt, keep the machines running and make distributions to Smith and partners.

There are still headaches. No sooner had Freeport LNG gotten all three trains operational in early 2020 than Covid-19 lockdowns dashed global demand for gas. Amid canceled cargoes, summer LNG prices slumped to $3.40 per million Btu (British thermal units). This January, though, LNG shot up to a record $18.50 per million Btu in Asia, before falling again to $7. Such volatility could spur dealmaking. “That’s the impetus to signing 20-year supply deals—utilities in Japan have to make sure they have the gas they need,” says analyst Alex Munton, of energy consultancy Wood Mackenzie. As for Freeport, “they need to know there’s a buyer for the gas.”

Smith already has approvals to add a fourth train and might use it to market premium, lower-carbon-footprint LNG. Sounds gimmicky, but customers want it. And because Freeport LNG gets all its electricity off the Texas power grid—which has benefited from a decade-long boom in wind power—he can sell his product as greener than LNG generated with gas-fired turbines.

The gas is greener, too. According to Lawrence Berkeley National Lab, we can credit the shale fracking boom for nearly half of the reduction in U.S. emissions since 2005, as utilities switch from higher-carbon coal. With plenty of coal left to displace, “our transition to renewables, no matter how fast we do it, is going to take a long time,” Smith says. “There’s still going to be a large role for natural gas.” He’s confident that the LNG market can grow 50% by 2030—and keep those ships docking at Quintana Island for decades to come.*


Northern Dynasty taps markets for $14.5m to continue Pebble appeal
Mining.Com, June 21, 2021

Northern Dynasty Minerals, (TSX: NDM; NYSE: NAK) announced Monday that it has entered into an at-the-market (ATM) offering agreement with H.C. Wainwright & Co acting as agent.

Under the agreement, the company will be entitled during the term of the ATM Agreement, to sell, through the agent, as sales agent, common shares of the company having an aggregate gross sales price of up to $14.5 million.

Northern Dynasty owns Pebble Limited Partnership, developer of the proposed Pebble project in Alaska.

In November 2020, Pebble Limited Partnership received formal notification from the US Army Corps of Engineers (USACE) that its application for permits under the Clean Water Act and other federal statutes has been denied.

The lead federal regulator found Pebble’s ‘compensatory mitigation plan’ as submitted earlier this month to be ‘non-compliant’, and that the project is ‘not in the public interest’.

Sales of the common shares will be made in “at the market distributions”, as defined in National Instrument 44-102, directly on the NYSE or on any other existing trading market in the United States, Northern Dynasty said in a press release. No offers or sales of common shares will be made in Canada. The company will determine, at its sole discretion, the date, price, and number of common shares to be sold under the ATM and Northern Dynasty is not required to sell any common shares at any time during the term of the ATM, it said in Monday’s statement.

Northern Dynasty said it intends to use the net proceeds of the offering, if any and at its discretion of the company, for the appeal of the Record of Decision by the USACE and continued engineering, environmental, permitting and evaluation work on the Pebble project.

Pebble’s permitting process has been surrounded by controversy and delays. Pebble faced environmental opposition from the onset as the mine would be near the world’s largest commercial sockeye salmon-producing region, and doubts surrounding the project rose steadily over recent months.

With resource estimates including 6.5 billion tonnes in the measured and indicated categories containing 57 billion pounds of copper and 71 million ounces of gold, 3.4 billion pounds of molybdenum and 345 million silver ounces, if permitted, Pebble would be North America’s largest mine.


Senators press Interior Secretary Haaland on oil lease pause
Matthew Daly, Associated Press, June 16, 2021

Both Republican and Democratic senators pressed Interior Secretary Deb Haaland for answers Wednesday after a federal court blocked the Biden administration’s suspension of new oil and gas leases on federal lands and waters.

In a sharply worded ruling Tuesday, U.S. District Judge Terry Doughty in Louisiana ordered that plans for lease sales continue in the Gulf of Mexico, off the coast of Alaska and in “all eligible onshore properties” nationwide. The ruling came after President Joe Biden shut down oil and gas lease sales from the nation’s vast public lands and waters in his first days in office, citing worries about climate change.

“It’s a fresh decision. Our department is reviewing the judge’s opinion as we speak and consulting with the Justice Department,” Haaland said under questioning at a Senate hearing on her department’s budget.

“We will respect the judge’s decision. Any other information will be forthcoming,” she said.

Alaska Sen. Lisa Murkowski, the top Republican on the Senate Appropriations Interior subcommittee, said she was flabbergasted that Haaland did not address the court ruling — or the government’s vast oil and gas leasing program — in her prepared remarks.

“I was really struck by the fact that in 17 pages of discussions outlining the budget there really is no recognition for the production on our federal land and the role that plays,” Murkowski said.

In light of the court ruling, she told Haaland: “I expect to hear your plans to resume implementation of those lease sales. We expect you to follow the law.”

Haaland, a former Democratic congresswoman from New Mexico, responded, “I will always follow the law.”

Democratic Sen. Jon Tester of Montana also appeared impatient with Haaland, saying the review ordered by Biden — nearly two months before Haaland took office in mid-March — appeared to be dragging on.

“As this review rolls on, a leasing pause gives folks in the oil and gas industry a lot of uncertainty,” Tester said. “It’s getting harder and harder to extend that trust without hard information in the review.”

Tester asked Haaland when the review will “be ready for prime time.”

Officials have “said all along early summer … so my guess is they’ll be getting it sometime in the near future,” Haaland said.

“I’m taking that as it’ll be out in the next month,” Tester replied. Haaland did not commit to a firm timetable.

The back-and-forth over the leasing pause and the court decision showed the stakes of Biden’s effort to reform — and likely scale back — the multibillion-dollar leasing program without crushing a significant sector of the U.S. economy.

Doughty’s ruling, in a lawsuit filed by Louisiana Republican Attorney General Jeff Landry and officials in 12 other states, is a blow to Biden’s efforts to transition the nation away from fossil fuels and stave off the worst effects of climate change, including catastrophic droughts, floods and wildfires.

Biden and Haaland have said the leasing ban is only temporary, though officials have declined to say how long it will last. And it’s unclear how much legal authority the government has to stop drilling on about 23 million acres (93,000 square kilometers) previously leased to energy companies.

Wyoming Sen. John Barrasso, the top Republican on the Senate Energy and Natural Resources Committee, called the judge’s decision “a victory for the rule of law and American energy workers. ″

Biden’s “illegal ban (on new lease sales) has hurt workers and deprived Wyoming and other states of a principal source of revenue that they use for public education,” Barrasso said. “President Biden should immediately rescind his punishing ban and let Americans get back to work.”

Following Biden’s Jan. 27 order, the Interior Department canceled oil and gas lease sales from public lands through June — affecting Nevada, Colorado, Montana, New Mexico, Utah, and Wyoming, as well as offshore sales in the Gulf of Mexico. The department also abandoned a public comment period for a planned offshore sale in Alaska.

The 13 states that sued said that the administration bypassed comment periods and other bureaucratic steps required before such delays can be undertaken and said that the moratorium would cost the states money and jobs.

Doughty, who was nominated to the federal bench by President Donald Trump in 2017, said “millions and possibly billions of dollars are at stake” for local governments and other public uses.


The Climate Solution That Cuts Emissions and Saves Money
Akshat Rathi, Bloomberg Green, June 22, 2021

There’s a way to cut emissions and save money, but not enough people talk about it.

Perhaps it’s because the phrase “energy efficiency” induces some to yawn. Or that quietly making something more efficient isn’t as politically rewarding as building a new shiny solar farm. Whatever the reason, it’s clear that the world isn’t investing enough in this critical climate lever.

Energy efficiency, along with wind and solar power, will provide half the emissions savings in the next decade in the International Energy Agency’s roadmap for reaching net zero by 2050. “Without those efficiency gains, electricity demand growth would make it much harder for renewables to displace fossil fuels in electricity generation,” the IEA concluded.

More with Less

The reduction in energy-related emissions that can be achieved with energy efficiency and behavioral changes.

It’s hard to frame energy efficiency as a superstar solution, in part because the consumer experiences little change. Filling leaks in home ventilation systems cuts the energy used for heating or cooling without sacrificing comfort. Setting higher mileage standards for internal combustion engines reduces fuel use but doesn’t make the drive less pleasant. Insulating a kiln in a cement factory means fewer coal lumps are needed for the same production volume. And so on.

Some measures aren’t even seen as an efficiency play. Switching from an internal-combustion engine car to an electric car means going the same distance for the less than half the of energy. Replacing a gas boiler with a heat pump leads to using a third less energy for the same output. Increasing recycling rates helps reduce the amount of virgin materials that need to be extracted. And traveling by public transport instead of a car is a lot more energy efficient.

Crucially, even as falling costs of renewables and batteries are helping push the electricity and transport sectors in the right direction, emissions trajectories in other industries remain little changed. Efficiency measures are the strongest lever to reduce emissions from those hard-to-abate areas such as buildings and industry.

Hard to Debate

Efficiency measures can make a serious dent in the energy demand from sectors with hard-to-abate emissions.

The catch is that taking these steps typically involves a high up-front cost. Someone has to pay for that electric car or home insulation first, while the return from lower fuel bills often takes a few years to materialize. Homo economicus, our most-rational cousin used as a model by economists, would make the investment knowing that long-term gains are worth it. But few act rationally, and fewer still have access to the capital to be able to act rationally.

In the last decade, energy intensity (defined as megajoules per dollar of gross domestic product) fell by about 1.7% annually. The IEA’s modeling shows that the rate will have to climb to 4.2% each year for the next decade if the world is to meet its net-zero goals.

There’s also a counterforce in the Jevons Paradox. The theory, named after the 19th century British economist William Stanley Jevons, posits that efficiency gains often lead to an increase in demand. For example, a lower electricity bill because of a more-efficient air conditioner might mean a homeowner installs another air conditioner. Total energy use remains the same, even as the air conditioners became more efficient. 

Most energy models do not account for this rebound. A systematic analysis of global energy models by academics in the U.K., the U.S. and France published last month found that scientists “may underestimate the future rate of growth of global energy demand.” That means the rate of energy efficiency improvements may need to be higher than even the IEA’s ambitious net-zero model states.

In the end, it comes down to a question of selling these solutions. If people get angry about rising energy bills (sometimes enough to take to the streets), then it’s possible to make them happy about lower energy bills. Many of the green measures that can help economies rebound after the pandemic can also help create jobs, say, in helping to insulate homes. In fact, we should celebrate continued efficiency gains— doing more while consuming less—as we celebrate the progress in healthcare that enable people to live twice as long today as a few hundred years ago.

As the naturalist David Attenborough recently put it, “Tackling climate change is now as much a political and communications challenge as it is a scientific or technological one.” That’s especially true when it comes to energy efficiency.