Louisiana sold on solar panels

Energy Pricing Factors span electricity generation, transmission, and distribution costs, plus natural gas supply-demand, renewables, seasonal peaks, and wholesale pricing effects across residential, commercial, and industrial customers, usage patterns, weather, and grid constraints.

Key Points

They are the costs and market forces driving electricity and natural gas prices, from generation to delivery and demand.

✅ Generation, transmission, distribution shape electricity rates

✅ Gas prices hinge on supply, storage, imports/exports

✅ Demand shifts: weather, economy, and fuel alternatives

There are a lot of factors that affect energy prices globally. What’s included in the price to heat homes and supply them with electricity may be a lot more than some people may think.

Electricity
Generating electricity is the largest component of its price, according to the U.S. Energy Information Administration (EIA). Generation accounts for 56% of the price of electricity, while distribution and transmission account for 31% and 13% respectively.

Homeowners and businesses pay more for electricity than industrial companies, and U.S. electricity prices have recently surged, highlighting broader inflationary pressures. This is because industrial companies can take electricity at higher voltages, reducing transmission costs for energy companies.

“Industrial consumers use more electricity and can receive it at higher voltages, so supplying electricity to these customers is more efficient and less expensive. The price of electricity to industrial customers is generally close to the wholesale price of electricity,” EIA explains.

NYSEG said based on the average use of 600 kilowatt-hours per month, its customers spent the most money on delivery and transition charges in 2020, 57% or about $42, and residential electricity bills increased 5% in 2022 after inflation, according to national data. They also spent on average 35% (~$26) on supply charges and 8% (~$6) on surcharges.

Electricity prices are usually higher in the summer. Why? Because energy companies use sources of electricity that cost more money. It used to be that renewable sources, like solar and wind, were the most expensive sources of energy but increased technological advances have changed this, according to the International Energy Agency’s 2021 World Energy Outlook.

“In most markets, solar PV or wind now represents the cheapest available source of new electricity generation. Clean energy technology is becoming a major new area for investment and employment – and a dynamic arena for international collaboration and competition,” the report said.

Natural gas
The price of natural gas is driven by supply and demand. If there is more supply, prices are generally lower. If there is not as much supply, prices are generally higher the EIA explains. On the other side of the equation, more demand can also increase the price and less demand can decrease the price.

High natural gas prices mean people turn their home thermostats down a few degrees to save money, so the EIA said reduced demand can encourage companies to produce more natural gas, which would in turn help lower the cost. Lower prices will sometimes cause companies to reduce their production, therefore causing the price to rise.

The three major supply factors that affect prices: the amount of natural gas produced, how much is stored, and the volume of gas imported and exported. The three major demand factors that affect price are: changes in winter/summer weather, economic growth, and the broader energy crisis dynamics, as well as how much other fuels are available and their price, said EIA.

To think the price of natural gas is higher when the economy is thriving may sound counterintuitive but that’s exactly what happens. The EIA said this is because of increases in demand.

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OPG Pickering Nuclear Refurbishment extends four CANDU reactors to bolster Ontario clean energy, grid reliability, and decarbonization goals, leveraging Darlington lessons, mature supply chains, and AtkinsRealis OEM expertise for cost effective life extension.

Key Points

Modernizing four Pickering CANDU units to extend life, add clean power, and enhance Ontario grid reliability.

✅ Extends four 515 MW CANDU reactors by 30 years

✅ Supports clean, reliable baseload and decarbonization

✅ Leverages Darlington playbook and AtkinsRealis OEM supply chain

In a pivotal shift last month, Ontario Power Generation (OPG) revised its strategy for the Pickering Nuclear Power Station, scrapping plans to decommission its six remaining reactors. Instead, OPG has opted to modernize four reactors (Pickering B Units 5-8) starting in 2027, while Units 1 and 4 are slated for closure by the end of the current year.

This revision ensures the continued operation of the four 515 MW Canada Deuterium Uranium (CANDU) reactors—originally constructed in the 1970s and 1980s—extending their service life by at least 30 more years amid an extension request deadline for Pickering.

Todd Smith, Ontario's Energy Minister, underscored the significance of nuclear power in maintaining Ontario's status as a region with one of the cleanest and most reliable electricity grids globally. He emphasized the integral role of nuclear facilities, particularly the Pickering station, in the provincial energy strategy during the announcement supporting continued operations, which was made in the presence of union workers at the plant.

The Pickering station has demonstrated remarkable efficiency and reliability, notably achieving its second-highest output in 2023 and setting a record in 2022 for continuous operation. Extending the lifespan of nuclear plants like Pickering is deemed the most cost-effective method for sustaining low-carbon electricity, according to research conducted by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) across 243 plants in 24 countries.

The refurbishment project is poised to significantly boost Ontario's economy, projected to add CAN$19.4 billion to the GDP over 11 years and generate approximately 11,000 jobs annually. The Independent Electricity System Operator (IESO) has indicated that to meet the province's future electrification and decarbonization goals, as it faces a growing electricity supply gap, Ontario will need to double its nuclear capacity by 2050, requiring an addition of 17.8 GW of nuclear power.

Subo Sinnathamby, OPG's Senior Vice President of Nuclear Refurbishment, emphasized the necessity of nuclear energy in reducing reliance on natural gas. Sinnathamby, who is leading the refurbishment efforts at OPG's Darlington nuclear power station, where SMR plans are also underway, highlighted the positive impact of the Darlington and Bruce Power projects on the nuclear power supply chain and workforce.

The procurement strategy employed for Darlington, which involved placing orders early to ensure readiness among suppliers, is set to be replicated for the Pickering refurbishment. This approach aims to facilitate a seamless transition of skilled workers and resources from Darlington to Pickering refurbishment, leveraging a matured supply chain and experienced vendors.

AtkinsRealis, the original equipment manufacturer (OEM) for CANDU reactors, has a track record of successfully refurbishing CANDU plants worldwide. The CANDU reactor design, known for its refurbishment capabilities, allows for individual replacement of pressure tubes and access to fuel channels without decommissioning the reactor. Gary Rose, Executive Vice-President of Nuclear at AtkinsRealis, highlighted the economic benefits and environmental benefits of refurbishing reactors, stating it as a viable and swift solution to maximize fossil-free energy.

Looking forward, AtkinsRealis is exploring the potential for multiple refurbishments of CANDU reactors, which could extend their operational life beyond 100 years, addressing local energy needs and economic factors in the decision-making process. This innovative approach underscores the role of nuclear refurbishment in meeting global energy demands sustainably and economically.

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Duration Portfolio Energy Storage aligns layered peak demand with right-sized batteries, enabling peak shaving, gas peaker replacement, and solar-plus-storage synergy while improving grid flexibility, reliability, and T&D deferral through two- to four-hour battery durations.

Key Points

An approach that layers battery durations to match peaks, cut costs, replace peakers, and boost grid reliability.

✅ Layers 2- to 4-hour batteries by peak duration

✅ Enables solar-plus-storage and peak shaving

✅ Cuts T&D upgrades, emissions, and fuel costs

The debate over energy storage replacing gas-fired peakers has raged for years, but a new approach that shifts the terms of the argument could lead to an acceleration of storage deployments.

Rather than looking at peak demand as a single mountainous peak, some analysts now advocate a layered approach that allows energy storage to better match peak needs and complement ongoing efforts to improve solar and wind power across the grid.

"You don’t have to have batteries that run to infinity."

Some developers of solar-plus-storage projects, bolstered by cheap batteries, say they can already compete head-to-head with gas-fired peakers. "I can beat a gas peaker anywhere in the country today with a solar-plus-storage power plant," Tom Buttgenbach, president and CEO of developer 8minutenergy Renewables, recently told S&P Global.

Customers are very busy these days and rebate programs need to fit the speed of their life. Participation should be quick, easy, and accessible anywhere.

Others disagree. Storage is not disruptive for generation, but will be disruptive for transmission and distribution, Kris Zadlo, executive vice president and chief development officer at Invenergy, told the audience at a Bloomberg New Energy Finance conference last spring. Invenergy, like many renewable power developers, develops generation, energy storage and transmission projects.

But there is another path that avoids the pitfalls of positions on either end of the all-or-none approach. "Do the analysis of the need itself," Ray Hohenstein, market applications director at Fluence, told Utility Dive. If the need is only two hours in duration, it may be best served by a two-hour battery. "You don’t have to have batteries that run to infinity."

Storage vs. fossil fuel peakers

Energy storage has several benefits over traditional fossil fuel peaking plants, Hohenstein said. It is instantaneous, it has no emissions and requires no fuel, and has limited infrastructure needs. It can also help the grid absorb higher levels of renewable generation by soaking up excess output, such as solar power at noon, and many planned storage additions will be paired with solar in the next few years. But the one thing energy storage cannot do, he said, is provide limitless energy.

So, instead of looking at replacing an individual peaker, Hohenstein advocated a "duration portfolio" approach that uses energy storage to shave peak load.

If the need is for 150 MW of resources that will never need to run for more than two hours at a time, then a battery is "quite cheap," significantly less than a four or eight-hour battery, said Hohenstein. "If you fill up your peak by duration layer, it could be more cost effective."

NREL research driver

Fluence’s approach is informed by research by Paul Denholm and Robert Margolis at the National Renewable Energy Laboratory (NREL), released last spring.

The NREL researchers looked at the California market where they said 11 GW of fossil fuel capacity is expected to be retired by 2029 because of new once-through-cooling requirements that are taking effect. A lot of that capacity is peaking capacity and, according to NREL’s analysis, a large fraction could be replaced with four-hour energy storage, assuming continued storage cost reductions and growth in solar installations.

The key in NREL’s research was the level of solar power penetration. There is a "synergistic" relationship between solar penetration and storage deployment, the researchers wrote, and other studies suggest wind and solar could meet 80% of U.S. demand as these trends continue.

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WA $600 Electricity Credit supports households with power bills as a budget stimulus, delivering an automatic rebate via Synergy and Horizon, funded by the Bell Group settlement to aid COVID-19 recovery and local spending.

Key Points

A one-off $600 power bill credit for all Synergy and Horizon residential accounts, funded by the Bell Group settlement.

✅ Automatic, not means-tested; applied to Synergy and Horizon accounts.

✅ Can offset upcoming bills or carry forward to future statements.

✅ Funded by Bell Group payout; aims to ease cost-of-living pressures.

Washington Premier Mark McGowan has announced more than a million households will receive a $600 electricity credit on their electricity account before their next bill.

The $650 million measure will form part of Thursday's pre-election state budget, similar to legislation to lower electricity rates in other jurisdictions, which has been delayed since May because of the pandemic and will help deflect criticism by the opposition that Labor hasn't done enough to stimulate WA's economy.

Mr McGowan made the announcement on Sunday while visiting a family in the electorate of Bicton.

"Here in WA, our state is in the best possible position as we continue our strong recovery from COVID-19, but times are still tough for many West Australians, and there is always more work to do," he said.

"[The credit] will mean WA families have a bit of extra money available in the lead up to Christmas.

"But I have a request, if this credit means you can spend some extra money, use it to support our local WA businesses."

The electricity bill credit will be automatically applied to every Synergy or Horizon residential account from Sunday, echoing moves such as reconnections for nonpayment by Hydro One in Canada.

It can be applied to future bills and will not be means tested.

"The $600 credit is fully funded through the recent Bell Group settlement, for the losses incurred in the Bell Group collapse in the early 1990s," Mr McGowan said.

"It made sense that these funds go straight back to Western Australians."

In September, the liquidator for the Bell Group and its finance arm distributed funds to its five major creditors, including $670 million to the WA government. The payment marked the close of the 30-year battle to recover taxpayer funds squandered during the WA Inc era of state politics.

The payout is the result of litigation stemming from the 1988 partnership between then Labor government and entrepreneur Alan Bond in acquiring major interests in Robert Holmes à Court’s failing Bell Group, following the 1987 stock market crash.

WA shadow minister for cost of living, Tony Krsticevic, said the $600 credit was returning money back into West Australian's pockets from "WA Labor's darkest days".

“This is taxpayers’ money out of a levy which was brought in to pay for Labor’s scandalous WA Inc losses of $450 million in the 1980s,” he said.

“This money should be returned to West Australians.

“WA families are in desperate need of it because they are struggling under cost of living increases of $850 every year since 2017 under WA Labor, amid concerns elsewhere that an electricity recovery rate could lead to higher hydro bills.

“But they need more than just a one-off payment. These $850 cost of living increases are an on-going burden.”

Prior to the onset of the coronavirus pandemic, the opposition believed it was gaining traction by attacking the government's increases to fees and charges in its first three budgets, and by urging an electricity market overhaul to favor consumers.

Last year, Labor increased household fees and charges by $127.77, which came on top of increases over the prior two budgets, as other jurisdictions faced hydro rate increases of around 3 per cent.

According the state's annual report on its finances released in September, the $2.6 billion budget surplus forecast in the at the end of 2019 had been reduced by $920 million to $1.7 billion despite the impact of the coronavirus.

But total public sector net debt was at $35.4 billion, down from the $36.1 billion revision at the end of 2019 in the mid-year review.

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PG&E Wind Shutdown and Renewable Reliability examines PSPS strategy, wildfire risk, transmission line exposure, wind turbine cut-out speeds, grid stability, and California's energy mix amid historic high-wind events and supply constraints across service areas.

Key Points

An overview of PG&E's PSPS decisions, wildfire mitigation, and how wind cut-out limits influence grid reliability.

✅ Wind turbines reach cut-out near 55 mph, reducing generation.

✅ PSPS mitigates ignition from damaged transmission infrastructure.

✅ Baseload diversity improves resilience during high-wind events.

According to the official, widely reported story, Pacific Gas & Electric (PG&E) initiated power shutoffs across substantial portions of its electric transmission system in northern California as a precautionary measure.

Citing high wind speeds they described as “historic,” the utility claims that if it didn’t turn off the grid, wind-caused damage to its infrastructure could start more wildfires.

Perhaps that’s true. Perhaps. This tale presumes that the folks who designed and maintain PG&E’s transmission system are unaware of or ignored the need to design it to withstand severe weather events, and that the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) allowed the utility to do so.

Ignorance and incompetence happens, to be sure, but there’s much about this story that doesn’t smell right—and it’s disappointing that most journalists and elected officials are apparently accepting it without question.

Take, for example, this statement from a Fox News story about the Kincade Fires: “A PG&E meteorologist said it’s ‘likely that many trees will fall, branches will break,’ which could damage utility infrastructure and start a fire.”

Did you ever notice how utilities cut wide swaths of trees away when transmission lines pass through forests? There’s a reason for that: When trees fall and branches break, the grid can still function, and even as the electric rhythms of New York City shifted during COVID-19, operators planned for variability.

So, if badly designed and poorly maintained infrastructure isn’t the reason PG&E cut power to millions of Californians, what might have prompted them to do so? Could it be that PG&E’s heavy reliance on renewable energy means they don’t have the power to send when a “historic” weather event occurs, especially as policymakers weigh the postponed closure of three power plants elsewhere in California?

Wind Speed Limits

The two most popular forms of renewable energy come with operating limitations, which is why some energy leaders urge us to keep electricity options open when planning the grid. With solar power, the constraint is obvious: the availability of sunlight. One doesn’t generate solar power at night and energy generation drops off with increasing degrees of cloud cover during the day.

The main operating constraint of wind power is, of course, wind speed, and even in markets undergoing 'transformative change' in wind generation, operators adhere to these technical limits. At the low end of the scale, you need about a 6 or 7 miles-per-hour wind to get a turbine moving. This is called the “cut-in speed.” To generate maximum power, about a 30 mph wind is typically required. But, if the wind speed is too high, the wind turbine will shut down. This is called the “cut-out speed,” and it’s about 55 miles per hour for most modern wind turbines.

It may seem odd that wind turbines have a cut-out speed, but there’s a very good reason for it. Each wind turbine rotor is connected to an electric generator housed in the turbine nacelle. The connection is made through a gearbox that is sized to turn the generator at the precise speed required to produce 60 Hertz AC power.

The blades of the wind turbine are airfoils, just like the wings of an airplane. Adjusting the pitch (angle) of the blades allows the rotor to maintain constant speed, which, in turn, allows the generator to maintain the constant speed it needs to safely deliver power to the grid. However, there’s a limit to blade pitch adjustment. When the wind is blowing so hard that pitch adjustment is no longer possible, the turbine shuts down. That’s the cut-out speed.

Now consider how California’s power generation profile has changed. According to Energy Information Administration data, the state generated 74.3 percent of its electricity from traditional sources—fossil fuels and nuclear, amid debates over whether to classify nuclear as renewable—in 2001. Hydroelectric, geothermal, and biomass-generated power accounted for most of the remaining 25.7 percent, with wind and solar providing only 1.98 percent of the total.

By 2018, the state’s renewable portfolio had jumped to 43.8 percent of total generation, with clean power increasing and wind and solar now accounting for 17.9 percent of total generation. That’s a lot of power to depend on from inherently unreliable sources. Thus, it wouldn’t be at all surprising to learn that PG&E didn’t stop delivering power out of fear of starting fires, but because it knew it wouldn’t have power to deliver once high winds shut down all those wind turbines

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Trump Offshore Wind Pledge signals a push for deregulation over renewable energy, challenging climate policy, green jobs, and coastal development while citing marine ecosystems, navigation, and energy independence amid state-federal permitting and legal hurdles.

Key Points

Trump's vow to cancel offshore wind projects favors deregulation and fossil fuels, impacting climate policy and jobs.

✅ Day-one plan to scrap offshore wind leases and permits

✅ Risks to renewable targets, grid mix, and coastal supply chains

✅ Likely court fights and state-federal regulatory conflicts

During his tenure as President of the United States, Donald Trump made numerous promises and policy proposals, many of which sparked controversy and debate. One such pledge was his vow to scrap offshore wind projects on "day one" of his presidency. This bold statement, while appealing to certain interests, raised concerns about its potential impact on U.S. offshore wind growth and environmental conservation efforts.

Trump's opposition to offshore wind projects stemmed from various factors, including his skepticism towards renewable energy, even as forecasts point to a $1 trillion offshore wind market in coming years, concerns about aesthetics and property values, and his focus on promoting traditional energy sources like coal and oil. Throughout his presidency, Trump prioritized deregulation and sought to roll back environmental policies introduced by previous administrations, arguing that they stifled economic growth and hindered American energy independence.

The prospect of scrapping offshore wind projects drew mixed reactions from different stakeholders. Supporters of Trump's proposal pointed to potential benefits such as preserving scenic coastal landscapes, protecting marine ecosystems, and addressing concerns about navigational safety and national security. Critics, however, raised valid concerns about the implications of such a decision on the renewable energy sector, including progress toward getting 1 GW on the grid nationwide, climate change mitigation efforts, and job creation in the burgeoning green economy.

Offshore wind energy has emerged as a promising source of clean, renewable power with the potential to reduce greenhouse gas emissions and diversify the energy mix. Countries like Denmark, the United Kingdom, and Germany have made significant investments in offshore wind in Europe, demonstrating its viability as a sustainable energy solution. In the United States, offshore wind projects have gained traction in states like Massachusetts, New York, and New Jersey, where coastal conditions are conducive to wind energy generation.

Trump's pledge to scrap offshore wind projects on "day one" of his presidency raised questions about the feasibility and legality of such a move. While the president has authority over certain aspects of energy policy and regulatory oversight, the development of offshore wind projects often involves multiple stakeholders, including state governments, local communities, private developers, and federal agencies, and actions such as Interior's move on Vineyard Wind illustrate federal leverage in permitting. Any attempt to halt or reverse ongoing projects would likely face legal challenges and regulatory hurdles, potentially delaying or derailing implementation.

Moreover, Trump's stance on offshore wind projects reflected broader debates about the future of energy policy, environmental protection, and economic development. While some argued for prioritizing fossil fuel extraction and traditional energy infrastructure, others advocated for a transition towards clean, renewable energy sources, drawing on lessons from the U.K. about wind deployment, to mitigate climate change and promote sustainable development. The Biden administration, which succeeded the Trump presidency, has signaled a shift towards a more climate-conscious agenda, including support for renewable energy initiatives and commitments to rejoin international agreements like the Paris Climate Accord.

In hindsight, Trump's pledge to scrap offshore wind projects on "day one" of his presidency underscores the complexities of energy policy and the importance of balancing competing interests and priorities. While concerns about aesthetics, property values, and environmental impact are valid, addressing the urgent challenge of climate change requires bold action and innovation in the energy sector. Offshore wind energy presents an opportunity, as seen in the country's biggest offshore wind farm approved in New York, to harness the power of nature in a way that is both environmentally responsible and economically beneficial. As the United States navigates its energy future, finding common ground and forging partnerships will be essential to ensure a sustainable and prosperous tomorrow.

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