Billions wasted when replacing failed motors

By Electricity Forum


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According to the Department of Commerce, U.S. industry will have to replace nearly 3 million failed electric motors rated between 1 and 200 HP in their plants this year. Unfortunately, in more than 4-out-of-5 cases, plant operation or purchasing managers will choose the wrong replacement unit.

This is because organizations across the board continue to specify motors based on lowest capital cost, rather than looking at total cost of ownership.

“If you look at the total cost of operating an electric motor over its typical 20 year service lifetime, you will find that the initial purchase price of the motor represents about 2% of the total lifetime cost,” said Valone Gomes, national OEM sales and product manager at WEG Electric Motors Corp., “whereas 97% of the total expenditures are for the electricity to power the motor. Clearly this means that motor efficiency and reliability should be the principle selection criterion, not the cheapest initial purchase price.”

Gomes explained that since the passage of the Energy Policy Act of 1992 (EPAct), U.S. industry had to meet certain minimum electrical efficiency standards when replacing electric motors. These were embodied by a class of EPAct high efficiency motors which represented a snapshot of the best available motor technology available around 1990 to gain 1 to 4% in efficiency.

But, technology has improved considerably, and a new class of motors — called NEMA Premium Efficiency (NPE) motors — is now available from suppliers throughout the industry. NPE motors deliver efficiencies of 1 to 4% above EPAct designs, but are more expensive to manufacture and so have initial cost premiums of 10 to 30% over EPAct units.

“So the vast majority of people replacing a motor will buy the EPAct variety based on its lower initial purchase cost,” Gomes said. “But by selecting an NPE motor for the same application, they could have saved the purchase premium in as little as two or three months in reduced electricity bills, and pay for the entire motor in less than 3 years based on the lower energy costs during that period. And this does not take into account the programs sponsored by local governments and utilities that subsidize the purchase of higher efficiency motors with rebates, tax credits, and other incentives.”

Gomes noted that, “NEMA Premium Efficiency motors will be required for motor replacement after 2010, when the Energy Independence and Security Act comes into force. But in the meantime, U.S. industry could be saving million of dollars a years if they selected motors based on lifetime cost rather than purchase price.

“In fact, the Department of Energy has estimated that switching exclusively to NEMA premium motors would save U.S. industry more than $10 billion annually, and reduce carbon emissions by nearly 80 million metric tons – the carbon equivalent of taking 16 million autos off the road. That’s good business and good environmental citizenship.

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Ermineskin First Nation soon to become major electricity generator

Ermineskin First Nation Solar Project delivers a 1 MW distributed generation array with 3,500 panels, selling power to Alberta's grid, driving renewable energy revenue, jobs, and regional economic development with partner SkyFire Energy.

 

Key Points

A 1 MW, 3,500-panel distributed generation plant selling power to Alberta's grid to support revenue and jobs.

✅ 1 MW array, 3,500 panels; grid-tied distributed generation

✅ Annual revenue projected at $80k-$150k, scalable

✅ Built with SkyFire Energy; expansion planned next summer

 

The switch will soon be flipped on a solar energy project that will generate tens of thousands of dollars for Ermineskin First Nation, while energizing economic development across Alberta, where selling renewables is emerging as a promising opportunity.

Built on six acres, the one-megawatt generator and its 3,500 solar panels will produce power to be sold into the province’s electrical grid, providing annual revenues for the band of $80,000 to $150,000, depending on energy demand and pricing.

The project cost $2.7 million, including connection costs and background studies, said Sam Minde, chief executive officer of the band-owned Neyaskweyahk Group of Companies Inc.

It was paid for with grants from the Western Economic Diversification Fund and the province’s Climate Leadership Plan, and, amid Ottawa’s green electricity contracting push, is expected to be connected to the grid by mid-December.

“It’s going to be the biggest distributed generation in Alberta,” he said.

Called the Sundancer generator, it was built and will be operated through a partnership with SkyFire Energy, reflecting how renewable power developers design better projects by combining diverse resources.

Minde said the project’s benefits extend beyond Ermineskin First Nation, one of four First Nations at Maskwacis, 20 km north of Ponoka, in a province where renewable energy surge could power thousands of jobs.

“Our nation is looking to do the best it can in business. It’s competitive, but at the same time, what is good for us is good for the region.

“If we’re creating jobs, we’re going to be building up our economy. And if you look at our region right now, we need to continue to create opportunities and jobs.”

Electricity prices are rock bottom right now, in the six to nine cents per kilowatt hour range, with recent Alberta solar contracts coming in below natural gas on cost. During the oilsands boom, when power demand was skyrocketing, the price was in the 16 to 18 cent range.

That means there is a lot of room for bigger returns for Ermineskin in the future, especially if pipelines such as TransMountain get going or the oilsands pick up again, and as Alberta solar growth accelerates in the years ahead.

The band is so confident that Sundancer will prove a success that there are plans to double it in size, a strategy echoed by community-scale efforts such as the Summerside solar project that demonstrate scalability. By next summer, a $1.5-million to $1.7-million project funded by the band will be built on another six acres nearby.

Minde said the project is an example of the community’s connection with the environment being used to create opportunities and embracing technologies that will likely figure large in the world’s energy future.

 

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Africa's Electricity Unlikely To Go Green This Decade

Africa 2030 Energy Mix Forecast finds electricity generation doubling, with fossil fuels dominant, non-hydro renewables under 10%, hydro vulnerable to droughts, and machine-learning analysis of planned power plants shaping climate and investment decisions.

 

Key Points

An analysis predicting Africa's 2030 power mix, with fossil fuels dominant, limited renewables growth, and hydro risks.

✅ ML model assesses 2,500 planned plants' commissioning odds

✅ Fossil fuels ~66% of generation; non-hydro RE <10% by 2030

✅ Policy shifts and finance reallocation to scale solar and wind

 

New research today from the University of Oxford predicts that total electricity generation across the African continent will double by 2030, with fossil fuels continuing to dominate the energy mix posing potential risk to global climate change commitments.

The study, published in Nature Energy, uses a state-of-the art machine-learning technique to analyse the pipeline of more than 2,500 currently-planned power plants and their chances of being successfully commissioned. It shows the share of non-hydro renewables in African electricity generation is likely to remain below 10% in 2030, although this varies by region.

'Africa's electricity demand is set to increase significantly as the continent strives to industrialise and improve the wellbeing of its people, which offers an opportunity to power this economic development and expand universal electricity access through renewables' says Galina Alova, study lead author and researcher at the Oxford Smith School of Enterprise and the Environment.

'There is a prominent narrative in the energy planning community that the continent will be able to take advantage of its vast renewable energy resources and rapidly decreasing clean technology prices to leapfrog to renewables by 2030 but our analysis shows that overall it is not currently positioned to do so.'

The study predicts that in 2030, fossil fuels will account for two-thirds of all generated electricity across Africa. While an additional 18% of generation is set to come from hydro-energy projects across Africa. These have their own challenges, such as being vulnerable to an increasing number of droughts caused by climate change.

The research also highlights regional differences in the pace of the transition to renewables across Sub-Saharan Africa, with southern Africa leading the way. South Africa alone is forecast to add almost 40% of Africa's total predicted new solar capacity by 2030.

'Namibia is committed to generate 70% of its electricity needs from renewable sources, including all the major alternative sources such as hydropower, wind and solar generation, by 2030, as specified in the National Energy Policy and in Intended Nationally Determined Contributions under Paris Climate Change Accord,' says Calle Schlettwein, Namibia Minister of Water (former Minister of Finance and Minister of Industrialisation). 'We welcome this study and believe that it will support the refinement of strategies for increasing generation capacity from renewable sources in Africa and facilitate both successful and more effective public and private sector investments in the renewable energy sector.'

Minister Schlettwein adds: 'The more data-driven and advanced analytics-based research is available for understanding the risks associated with power generation projects, the better. Some of the risks that could be useful to explore in the future are the uncertainties in hydrological conditions and wind regimes linked to climate change, and economic downturns such as that caused by the COVID-19 pandemic.'

The study further suggests that a decisive move towards renewable energy in Africa would require a significant shock to the current system. This includes large-scale cancellation of fossil fuel plants currently being planned. In addition, the study identifies ways in which planned renewable energy projects can be designed to improve their success chances for example, smaller size, fitting ownership structure, and availability of development finance for projects.

'The development community and African decision makers need to act quickly if the continent wants to avoid being locked into a carbon-intense energy future' says Philipp Trotter, study author and researcher at the Smith School. 'Immediate re-directions of development finance from fossil fuels to renewables are an important lever to increase experience with solar and wind energy projects across the continent in the short term, creating critical learning curve effects.'

 

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Energy storage poised to tackle grid challenges from rising EVs as mobile chargers bring new flexibility

EV Charging Grid Readiness addresses how rising EV adoption, larger batteries, and fast charging affect electric utilities, using vehicle-to-grid, energy storage, mobile and temporary chargers, and smart charging to mitigate distribution stress.

 

Key Points

Planning and tech to manage EV load growth with V2G, storage and smart charging to avoid overloads on distribution grids.

✅ Lithium-ion costs may drop 60%, enabling new charger models

✅ Mobile and temporary chargers buffer local distribution peaks

✅ Smart charging and V2G defer transformer and feeder upgrades

 

The impacts of COVID-19 likely mean flat electric vehicle (EV) sales this year, but a trio of new reports say the long-term outlook is for strong growth — which means the electric grid and especially state power grids will need to respond.

As EV adoption grows, newer vehicles will put greater stress on the electric grid due to their larger batteries and capacity for faster charging, according to Rhombus Energy Solutions, while a DOE lab finds US electricity demand could rise 38% as EV adoption scales. A new white paper from the company predicts the cost of lithium-ion batteries will drop by 60% over the next decade, helping enable a new set of charging solutions.

Meanwhile, mobile and temporary EV charging will grow from 0.5% to 2% of the charging market by 2030, according to new Guidehouse research. The overall charging market is expected to reach reach almost $16 billion in revenues in 2020 and more than $60 billion by 2030. ​A third report finds long-range EVs are growing their share of the market as well, and charging them could cause stress to electric distribution systems. 

"One can expect that the number of EVs in fleets will grow very rapidly over the next ten years," according to Rhombus' report. But that means many fleet staging areas will have trouble securing sufficient charging capacity as electric truck fleets scale up.

"Given the amount of time it takes to add new megawatt-level power feeds in most cities (think years), fleet EVs will run into a significant 'power crisis' by 2030," according to Rhombus.

"Grid power availability will become a significant problem for fleets as they increase the number of electric vehicles they operate," Rhombus CEO Rick Sander said in a statement. "Integrating energy storage with vehicle-to-grid capable chargers and smart [energy management system] solutions as seen in California grid stability efforts is a quick and effective mitigation strategy for this issue."

Along with energy storage, Guidehouse says a new, more flexible approach to charger deployment enabled by grid coordination strategies will help meet demand. That means chargers deployed by a van or other mobile stations, and "temporary" chargers that can help fleets expand capacity. 

According to Guidehouse, the temporary units "are well positioned to de-risk large investments in stationary charging infrastructure" while also providing charge point networks and service providers "with new capabilities to flexibly supply predictable changes in EV transportation behaviors and demand surges."

"Mobile charging is a bit of a new area in the EV charging scene. It primarily leverages batteries to make chargers mobile, but it doesn't necessarily have to," Guidehouse Senior Research Analyst Scott Shepard told Utility Dive. 

"The biggest opportunity is with the temporary charging format," said Shepard. "The bigger units are meant to be located at a certain site for a period of time. Those units are interesting because they create a little more scale-ability for sites and a little risk mitigation when it comes to investing in a site."

"Utilities could use temporary chargers as a way to provide more resilient service, using these chargers in line with on-site generation," Shepard said.

Increasing rates of EV adoption, combined with advances in battery size and charging rates, "will impact electric utility distribution infrastructure at a higher rate than previously projected," according to new analysis from FleetCarma.

The charging company conducted a study of over 3,900 EVs, illustrating the rapid change in vehicle capabilities in just the last five years. According to FleetCarma, today's EVs use twice as much energy and draw it at twice the power level. The long-range EV has increased as a proportion of new electric vehicle sales from 14% in 2014 to 66% in 2019 in the United States, it found.

Long-range EVs "are very different from older electric vehicles: they are driven more, they consume more energy, they draw power at a higher level and they are less predictable," according to FleetCarma.

Guidehouse analysts say grid modernization efforts and energy storage can help smooth the impacts of charging larger vehicles. 

Mobile and temporary charging solutions can act as a "buffer" to the distribution grid, according to Guidehouse's report, allowing utilities to avoid or defer some transmission and distribution upgrade costs that could be required due to stress on the grid from newer vehicles.

"At a high level, there's enough power and energy to supply EVs with proper management in place," said Shepard. "And in a lot of different locations, those charging deployments will be built in a way that protects the grid. Public fast charging, large commercial sites, they're going to have the right infrastructure embedded."

"But for certain areas of the grid where there is low visibility, there is the potential for grid disruption and questions about whether the UK grid can cope with EV demand," said Shepard. "This has been on the mind of utilities but never realized: overwhelming residential transformers."

As EVs with higher charging and energy capacities are connected to the grid, Shepard said, "you are going to start to see some of those residential systems come under pressure, and probably see increased incidences of having to upgrade transformers." Some residential upgrades can be deferred through smarter charging programs, he added.

 

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Amazon launches new clean energy projects in US, UK

Amazon Renewable Energy Projects advance net zero goals with a Scotland wind farm PPA and US solar farms in North Carolina and Virginia, delivering clean power, added capacity, and lower carbon emissions across cloud operations.

 

Key Points

Amazon initiatives adding wind and solar capacity in the UK and US to cut carbon and power cloud operations.

✅ Largest UK corporate wind PPA on Scotland Kintyre Peninsula

✅ Two US solar farms in North Carolina and Virginia

✅ 265 MW added capacity, 668,997 MWh clean power annually

 

Amazon is launching three renewable energy projects in the United States and the United Kingdom that support Amazon’s commitment to using net zero carbon energy by 2040.

The U.K. project is a wind farm on the Kintyre Peninsula in Scotland, aligned with a 10 GW renewables contract boosting the U.K. grid. It will generate 168,000 megawatt hours (MWh) of clean energy each year, enough to power 46,000 U.K. homes. It will be the largest corporate wind power purchase agreement (PPA) in the U.K.

Offshore wind energy in the UK is powering up rapidly, complementing onshore developments.

The other two are solar projects – one in Warren County, N.C, and the other in Prince George County, Va, reflecting broader US solar and wind growth trends nationwide. Together, they are expected to generate 500,997 MWh of energy annually. It is Amazon’s second renewable energy project in North Carolina, following the Amazon Wind Farm US East operated by Avangrid Renewables, and eighth in Virginia.

The three new Amazon wind and solar projects – which are expected to be in operation in 2012 — will provide 265 MW of additional renewable capacity, and align with U.K. wind power lessons for the U.S. market nationwide.

“In addition to the environmental benefits inherently associated with running applications in the cloud, Amazon is committed to minimizing our carbon emissions and reaching 80% renewable energy use across the company by 2024. We’ve announced eight projects this year and have more projects on the horizon – and we’re committed to investing in renewable energy as a critical step toward addressing our carbon footprint globally,” Kara Hurst, director of sustainability at Amazon, said. “With nearly 70 renewable energy projects around the globe – including 54 solar rooftops – we are making significant progress towards reaching Amazon’s company-wide commitment to reach 100% renewable energy by 2030.”

Amazon has launched 18 utility-scale wind and solar renewable energy projects to date, and in parallel, Duke Energy Renewables has acquired three California solar projects, underscoring sector momentum. They will generate over 1,600 MW of renewable capacity and deliver more than 4.6 million MWh of clean energy annually. Amazon has also installed more than 50 solar rooftops on fulfillment centers and sort centers around the world. They generate 98 MW of renewable capacity and deliver 130,000 MWh of clean energy annually.

“Today’s announcement by Amazon is another important step for North Carolina’s clean energy plan that will increase our reliance on renewables and reduce our greenhouse gas emissions,” North Carolina Governor Roy Cooper said. “Not only is this the right thing to do for our planet, it’s the right thing to do for our economy. More clean energy jobs means better jobs for North Carolina families.”

Amazon reports on its sustainability commitments, initiatives, and performance on a new web site the company recently launched. It includes information on Amazon’s carbon footprint and other metrics and updates the company’s progress towards reaching The Climate Pledge. 

“It’s wonderful to see the announcement of these new projects, helping bring more clean energy to the Commonwealth of Virginia where Amazon is already recognized as a leader in bringing renewable energy projects online,” Virginia Governor Ralph Northam said. “These solar farms help reaffirm the Commonwealth’s role as a leading producer of clean energy in the U.S., helping take the nation forward in responding to climate change.”

 

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Its Electric Grid Under Strain, California Turns to Batteries

California Battery Storage is transforming grid reliability as distributed energy, solar-plus-storage, and demand response mitigate rolling blackouts, replace peaker plants, and supply flexible capacity during heat waves and evening peaks across utilities and homes.

 

Key Points

California Battery Storage uses distributed and utility batteries to stabilize power, shift solar, and curb blackouts.

✅ Supplies flexible capacity during peak demand and heat waves

✅ Enables demand response and replaces gas peaker plants

✅ Aggregated assets form virtual power plants for grid support

 

Last month as a heat wave slammed California, state regulators sent an email to a group of energy executives pleading for help to keep the lights on statewide. “Please consider this an urgent inquiry on behalf of the state,” the message said.

The manager of the state’s grid was struggling to increase the supply of electricity because power plants had unexpectedly shut down and demand was surging. The imbalance was forcing officials to order rolling blackouts across the state for the first time in nearly two decades.

What was unusual about the emails was whom they were sent to: people who managed thousands of batteries installed at utilities, businesses, government facilities and even homes. California officials were seeking the energy stored in those machines to help bail out a poorly managed grid and reduce the need for blackouts.

Many energy experts have predicted that batteries could turn homes and businesses into mini-power plants that are able to play a critical role in the electricity system. They could soak up excess power from solar panels and wind turbines and provide electricity in the evenings when the sun went down or after wildfires and hurricanes, which have grown more devastating because of climate change in recent years. Over the next decade, the argument went, large rows of batteries owned by utilities could start replacing power plants fueled by natural gas.

But that day appears to be closer than earlier thought, at least in California, which leads the country in energy storage. During the state’s recent electricity crisis, more than 30,000 batteries supplied as much power as a midsize natural gas plant. And experts say the machines, which range in size from large wall-mounted televisions to shipping containers, will become even more important because utilities, businesses and homeowners are investing billions of dollars in such devices.

“People are starting to realize energy storage isn’t just a project or two here or there, it’s a whole new approach to managing power,” said John Zahurancik, chief operating officer at Fluence, which makes large energy storage systems bought by utilities and large businesses. That’s a big difference from a few years ago, he said, when electricity storage was seen as a holy grail — “perfect, but unattainable.”

On Friday, Aug. 14, the first day California ordered rolling blackouts, Stem, an energy company based in the San Francisco Bay Area, delivered 50 megawatts — enough to power 20,000 homes — from batteries it had installed at businesses, local governments and other customers. Some of those devices were at the Orange County Sanitation District, which installed the batteries to reduce emissions by making it less reliant on natural gas when energy use peaks.

John Carrington, Stem’s chief executive, said his company would have provided even more electricity to the grid had it not been for state regulations that, among other things, prevent businesses from selling power from their batteries directly to other companies.

“We could have done two or three times more,” he said.

The California Independent System Operator, which manages about 80 percent of the state’s grid, has blamed the rolling blackouts on a confluence of unfortunate events, including extreme weather impacts on the grid that limited supply: A gas plant abruptly went offline, a lack of wind stilled thousands of turbines, and power plants in other states couldn’t export enough electricity. (On Thursday, the grid manager urged Californians to reduce electricity use over Labor Day weekend because temperatures are expected to be 10 to 20 degrees above normal.)

But in recent weeks it has become clear that California’s grid managers also made mistakes last month, highlighting the challenge of fixing California’s electric grid in real time, that were reminiscent of an energy crisis in 2000 and 2001 when millions of homes went dark and wholesale electricity prices soared.

Grid managers did not contact Gov. Gavin Newsom’s office until moments before it ordered a blackout on Aug. 14. Had it acted sooner, the governor could have called on homeowners and businesses to reduce electricity use, something he did two days later. He could have also called on the State Department of Water Resources to provide electricity from its hydroelectric plants.

Weather forecasters had warned about the heat wave for days. The agency could have developed a plan to harness the electricity in numerous batteries across the state that largely sat idle while grid managers and large utilities such as Pacific Gas & Electric scrounged around for more electricity.

That search culminated in frantic last-minute pleas from the California Public Utilities Commission to the California Solar and Storage Association. The commission asked the group to get its members to discharge batteries they managed for customers like the sanitation department into the grid. (Businesses and homeowners typically buy batteries with solar panels from companies like Stem and Sunrun, which manage the systems for their customers.)

“They were texting and emailing and calling us: ‘We need all of your battery customers giving us power,’” said Bernadette Del Chiaro, executive director of the solar and storage association. “It was in a very last-minute, herky-jerky way.”

At the time of blackouts on Aug. 14, battery power to the electric grid climbed to a peak of about 147 megawatts, illustrating how virtual power plants can rapidly scale, according to data from California I.S.O. After officials asked for more power the next day, that supply shot up to as much as 310 megawatts.

Had grid managers and regulators done a better job coordinating with battery managers, the devices could have supplied as much as 530 megawatts, Ms. Del Chiaro said. That supply would have exceeded the amount of electricity the grid lost when the natural gas plant, which grid managers have refused to identify, went offline.

Officials at California I.S.O. and the public utilities commission said they were working to determine the “root causes” of the crisis after the governor requested an investigation.

Grid managers and state officials have previously endorsed the use of batteries, using AI to adapt as they integrate them at scale. The utilities commission last week approved a proposal by Southern California Edison, which serves five million customers, to add 770 megawatts of energy storage in the second half of 2021, more than doubling its battery capacity.

And Mr. Zahurancik’s company, Fluence, is building a 400 megawatt-hour battery system at the site of an older natural gas power plant at the Alamitos Energy Center in Long Beach. Regulators this week also approved a plan to extend the life of the power plant, which was scheduled to close at the end of the year, to support the grid.

But regulations have been slow to catch up with the rapidly developing battery technology.

Regulators and utilities have not answered many of the legal and logistical questions that have limited how batteries owned by homeowners and businesses are used. How should battery owners be compensated for the electricity they provide to the grid? Can grid managers or utilities force batteries to discharge even if homeowners or businesses want to keep them charged up for their own use during blackouts?

During the recent blackouts, Ms. Del Chiaro said, commercial and industrial battery owners like Stem’s customers were compensated at the rates similar to those that are paid to businesses to not use power during periods of high electricity demand. But residential customers were not paid and acted “altruistically,” she said.

 

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High Natural Gas Prices Make This The Time To Build Back Better - With Clean Electricity

Build Back Better Act Energy Savings curb volatile fossil fuel heating bills by accelerating electrification and renewable electricity, insulating households from natural gas, propane, and oil price spikes while cutting emissions and lowering energy costs.

 

Key Points

BBBA policies expand clean power and electrification to curb volatility, lower bills, and cut emissions.

✅ Tax credits for renewables, EVs, and efficient all-electric homes

✅ Shields households from natural gas, propane, and heating oil spikes

✅ Cuts methane, lowers bills, and improves grid reliability and jobs

 

Experts are forecasting serious sticker shock from home heating bills this winter. Nearly 60 percent of United States’ households heat their homes with fossil fuels, including natural gas, propane, or heating oil, and these consumers are expected to spend much more this winter because of fuel price increases.

That could greatly burden many families and businesses already operating on thin margins. Yet homes that use electricity for heating and cooking are largely insulated from the pain of volatile fuel markets, and they’re facing dramatically lower price increases as a result.

Projections say cost increases for households could range anywhere from 22% to 94% more, depending on the fuel used for heating and the severity of the winter temperatures. But the added expenditures for the 41% of U.S. households using electricity for heating are much less stark—these consumers will see only a 6% price increase on average. The projected fossil fuel price spikes are largely due to increased demand, limited supply, declining fuel stores, and shifting investment priorities in the face of climate change.

The fossil fuel industry is already seizing this moment to use high prices to persuade policymakers to vote against clean energy policies, particularly the Build Back Better Act (BBBA). Spokespeople with ties to the fossil fuel industry and some consumer groups are trying to pin higher fuel prices on the proposed legislation even before it has passed, even as analyses show the energy crisis is not spurring a green revolution on its own, let alone begun impacting fuel markets. But the claim the BBBA would cost Americans and the economy is false.

The facts tell a different story. Adopting smart climate policies and accelerating the clean energy transition are precisely the solutions to counter this vicious cycle by ending our dependance on volatile fossil fuels. The BBBA will ensure reliable, affordable clean electricity for millions of Americans, in line with a clean electricity standard many experts advocate—a key strategy for avoiding future vulnerability. Unlike fossil fuels subject to the whims of a global marketplace, wind and sunshine are always free. So renewable-generated electricity comes with an ultra-low fixed price decades into the future.

By expanding clean energy and electric vehicle tax credits, creating new incentives for efficient all-electric homes, and dedicating new funding for state and local programs, the BBBA provides practical solutions that build on lessons from Biden's climate law to protect Americans from price shocks, save consumers money, and reduce emissions fueling dangerous climate change.


What’s really causing the gas price spikes?
The U.S. Energy Information Administration’s winter 2021 energy price forecasts project that homes heated with natural gas, fuel oil, and propane will see average price increases of 30%, 43%, and 54%, respectively. Those who heat their homes with electricity, on the other hand, should expect a modest 6% increase. At the pump, drivers are seeing some of the highest gas prices in nearly a decade as the U.S. energy crisis ripples through electricity, gas, and EV markets today. And the U.S. is not alone. Countries around the globe are experiencing similar price jumps, including Britain's high winter energy costs this season.

A closer look confirms the cause of these high prices is not clean energy or climate policies—it’s fossil fuels themselves.  

First, the U.S. (and the world) are just now feeling the effects of the oil and gas industry’s reduced fuel production and spending due to the pandemic. COVID-19 brought the world’s economies to a screeching halt, and most countries have not returned to pre-COVID economic activity. During the past 20 months, the oil and gas industry curtailed its production to avoid oversupply as demand fell to all-time lows. Just as businesses were reopening, stored fuel was needed to meet high demand for cooling during 2021’s hottest summer on record, driving sky-high summer energy bills for many households. February’s Texas Big Freeze also disrupted gas distribution and production.

The world is moving again and demand for goods and services is rebounding to pre-pandemic levels. But even with higher energy demand, OPEC announced it would not inject more oil into the economy. Major oil companies have also held oil and gas spending flat in 2021, with their share of overall upstream spending at 25%, compared with nearly 40% in the mid-2010s. And as climate change threats loom in the financial world, investors are reducing their exposure to the risks of stranded assets, increasingly diversifying and divesting from fossil fuels. 

Second, despite strong and sustained growth for renewable energy, energy storage, and electric vehicles, the relatively slow pace to adopt fossil fuel alternatives at scale has left U.S. households and businesses tethered to an industry well-known for price volatility. Today, some oil drillers are using profits from higher gas prices to pay back debt and reward shareholders as demanded by investors, instead of increasing supply. Rising prices for a limited commodity in high demand is generating huge profits for many of the world’s largest companies at the expense of U.S. households.

Because 48% of homes use fossil gas for heating and another 10% heat with propane and fuel oil, more than half of U.S. households will feel the impact of rising prices on their home energy bills. One in four U.S. households continues to experience a high energy burden (meaning their energy expenses consume an inordinate amount of their income), including risks of pandemic power shut-offs that deepen energy insecurity, and many are still experiencing financial hardships exacerbated by the pandemic. Those with inefficient fossil-fueled appliances, homes, and cars will be hardest hit, and many families with fixed- and lower-incomes could be forced to choose between heat or other necessities.

We have the solutions—the BBBA will unlock their benefits for all households

Short-term band-aids may be enticing, but long-term policies are the only way out of this negative feedback loop. Clean energy and building electrification will prevent more costly disasters in the future, but they’re the very solutions the fossil fuel industry fights at every turn. All-electric homes and vehicles are a natural hedge against the price spikes we’re experiencing today since renewables are inherently devoid of fuel-related price fluctuations.

RMI analysis shows all-electric single-family homes in all regions of the country have lower energy bills than a comparable mixed fuel-homes (i.e., electricity and gas). Electric vehicles also save consumers money. Research from University of California, Berkeley and Energy Innovation found consumers could save a total of $2.7 trillion in 2050—or $1,000 per year, per household for the next 30 years—if we accelerate electric vehicle deployment in the coming decade.

The BBBA would help deliver these consumer savings by expanding and expediting clean energy, while ensuring equitable adoption among lower-income households and underserved communities. Extending and expanding clean energy tax credits; new incentives for electric vehicles (including used electric vehicles); and new incentives for energy efficient homes and all-electric appliances (and electrical upgrades) will reduce up-front costs and spur widespread adoption of all-electric homes, buildings, and cars.

A combination of grants, incentives, and programs will promote private sector investments in a decarbonized economy, while also funding and supporting state and local governments already leading the way. The BBBA also allocates dedicated funding and makes important modifications (such as higher rebate amounts and greater point-of-purchase availability) to ensure these technologies are available to low-income households, underserved urban and rural communities, tribes, frontline communities, and people living in multifamily housing.

Finally, the BBBA proposes to make oil and gas polluters pay for the harm they are causing to people’s health and the climate through a methane fee. This fee would cost companies less than 1% of their revenue, meaning the industry would retain over 99% of its profits. In return return we’d see substantial reductions of a powerful greenhouse gas and a healthier environment in communities living near fossil fuel production. These benefits also come with a stronger economy—Energy Innovation analysis shows the methane fee would create more than 70,000 jobs by 2050 and boost gross domestic product more than $250 billion from 2023 to 2050.

The facts speak for themselves. Gas prices are rising because of reasons totally unrelated to smart climate and clean energy policies, which research shows actually lower costs. For the first time in more than a decade, America has the opportunity to enact a comprehensive energy policy that will yield measurable savings to consumers and free us from oil and gas industry control over our wallets.

The BBBA will help the U.S. get off the fossil fuel rollercoaster and achieve a stable energy future, ensuring that today’s price spikes will be a thing of the past. Proving, once and for all, that the solution to our fossil fuel woes is not more fossil fuels.

 

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