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Black Hills Energy Corriedale Wind Farm Expansion earns regulatory approval in Wyoming, boosting capacity to over 52MW near Cheyenne with five turbines, supporting Renewable Ready customers and wind power goals under PUC and PSC oversight.

Key Points

An approved Wyoming wind project upgrade to over 52MW, adding five turbines to serve Renewable Ready customers.

✅ Adds 12.5MW via five new wind turbines near Cheyenne

✅ Cost increases to $79m; prior estimate $57m

✅ Approved by SD PUC after Wyoming PSC review

US company Black Hills Energy has received regulatory approval to increase the size of its Corriedale wind farm in Wyoming, where Wyoming wind exports to California are advancing, to over 52MW from 40MW previously.

The South Dakota Public Utilities Commission approved the additional 12.5MW capacity after the Wyoming Public Service Commission determined the boost was within commission rules, as federal initiatives like DOE wind energy awards continue to support the sector.

Black Hills Energy will install five additional turbines, raising the project cost to $79m from $57m, amid growing heartland wind investment across the region.
Corriedale will be built near Cheyenne and is expected to be placed in service in late 2020.

Similar market momentum is seen in Canada, where a Warren Buffett-linked Alberta wind farm is planned to expand capacity across the region.

Black Hills said that during the initial subscription period for its Renewable Ready program, applications of interest from eligible commercial, industrial and governmental agency customers were received in excess of the program's 40MW, underscoring the view that more energy sources can make stronger projects.

Black Hills Corporations chief executive and president Linden Evans said: “We are pleased with the opportunity to expand our Renewable Ready program, allowing us to meet our customers’ interest in renewable wind energy, which co-op members increasingly support.

“This innovative program expands our clean energy portfolio while meeting our customers’ evolving needs, particularly around cleaner and more sustainable energy, as projects like new energy generation coming online demonstrate.”

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NB Power Pulp and Paper Subsidies lower electricity rates for six New Brunswick mills using firm power benchmarks and interruptible discounts, while government mandates, utility debt, ratepayer impacts, and competitiveness pressures shape provincial energy policy.

Key Points

Provincial mandates that buy down firm electricity rates for six mills to a national average, despite NB Power's debt.

✅ Mandated buy-down to match national firm electricity rates

✅ Ignores large non-firm interruptible power discounts

✅ Raises equity concerns amid NB Power debt and rate pressure

An effort to fix NB Power's struggling finances that is supposed to involve a look at "all options" will not include a review of the policy that requires the utility to subsidize electricity prices for six New Brunswick pulp and paper mills, according to the Department of Natural Resources and Energy Development.

The program is meant "to enable New Brunswick's pulp and paper companies have access to competitive priced electricity,"  said the department's communications officer Nick Brown in an email Monday 

"Keeping our large industries competitive with other Canadian jurisdictions, amid Nova Scotia rate hike opposition debates elsewhere, is important," he wrote, knocking down the idea the subsidy program might be scrutinized for shortcomings like other NB Power expenses.

Figures released last week show NB Power paid out $9.7 million in rate subsidies to the mills under the program in the fiscal year ended in March 2021, even though the utility was losing $4 million for the year and falling deeper into debt, amid separate concerns about old meter issues affecting households.

Subsidies went to three mills owned by J.D. Irving Ltd. including two in Saint John and one in Lake Utopia, two owned by the AV group in Nackawic and Atholville and the Twin Rivers pulp mill in Edmundston.

The New Brunswick government has made NB Power subsidize pulp and paper mills like Twin Rivers Paper Company since 2012, and is requiring the program to continue despite financial problems at the utility. (CBC)
It was NB Power's second year in a row of financial losses, while it is supposed to pay down $500 million of its $4.9 billion debt load in the next five years to prepare for the refurbishment of the Mactaquac dam, a burden comparable to customers in Newfoundland paying for Muskrat Falls elsewhere under separate policies, under a directive issued by the province

NB Power president Keith Cronkhite said he was "very disappointed" with debt increasing last year instead of  falling and senior vice president and chief financial officer Darren Murphy said everything would be under the microscope this year to turn the utility's finances around.  

"We need to do better," said Murphy on Thursday

"We need to step back and make sure we're considering all options, including approaches like Newfoundland's ratepayer shield agreement on megaproject overruns, to achieve that objective because the objective is quickly closing in on us."

However, reviewing the subsidy program for the six pulp and paper mills is apparently off limits.

The subsidy program requires NB Power to buy down the cost of "firm" electricity bought by pulp and paper mills to a national average that is calculated by the Department of Natural Resources and Energy Development.

Last year the province declared the price mills in New Brunswick pay to be an average of  7.536 cents per kilowatt hour (kwh).  It is higher than rates in five other provinces that have mills, which the province points to as justification for the subsidies, even as Nova Scotia's 14% rate hike approval highlights broader upward pressure, although the true significance of that difference is not entirely clear.

In British Columbia, the large forest products company Paper Excellence operates five pulp and paper mills which are charged 17.2 per cent less for firm electricity than the six mills in New Brunswick.

The Paper Excellence Paper Mill in Port Alberni, B.C. pays lower electricity prices than mills in New Brunswick, a benefit largely offset by higher property taxes. It's a factor New Brunswick does not count in calculating subsidies NB Power must pay. (Paper Excellence)
However, local property taxes on the five BC mills are a combined $7.8 million higher than the six New Brunswick plants, negating much of that difference.

The province's subsidy formula does not account for differences like that or for the fact New Brunswick mills buy a high percentage of their electricity at cheap non-firm prices.

Not counting the subsidies, NB Power already sells high volumes of what it calls interruptible and surplus power to industry at deep discounts on the understanding it can be cut off and redeployed elsewhere on short notice when needed.

Actual interruptions in service are rare.  Last year there were none, but NB Power sold 837 million kilowatt hours of the discounted power to industry at an average price of 4.9 cents per kwh.   

NB Power does not disclose how much of the $22 million or more in savings went to the six mills, but the price was 35 per cent below NB Power's posted rate for the plants and rivaled firm prices big mills receive anywhere in Canada, including Quebec.

Asked why the subsidy program ignores large amounts of discounted interruptible power used by New Brunswick mills in making comparisons between provinces, Brown said regulations governing the program require a comparison of firm prices only.

"The New Brunswick average rate is based on NB Power's published large industrial rate for firm energy, as required by the Electricity from Renewable Resources regulation," he wrote.

The subsidy program itself was imposed on NB Power by the province in 2012 to aid companies suffering after years of poor markets for forest products following the 2008 financial collapse and recession.  

Providing subsidies has cost NB Power $100 million so far and has continued even as markets for pulp products improved significantly and NB Power's own finances worsened.

Report warned against subsidies
NB Power has never directly criticized the program, but in a matter currently in front the of the New Brunswick Energy and Utilities Board looking at how NB Power might restructure its rates, including proposals such as seasonal rates that could prompt backlash, an independent consultant hired by the utility suggested rate subsidies to large export oriented manufacturing facilities, like pulp and paper mills, is generally a poor idea.

"We do not recommend offering subsidies to exporters," says the report by Christensen Associates Energy Consulting of Madison, Wis.

"There are two serious economic problems with subsidizing exports. The first is that the benefits may be less than the costs. The second problem is that subsidies tend to last forever, even if the circumstances that initially justified the subsidies have disappeared."

The Christensen report did not directly assess the merits of the current subsidy for pulp and paper mills but it addressed the issue because it said in the design of new rates "one NB Power business customer has raised the possibility that their electricity-intensive business ought to be granted subsidies because of the potential to generate extra benefits for the Province through increases in their exports"

That, said Christensen, rarely benefits the public.

"The direct costs of the subsidies are the subsidies themselves, a part of which ends up in the pockets of out-of-province consumers of the exported goods," said the report.  

"But there are also indirect costs due to the fact that the subsidies are financed through higher electricity prices, which means that other electricity customers have less money to spend on services provided by local businesses, thus putting a drag on the local economy."

The province does not agree.

Asked whether it has any studies or cost-benefit reviews that show the subsidy program is a net benefit to New Brunswick, the department cited none but maintained it is an important initiative, even as elsewhere governments have offered electricity bill credit relief to ratepayers.

"The program was designed to give large industrial businesses the ability to compete on a level energy field," wrote Brown.
 

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Ontario Electricity Rates update: OEB sets time-of-use and tiered pricing for residential customers, with kWh charges for peak, mid-peak, and off-peak periods reflecting COVID-19 impacts on demand, supply costs, and pricing.

Key Points

Ontario Electricity Rates are OEB-set time-of-use and tiered prices that set per-kWh costs for residential customers.

✅ Time-of-use: 21.7 peak, 15.0 mid-peak, 10.5 off-peak cents/kWh

✅ Tiered: 12.6 cents/kWh up to 1000 kWh, then 14.6 cents/kWh

✅ Average 700 kWh home pays about $2.24 more per month

Energy bills for the typical Ontario home are going up by about two per cent with fixed pricing coming to an end on Nov. 1, the Ontario Energy Board says. 

The province's electricity regulator has released new time-of-use pricing and says the rate for the average residential customer using 700 kWh per month will increase by about $2.24.

The change comes as Ontario stretches into its eight month of the COVID-19 pandemic with new case counts reaching levels higher than ever seen before.

Time-of-use pricing had been scrapped for residential bills for much for the pandemic with a single fixed COVID-19 hydro rate set for all hours of the day. The move, which came into effect June 1, was meant "to support families, small business and farms while Ontario plans for the safe and gradual reopening of the province," the OEB said at the time.

Ontario later set the off-peak price until February 7 around the clock to provide additional relief.

Fixed pricing meant customers' bills reflected how much power they used, rather than when they used it. Customers were charged 12.8 cents/kWh under the COVID-19 recovery rate no matter their time of use.

Beginning November, the province says customers can choose between time-of-use and tiered pricing options. Rates for time-of-use plans will be 21.7 cents/kWh during peak hours, 15 cents/kWh for mid-peak use and 10.5 cents/kWh for off-peak use. 

Customers choosing tiered pricing will pay 12.6 cents/kWh for the first 1000 kWh each month and then 14.6 cents/kWh for any power used beyond that.

The energy board says the increase in pricing reflects "a combination of factors, including those associated with the COVID-19 pandemic, that have affected demand, supply costs and prices in the summer and fall of 2020."

Asked for his reaction to the move Tuesday, Premier Doug Ford said, "I hate it," adding the province inherited an energy "mess" from the previous Liberal government and are "chipping away at it."

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B.C. Hydro Salary Continuance Payout spotlights executive compensation, severance, and governance at a Crown corporation after a firing, citing financial disclosure reports, Site C dam ties, and a leadership change under a new government.

Key Points

Severance-style pay for B.C. Hydro's fired CEO, via salary continuance and disclosed in public filings.

✅ $541,615 total compensation without working days

✅ Salary continuance after NDP firing; financial disclosures

✅ Later named Canada Post interim CEO amid strike

Former B.C. Hydro president and chief executive officer Jessica McDonald received a total of $541,615 in compensation during the 2017-2018 fiscal year, a figure that sits amid wider debates over executive pay at utilities such as Hydro One CEO pay at the provincial utility, without having worked a single day for the Crown corporation.

She earned this money under a compensation package after the in-coming New Democratic government of John Horgan fired her, a move comparable to Ontario's decision when the Hydro One CEO and board exit amid share declines. The previous B.C. Liberal government named her president and CEO of B.C. Hydro in 2014, and McDonald was a strong supporter of the controversial Site C dam project now going ahead following a review.

The current New Democratic government placed her on what financial disclosure documents call “salary continuance” effective July 21, 2017 — the day the government announced her departure — at a utility scrutinized in a misled regulator report that raised oversight concerns.

According to financial disclosure statements, McDonald remained on “salary continuance” until Sept. 21 of this year, and the utility has also been assessed in a deferred operating costs report released by the auditor general. During this period, she earned $272,659, a figure that includes benefits, pension and other compensation.

McDonald — who used to be the deputy minister to former premier Gordon Campbell — is now working for Canada Post, which appointed her as interim president and chief executive officer in March, while developments at Manitoba Hydro highlight broader political pressures on Crown utilities.

She started in her new role on April 2, 2018, and now finds herself in the middle of managing a postal carrier strike.

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U.S. Natural Gas Power Demand is surging for electricity generation amid summer heat, with ERCOT, Texas grid reserves tight, EIA reporting coal and nuclear retirements, renewables intermittency, and pipeline expansions supporting combined-cycle capacity and prices.

Key Points

It is rising use of natural gas for power, driven by summer heat, plant retirements, and new combined-cycle capacity.

✅ ERCOT reserve margin 9%, below 14% target in Texas

✅ Gas share of U.S. power near 40-43% this summer

✅ Coal and nuclear retirements shift capacity to combined cycle

As the hot months linger, it will be natural gas that is leaned on most to supply the electricity that we need to run our air conditioning loads on the grid and keep us cool.

And this is surely a great and important thing: "Heat causes most weather-related deaths, National Weather Service says."

Generally, U.S. gas demand for power in summer is 35-40% higher than what it was five years ago, with so much more coming (see Figure).

The good news is regions across the country are expected to have plenty of reserves to keep up with power demand.

The only exception is ERCOT, covering 90% of the electric load in Texas, where a 9% reserve margin is expected, below the desired 14%.

Last summer, however, ERCOT’s reserve margin also was below the desired level, yet the grid operator maintained system reliability with no load curtailments.

Simply put, other states are very lucky that Texas has been able to maintain gas at 50% of its generation, despite being more than justified to drastically increase that.

At about 1,600 Bcf per year, the flatness of gas for power demand in Texas since 2000 has been truly remarkable, especially since Lone Star State production is up 50% since then.

Increasingly, other U.S. states (and even countries) are wanting to import huge amounts of gas from Texas, a state that yields over 25% of all U.S. output.

Yet if Texas justifiably ever wants to utilize more of its own gas, others would be significantly impacted.

At ~480 TWh per year, if Texas was a country, it would be 9th globally for power use, even ahead of Brazil, a fast growing economy with 212 million people, and France, a developed economy with 68 million people.

In the near-term, this explains why a sweltering prolonged heat wave in July in Texas, with a hot Houston summer setting new electricity records, is the critical factor that could push up still very low gas prices.

But for California, our second highest gas using state, above-average snowpack should provide a stronger hydropower for this summer season relative to 2018.

Combined, Texas and California consume about 25% of U.S. gas, with Texas' use double that of California.

Across the U.S., gas could supply a record 40-43% of U.S. electricity this summer even as the EIA expects solar and wind to be larger sources of generation across the mix

Our gas used for power has increased 35-40% over the past five years, and January power generation also jumped on the year, highlighting broad momentum.

Our gas used for power has increased 35-40% over the past five years. DATA SOURCE: EIA; JTC

Indeed, U.S. natural gas for electricity has continued to soar, even as overall electricity consumption has trended lower in some years, at nearly 10,700 Bcf last year, a 16% rise from 2017 and easily the highest ever.

Gas is expected to supply 37% of U.S. power this year, even as coal-fired generation saw a brief uptick in 2021 in EIA data, versus 27% just five years ago (see Figure).

Capacity wise, gas is sure to continue to surge its share 45% share of the U.S. power system.

"More than 60% of electric generating capacity installed in 2018 was fueled by natural gas."

We know that natural gas will continue to be the go-to power source: coal and nuclear plants are retiring, and while growing, wind and solar are too intermittent, geography limited, and transmission short to compensate like natural gas can.

"U.S. coal power capacity has fallen by a third since 2010," and last year "16 gigawatts (16,000 MW) of U.S. coal-fired power plants retired."

This year, some 2,000 MW of coal was retired in February alone, with 7,420 MW expected to be closed in 2019.

Ditto for nuclear.

Nuclear retirements this year include Pilgrim, Massachusetts’s only nuclear plant, and Three Mile Island in Pennsylvania.

This will take a combined ~1,600 MW of nuclear capacity offline.

Another 2,500 MW and 4,300 MW of nuclear are expected to be leaving the U.S. power system in 2020 and 2021, respectively.

As more nuclear plants close, EIA projects that net electricity generation from U.S. nuclear power reactors will fall by 17% by 2025.

From 2019-2025 alone, EIA expects U.S. coal capacity to plummet nearly 25% to 176,000 MW, with nuclear falling 15% to 83,000 MW.

In contrast, new combined cycle gas plants will grow capacity almost 30% to around 310,000 MW.

Lower and lower projected commodity prices for gas encourage this immense gas build-out, not to mention non-stop increases in efficiency for gas-based units.

Remember that these are official U.S. Department of Energy estimates, not coming from the industry itself.

In other words, our Department of Energy concludes that gas is the future.

Our hotter and hotter summers are therefore more and more becoming: "summers for natural gas"

Ultimately, this shows why the anti-pipeline movement is so dangerous.

"Affordable Energy Coalition Highlights Ripple Effect of Natural Gas Moratorium."

In April, President Trump signed two executive orders to promote energy infrastructure by directing federal agencies to remove bottlenecks for gas transport into the Northeast in particular, where New England oil-fired generation has spiked, and to streamline federal reviews of border-crossing pipelines and other infrastructure.

Builders, however, are not relying on outside help: all they know is that more U.S. gas demand is a constant, so more infrastructure is mandatory.

They are moving forward diligently: for example, there are now some 27 pipelines worth $33 billion already in the works in Appalachia.

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California Rooftop Solar Cost Shift examines PG&E rate hikes, net metering changes, and utility infrastructure spending impacts on low-income households, distributed generation, and clean energy adoption, potentially raising bills and undermining grid resilience.

Key Points

A claim that rooftop solar shifts fixed grid costs to others; critics cite PG&E rates, avoided costs, and impacts.

✅ PG&E rates outpace national average, underscoring cost drivers.

✅ Net metering cuts risk burdening low- and middle-income homes.

✅ Distributed generation avoids infrastructure spend and grid strain.

California is grappling with soaring electricity prices across the state, with Pacific Gas & Electric (PG&E) rates more than double the national average and increasing at an average of 12.5% annually over the past six years. In response, Governor Gavin Newsom issued an executive order directing state energy agencies to identify ways to reduce power costs. However, recent policy shifts targeting rooftop solar users may exacerbate the problem rather than alleviate it.

The "Cost Shift" Theory

A central justification for these pricing changes is the "cost shift" theory. This theory posits that homeowners with rooftop solar panels reduce their electricity consumption from the grid, thereby shifting the fixed costs of maintaining and operating the electrical grid onto non-solar customers. Proponents argue that this leads to higher rates for those without solar installations.

However, this theory is based on a flawed assumption: that PG&E owns 100% of the electricity generated by its customers and is entitled to full profits even for energy it does not deliver. In reality, rooftop solar users supply only about half of their energy needs and still pay for the rest. Moreover, their investments in solar infrastructure reduce grid strain and save ratepayers billions by avoiding costly infrastructure projects and reducing energy demand growth, aligning with efforts to revamp electricity rates to clean the grid as well.

Impact on Low- and Middle-Income Households

The majority of rooftop solar users are low- and middle-income households. These individuals often invest in solar panels to lower their energy bills and reduce their carbon footprint. Policy changes that undermine the financial viability of rooftop solar disproportionately affect these communities, and efforts to overturn income-based charges add uncertainty about affordability and access.

For instance, Assembly Bill 942 proposes to retroactively alter contracts for millions of solar consumers, cutting the compensation they receive from providing energy to the grid, raising questions about major changes to your electric bill that could follow if their home is sold or transferred. This would force those with solar leases—predominantly lower-income individuals—to buy out their contracts when selling their homes, potentially incurring significant financial burdens.

The Real Drivers of Rising Energy Costs

While rooftop solar users are being blamed for rising electricity rates, calls for action have mounted as the true culprits lie elsewhere. Unchecked utility infrastructure spending has been a significant factor in escalating costs. For example, PG&E's rates have increased rapidly, yet the utility's spending on infrastructure projects has often been criticized for inefficiency and lack of accountability. Instead of targeting solar users, policymakers should scrutinize utility profit motives and infrastructure investments to identify areas where costs can be reduced without sacrificing service quality.

California's approach to addressing rising electricity costs by targeting rooftop solar users is misguided. The "cost shift" theory is based on flawed assumptions and overlooks the substantial benefits that rooftop solar provides to the grid and ratepayers. To achieve a sustainable and equitable energy future, the state must focus on controlling utility spending, promoting clean energy access for all, especially as it exports its energy policies across the West, and ensuring that policies support—not undermine—the adoption of renewable energy technologies.

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