Great Plains Energy shareholders approve Aquila purchase

Southeast Alaska Energy Projects advance hydroelectric, biomass, and heat pumps, displacing diesel via grants. Inside Passage Electric Cooperative and Alaska Energy Authority support Kake, Hoonah, Ketchikan with wood pellets, feasibility studies, and rate relief.

Key Points

Programs using hydro, biomass, and heat pumps to cut diesel use and lower electricity costs in Southeast Alaska.

✅ Hydroelectric at Gunnuk Creek to replace diesel in Kake

✅ Biomass and wood pellets displacing fuel oil in facilities

✅ Free feasibility studies; heat pumps where economical

New projects are under development throughout the region to help reduce energy costs for Southeast Alaska residents. A panel presented some of those during last week’s Southeast Conference annual fall meeting in Ketchikan.

Jodi Mitchell is with Inside Passage Electric Cooperative, which is working on the Gunnuk Creek hydroelectric project for Kake. IPEC is a non-profit, she said, with the goal of reducing electric rates for its members.

The Gunnuk Creek project will be built at an existing dam.

“The benefits for the project will be, of course, renewable energy for Kake. And we estimate it will save about 6.2 million gallons over its 50-year life,” she said. “Although, as you heard earlier, these hydro projects last forever.”

The gallons saved are of diesel fuel, which currently is used to power generators for electricity, though in places with limited options some have even turned to new coal plants to keep the lights on.

IPEC operates other hydro projects in Klukwan and Hoonah. Mitchell said they’re looking into future projects, one near Angoon and another that would add capacity to the existing Hoonah project, even as an independent power project in British Columbia is in limbo.

Mitchell said they fund much of their work through grants, which helps keep electric rates at a reasonable level.

Devany Plentovich with the Alaska Energy Authority talked about biomass projects in the state. She said the goal is to increase wood energy use in Alaska, even as some advocates call for a reduction in biomass electricity in other regions.

“We offer any community, any entity, a free feasibility study to see if they have a potential heating system in their community,” she said. “We do advocate for wood heating, but we are trying to get a community to pick the best heating technology for their situation, including options that use more electricity for heat when appropriate. So in a lot of situations, our consultants will give you the economics on a wood heating system but they’ll also recommend maybe you should look at heat pumps or look at waste energy.”

Plentovich said they recently did a study for Ketchikan’s Holy Name Church and School. The result was a recommendation for a heat pump rather than wood.

But, she said, wood energy is on the rise, and utilities elsewhere are increasing biomass for electricity as well. There are more than 50 systems in the state displacing more than 500,000 gallons of fuel oil annually. Those include systems on Prince of Wales Island and in Ketchikan.

Ketchikan recently experienced a supply issue, though. A local wood-pellet manufacturer closed, which is a problem for the airport and the public library, among other facilities that use biomass heaters.

Karen Petersen is the biomass outreach coordinator for Southeast Conference. She said this opens up a great opportunity for someone.

“Devany and I are working on trying to find a supplier who wants to go into the pellet business,” she said. “Probably importing initially, and then converting over to some form of manufacturing once the demand is stabilized.”

So, Petersen said, if anyone is interested in this entrepreneurial opportunity, contact her through Southeast Conference for more information.

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Nevada Renewable Portfolio Standard 2030 targets 50% clean energy, advancing solar, geothermal, and wind, cutting GHG emissions, phasing out coal, and expanding storage, EV infrastructure, and in-state renewables under PUCN oversight and tax abatements.

Key Points

A state mandate requiring 50% of electricity from renewables by 2030, driving solar, geothermal, wind, and storage.

✅ 50% clean power by 2030; 100% carbon-free target by 2050

✅ Growth in solar, geothermal, wind; coal phase-out; natural gas remains

✅ RETA incentives spur 6.1 GW capacity, jobs, and in-state investment

Nevada is on track to meet its Renewable Portfolio Standard of 50% of electricity generated by renewable energy sources by 2030, according to the Governor's Office of Energy's annual Status of Energy Report.

Based on compliance reports the Public Utilities Commission of Nevada has received, across all providers, about 20% of power is currently generated by renewable resources, and, nationally, renewables ranked second in 2020 as filings show Nevada's investor-owned utility and other power providers have plans to reach the state's ambitious RPS of 50% by 2030, according to the report released Jan. 28.

"Because transportation and electricity generation are Nevada's two largest contributors to greenhouse gas emissions, GOE's program work in 2021 underscored our focus on transportation electrification and reaching the state's legislatively required renewable portfolio standard," GOE Director David Bobzien said in a statement Jan. 28. "While electricity generated from renewable resources currently accounts for about 25% of the state's electricity, a share similar to projections that renewables will soon provide about one-fourth of U.S. electricity overall, we continue to collaborate with the Public Utilities Commission of Nevada, electricity providers, the renewable energy industry and conservation organizations to ensure Nevada reaches our target of 50% clean energy by 2030."

The state's RPS, enacted in 1997 and last modified in 2019, requires an increase in renewable energy, starting with 22% in 2020 and increasing to 50% by 2030. The increase in renewables will reduce GHG emissions and help the state reach its goal of 100% carbon-free power by 2050, while states like Rhode Island have a 100% by 2030 plan, highlighting varying timelines.

Renewable additions
The state added 1.332 GW of renewable capacity in 2021 as part of the Renewable Energy Tax Abatement program, at a time when U.S. renewable energy hit a record 28% in April, for a total renewable capacity of 6.117 GW, according to the report.

The RETA program awards partial sales and use tax and partial property-tax abatements to eligible renewable energy facilities, which increase Nevada's tax revenue and create jobs in a growing industry. Eligible projects must employ at least 50% Nevada workers, pay 175% of Nevada's average wage during construction, and offer health care benefits to workers and their dependents.

Since its adoption in 2010, the GOE has approved 60 projects, including large-scale solar PV, solar thermal, biomass, geothermal and wind projects throughout the state, according to the report. Projects granted abatements in 2021 include:

• 100-MW Citadel Solar Project
• 150-MW Dry Lake Solar + Storage Project
• 714-MW Gemini Solar Project
• 55-MW North Valley Power Geothermal Project
• 113-MW Boulder Flats Solar Project
• 200-MW Arrow Canyon Solar Project

"Nevada does not produce fossil fuels of any significant amount, and gasoline, jet fuel and natural gas for electricity or direct use must be imported," according to the report. "Transitioning to domestically produced renewable resources and electrified transportation can provide cost savings to Nevada residents and businesses, as seen in Idaho's largely renewable mix today, while reducing GHG emissions. About 86% of the fuel for energy that Nevada consumes comes from outside the state."

Phasing out coal plants
Currently, more than two-thirds of the state's electricity is produced by natural gas-fired power plants, with renewables covering most of the remaining generation, according to the report. Nevada continues to phase out its remaining coal power plants, as renewables surpassed coal nationwide in 2022, which provide less than 10% of produced electricity.

"Nevada has seen a significant increase in capturing its abundant renewable energy resources such as solar and geothermal," according to the report. "Renewable energy production continues to grow, powering Nevada homes and business and serves to diversify the state's economy by exporting solar and geothermal to neighboring states, as California neared 100% renewable electricity for the first time. Nevada has more than tripled its renewable energy production since 2011."

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Offshore Wind Cost Competitiveness is rising as larger turbines boost megawatt output, cut LCOE, and trim maintenance and installation time, enabling projects in New England to rival natural gas pricing while scaling reliably.

Key Points

It describes how larger offshore turbines lower LCOE and O&M, making U.S. projects price competitive with natural gas.

✅ Larger turbines boost MW output and reduce LCOE.

✅ Lower O&M and faster installation cut lifecycle costs.

✅ Competes with gas in New England bids, per BNEF.

Massive offshore wind turbines keep getting bigger, as projects like the biggest UK offshore wind farm come online, and that’s helping make the power cheaper — to the point where developers say new projects in U.S. waters can compete with natural gas.

The price “is going to be a real eye-opener,” said Bryan Martin, chairman of Deepwater Wind LLC, which won an auction in May to build a 400-megawatt wind farm southeast of Rhode Island.

Deepwater built the only U.S. offshore wind farm, a 30-megawatt project that was completed south of Block Island in 2016. The company’s bid was selected by Rhode Island the same day that Massachusetts picked Vineyard Wind to build an 800-megawatt wind farm in the same area, while international investors such as Japanese utilities in UK projects signal growing confidence.

#google#

Bigger turbines that make more electricity have cut the cost per megawatt by about half, a trend aided by higher-than-expected wind potential in many markets, said Tom Harries, a wind analyst at Bloomberg New Energy Finance. That also reduces maintenance expenses and installation time. All of this is helping offshore wind vie with conventional power plants.

“You could not build a thermal gas plant in New England for the price of the wind bids in Massachusetts and Rhode Island,” Martin said Friday at the U.S. Offshore Wind Conference in Boston. “It’s very cost-effective for consumers.”

The Massachusetts project could be about $100 to $120 a megawatt hour, according to a February estimate from Harries, though recent UK price spikes during low wind highlight volatility. The actual prices there and in Rhode Island weren’t disclosed.

For comparison, a new U.S. combine-cycle gas turbine ranges from $40 to $60 a megawatt-hour, and a new coal plant is $67 to $113, according to BNEF data.

A new power plant in land-constrained New England would probably be higher than that, and during winter peaks the region has seen record oil-fired generation in New England that underscores reliability concerns. More importantly, gas plants get a significant portion of their revenue from being able to guarantee that power is always available, something wind farms can’t do, said William Nelson, a New York-based analyst with BNEF. Looking only at the price at which offshore turbines can deliver electricity is a “narrow mindset,” he said.

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CO2 Tax for UK Offshore Energy Efficiency can accelerate adoption of aero-derivative gas turbines, flare gas recovery, and combined cycle power, reducing emissions on platforms like Equinor's Mariner and supporting net zero goals.

Key Points

A carbon price pushing operators to adopt efficient turbines, flare recovery, and combined cycle to cut emissions.

✅ Aero-derivative turbines beat industrial units on efficiency

✅ Flare gas recovery cuts routine flaring and fuel waste

✅ Combined cycle raises efficiency and lowers emissions

By Tom Baxter

The recent Energy Voice article from the Equinor chairman concerning the Mariner project heralding a ‘significant point of reference’ for growth highlighted the energy efficiency achievements associated with the platform.

I view energy efficiency as a key enabler to net zero, and alongside this the UK must start large-scale storage to meet system needs; it is a topic I have been involved with for many years.

As part of my energy efficiency work, I investigated Norwegian practices and compared them with the UK.

There were many differences, here are three;

1. Power for offshore installations is usually supplied from gas turbines burning fuel from the oil and gas processing plant, and even as the UK's offshore wind supply accelerates, installations convert that to electricity or couple the gas turbine to a machine such as a gas compressor.

There are two main generic types of gas turbine – aero-derivative and industrial. As the name implies aero-derivatives are aviation engines used in a static environment. Aero-derivative turbines are designed to be energy efficient as that is very import for the aviation industry.

Not so with industrial type gas turbines; they are typically 5-10% less efficient than a comparable aero-derivative.

Industrial machines do have some advantages – they can be cheaper, require less frequent maintenance, they have a wide fuel composition tolerance and they can be procured within a shorter time frame.

My comparison showed that aero-derivative machines prevailed in Norway because of the energy efficiency advantages – not the case in the UK where there are many more offshore industrial gas turbines.

Tom Baxter is visiting professor of chemical engineering at Strathclyde University and a retired technical director at Genesis Oil and Gas Consultants

2. Offshore gas flaring is probably the most obvious source of inefficient use of energy with consequent greenhouse gas emissions.

On UK installations gas is always flared due to the design of the oil and gas processing plant.

Though not a large quantity of gas, a continuous flow of gas is routinely sent to flare from some of the process plant.

In addition the flare requires pilot flames to be maintained burning at all times and, while Europe explores electricity storage in gas pipes, a purge of hydrocarbon gas is introduced into the pipes to prevent unsafe air ingress that could lead to an explosive mixture.

On many Norwegian installations the flare system is designed differently. Flare gas recovery systems are deployed which results in no flaring during continuous operations.

Flare gas recovery systems improve energy efficiency but they are costly and add additional operational complexity.

3. Returning to gas turbines, all UK offshore gas turbines are open cycle – gas is burned to produce energy and the very hot exhaust gases are vented to the atmosphere. Around 60 -70% of the energy is lost in the exhaust gases.

Some UK fields use this hot gas as a heat source for some of the oil and gas treatment operations hence improving energy efficiency.

There is another option for gas turbines that will significantly improve energy efficiency – combined cycle, and in parallel plans for nuclear power under the green industrial revolution aim to decarbonise supply.

Here the exhaust gases from an open cycle machine are taken to a separate turbine. This additional turbine utilises exhaust heat to produce steam with the steam used to drive a second turbine to generate supplementary electricity. It is the system used in most UK power stations, even as UK low-carbon generation stalled in 2019 across the grid.

Open cycle gas turbines are around 30 – 40% efficient whereas combined cycle turbines are typically 50 – 60%. Clearly deploying a combined cycle will result in a huge greenhouse gas saving.

I have worked on the development of many UK oil and gas fields and combined cycle has rarely been considered.

The reason being is that, despite the clear energy saving, they are too costly and complex to justify deploying offshore.

However that is not the case in Norway where combined cycle is used on Oseberg, Snorre and Eldfisk.

What makes the improved Norwegian energy efficiency practices different from the UK – the answer is clear; the Norwegian CO2 tax.

A tax that makes CO2 a significant part of offshore operating costs.

The consequence being that deploying energy efficient technology is much easier to justify in Norway when compared to the UK.

Do we need a CO2 tax in the UK to meet net zero – I am convinced we do. I am in good company. BP, Shell, ExxonMobil and Total are supporting a carbon tax.

Not without justification there has been much criticism of Labour’s recent oil tax plans, alongside proposals for state-owned electricity generation that aim to reshape the power market.

To my mind Labour’s laudable aims to tackle the Climate Emergency would be much better served by supporting a CO2 tax that complements the UK's coal-free energy record by strengthening renewable investment.

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California Governor Gavin Newsom vetoed a bill aimed at expanding load flexibility in state grid planning, citing conflicts with California’s resource adequacy framework and concerns over grid reliability and energy planning uncertainty.

Why has Newsom vetoed the Bill to Codify Load Flexibility?

Governor Gavin Newsom’s veto blocks legislation that would have required the California Energy Commission to incorporate load flexibility into the state’s energy planning and policy framework, a move that has stirred debate across the clean energy sector.

✅ Argues the bill conflicts with California’s existing Resource Adequacy system

✅ Draws backlash from clean energy and grid modernization advocates

✅ Exposes ongoing tension over how to manage renewable integration and demand response

California Governor Gavin Newsom has vetoed Assembly Bill 44, which would have required the California Energy Commission to evaluate and incorporate load management mechanisms into the state’s energy planning process. The move drew criticism from clean energy advocates who say it undermines efforts to strengthen grid reliability and reduce costs.

The bill directed the commission to adopt “upfront technical requirements and load modification protocols” that would allow load-serving entities to adjust their electrical demand forecasts. Proponents viewed this as a way to modernize California’s grid management, and to explore a revamp of electricity rates to help clean the grid, making it more responsive to demand fluctuations and renewable energy variability.

In his veto statement, Newsom said the bill was incompatible with existing energy planning frameworks, even as a looming electricity shortage remains a concern. “While I support expanding electric load flexibility, this bill does not align with the California Public Utility Commission’s Resource Adequacy framework,” he said. “As a result, the requirements of this bill would not improve electric grid reliability planning and could create uncertainty around energy resource planning and procurement processes.”

Newsom’s decision comes shortly after he signed a broad package of energy legislation that set the stage for a regional Western electricity market and extended the state’s cap-and-trade program. However, that legislative package did not include continued funding for several key grid reliability programs — including what advocates have called the world’s largest virtual power plant, a distributed network of connected devices that can balance electricity demand in real time.

Clean energy supporters saw AB 44 as a crucial step toward integrating these distributed energy resources into long-term grid planning. “With Assembly Bill 44 being vetoed, the state has missed a huge opportunity to advance common-sense policy that would have lowered costs, strengthened the grid, and unlocked the full potential of advanced energy,” said Edson Perez, California lead at Advanced Energy United.

Perez added that the setback increases pressure on lawmakers to take stronger action in the next legislative session. “The pressure is on next session to ensure that California is using all tools in its policy toolbox to build critically needed infrastructure, strengthen the grid, and bring costs down,” he said.

California’s growing use of demand response programs and virtual power plants has been central to its strategy for managing grid stress during heat waves and wildfire seasons. These systems allow utilities and customers to temporarily reduce or shift energy use, helping to prevent blackouts and reduce the need for fossil-fuel peaker plants during peak demand.

A recent report by the Brattle Group found that California’s taxpayer-funded virtual power plant could save ratepayers $206 million between 2025 and 2028 while reducing reliance on gas generation. The study, commissioned by Sunrun and Tesla Energy, highlighted the potential for flexible load management to improve both grid reliability and reduce costs, even as regulators weigh whether the state needs more power plants to ensure reliability.

Despite these findings, Newsom’s veto signals continued tension between state policymakers and clean energy advocates over how best to modernize California’s power grid. While the governor has prioritized large-scale renewable development and regional market integration, critics argue that California’s climate policy choices risk exacerbating reliability challenges and that failing to codify load flexibility could slow progress toward a more adaptive, resilient, and affordable clean energy future.

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Labrador Island Link Reliability faces scrutiny as Nalcor Energy and General Electric address software issues; Liberty Consulting warns of Holyrood risks, winter outages, grid stability concerns, and PUB oversight for Newfoundland and Labrador.

Key Points

It is the expected dependability of the link this winter, currently uncertain due to GE software and Holyrood risks.

✅ GE software delays may hinder reliable in-service by mid-November.

✅ Holyrood performance issues increase winter outage risk.

✅ PUB directs Hydro to plan contingencies and improve assets.

An independent consultant is questioning if the brand new Labrador Island link can be counted on to supply power to Newfoundland this coming winter.

In June, Nalcor Energy confirmed it had successfully sent power from Churchill Falls to the Avalon Peninsula through its more than 1500-kilometre link, but now the Liberty Consulting Group says it doesn't expect the link will be up and running consistently this winter.

"What we have learned supports a conclusion that the Labrador Island Link is unlikely to be reliably in commercial operation at the start of the winter," says the report dated Aug. 30, 2018.

The link relies on software provided by General Electric but Liberty says there are lingering questions about GE's ability to ensure the necessary software will be in place this fall.

"At an August meeting, company representatives did not express confidence in GE's ability to meet an in-service date for the Labrador Island Link of mid-November," says the report.

Liberty also says testing the link for a brief period this spring and fall doesn't demonstrate long-term reliability.

"The link will remain prone to the uncertainties any new major facility faces early in its operating life, especially one involving technology new to the operating company," according to the report.

Holyrood trouble

The report goes on to say island residents should also be worried about the reliability of the troubled Holyrood facility — a facility that's important when demand for energy is high during winter months.

Liberty says "poor performance at the Holyrood thermal generating station increases the risk of outages considerably."

The group's report concludes the deteriorating condition of Holyrood is a major threat to the island's power supply and Liberty says that threat "could produce very severe consequences when the Labrador Island Link is unavailable."

The consultant says questions about the Labrador Island Link's readiness combined with concerns about the reliability of Holyrood may mean power outages, and for vulnerable customers, debates over hydro disconnections policies often intensify during winter.

"This all suggests that, for at least part of this winter, the island interconnected system may be at the mercy of the weather, where severe events can test utilities' storm response efforts further."

The consultant's report also includes five recommendations to the PUB, reflecting the kind of focused nuclear alert investigation follow-up seen elsewhere.

In essence, Liberty is calling for the board to direct Newfoundland and Labrador Hydro to make plans for the possibility that the link won't be available this winter. It's also calling on hydro to do more to improve the reliability of its other assets, such as Holyrood, as some operators have even contemplated locking down key staff to maintain operations during crises.

Response to Liberty's report

Nalcor CEO Stan Marshall defended the Crown corporation's winter preparedness in an email statement to CBC.

"The right level of planning and investment has been made for our existing equipment so we can continue to meet all of our customer electricity needs for this coming winter season," he wrote.

Regarding the Labrador Island Link, Marshall called for patience.

"This is new technology for our province and integrating the new transmission assets into our current electricity system is complex work that takes time," he said.

There is also a more detailed response from Newfoundland and Labrador Hydro which was sent to the province's Public Utiltiies Board.

Hydro says it will keep testing the Labrador Island Link and increasing the megawatts that are wheeled through it. It also says in October it will begin to give the PUB regular reports on the link's anticipated in-service date.

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