Florida PSC approves Gulf Power’s purchase of renewable energy produced at municipal solid waste plant


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Gulf Power renewable energy contract underscores a Florida PSC-approved power purchase from Bay County's municipal solid waste plant, delivering 13.65 MW at a fixed price, boosting fuel diversity, lowering landfill waste, and saving customers money.

 

Key Points

A fixed-price PPA for 13.65 MW from Bay County's waste-to-energy plant, approved by Florida PSC to cut costs.

✅ Fixed-price purchase; pay only for energy produced.

✅ 13.65 MW from Bay County waste-to-energy facility.

✅ Cuts landfill waste and natural gas dependency.

 

The Florida Public Service Commission (PSC) approved Tuesday a contract under which Gulf Power Company will purchase all the electricity generated by the Bay County Resource Recovery Facility, a municipal solid waste plant, similar to SaskPower-Manitoba Hydro deal structures seen elsewhere, over the next six years.

“Gulf’s renewable energy purchase promotes Florida’s fuel diversity, further reducing our dependency on natural gas,” PSC Chairperson Julie Brown said. “This renewable energy option also reduces landfill waste, saves customers money, and serves the public interest.”

The contract provides for Gulf to acquire the Panama City facility’s 13.65 megawatts of renewable generation for its customers beginning in July 2017. Gulf will pay a fixed price, aligned with approaches in Alberta's clean electricity RFP programs, and only pays for the energy produced. The contract is expected to save approximately $250,000 and provides security for customers, a contrast to overruns at the Kemper power plant project, because if the plant does not supply energy, Gulf does not have to provide payment.

This contract is the third renewable energy contract between Gulf and Bay County, at a time when the Southern California plant closures may be postponed, continuing agreements approved in 2008 and 2014. In making the decision, the PSC considered Gulf’s need for power and developments such as the Turkey Point license renewal process, as well as the contract’s cost-effectiveness, payment provisions, and performance guarantees, as required by rule.

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B.C. ordered to pay $10M for denying Squamish power project

Greengen Misfeasance Ruling details a B.C. Supreme Court decision awarding $10.125 million over wrongfully denied Crown land and water licence permits for a Fries Creek run-of-river hydro project under a BC Hydro contract.

 

Key Points

A B.C. Supreme Court ruling awarding $10.125M for wrongful denial of Crown land and water licences on Greengen's project.

✅ $10.125M damages for misfeasance in public office

✅ Denial of Crown land tenure and water licence permits

✅ Tied to Fries Creek run-of-river and BC Hydro EPA

 

A B.C. Supreme Court judge has ordered the provincial government to pay $10.125 million after it denied permits to a company that wanted to build a run-of-the river independent power project near Squamish.

In his Oct. 10 decision, Justice Kevin Loo said the plaintiff, Greengen Holdings Ltd., “lost an opportunity to achieve a completed and profitable hydro-electric project” after government representatives wrongfully exercised their legal authority, a transgression described in the ruling as “misfeasance,” with separate concerns reflected in an Ontario market gaming investigation reported elsewhere.

Between 2003 and 2009, the company sought to develop a hydro-electric project on and around Fries Creek, which sits opposite the Brackendale neighbourhood on the other side of the Squamish River. To do so, Greengen Holdings Ltd. required a water licence from the Minister of the Environment and tenure over Crown land from the Minister of Agriculture.

After a lengthy process involving extensive communications between Greengen and various provincial and other ministries and regulatory agencies, the permits were denied, according to Loo. Both decisions cited impacts on Squamish Nation cultural sites that could not be mitigated.

Elsewhere, an Indigenous-owned project in James Bay proceeded despite repeated denials, underscoring varied approaches to community participation.

40-year electricity plan relied on Crown land
The case dates back to December 2005, when BC Hydro issued an open call for power with Greengen. The company submitted a tender several months later.

On July 26, 2006, BC Hydro awarded Greengen an energy purchase agreement, amid evolving LNG electricity demand across the province, under which Greengen would be entitled to supply electricity at a fixed price for 40 years.

Unlike conventional hydroelectric projects, such as new BC generating stations recently commissioned, which store large volumes of water in reservoirs, and in so doing flood large tracts of land, a run of the river project often requires little or no water storage. Instead, from a high elevation, they divert water from a stream or river channel.

Water is then sent into a pressured pipeline known as a penstock, and later passed through turbines to generate electricity, Loo explained, as utilities pursue long-term plans like the Hydro-Québec strategy to reduce fossil fuel reliance. The system returns water to the original stream or river, or into another body of water. 

The project called for most of that infrastructure to be built on Crown land, according to the ruling.

All sides seemed to support the project
In early 2005, company principle Terry Sonderhoff discussed the Fries Creek project in a preliminary meeting with Squamish Nation Chief Ian Campbell.

“Mr. Sonderhoff testified that Chief Campbell seemed supportive of the project at the time,” Loo said.

 

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Canada to spend $2M on study to improve Atlantic region's electricity grid

Atlantic Clean Power Superhighway outlines a federally backed transmission grid upgrade for Atlantic Canada, adding 2,000 MW of renewable energy via interprovincial ties, improved hydro access from Quebec and Newfoundland and Labrador, with utility-regulator funding.

 

Key Points

A federal-provincial plan upgrading Atlantic Canada's grid to deliver 2,000 MW of renewables via interprovincial links.

✅ $2M technical review to rank priority transmission projects

✅ Target: add 2,000 MW renewable power to Atlantic grid

✅ Cost-sharing by utilities, regulators, and federal-provincial funding

 

The federal government will spend $2 million on an engineering study to improve the Atlantic region's electricity grid.

The study was announced Friday at a news conference held by 10 federal and provincial politicians at a meeting of the Atlantic Growth Strategy in Halifax, which includes ongoing regulatory reform efforts for cleaner power in Atlantic Canada.

The technical review will identify the most important transmission projects including inter-provincial ties needed to move electricity across the region.

Nova Scotia Premier Stephen McNeil said the results are expected in July.

Provinces will apply to the federal government for federal funding to build the infrastructure. Utilities in each province will be expected to pay some portion of the cost by applying to respective regulators, but what share falls to ratepayers is not known.

​Federal Intergovernmental Affairs Minister Dominic LeBlanc characterized the grid improvements as something that will cost hundreds of millions of dollars.

He said the study was the first step toward "a clean power superhighway across the region.

"We have a historic opportunity to quickly get to work on upgrading ultimately a whole series of transmission links of inter-provincial ties. That's something that the government of Canada would be anxious to work with in terms of collaborating with the provinces on getting that right."

Premier McNeil referred specifically to improving hydro access from Quebec and Newfoundland and Labrador.

For context, a massive cross-border hydropower line to New York is planned, illustrating the scale of projects under consideration.

 

Goal of 2,000 megawatts

McNeil said the goal was to bring an additional 2,000 megawatts of renewable electricity into the region.

"I can't stress to you enough how critical this will be for the future economic success and stability of Atlantic Canada, especially as Atlantic grids face intensifying storms," he said.

Federal Immigration Minister Ahmed Hussen also announced a pilot project to attract immigrant workers will be extended by two years to the end of 2021.

International graduate students will be given 24 months to apply under the program — a one-year increase.

 

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Balancing Act: Germany's Power Sector Navigates Energy Transition

Germany January Power Mix shows gas-fired generation rising, coal steady, and nuclear phaseout impacts, amid cold weather, energy prices, industrial demand, and emissions targets shaping renewables, grid stability, and security of supply.

 

Key Points

The January electricity mix, highlighting gas, coal, renewables, and nuclear exit effects on emissions, prices, and demand.

✅ Gas output up 13% to 8.74 TWh, share at 18.6%.

✅ Coal share 23%, down year on year, steady vs late 2023.

✅ Nuclear gap filled by gas and coal; emissions below Jan 2023.

 

Germany's electricity generation in January presented a fascinating snapshot of its energy transition journey. As the country strives to move away from fossil fuels, with renewables overtaking coal and nuclear in its power mix, it grapples with the realities of replacing nuclear power and meeting fluctuating energy demands.

Gas Takes the Lead:

Gas-fired power plants saw their highest output in two years, generating 8.74 terawatt hours (TWh). This 13% increase compared to January 2023 compensated for the closure of nuclear reactors, which were extended during the energy crisis to shore up supply, and colder weather driving up heating needs. This reliance on gas, however, pushed its share in the electricity mix to 18.6%, highlighting Germany's continued dependence on fossil fuels.

Coal Fades, but Not Forgotten:

While gas surged, coal-fired generation remained below previous levels, dropping 29% from January 2023. However, it stayed relatively flat compared to late 2023, suggesting utilities haven't entirely eliminated it. Coal still held a 23% share, and periodic coal reliance remains evident, exceeding gas' contribution, reflecting its role as a reliable backup for intermittent renewable sources like wind.

Nuclear Void and its Fallout:

The shutdown of nuclear plants in April 2023 created a significant gap, previously accounting for an average of 12% of annual electricity output. This loss is being compensated through gas and coal, with gas currently the preferred choice, even as a nuclear option debate persists among policymakers. This strategy kept January's power sector emissions lower than the previous year, but rising demand could shift the balance.

Industry's Uncertain Impact:

Germany's industrial sector, a major energy consumer, is facing challenges like high energy prices and weak consumer demand. While the government aims to foster industrial recovery, uncertainties linger due to a shaky coalition and limited budget, and debate about a possible nuclear resurgence continues in parallel, which could reshape policy. Any future industrial revival would likely increase energy demand and potentially necessitate more gas or coal.

Cost-Driven Choices and Emission Concerns:

The choice between gas and coal depends on their relative costs, in a system pursuing a coal and nuclear phase-out under long-term policy. Currently, gas seems more favorable emission-wise, but if its price rises, coal might become more attractive, impacting overall emissions.

Looking Ahead:

Germany's energy transition faces a complex balancing act, with persistent grid expansion woes and exposure to cheap gas complicating progress. While the reliance on gas and coal highlights the difficulties in replacing nuclear, the focus on emissions reduction is encouraging. Navigating the challenges of affordability, industrial needs, and climate goals will be crucial for a successful transition to a clean and secure energy future.

 

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Feds to study using electricity to 'reduce or eliminate' fossil fuels

Electrification Potential Study for Canada evaluates NRCan's decarbonization roadmap, assessing electrification of end uses and replacements for fossil fuels across transportation, buildings, and industry, including propane, diesel, natural gas, and coal, to guide energy policy.

 

Key Points

An NRCan study assessing electrification to replace fossil fuels across sectors and guide deep decarbonization R&D.

✅ Evaluates non-electric alternatives alongside electrification paths

✅ Covers propane, diesel, natural gas, and coal end uses

✅ Guides NRCan R&D priorities for deep decarbonization

 

The federal government wants to spend up to $300,000 on a study aimed at understanding whether existing electrical technologies can “reduce or eliminate” fossil fuels used for virtually every purpose other than generating electricity.

The proposal has caused consternation within the Saskatchewan government, whose premier has criticized a 2035 net-zero grid target as shifting the goalposts, and which has spent months attacking federal policies it believes will harm the Western Canadian energy sector without meaningfully addressing climate change.

Procurement documents indicate the “Electrification Potential Study for Canada” will provide “strategic guidance on the need to pursue both electric and non-electric energy research and development to enable deep decarbonisation scenarios.”

“It is critical that (Natural Resources Canada) as a whole have a cross-sectoral, consistent, and comprehensive understanding of the viability of electric technologies as a replacement for fossil fuels,” the documents state.

The study proponent will be asked to examine possible replacements for a range of fuels, including propane, transportation fuel, fuel oil, diesel, natural gas and coal, even as Alberta maps a path to clean electricity for its grid. Only international travel fuel and electricity generation are outside the scope of the study.

“To be clear, the consultant should not answer these questions directly, but should conduct the analysis with them in mind. The goal … is to collate data which can be used by (Natural Resources Canada) to conduct analysis related to these questions,” the documents state.

Natural Resources Canada issued the request for proposals one week before Prime Minister Justin Trudeau officially launched a 40-day election campaign in which climate and energy policy, including debates over Alberta's power market like a Calgary retailer's challenge, is expected to play a defining role.

It also comes as the federal government works to complete the controversial Trans Mountain Pipeline Expansion project through British Columbia, amid tariff threats boosting support for Canadian energy projects, which it bought last year for $4.5 billion and is currently bogged down in the court system.

A Natural Resources Canada spokeswoman said the ministry would not be able to respond to questions until sometime on Thursday.

While the documents make clear that the study aims to answer unresolved questions about what the International Energy Agency calls an increasingly-electric future, with clean grid and storage trends emerging, without a specific timeline, the provincial government is far from thrilled.

Energy and Resources Minister Bronwyn Eyre said the document reflects the federal government’s “hostility” to the energy sector, even as Alberta's electricity sector faces profound change, because government ministries like Natural Resources Canada don’t do anything without political direction.

Asked whether a responsible government should consider every option before taking a decision, Eyre said a government that was not interested in eliminating fossil fuels entirely would not have used such “strong” language in a public document, noting that provinces like Ontario are grappling with hydro system problems as well.

“I think it’s a real wake-up call to what (Ottawa’s) endgame really is here,” she said, adding that the document does not ask the proponent to conduct an economic impact analysis or consider potential job losses in the energy sector.

The study is organized by Natural Resources Canada’s office of energy research and development, which is tasked with accelerating energy technology “in order to produce and use energy in … more clean and efficient ways,” the documents state.

Bidding on the proposal closes Oct. 14, one week before the federal election. The successful proponent must deliver a final report in April 2020, according to the documents.

 

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Seven small UK energy suppliers must pay renewables fees or risk losing licence

Ofgem Renewables Obligations drive supplier payments for renewables fees, feed-in tariffs, and renewable generation, with non-payment risking supply licences amid the price cap and volatile wholesale prices across the UK energy market.

 

Key Points

Mandatory payments by suppliers funding renewables via feed-in tariffs; non-payment can trigger supply licence revoking.

✅ Covers Renewables Obligation and Feed-in Tariff scheme compliance.

✅ Non-payment can lead to Ofgem action and licence loss.

✅ Affected by price cap and wholesale price volatility.

 

Seven small British energy suppliers owe a total of 34 million pounds ($43.74 million) in renewables fees, amid a renewables backlog that has stalled projects, and could face losing their supply licences if they cannot pay, energy regulator Ofgem reports.

Under Britain’s energy market rules, suppliers of energy must meet so-called renewables obligations and feed-in tariffs, including households' ability to sell solar power back to energy firms, which are imposed on them by the government to help fund renewable power generation.

Several small energy companies have gone bust over the past two years, a trend echoed by findings from a global utility study on renewable priorities, as they struggled to pay the renewables fees and as their profits were affected by a price cap on the most commonly used tariffs and fluctuating wholesale prices, even as a 10 GW contract brings new renewable capacity onto the UK grid.

Ofgem has called on the companies to make necessary payments by Oct. 31, as moves to offer community-generated power to all UK customers progress.

“If they do not pay Ofgem could start the process of revoking their licences to supply energy,” it said in a statement, as offshore wind power continues to scale nationwide.

The seven suppliers are, amid debates over clean energy impacts, Co-Operative Energy Limited; Flow Energy Limited; MA Energy Limited; Nabuh Energy Limited; Robin Hood Energy Limited; Symbio Energy Limited and Tonik Energy Limited. ($1 = 0.7773 pounds)

 

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B.C. electricity demand hits an all-time high

BC Hydro Peak Electricity Demand reached a record 10,902 megawatts during a cold snap, driven by home heating. Peak hours surged; load shifting and energy conservation can ease strain on the grid and lower bills.

 

Key Points

Record winter peak of 10,902 MW, set during a cold snap, largely from home heating demand at peak hours.

✅ All-time high load: 10,902 MW between 5 and 6 p.m., Dec. 27.

✅ Cold snap increased home heating demand during peak hours.

✅ Shift laundry and dishwashers off-peak; use programmable thermostats.

 

BC Hydro says the province set a new record for peak electricity demand on Monday as temperatures hit extreme lows, and Quebec shattered consumption records during similar cold weather.

Between 5 and 6 p.m. on Dec. 27, demand for electricity hit an all-time high of 10,902 megawatts, which is higher than the previous record of 10,577 megawatts set in 2020, and follows a record-breaking year in 2021 for the utility.

“The record represents a single moment in the hour when demand for electricity was the highest yesterday,” says Simi Heer, BC Hydro spokesperson, in a statement. “Most of the increase is likely due to additional home heating required during this cold snap.”

In addition to the peak demand record on Monday, BC Hydro has observed an overall increase in electricity demand since Friday, and has noted that cryptocurrency mining electricity use is an emerging load in the province as well. Monday’s hourly peak demand was 18 per cent higher than Friday’s, while Calgary's electricity use soared during a frigid February, underscoring how cold snaps strain regional grids.

“BC Hydro has enough supply options in place to meet increasing electricity demand,” adds Heer, and pointed to customer supports like a winter payment plan for households managing higher bills. “However, if British Columbians want to help ease some of the demand on the system during peak times, we encourage shifting activities like doing laundry or running dishwashers to earlier in the day or later in the evening.”

BC Hydro is also offering energy conservation tips for people looking to lower their electricity use and their electricity bills, noting that Earth Hour once saw electricity use rise in the province:

Manage your home heating actively by turning the heat down when no one his home or when everyone is sleeping. Consider installing a programmable thermostat to automatically adjust temperatures at different times based on your family's activities, and remember that in warmer months wasteful air conditioning can add $200 to summer energy bills. BC Hydro recommends the following temperatures:

16 degrees Celsius when sleeping or away from home
21 degrees Celsius when relaxing, watching TV
18 degrees Celsius when doing housework or cleaning
 

 

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