It took Donald Trump less than a week after his bombing raid in Venezuela to raise the ire of one major group of fossil industry donors, while threatening to freeze his country’s biggest publicly-traded oil company out of the production boom he thinks he can set in motion.

In the 10 days since the raid, Trump has claimed that Venezuela “will be turning over” 30 to 50 million barrels of oil to the U.S., that he will personally control the revenue from selling that oil, and that the U.S. fossil industry will pile in to Venezuela to restore its decrepit, poorly-maintained production infrastructure.

But that isn’t sitting well with fracking executives in Texas—many of whom “bankrolled the president’s return to office”—who expect any increase in production to push global oil prices below the threshold where they can continue to operate, the Financial Times reports.

“Problems in Texas’s oil industry are mounting, as cheaper oil forces producers to idle rigs needed to keep production ticking higher,” the Times explains. So “Trump’s drive to open up Venezuela’s oil riches, potentially subsidizing investors, has further strained relations with oil executives in Texas, who have been angered by his dogged pursuit of ever-lower crude prices.”

In the 2024 general election in the U.S., the fossil fuel industry spent $219 million to elect the country’s next government, Yale Climate Connections reported afterwards, most of it on Republican campaigns. That was after Trump invited about 20 oil and gas executives to his Mar-a-Lago estate in April to present what one independent journalist called a “breathtakingly corrupt proposal: If they raised a billion dollars to help him retake the White House, he would roll back any policy they didn’t like when he took office.”

Now some of those donors sound like they’re questioning the return on their investment.

“We’re talking about this administration screwing us over again,” one exec told the Times. “If the U.S. government starts providing guarantees to oil companies to produce or grow oil production in Venezuela I’m going to be… pissed.”

Some industry sources are angrily calling it a “betrayal” after Trump “flew to Texas multiple times in 2024 to tap deep-pocketed oil barons for cash,” the news story adds. Their problem is that “only the biggest [fossil] energy groups, such as ExxonMobil, Chevron,  and ConocoPhillips, have access to the tens of billions of dollars in capital, teams of lawyers, and security protection needed for a foray into Venezuelan oil. For smaller U.S. operators, a revitalized Venezuelan industry—if Trump can pull it off—means worsening the market glut,” with prices already below the US$60 per barrel that shale producers need to turn a profit.

“To me, the signal from the administration is: we’d rather spend our American money on propping up a Venezuelan oil business than supporting our current independent businesses,” said Trump donor Kirk Edwards, CEO of Odessa, Texas-based Latigo Petroleum.

“I think it’s an appropriate reaction by U.S. shale to be miffed,” added Pickering Energy Partners founder Dan Pickering. “Not just because Venezuelan production might go up but because the U.S. government, in theory, is going to subsidize that.”

On the surface, colossal fossil ExxonMobil may be miffed, as well, after Trump took umbrage at CEO Darren Woods’ assessment that his production plan would be “uninvestable”. After meeting with fossil CEOs Friday, Trump said Woods’ bad attitude might disqualify the company from any new business in Venezuela.

“I didn’t like Exxon’s response,” he told reporters. “I’d probably be inclined to keep Exxon out. I didn’t like their response. They’re playing too cute.”

Woods maintained that Venezuela would have to make “significant changes” before Exxon would consider investing there. “We’ve had our assets seized there twice, and so you can imagine to re-enter a third time would require some pretty significant changes from what we’ve historically seen here and what is currently the state,” he said. “If we look at the legal and commercial constructs, frameworks in place today in Venezuela, today it’s uninvestable.”

He also told Trump he was “confident” those changes “can be put in place,” the Times writes.

But Venezuela’s oilfields may not be the prize Exxon is after—or even the main motivation behind Trump’s takeover. Drilled Executive Editor Amy Westervelt recaps Exxon’s extensive investments in neighbouring Guyana and recalls Venezuela’s escalating threats against those operations before the U.S. removed President Nicolás Maduro from office.

Most of the other oil execs who met at the White House Friday “delivered optimistic messages to Trump about the prospect of reviving Venezuela’s oil sector,” the Times says. But at least one U.S. news site is reporting that industry insiders “are mocking the president behind his back, predicting companies will string him along to get on his ‘good side’ and never follow through” on their promises to invest.

“The big oil companies who move slowly, who have corporate boards are not interested,” U.S. Treasury Secretary Scott Bessent told Politico, in a sequence republished by RawStory. “I can tell you that independent oil companies and individuals, wildcatters, [our] phones are ringing off the hook. They want to get to Venezuela yesterday.”

But that only shows that “the most enthusiastic are among the least prepared and least sophisticated,” said one industry official. “Anyone with a degree of international sophistication is taking a more measured approach.”

The post U.S. Fossil Donors ‘Pissed’ at Trump, Mock Him Behind His Back, as Venezuela Plan Takes Shape appeared first on Thoughtful Journalism About Energy's Future.

With Jacob Blanc

The United States military recently carried out a covert operation to capture and then remove Venezuelan President Nicolás Maduro and his wife, transporting them from Caracas to New York. The pair is accused of narco-terrorism, conspiracy, drug trafficking and money laundering.

President Donald Trump announced that the U.S. will temporarily “run” Venezuela until a “safe, proper and judicious transition” can be ensured. Trump also announced Venezeula was handing over up to 50 million barrels of oil to the U.S. to be sold at “market price.”

Read more: A predawn op in Latin America? The US has been here before, but the seizure of Venezuela’s Maduro is still unprecedented

There’s nothing new about the American desire to put an end to the Maduro regime. In March 2020, during Trump’s first term, Maduro was indicted by the U.S. on narco-terrorism and cocaine trafficking charges. A reward of US$15 million was offered for his arrest. But the U.S. had been increasing pressure on Venezuela for months through both military and diplomatic tactics.

Nor is it the first time that the U.S. has intervened militarily in Latin America. It happened in Grenada and Panama in 1983 and in Honduras in 1988.

But an intervention of this magnitude in a large South American country is unprecedented. Jacob Blanc, a Latin American specialist and professor in the history department at McGill University, explains.

The Conversation Canada: Were you surprised by the American intervention in Caracas?

Jacob Blanc: Yes, I was, especially because of how audacious it was. There is a long history of American interventions in Latin America, but in the larger countries these have generally been carried out in a more subtle way. The United States has supported regime changes when they are perceived as pro-Communist or anti-American. But this case — a military intervention in the middle of the night at the presidential palace and the abduction of the leader of a modern country — is unusual. What’s more, Trump is not touching the political system. He is leaving the regime in place, with Vice-President Delcy Rodriguez as interim president. This is unprecedented.

TCC: What kind of relationship did the United States have with Venezuela?

J.B.: Venezuela is particularly important to Americans because it was the country where one of the first independence movements against the Spanish took place. This was where the colonial wars took root, and where [military and political leader] Simón Bolívar proposed unifying the South American hemisphere in a confederation. Bolivar’s plan did not succeed, but Venezuela was at the forefront of this movement. Then, in the 20th century, oil was discovered in several countries in northern South America, including Venezuela — which has the largest reserves in the world — and Colombia. The economy benefited, but this also created regional problems.

The region became more important to the Americans in the 1990s with the instability in the Middle East. With the rise to power of Hugo Chávez, [president from 1999 until his death], and his left-wing ideas, relations cooled. Chávez became the bête noire of the Americans, who accused him of corruption, among other things.

An oil embargo was imposed in 2019, which considerably weakened the oil sector. Under Hugo Chavez, the oil sector was already slowing down, mainly due to corruption. It will take years and a lot of money for the Americans to get it back on track, but the Americans themselves created part of the problem with the embargo.

TCC: How do other South American countries view this intervention?

J.B.: It depends on their ideology. Brazil, Mexico and Colombia, which are more left-wing, have denounced the intervention, but Argentina and Chile have supported it. In my opinion, this will accentuate the divide between the two ideologies present in South America, but this situation is not really new. For Cuba, the threat is real. But an American intervention on the island would be purely ideological, as the country has almost nothing to offer. It would be a trophy for Trump to show off.

TCC: Trump’s bellicose rhetoric against Colombia is surprising, given that the country is a democracy. How should we interpret this?

J.B.: Yes, it surprises me a little. But at the same time, it makes sense: the official justification for the intervention against Venezuela is the illegal entry of drugs into the United States. But Venezuela is a small player. Colombia, on the other hand, is a very large exporter. So if the justification is true, that makes it all the easier to do the same thing in Colombia.

TCC: What message is Trump sending to the rest of the world?

J.B.: Trump’s actions are reminiscent of what Putin is doing in Ukraine, and what Xi Jinping could do in Taiwan or other neighbouring countries. This jeopardizes the international rules that nations established after the Second World War, when they set up a system — which might be weak, but it’s still a system — to prevent wars.

Read more: Venezuela attack, Greenland threats and Gaza assault mark the collapse of international legal order

TCC: What does the future hold for Venezuela?

J.B.: It will all depend on the type of administration Trump supports. For now, he is not changing the regime or the system and says he wants to manage it from a distance, through various incentives. I believe the Trump administration is crossing its fingers and hoping that the new presidency will not implode due to internal factions. We can expect infighting within the current government, as well as with the military.

Many want power. Donald Trump wants to have his cake and eat it too. He wants to make the operation look like a victory without any risks or costs; without sending soldiers who could lose their lives. But nothing is less certain. And if chaos spreads in the region, particularly in Colombia, it will be Trump’s fault. He has taken a very, very risky gamble.

The post Maduro’s capture: ‘Trump has taken an unprecedented and very risky gamble’: Historian appeared first on Thoughtful Journalism About Energy's Future.

By Tom Lorenz

U.S. manufacturing energy consumption has continued to increase, according to our recently released survey results for 2022. We conduct the Manufacturing Energy Consumption Surveys (MECS) every four years, and the latest iteration shows the third consecutive increase in energy consumed in the manufacturing sector since a low point in 2010. Natural gas consumption in the manufacturing sector increased by more than all other energy sources combined, as compared with the previous MECS results from 2018.

MECS is a nationally representative sample survey of approximately 15,000 establishments representing 97 per cent to 98 per cent of the manufacturing payroll. MECS collects information on U.S. manufacturing establishments, their energy-related building characteristics, and their energy consumption and expenditures through a web-based questionnaire. MECS reports separate estimates of energy use for 79 different industry subsectors and groups across U.S. manufacturing. MECS was first conducted in 1985; the most recent survey is the 11th iteration.

Some manufacturers consume energy as both a fuel—for heat, power, and electricity generation—and as a feedstock—a nonfuel or material input. MECS uses first use, which excludes quantities of energy that were produced from other energy inputs to avoid double-counting. For example, if an establishment consumes coal to produce coke, the coal is considered first use, but not the coke.

First use of natural gas, hydrocarbon gas liquids (excluding natural gasoline), and electricity increased the most across the manufacturing sector from 2018 and 2022. By contrast, first use of petroleum coke and steam or hot water decreased.

This week’s initial release of MECS data is the first of several detailed manufacturing data releases we expect to publish later in 2025 and early 2026. This initial release is considered preliminary, and some data may change slightly with subsequent releases.

Among the most significant changes for the 2022 MECS is the inclusion of hydrogen estimates, which had previously been aggregated with several other energy sources. We estimate that the first use of hydrogen totalled 170 trillion British thermal units (Btu) in 2022, or more than twice as much as the first use of distillate fuel oil (81 trillion Btu).

The post U.S. manufacturing energy consumption has continued to increase since 2010 low appeared first on Thoughtful Journalism About Energy's Future.

Eight years ago, the City of Chicago vowed to eventually run all its operations on carbon-free power. Now, it has fulfilled that promise, thanks to the largest U.S. solar farm east of the Mississippi River—and a temporary reliance on renewable energy credits.

The city’s 400+ buildings consume nearly 800,000 megawatt-hours of electricity each year, and, “as of January 1, every single one of them—including 98 fire stations, two international airports, and two of the largest water treatment plants on the planet”—is running on renewables, reports Grist.

The goal to power 100 per cent of Chicago’s facilities and operations with green energy was first proposed in 2017 by then-mayor Rahm Emanuel. It received a major boost in 2022 when Emanuel’s successor, Lori Lightfoot, struck a US$422-million agreement to purchase 70 per cent of the city’s power supply from a massive solar farm, developed by Boston-based renewables company Swift Current Energy.

Swift Current’s newly-completed 593-megawatt Double Black Diamond solar farm, spanning 15 square-kilometres, is the largest of its kind east of the Mississippi, capable of powering more than 100,000 homes.

Half of the solar farm’s output will cover 70 per cent of the city’s power demand. The remaining 30 per cent will come mostly from renewable energy credits (RECs)—though this arrangement will not be permanent, if all goes according to plan.

“We made an intentional choice to not meet our overall 100  per cent commitment solely through offtake from the new Double Black Diamond facility,” Deputy Chief Sustainability Officer Jared Policicchio told The Energy Mix. “Instead, in the coming years we plan to focus on various strategies to encourage and deploy renewables, other distributed energy resources like battery storage, and energy efficiency, so that the remaining portion of our commitment—30 per cent of our usage, a sizable 300,000 megawatt-hours—occurs locally or in the nearby metro areas.”

An initial project now ongoing involves installation of rooftop solar, together with “comprehensive” energy efficiency upgrades, at “several Chicago Public Library branch libraries located in environmental justice neighbourhoods.”

As the city phases in this approach in the coming years, it will purchase renewable energy credits on the market to fill any gaps, “with a goal of reducing these market REC purchases eventually to zero,” Policicchio added.

Chicago’s decision not to rely on a 100 per cent off-take from Double Black Diamond demonstrates its commitment to “additionality,” bringing new, local renewable resources into the market and onto the grid, Matthew Popkin, cities and communities program manager at RMI, told Grist.

Under the agreement with Swift Current, Chicago also secured an annual $400,000 commitment to fund clean energy work force training, with a particular focus on bringing more women into the field.

Decarbonizing America’s third-largest city’s operations will reduce its carbon footprint by roughly 290,000 tonnes of carbon dioxide annually, the rough equivalent of taking 62,000 cars off the road, writes Grist. Community involvement was critical to achieving the milestone.

“The project fulfills a long-term advocacy campaign, Ready for 100, led by Sierra Club and local community organizations, to encourage the city to make the transition to renewable energy,” said Chicago officials in a release.

The post Chicago switches its 400+ City buildings to 100 per cent clean power appeared first on Thoughtful Journalism About Energy's Future.

Interactive dashboard allows users to explore clean energy growth in Texas and nation over the past decade

DALLAS – Texas ranks first in the nation for wind power generation, second for solar power generation, second in the nation for battery storage, and third in the nation for the number of electric vehicle registrations through 2023, according to the online Renewables on the Rise 2024 dashboard released on Wednesday by Environment Texas Research & Policy Center.

This analysis comes as Texas is set to receive $360 million from the federal government to interconnect the ERCOT grid with other southern states, potentially bringing cheap, clean, Texan energy to hundreds of thousands more.

“Texas is truly setting the pace in the race toward 100 per cent clean and renewable energy,” said Ian Seamans, City Hall Advocate with Environment Texas Research & Policy Center.

Texas has seen a more than 70-fold increase in the amount of electricity it gets from the sun and a nearly 95-fold increase in battery capacity since 2014. Last year, wind and solar energy produced 31 per cent of the state’s electricity.

Beyond top-ranking growth in wind and solar energy, Texas has also seen a 40-fold increase in the number of registered electric vehicles. Strong and supportive policies from the federal government, combined with improving technologies and falling prices, have played a key role in driving adoption, according to the report.

”As climate change increases the severity of hurricanes, back-up power capable EVs are also increasingly becoming life-saving equipment to residents along the Texas coast,” said Seamans.

In addition to highlighting states that have made the most progress in adopting renewable energy technologies, the research also details the rapid gains achieved nationally over the past decade. According to the report, America produced more than three times as much renewable electricity from the sun and the wind in 2023 as in 2014.

The Renewables on the Rise 2024 dashboard documents the growth of six key clean energy technologies across the United States over the past decade: solar power, wind power, battery storage, energy efficiency, electric vehicles and electric vehicle charging stations.

“Millions of Americans and Texans are already reaping the benefits of the dramatic clean energy progress we’ve made so far,” Seamans said. “With federal tax credits turbocharging clean energy, now is the time for states to lean in to clean energy. In the upcoming legislative session we need legislators to cut the red tape for rooftop solar and reject efforts to hamstring the incredible growth of clean energy in Texas.”

The post Texas continues dominance in wind and solar power generation appeared first on Thoughtful Journalism About Energy's Future.

By Trinity Manning-Pickett

Five states produced more than 70 per cent of the record 113.1 billion cubic feet per day (Bcf/d) of U.S. marketed natural gas production in 2023. Texas accounted for 28 per cent of U.S. marketed natural gas production in 2023, according to our Natural Gas Monthly, followed by Pennsylvania (18 per cent), Louisiana (10 per cent), West Virginia (8 per cent), and New Mexico (8 per cent). Even though production slowed in 2024, output from these five states continued to make up most—73 per cent—of marketed U.S. natural gas this year.

In 2023, marketed natural gas production in Texas, which includes offshore output from fields in state waters, totalled 31.6 Bcf/d, a 7 per cent increase from 2022. The Permian and Haynesville plays, which combined account for nearly 40 per cent of U.S. dry natural gas production from shale gas plays, are in Texas.

The Permian region also extends into New Mexico, where production averaged 8.7 Bcf/d in 2023, an increase of 18 per cent compared with 2022. Because most Permian production of natural gas is associated natural gas from oil wells, producers respond to changes in the crude oil price rather than the natural gas price when planning their exploration and production activities. Adjusted for inflation, the annual West Texas Intermediate (WTI) crude oil spot price averaged $102 per barrel (b) in 2022—the highest price since 2014—before moderating to $80/b in 2023. As a result, marketed natural gas production in both Texas and New Mexico established new records in 2023.

Marketed natural gas production in Louisiana, which includes offshore output from state waters, averaged 11.8 Bcf/d in 2023, an increase of 6 per cent from 2022 and the most natural gas produced in Louisiana since 1996, despite low natural gas prices. Production in Louisiana mostly comes from the Haynesville region, located in both Louisiana and Texas. The United States became the world’s largest liquefied natural gas (LNG) exporter in 2023, and producers in the Haynesville play continued to supply much of the natural gas used by Gulf Coast LNG export facilities.

In 2023, natural gas production in Pennsylvania matched the 2021 record of 20.9 Bcf/d, a 1 per cent increase over 2022, and West Virginia production reached a record 8.9 Bcf/d, an increase of 11 per cent. Natural gas production from both states comes from the Appalachian Basin, which contains the Marcellus and Utica shale gas plays, and accounted for 32 per cent of U.S. marketed natural gas production.

Growth in U.S. marketed natural gas production has slowed in 2024, due mainly to reduced output from shale and tight formations. From January through August 2024, U.S. production of marketed natural gas averaged 113.0 Bcf/d, a 1 per cent increase compared with the same period in 2023. The Permian region drove the increase in 2024, supported by WTI crude oil prices that averaged $80/b. Production in Texas increased 5 per cent (1.5 Bcf/d), and output in New Mexico increased 12 per cent (1.0 Bcf/d). Less production in Louisiana, where output decreased 15 per cent (1.8 Bcf/d), and Pennsylvania, where output decreased 2 per cent (0.5 Bcf/d), offset growth in the Permian region. Producers in the Haynesville and Appalachia regions curtailed production in 2024 when faced with record-low Henry Hub prices, which averaged $2.09 per million British thermal units through August 2024, and flat growth in demand from LNG export facilities.

The post Five states drove record U.S. natural gas production in 2023 appeared first on Thoughtful Journalism About Energy's Future.

By Mitchell Beer

With the weeks ticking down before he leaves the White House, U.S. President Joe Biden’s administration is picking up the pace on clean energy financing, while getting serious about blocking tens of billions of dollars in export financing for oil and gas that could instead be diverted to the energy transition.

The White House has surpassed the US$100 billion mark in financing for clean energy projects under the landmark Inflation Reduction Act (IRA), and announced that more than 80 per cent of the IRA’s grant funding will be “obligated” by the time Donald Trump takes office January 20, Reuters reports. And the administration has shifted its position on an international effort, put forward last year by the European Union, the United Kingdom, and Canada, to stop public financing for oil and gas export projects by member countries of the Organisation for Economic Co-operation and Development (OECD), Bloomberg writes.

“Crossing the milestone of $100 billion awarded shows just how quickly we’re getting these funds out the door and into communities so they can make a real difference for the American people,” Biden’s senior advisor for international climate policy, John Podesta, told Reuters.

The wider commitment of IRA dollars will make it harder for Trump to roll back Biden’s energy efficiency and renewable energy investments, as he has vowed to do, a senior administration official told the news agency.

“When funds are obligated, they are protected,” the official said. “They are subject to the terms of the contract, so when those contracts are signed and executed, this becomes a matter of contract law more than a matter of politics.”

And Trump’s plan to rescind a decade of clean energy tax credits under the IRA would require an act of Congress, Reuters adds, after those federal investments created 400,000 or more jobs across the country—by far the largest share of them in Republican-held districts.

“In August, 18 Republican House members wrote to House Speaker Mike Johnson asking him not to gut the law’s incentives because it would jeopardize major investments,” the news agency writes. “Some of Trump’s close allies have also benefited from the IRA, particularly its provisions boosting carbon capture and sequestration, as well as clean hydrogen.”

While the Biden White House races to protect as much of its IRA investment as possible, the U.S. and the EU have also been pushing the OECD to make good on the 2023ncommitment to cut off public financing for oil and gas exports, Bloomberg writes. At an OECD meeting in Paris in the second half of November, the countries were pushing—over objections from Korea and Türkiye—to finalize a 2024 agreement to “expand existing rules that prohibit member nations’ export credit agencies from financing unabated coal projects.”

That negotiating position “is an about-turn for the U.S., which had effectively stalled work on the broader fossil fuel restrictions for months amid concerns from the country’s Export-Import Bank,” the news agency says. But with Trump about to take office, “it’s a last-ditch bid to lock in a climate policy that environmental advocates say may be difficult for the new administration to reverse while freeing up multi-billion-dollar funds for global clean energy projects.”

“There aren’t many policy tools that Trump can’t undo, and this is one of the few,” Laurie van der Burg, public finance lead at Oil Change International, told Bloomberg.

“Export credit agencies (ECAs) have a key role in fossil fuel expansion,” the International Institute for Sustainable Development (IISD) explains in a backgrounder published this week. They’re public financial institutions, typically owned or controlled by governments, that “provide finance in the form of loans, guarantees, and credit to domestic companies to facilitate the export of goods and services, including capital equipment and large-scale infrastructure projects in other countries. Since many of these projects are too risky for the private sector to take on alone, they depend on ECA support to go ahead.”

Between 2018 and 2020, export credit agencies poured an average US$41 billion per year into new fossil fuel extraction, making them the industry’s biggest international public financiers, IISD writes. Over that time, “fossil gas received 30 per cent of this support, and 40 per cent of gas finance went to LNG projects,” even though “there is no room in 1.5°C carbon budgets for any new oil and gas projects.”

IISD has details of what an OECD deal would look like.

The post Biden exceeds $100B in clean energy funding, backs new deal to end oil and gas export financing appeared first on Thoughtful Journalism About Energy's Future.

By Christopher Bonasia

The launch of one of the first utility-scale solar+storage peaker plants in the United States is paving the way for renewables to replace gas-fired facilities during peak power demand.

Built in Imperial County, California, the Vikings project is a benchmark for safe and reliable configurations of its kind, Kevin Smith, CEO of project developer and owner Arevon Energy, said in a release. Vikings incorporates solar panels, trackers, and batteries, showcasing “the growing strength of U.S. renewable energy manufacturing.”

Arevon describes the project as one of the first utility-scale solar peaker plants in the country. Peaker plants are electricity-generating facilities activated on demand when regular power plants cannot meet electricity needs. Most peaker plants rely on fossil fuels, producing costly, emissions-intensive electricity.

“An estimated 10 per cent of grid infrastructure is built to supply energy during times of dangerous peak demand, which only make up 1 per cent of the year,” according to energy company Enel.

The Vikings project—its name derived from a local high-school mascot—will add peaking capacity to the grid without burning fossil fuels. It uses Tesla megapack battery energy storage systems, First Solar thin-film photovoltaic solar panels, and Nextracker smart solar trackers for a 157-megawatt solar array paired with 150 megawatts/600 megawatt-hours of battery storage. Jacob Montgomery, director of development at Arevon, said the “unique 1:1 solar to storage configuration” allows all the energy generated during sunlight hours to be stored and used later during peak demand, writes Renewable Energy World.

“We’re specifically thrilled regarding the unique layout, which gives a storage component that is as powerful as our ability to produce solar energy,” COO Justin Johnson said in February.

“This unique layout, an expansion of our ongoing commitment to leading-edge modern technologies, will enable the facility to provide energy whenever needed, assisting to support the grid, as well as profiting everybody in this community, as well as throughout the state of California.”

Arevon was one of the first companies to use a transferability provision for utility-scale solar or storage projects in the Biden administration’s Inflation Reduction Act, which allows project owners to hand over tax credits to profitable shareholders.

The post California solar+storage plant pioneers fossil-free power for peak demand appeared first on Thoughtful Journalism About Energy's Future.

By Lori Aniti

Annual spending by major utilities to produce and deliver electricity increased 12 per cent from $287 billion in 2003 to $320 billion in 2023 as measured in real 2023 dollars, according to financial reports to the Federal Energy Regulatory Commission (FERC).

Capital investment in electric infrastructure mostly drove the increase, more than doubling over the period as:

• Aging generation and delivery infrastructure were replaced or upgraded to resist fire and storm damage.
• Utilities installed first natural gas-fired generation, then wind and solar generation, and, more recently, battery storage.
• New lines were connected to renewable resources.
• New technology, including smart meters, sensors, and automated controls, was added to the system.

Production
Spending to produce electricity fell 24 per cent from 2003 to 2023, mainly due to lower fuel costs and, to a lesser extent, the retirement of older, costlier-to-maintain fossil fuel plants. Fuel costs, the main operating expense, make up most of the production costs.

More recently, capital spending on electricity production increased by 23 per cent ($4.7 billion) in 2023 compared with 2022. Most of this increase was driven by costs related to the construction of the Vogtle nuclear plant operated by Georgia Power. The fourth and final Vogtle unit entered commercial operation at the end of April 2024.

Transmission
Spending on electricity transmission systems nearly tripled from 2003 to 2023, increasing to $27.7 billion. Electricity transmission systems consist of the wires and structures required to transmit high-voltage power long distances from the generator to the neighbourhood, lower-voltage distribution grid.

More recently, capital investment in the transmission of electricity increased $2.7 billion (11 per cent) in 2023 from 2022. Most of this increase came from spending on the transmission station equipment ($1.0 billion), poles ($1.1 billion), and computer software ($0.4 billion) necessary for operating regional transmission markets.

Distribution
Capital spending on the distribution system, responsible for delivering electricity to end users, was the main driver of electricity spending increases over the last two decades. Capital investment in distribution infrastructure increased by $31.4 billion, or 160 per cent, from 2003 to 2023.

More than one-fifth of this increase occurred between 2022 and 2023 when spending increased by $6.5 billion to a total of $50.9 billion as utilities replaced and upgraded aging equipment and installed new lines, transformers, and other equipment to help neighbourhood electricity grids withstand extreme weather events and to manage the intermittency of renewable resources.

Capital spending on overhead lines, poles, and towers increased the most. Utilities spent $17.4 billion on overhead infrastructure in 2023, an 11 per cent increase from 2022 and a 220 per cent increase from 2003.

Investment in underground lines also increased considerably, more than doubling over the past 20 years to reach $11.8 billion in 2023. Utilities installed underground lines in new housing and commercial developments and replaced some overhead lines to mitigate power outages during storms and fires or to improve neighbourhood appearance.

Capital investment in line transformers, which decrease voltage to household levels, increased 23 per cent from 2022 to $7.5 billion in 2023—a result of supply chain and manufacturing issues.

Utilities spent $6.1 billion on distribution substation equipment in 2023—a 184 per cent increase from 2003 and a 15 per cent increase from 2022. Substation investment has increased to help utilities better withstand extreme weather events, manage the intermittency of renewable resources, and allow greater voltage control during emergencies.

Utilities spent $5.1 billion in 2023 on infrastructure located on or near customers’ property such as meters, leased property, and rooftop solar installations—up 84 per cent from 2003 and up 25 per cent from 2022.

Although energy storage remains a relatively small portion of the total budget for distribution infrastructure, spending increased from $97 million in 2022 to $723 million in 2023. Energy storage at the substation or customer site enhances power quality and provides backup power in areas where lines and transformers cannot handle additional capacity, especially as more intermittent renewable resources come online.

Other
Utilities increased spending by $8.6 billion (30 per cent) on other electricity systems costs from 2003 to 2023. Most of these increases ($7.9 billion) were spent on intangible plant expenses (such as licenses and franchises) and general plant expenses (such as offices and storage buildings). Other electricity systems costs also consist of administrative and general expenses.

The post Grid infrastructure investments drive increase in utility spending over last two decades appeared first on Thoughtful Journalism About Energy's Future.

By Lindsay Aramayo

In our latest Short-Term Energy Outlook (STEO), we forecast that electricity generation from U.S. hydropower plants in 2024 will be 13 per cent less than the 10-year average, the least amount of electricity generated from hydropower since 2001. Extreme and exceptional drought conditions have been affecting different parts of the United States, especially the Pacific Northwest, which is home to most U.S. hydropower capacity.

As of the end of September, 72.6 per cent of the continental United States was experiencing dryer-than-normal to exceptional drought conditions, according to the U.S. Drought Monitor. By the end of October, this value increased to 87.2 per cent. Multiple regions are affected by drought conditions, but the effects on hydropower generation are more obvious in the Pacific Northwest. For example, a recent study conducted by the University of Alabama found that hydropower generation in Washington state is one of the most susceptible to droughts in the country, ranking right below California based on data from 2003 to 2020.

Drought impacts this year
The Pacific Northwest’s Columbia River is the fourth-largest river in the United States by volume. Its watershed, the Columbia River Basin, covers large parts of four states: Washington, Oregon, Idaho, and Montana. The basin is home to some of the largest hydropower dams in the country, such as the Grand Coulee with a net summer capacity of 6.7 gigawatts (GW) and Chief Joseph with 2.4 GW of capacity.

As early as April of this year, the Washington State Department of Ecology declared most counties in the state under drought. The department takes this step when water supply in the state is less than 75 per cent of normal. In Oregon, two counties declared a drought emergency this summer, first in June in Jefferson County and then in September in Lake County.

The Dalles Dam located between Oregon and Washington, with a total net summer capacity of 1.8 GW, is considered a good indicator of water supply conditions in the upper Columbia River. At the end of September, water supply at The Dalles Dam was at 74 per cent of the 30-year normal for the summer months (April through September), according to the Northwestern River Forecast Center. Hydropower generation peaks in the summer months in response to seasonal peak demand.

According to the U.S. Department of Agriculture’s Basin Outlook Reports, reservoir storage at the end of September was 48 per cent of capacity in Oregon, 67 per cent of capacity in Washington, 76 per cent in Montana, and 60 per cent in Idaho.

On a monthly basis in 2023, across Washington, Oregon, Idaho, and Montana, hydropower generation has been close to or below the lower end of the 10-year range, except for a brief spike in May due to a heatwave. In Washington and Oregon, hydropower generation in 2024 was mostly higher than in 2023, especially during the summer months. In Idaho and Montana, hydropower generation in 2024 was below 2023 levels from April through August.

Drought effects in the Northwest according to STEO
In the STEO, we forecast electricity generation for electricity market regions instead of state geographical boundaries. We expect hydropower generation in the Northwest electricity region, which includes the Columbia River Basin and parts of other Rocky Mountain states, to total 101.8 billion kilowatthours (kWh) in 2024, a 23 per cent decrease from the 10-year average of 132.8 billion kWh and a 1 per cent decrease from 2023.

The post Drought conditions reduce hydropower generation, particularly in the Pacific Northwest appeared first on Thoughtful Journalism About Energy's Future.