Homegrown, renewable energy in Florida

By Charles H. Bronson, St. Petersburg Times


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Today's political climate can make finding areas of agreement tough. But when it comes to energy, common ground can be found on our nation's working lands.

Most Americans would probably agree that developing homegrown sources of energy that will never run out is a good thing. And having served as Florida's agriculture commissioner for the past decade, I know that our state's farms, ranches and forestland can be an important part of our energy future.

I sit on the steering committee of 25x'25, a national coalition whose vision is to see America's agricultural and forest lands produce 25 percent of America's energy by 2025 - while continuing to produce safe, abundant, and affordable food, feed and fiber. It's a broad coalition that doesn't prescribe policy solutions, but that provides a lot of information and asks those of us who work in the agricultural and forestry communities to consider solutions.

A new report from the University of Tennessee, commissioned by 25x'25, provides fresh information about the role of our agriculture and forestry sectors play in our nation's energy future. Researchers looked at what would happen if, in addition to implementing the national Renewable Fuels Standard - passed by Congress in 2005 and expanded by the Energy Independence and Security Act of 2007 - the United States added a Renewable Electricity Standard, or RES. An RES would require utilities to generate a certain percentage of the electricity they produce from renewable sources, including solar, wind and bio-energy.

The study found that farmers, ranchers and foresters across the country would benefit from such an effort. The one-two punch of renewable fuels and renewable electricity could spur an additional $215 billion of economic activity, create 700,000 jobs, and add $84 billion to the nation's GDP.

The study projects that an estimated $14 billion in new revenue would flow to the agricultural and forestry sectors. Growing crops that can be turned directly into energy or co-fired in combination with traditional power sources, leasing land for wind turbines and solar panels, selling waste wood to be turned into electricity - these could be important new revenue streams.

I was born into a family that has been farming and ranching for 375 years, and I know it's not the easiest way to earn a living. As times change, innovation is essential. Getting more of our energy from farms, ranches, and forests could make a real difference for our fellow Floridians who make a living from the land.

It's an idea that is worth a serious conversation, especially as part of a long-term, comprehensive and stable energy policy. And it's worth noting that two-dozen states already have some kind of renewable energy standard. Done right, policies that encourage renewable energy can attract clean-tech businesses, spur technological innovation, and create jobs.

Florida's farmers, ranchers and foresters - and their partners in business and academia - are already working on producing energy, often with assistance from the state government. During my time as the state's agriculture commissioner, we have:

• Granted more than $67 million to companies and universities researching and developing commercial production of renewable energy here in Florida

• Developed the "Farm to Fuel" program, designed to make Florida a leader in the production of alternative energy using crops and woody biomass.

The market for renewable energy is growing fast, here at home and around the world. With our robust agricultural sector, excellent universities and research institutions, innovative companies, and entrepreneurial spirit, Florida is well placed to benefit. In our state and across the nation, our farms, ranches, and forests have a lot to offer. Policies that encourage renewable energy will accelerate the delivery of clean energy solutions, and help move us toward a more profitable, more sustainable future.

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Nova Scotia regulator approves 14% electricity rate hike, defying premier

Nova Scotia Power Rate Increase 2023-2024 approved by the UARB lifts electricity rates 14 percent, citing fuel costs and investments, despite Bill 212; includes ROE 9 percent, decarbonization deferral, and a storm cost recovery rider.

 

Key Points

An approved UARB rate case raising electricity bills about 14% over 2023-2024, with ROE 9% and cost recovery tools.

✅ UARB approves average 6.9% annual increases for 2023 and 2024.

✅ Maintains 9% ROE; sets storm cost rider trial and decarbonization deferral.

✅ Government opposed via Bill 212, but settlement mostly upheld.

 

Nova Scotia regulators approved a 14 per cent electricity rate hike on Thursday, defying calls by Premier Tim Houston to reject the increase.

Rates will rise on average by 6.9 per cent each year in 2023 and 2024.

In Newfoundland and Labrador, the NL Consumer Advocate called an 18 per cent electricity rate hike unacceptable amid affordability concerns.

The Nova Scotia Utility and Review Board (UARB) issued a 203-page decision ratifying most of the elements in a settlement agreement reached between Nova Scotia Power and customer groups after Houston's government legislated a rate, spending and profit cap on the utility in November.

The board said approval was in the public interest and the increase is "reasonable and appropriate."

"The board cannot simply disallow N.S. Power's reasonable costs to make rates more affordable. These principles ensure fair rates and the financial health of a utility so it can continue to invest in the system providing services to its customers," the three-member panel wrote.

"While the board can (and has) disallowed costs found to be imprudent or unreasonable, absent such a finding, N.S. Power's costs must be reflected in the rates."

In addition to the 14 per cent hike, the board maintained Nova Scotia Power's current return on equity of 9 per cent, with an earnings band of 8.75 to 9.25 per cent. It agreed in principle to establish a decarbonization deferral account to pay for the retirement of coal plants and related decommissioning costs, and implemented a storm cost recovery rider for a three-year trial period.

The board rejected several items in the agreement, including rolling some Maritime Link transmission capital projects into consumers' rates.

Nova Scotia Power welcomed the ruling in a statement, describing it as "the culmination of an extensive and transparent regulatory process over the past year."

Natural Resources and Renewables Minister Tory Rushton, who has said the government cannot order lower power rates in Nova Scotia, stated the UARB decision was not what the government wanted, but he did not indicate the government has any plans to bring forward legislation to overturn it. 

"We're disappointed by the decision today. We've always been very clear that we were standing by ratepayers right from the get-go but we also respect the independent body of the UARB and their decision today."


Pressure from the province
Houston claimed the settlement breached his government's legislation, known as Bill 212 in Nova Scotia, which he said was intended to protect ratepayers. It capped rates to cover non-fuel costs by 1.8 per cent. It did not cap rates to cover fuel costs or energy efficiency programs.

Bill 212 was passed after the board concluded weeks of public hearings into Nova Scotia Power's request for an electricity rate increase, its first general rate application in 10 years. Nova Scotia Power is a subsidiary of Halifax-based Emera, which is a publicly traded company.

The legislation triggered credit downgrades from two credit rating agencies who said it compromised the independence of the Nova Scotia Utility and Review Board.

In Newfoundland and Labrador, electricity users have begun paying for Muskrat Falls as project costs flow through rates, highlighting broader pressures on Atlantic Canada utilities.

In its decision, the board accepted that legislation was intended to protect ratepayers but did not preclude increases in rates.

"Given the exclusion of fuel and purchased power costs when these were expected to cause significant upward pressure on rates, it also did not preclude large increases in rates. Instead, the protection afforded by the Public Utilities Act amendments appears to be focused on N.S. Power's non-fuel costs, with several amendments targeting N.S. Power's cost of capital and earnings."

The board noted the province was the only intervenor in the rate case to object to the settlement.


Opposition reaction
Rushton said despite the outcome, Bill 212 achieved its goal, which was to protect ratepayers.

"Without Bill 212 the rates would have actually been higher," he said. "It would have double-digit rates for this year and next year and now it's single digits."

NDP Leader Claudia Chender said the end result is that Nova Scotians are still facing "incredibly unaffordable power."

Similar criticism emerged in Saskatchewan after an 8 per cent SaskPower increase, which the NDP opposed during provincial debates.

"It's really unfortunate for a lot of Nova Scotians who are heading into a freezing weekend where heat is not optional."

Chender said a different legislative approach is needed to change the regulatory system, and more needs to be done to help people pay their electricity bills.

Liberal MLA Kelly Regan echoed that sentiment.

"There are lots of people who can absorb this. There are a lot of people who cannot, and those are the people that we should be worried about right now. This is why we've been saying all along the government needs to actually give money directly to Nova Scotians who need help with power rates."

Rushton said the government has introduced programs to help Nova Scotians pay for heat, including raising the income threshold to access the Heating Assistance Rebate Program and creating incentives to install heat pumps.

Elsewhere, some governments have provided a lump-sum credit on electricity bills to ease short-term costs for households.

 

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N.L., Ottawa agree to shield ratepayers from Muskrat Falls cost overruns

Muskrat Falls Financing Restructuring redirects megadam benefits to ratepayers, stabilizes electricity rates, and overhauls federal provincial loan guarantees for the hydro project, addressing cost overruns flagged by the Public Utilities Board in Newfoundland and Labrador.

 

Key Points

A revised funding model shifting benefits to ratepayers to curb rate hikes linked to Muskrat Falls cost overruns.

✅ Shields ratepayers from megadam cost overruns

✅ Revises federal provincial loan guarantees

✅ Targets stable electricity rates by 2021 and beyond

 

Ottawa and Newfoundland and Labrador say they will rewrite the financial structure of the Muskrat Falls hydro project to shield ratepayers from paying for the megadam's cost overruns.

Federal Natural Resources Minister Seamus O'Regan and Premier Dwight Ball announced Monday that their two governments would scrap the financial structure agreed upon in past federal-provincial loan agreements, moving to a model that redirects benefits, such as a lump sum credit, to ratepayers.

Both politicians called the announcement, which was light on dollar figures, a major milestone in easing residents' fears that electricity rates will spike sharply, as seen with Nova Scotia's debated 14% hike, when the over-budget dam comes fully online next year.
"We are in a far better place today thanks to this comprehensive plan," Ball said.

Ball has said the issue of electricity rates is a top priority for his government, and he has pledged to keep rates near existing levels, but rate mitigation talks with Ottawa have dragged on since April.

A report by the province's Public Utilities Board released Friday forecast an "unprecedented" 75 per cent increase in average domestic rates for island residents in 2021, while Nova Scotia's regulator approved a 14% hike, and reported concerns from industrial customers about their ability to remain competitive.

Costs of the Muskrat Falls megadam on Labrador's Lower Churchill River have ballooned to more than $12.7 billion since the project was approved in 2012, according to the latest estimate of Crown corporation Nalcor Energy.

The dam is set to produce more power than the province can sell. Its existing financial structure would have left electricity ratepayers paying for Muskrat Falls to make up the difference starting in 2021, an issue both governments said Monday has been resolved with the relaunch of financing talks.

"Essentially, you won't pay this on your monthly light bills," Ball said.

But details of how the project will meet financing requirements in coming decades to make up the gap in funds are still to be worked out.

Both Ball and O'Regan criticized previous governments for sanctioning the poorly planned development and again pledged their commitment to easing the burden on residents.

"We promised we would be there to help, and we will be," O'Regan said before announcing a "relaunch" of negotiations around the project's financial structure.

He did not say how much the new setup might cost the federal government, despite earlier federal funding commitments, stressing that the new focus will be on the project's long-term sustainability. "There's no single piece of policy ... that can resolve such a large and complicated mess," O'Regan said.

The two governments also said they will work towards electrifying federal buildings to reduce an anticipated power surplus in the province.

In the short term, the federal government said it would allow for "flexibility" in upcoming cash requirements related to debt servicing, allowing deferral of payments if necessary.

Ball said that flexibility was built in to ensure the plan would still be applicable if costs continue to rise before Muskrat Falls is commissioned.

Political opponents criticized Monday's plan as lacking detail.

"What I heard talked about was an agreement that in the future, there's going to be an agreement," said Progressive Conservative Leader Ches Crosbie. "This was an occasion to reassure people that there's a plan in place to make life here affordable, and I didn't see that happen today."

Others addressed the lingering questions about the project's final cost.

Nalcor's latest financial update has remained unchanged since 2017, though the Muskrat Falls project has seen additional delays related to staffing and software issues.

Dennis Browne, the province's consumer advocate, said the switch to a cost of service model is a significant move that will benefit ratepayers, but he said it's impossible to truly restructure the project while it's a work in progress. "We need to know what the figures are, and we don't have them," he said.

 

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Ireland announces package of measures to secure electricity supplies

Ireland electricity support measures include PSO levy rebates, RESS 2 renewables, CRU-directed EirGrid backup capacity, and grid investment for the Celtic Interconnector, cutting bills, boosting security of supply, and reducing reliance on imported fossil fuels.

 

Key Points

Government steps to cut bills and secure supply via PSO rebates, RESS 2 renewables, backup power, and grid upgrades.

✅ PSO levy rebates lower domestic electricity bills.

✅ RESS 2 adds wind, solar, and hydro to the grid.

✅ EirGrid to procure temporary backup capacity for winter peaks.

 

Ireland's Cabinet has approved a package of measures to help mitigate the rising cost of rising electricity bills, as Irish provider price increases continue to pressure consumers, and to ensure secure supplies to electricity for households and business across Ireland over the coming years.

The package of measures includes changes to the Public Service Obligation (PSO) levy (beyond those announced earlier in the year), which align with emerging EU plans for more fixed-price electricity contracts to improve price stability. The changes will result in rebates, and thus savings, for domestic electricity bills over the course of the next PSO year beginning in October. This further reduction in the PSO levy occurs because of a fall in the relative cost of renewable energy, compared to fossil fuel generation.

The Government has also approved the final results of the second onshore Renewable Electricity Support Scheme (RESS 2) auction, echoing how Ontario's electricity auctions have aimed to lower costs for consumers. This will bring significantly more indigenous wind, solar and hydro-electric energy onto the National Grid. This, in turn, will reduce our reliance on increasingly expensive imported fossil fuels, as the UK explores ending the gas-electricity price link to curb bills.

The package also includes Government approval for the provision of funding for back-up generation capacity, to address risks to security of electricity supply over the coming winters, similar to the UK's forthcoming energy security law approach in this area. The Commission for the Regulation of Utilities (CRU), which has statutory responsibility for security of supply, has directed EirGrid to procure additional temporary emergency generation capacity (for the winters of 2023/2024 to 2025/2026). This will ultimately provide flexible and temporary back-up capacity, to safeguard secure supplies of electricity for households and businesses as we deploy longer-term generation capacity.

Today’s measures also see an increased borrowing limit (€3 billion) for EirGrid – to strengthen our National Grid as part of 'Shaping Our Electricity Future' and to deliver the Celtic (Ireland-France) Interconnector, amid wider European moves to revamp the electricity market that could enhance cross-border resilience. An increased borrowing limit (€650 million) for Bord na Móna will drive greater deployment of indigenous renewable energy across the Midlands and beyond – as part of its 'Brown to Green' strategy, while measures like the UK's household energy price cap illustrate the scale of consumer support elsewhere.

 

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Bitcoin consumes 'More electricity than Argentina' - Cambridge

Bitcoin energy consumption is driven by mining electricity demand, with TWh-scale power use, carbon footprint concerns, and Cambridge estimates. Rising prices incentivize more hardware; efficiency gains and renewables adoption shape sustainability outcomes.

 

Key Points

Bitcoin energy consumption is mining's electricity use, driven by price, device efficiency, and energy mix.

✅ Cambridge tool estimates ~121 TWh annual usage

✅ Rising BTC price incentivizes more mining hardware

✅ Efficiency, renewables, and costs shape footprint

 

"Mining" for the cryptocurrency is power-hungry, with power curtailments reported during heat waves, involving heavy computer calculations to verify transactions.

Cambridge researchers say it consumes around 121.36 terawatt-hours (TWh) a year - and is unlikely to fall unless the value of the currency slumps, even as Americans use less electricity overall.

Critics say electric-car firm Tesla's decision to invest heavily in Bitcoin undermines its environmental image.

The currency's value hit a record $48,000 (£34,820) this week. following Tesla's announcement that it had bought about $1.5bn bitcoin and planned to accept it as payment in future.

But the rising price offers even more incentive to Bitcoin miners to run more and more machines.

And as the price increases, so does the energy consumption, according to Michel Rauchs, researcher at The Cambridge Centre for Alternative Finance, who co-created the online tool that generates these estimates.

“It is really by design that Bitcoin consumes that much electricity,” Mr Rauchs told BBC’s Tech Tent podcast. “This is not something that will change in the future unless the Bitcoin price is going to significantly go down."

The online tool has ranked Bitcoin’s electricity consumption above Argentina (121 TWh), the Netherlands (108.8 TWh) and the United Arab Emirates (113.20 TWh) - and it is gradually creeping up on Norway (122.20 TWh).

The energy it uses could power all kettles used in the UK, where low-carbon generation stalled in 2019, for 27 years, it said.

However, it also suggests the amount of electricity consumed every year by always-on but inactive home devices in the US alone could power the entire Bitcoin network for a year, and in Canada, B.C. power imports have helped meet demand.

Mining Bitcoin
In order to "mine" Bitcoin, computers - often specialised ones - are connected to the cryptocurrency network.

They have the job of verifying transactions made by people who send or receive Bitcoin.

This process involves solving puzzles, which, while not integral to verifying movements of the currency, provide a hurdle to ensure no-one fraudulently edits the global record of all transactions.

As a reward, miners occasionally receive small amounts of Bitcoin in what is often likened to a lottery.

To increase profits, people often connect large numbers of miners to the network - even entire warehouses full of them, as seen with a Medicine Hat bitcoin operation backed by an electricity deal.

That uses lots of electricity because the computers are more or less constantly working to complete the puzzles, prompting some utilities to consider pauses on new crypto loads in certain regions.

The University of Cambridge tool models the economic lifetime of the world's Bitcoin miners and assumes that all the Bitcoin mining machines worldwide are working with various efficiencies.

Using an average electricity price per kilowatt hour ($0.05) and the energy demands of the Bitcoin network, it is then possible to estimate how much electricity is being consumed at any one time, though in places like China's power sector data can be opaque.
 

 

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Minister approves 30-megawatt wind farm expansion in Eastern Kings

Eastern Kings Wind Farm Expansion advances P.E.I. renewable energy with seven new wind turbines, environmental assessment, wildlife monitoring of birds and bats, and community consultation to double output to 30 MW for domestic consumption.

 

Key Points

A P.E.I. project adding seven turbines for 30 MW, under 17 conditions, with wildlife monitoring and community oversight.

✅ Seven new turbines, larger than existing units

✅ 17 conditions, monthly compliance reporting

✅ Two-year wildlife study for birds and bats

 

A proposal to expand an existing wind farm in eastern P.E.I. has been given the go-ahead, according to P.E.I.’s Department of Environment, Water and Climate Change, as related grid work like a new transmission line progresses in the region.

Minister Natalie Jameson approved the P.E.I. Energy Corporation’s Eastern Kings Wind Farm expansion project, the province announced in a release Wednesday afternoon, as Atlantic Canada advances other renewable initiatives like tidal power to diversify supply.

The project will be subject to 17 conditions, which were drawn from a review of the 80 responses the province received from the public on the proposed Eastern Kings Wind Farm expansion.

The corporation must provide a summary on the status of each condition to the department on a monthly basis.

“This decision balances the needs of people, communities, wellness and the environment,” Jameson said in the release.

“It allows this renewable energy project to proceed and reduce greenhouse [gas] emissions that cause climate change while mitigating the project’s impact to the Island’s ecosystem.”

The P.E.I. Energy Corporation wants to double the output of its Eastern Kings Wind Farm with the installation of seven wind turbines between the communities of Elmira and East Point to develop 30 megawatts of wind power for domestic consumption, according to the minister’s impact assessment, aligning with regional moves to expand wind and solar projects across Atlantic Canada.

The new turbines are expected to be larger than the existing 10 at the site, even as regional utilities study major grid changes to integrate more renewables.

Project must comply with conditions

In February, the province said it would identify any specific questions or concerns it felt needed to be addressed in the submissions, according to Greg Wilson, manager of environmental land management for the province, while some advocate for independent electricity planning to guide such decisions.

Public feedback closed in January, after an earlier extension to wait for a supplemental report on birds and bats.

The corporation needs to comply with all conditions – such as monitoring environmental impact, setting up an environmental management plan and creating a committee to address concerns – listed in the release on Wednesday, amid calls from environmental advocates to reduce biomass use in electricity generation.

A condition in the release suggests representatives from L’nuey, the Souris and Area Wildlife Branch, the Rural Municipality of Eastern Kings and local residents to make up the committee.

The corporation will also need to conduct a study over two years after construction to look at the impact on bats and birds, and implement a protocol to report deaths of birds to federal and provincial authorities.

According to Canada Energy Regulator, roughly 98 per cent of power generated on P.E.I. comes from wind farms. It also said there were 203 megawatts installed on P.E.I. as of 2018, and the majority of energy consumed on the Island comes from New Brunswick from a mix of nuclear, fossil fuels and hydroelectricity, while in Nova Scotia, the utility has increased biomass generation as part of its supply mix.

 

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Japan to host one of world's largest biomass power plants

eRex Biomass Power Plant will deliver 300 MW in Japan, offering stable baseload renewable energy, coal-cost parity, and feed-in tariff independence through economies of scale, efficient fuel procurement, and utility-scale operations supporting RE100 demand.

 

Key Points

A 300 MW Japan biomass project targeting coal-cost parity and FIT-free, stable baseload renewable power.

✅ 300 MW capacity; enough for about 700,000 households

✅ Aims to skip feed-in tariff via economies of scale

✅ Targets coal-cost parity with stable, dispatchable output

 

Power supplier eRex will build its largest biomass power plant to date in Japan, hoping the facility's scale will provide healthy margins, a strategy increasingly seen among renewable developers pursuing diverse energy sources, and a means of skipping the government's feed-in tariff program.

The Tokyo-based electric company is in the process of selecting a location, most likely in eastern Japan. It aims to open the plant around 2024 or 2025 following a feasibility study. The facility will cost an estimated 90 billion yen ($812 million) or so, and have an output of 300 megawatts -- enough to supply about 700,000 households. ERex may work with a regional utility or other partner

The biggest biomass power plant operating in Japan currently has an output of 100 MW. With roughly triple that output, the new facility will rank among the world's largest, reflecting momentum toward 100% renewable energy globally that is shaping investment decisions.

Nearly all biomass power facilities in Japan sell their output through the government-mediated feed-in tariff program, which requires utilities to buy renewable energy at a fixed price. For large biomass plants that burn wood or agricultural waste, the rate is set at 21 yen per kilowatt-hour. But the program costs the Japanese public more than 2 trillion yen a year, and is said to hamper price competition.

ERex aims to forgo the feed-in tariff with its new plant by reaping economies of scale in operation and fuel procurement. The goal is to make the undertaking as economical as coal energy, which costs around 12 yen per kilowatt-hour, even as solar's rise in the U.S. underscores evolving benchmarks for competitive renewables.

Much of the renewable energy available in Japan is solar power, which fluctuates widely according to weather conditions, though power prediction accuracy has improved at Japanese PV projects. Biomass plants, which use such materials as wood chips and palm kernel shells as fuel, offer a more stable alternative.

Demand for reliable sources of renewable energy is on the rise in the business world, as shown by the RE100 initiative, in which 100 of the world's biggest companies, such as Olympus, have announced their commitment to get 100% of their power from renewable sources. ERex's new facility may spur competition.

 

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