Is this the twilight of the coal era?

Tucson Electric Power Coal Phaseout advances an Integrated Resource Plan to exit Springerville coal by 2032, lift renewables past 70 percent by 2035, add wind, solar, battery storage, and cut carbon emissions 80 percent.

Key Points

A 2032 coal exit and 2035 plan to lift renewables above 70 percent, add wind, solar, storage, and cut CO2 80 percent.

✅ Coal purchases end at Springerville units by 2032

✅ Renewables exceed 70 percent of load by 2035

✅ 80 percent CO2 cut from 2005 baseline via wind, solar, storage

In a dramatic policy shift, Tucson Electric Power says it will stop using coal to generate electricity by 2032 and will increase renewable energy's share of its energy load to more than 70% by 2035.

As part of that change, the utility will stop buying electricity from its two units at its coal-fired Springerville Generating Station by 2032. The plant, TEP's biggest power source, provides about 35% of its energy.

The utility already had planned to start up two New Mexico wind farms and a solar storage plant in the Tucson area by next year. The new plan calls for adding an additional 2,000 megawatts of renewable energy capacity by 2035.

The utility's switch from fossil fuels is spelled out in the plan, submitted to the Arizona Corporation Commission, amid shifts in federal power plant rules that could affect implementation. Called an Integrated Resource Plan, it would reduce TEP's carbon dioxide emissions 80% by 2035 compared with 2005 levels.

The plan drew generally positive reviews from a number of environmentalists and other representatives of an advisory committee that had worked with TEP for a year.

Two commissioners, Chairman Bob Burns and Tucsonan Lea Marquez Peterson, also generally praised the plan, although they held off on final judgment.

University of Arizona researchers said the plan would likely meet the utility's share of the worldwide goal of holding down global temperatures to less than 2 degrees Celsius, or about 3.6 degrees Fahrenheit, above pre-industrial levels, even as studies find that climate change threatens grid reliability in many regions.

But a representative of AARP and the Pima Council on Aging expressed concern because the plan would require 1% annual electric rate increases a year to put into effect.

Officials in the eastern Arizona town of Springerville aren't happy.

And Sierra Club official Sandy Bahr said the plan doesn't move fast enough to get TEP off coal. She listed 14 separate units of various Western coal-fired plants that are scheduled to shut down sooner than 2032, many in the 2020s.

But TEP says the plan best balances costs and environmental benefits compared with 24 others it reviewed.

"We know our customers want safe, reliable energy from resources that are both affordable and environmentally responsible. TEP's 2020 Integrated Resource Plan will help us maintain that delicate balance," TEP CEO David Hutchens wrote in the forward to the plan.

The plan isn't legally binding but is aimed at sending a signal to regulators and the public about TEP's future direction. TEP and other regulated Arizona utilities update such plans every three years.

TEP has been one of the West's more fossil-fuel-friendly utilities. It stuck with coal even as many other utilities were moving away from it, including Alliant Energy's carbon-neutral plan to cut emissions and costs, and as the Sierra Club called on utilities to move beyond what it termed a highly polluting energy source that emits large quantities of heat-trapping greenhouse gases linked by scientists to global warming.

Last year, TEP got 13% of its electricity from renewables such as wind farms and solar plants along with photovoltaic solar panels atop individual homes. Fossil fuels coal and natural gas supplied the rest, a University of Arizona study paid for by TEP found.

Economics, not just emissions, a big factor

TEP's previous resource plan, from 2017, called for boosting renewable use to 30% by 2030 and to cut coal to 38% of its electric load by then from 69% in 2017, reflecting broader 2017 utility trends across the industry.

A TEP official said last week the utility is heading in a different direction not only due to concerns about greenhouse gas emissions but because of changing economics.

"For the last several decades, coal was the most economical resource. It was the lowest-cost resource to supply energy for our customers, and it wasn't really close," said Jeff Yockey, TEP's resource planning director.

But over the past few years, first natural gas prices and more recently solar and wind energy prices have fallen dramatically, he said.

Their prices are projected to keep falling, along with the cost of battery-fueled storage of solar energy for use when the sun is down, he said.

"Coal just isn't the most economical resource" now, Yockey said.

Yet the utility still needs, for now, the extra energy capacity that coal provides, he said, even as other states outline ways to improve grid reliability through targeted investments.

"Being a utility with no nuclear or hydro(electric) energy, with coal, there is reliability, a fuel on the ground, 30 or 90 days supply," he said. "It's the only source not subject to disruption in the next hour. It's our only long-term, stable fuel supply. Over time, we will be able to overcome that."

UA researchers, community panel worked on plan

TEP paid the UA $100,000 to have three researchers prepare two reports, one comparing 24 different proposals and a second comparing TEP's fossil fuel/renewable split with those of other utilities.

Also, the utility appointed an advisory council representing environmental, business and government interests that met regularly to guide TEP in producing the plan. The utility chose a preferred energy "portfolio," Yockey said.

The goal "was very much about basically achieving significant emissions reductions as quickly as we can and as cost effectively as we can," he said. TEP wanted the biggest cumulative emission cut possible over 15 years.

"If it was just about cost, we wouldn't have selected the portfolio that we selected. It wasn't the lowest cost portfolio."

UA assistant research professors Ben McMahan and Will Holmgren said combined carbon dioxide emission reductions from TEP's new plan over 15 years would be expected to hit the Paris accord's 2-degree target.

"There is considerable uncertainty about what will happen between now and 2050, but the preferred portfolio's early start on reductions and lowest cumulative emissions is certainly a positive sign that well below 2C is achievable," the researchers said in an email.

Environmentalists pleased, but some want coal cut sooner

The Sierra Club, Western Resource Advocates, the Southwest Energy Efficiency Project and Pima County offered varying degrees of praise for the new TEP plan.

In a memo Friday, County Administrator Chuck Huckelberry congratulated TEP for "the comprehensive, inclusive and transparent process" used to develop the plan.

Because of UA's involvement, TEP's advisory council and the public "can feel confident that the utility is on track to make significant progress in curbing greenhouse gas emissions to combat climate change," Huckelberry wrote.

The TEP plan "is the most aggressive commitment to reducing emissions by a utility in Arizona," said Autumn Johnson of Western Resource Advocates in a news release.

"Adding clean energy generation and storage while accelerating the retirement of coal units will ensure a healthier and better future for Arizonans," said Johnson, an energy policy analyst in Phoenix.

The Sierra Club will have a technical expert review the plan and already wants more energy savings, said Bahr, director of the group's Grand Canyon chapter. But overall, this plan is a step in the right direction for TEP, she said.

By comparison, Arizona Public Service's new resource plan only calls for 45% renewable energy by 2030, Bahr noted, while California regulators consider more power plants to ensure reliability. APS committed to going coal-free by 2031.

A Sierra Club proposal that the UA reviewed called for TEP to quit coal by 2027.

But TEP analyzed that proposal and concluded it would require $300 million in investments and would reduce the utility's cumulative emissions by only 2.4 million tons, to 70.2 million tons by 2035, Yockey said.

The Sierra Club plan was the most expensive portfolio investigated, Yockey said.

"The difference is in the timing. We still have a fair amount of value in our coal plants which we need to depreciate, which we do over time," Yockey said. "Trying to replace the capacity that coal provides in the near term with storage and solar is very expensive, although those costs are declining."

Seniors on fixed incomes could be hurt, advocate says

Rene Pina, an advisory council member representing two senior citizen organizations, praised the plan's goals but was concerned about impacts of even 1% annual rate increases on elderly people on fixed incomes.

They can't always handle such an increase, he said.

One possible fix is that TEP could ease eligibility requirements for its low-income energy assistance program, aligning with equity-focused electricity regulation principles, to allow more seniors to benefit, said Pina, representing AARP and the Pima Council on Aging.

"The program is structured so it just barely disqualifies most of our seniors. Their social security pension is just barely over the low-income limit. It can easily be adjusted without any problems to the utility," Pina said.

Advisory council member Rob Lamb, an engineer with GHLN, an architecture-engineering firm, said he was very pleased with TEP's plan.

"One of the things a lot of people don't realize when they put together a plan like that, is they have to balance environment with 'Hey, what's the reliability of service? Are we going to be able to keep our rates for something that will work?'" Lamb said.

"This a very balanced and resilient portfolio."

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Alberta Electricity Rate Cap stays despite carbon tax repeal, keeping the Regulated Rate Option at 6.8 cents/kWh. Levy funds cover market gaps as the UCP reviews NDP policies to maintain affordable utility bills.

Key Points

Program capping RRO power at 6.8 cents/kWh, using levy funds to offset market prices while the UCP reviews policy.

✅ RRO cap fixed at 6.8 cents/kWh for eligible customers

✅ Levy funds pay generators when market prices exceed the cap

✅ UCP reviewing NDP policies to ensure affordable rates

Alberta's carbon tax has been cancelled, but a consumer price cap on electricity — which the levy pays for — is staying in place for now.

June electricity rates are due out on Monday, about four days after the new UCP government did away with the carbon charge on natural gas and vehicle fuel.

Part of the levy's revenue was earmarked by the previous NDP government to keep power prices at or below 6.8 cents per kilowatt hour under new electricity rules set by the province.

"The Regulated Rate Option cap of 6.8 cents/kWh was implemented by the previous government and currently remains in effect. We are reviewing all policies put in place by the former government and will make decisions that ensure more affordable electricity rates for job-creators and Albertans," said a spokesperson for Alberta's energy ministry in an emailed statement.

Albertans with regulated rate contracts and all City of Medicine Hat utility customers only pay that amount or less, though some Alberta ratepayers have faced deferral-related arrears.

If the actual market price rises above that, the difference is paid to generators directly from levy funds, a buffer that matters as experts warn prices are set to soar later this year.

The government has paid more than $55 million to utilities over the past year ending in March 2019, due to that electricity price cap being in place.

Alberta Energy says the price gap program will continue, at least for the time being, amid electricity policy changes being considered.

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Texas PUC Electricity Market Reforms aim to boost grid reliability, support ERCOT resilience, pay standby generators, require capacity procurement, and mitigate blackout risk, though analysts warn higher consumer bills and winter reserve margin deficits.

Key Points

PUC proposals to bolster ERCOT reliability via standby capacity, capacity procurement, and measures to reduce blackout risk.

✅ Pays generators for standby capacity during grid stress

✅ Requires capacity procurement to meet forecast demand

✅ Could raise consumer bills despite reliability gains

The Public Utility Commission of Texas is discussing major reforms to the state’s electricity market with the purpose to avoid a repeat of the power failures and blackouts during the February 2021 winter storm, which led to the death of more than 100 people and left over 11 million residents without electricity for days.

The regulator is discussing at a meeting on Thursday around a dozen proposals to make the grid more stable and reliable in case of emergencies. Proposals include paying power generators that are on standby when the grid needs backup, and requiring companies to pre-emptively buy capacity to meet future demand.

It is not clear yet how many and which of the proposals for electricity market reforms PUC will endorse today, while Texans vote on funding to modernize electricity generation later this year.

Analysts and consumer protection bodies warn that the measures will raise the energy bills for consumers, as some electricity market bailout ideas shift costs to ratepayers as well.

“Customers will be paying for more, but will they be getting more reliability?” Michael Jewell, an attorney with Jewell & Associates PLLC who represents clients at PUC proceedings, told Bloomberg.

“This is going to take us further down a path that’s going to increase cost to consumers, we better be darn sure these are the right choices,” Tim Morstad, Associate State Director, AARP Texas, told FOX 4 NEWS.

Last month, a report by the North American Electric Reliability Corp warned that the Texas power grid remained vulnerable to blackouts in case of a repeat of this year’s February Freeze.

Beyond Texas, electricity blackout risks have been identified across the U.S., underscoring the stakes for grid planning.

According to the 2021-2022 Winter Reliability Assessment report, Texas risks a 37-percent reserve margin deficit in case of a harsh winter, with ERCOT moving to procure capacity to address winter concerns, NERC said.

A reserve margin is the reserve of power generation capacity comparative to demand. The expected reserve margin for Texas for this winter, according to NERC, is 41.9 percent. Yet if another cold spell hits the state, it would affect this spare capacity, pushing the margin deeply into negative territory.

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California Battery Storage is transforming grid reliability as distributed energy, solar-plus-storage, and demand response mitigate rolling blackouts, replace peaker plants, and supply flexible capacity during heat waves and evening peaks across utilities and homes.

Key Points

California Battery Storage uses distributed and utility batteries to stabilize power, shift solar, and curb blackouts.

✅ Supplies flexible capacity during peak demand and heat waves

✅ Enables demand response and replaces gas peaker plants

✅ Aggregated assets form virtual power plants for grid support

Last month as a heat wave slammed California, state regulators sent an email to a group of energy executives pleading for help to keep the lights on statewide. “Please consider this an urgent inquiry on behalf of the state,” the message said.

The manager of the state’s grid was struggling to increase the supply of electricity because power plants had unexpectedly shut down and demand was surging. The imbalance was forcing officials to order rolling blackouts across the state for the first time in nearly two decades.

What was unusual about the emails was whom they were sent to: people who managed thousands of batteries installed at utilities, businesses, government facilities and even homes. California officials were seeking the energy stored in those machines to help bail out a poorly managed grid and reduce the need for blackouts.

Many energy experts have predicted that batteries could turn homes and businesses into mini-power plants that are able to play a critical role in the electricity system. They could soak up excess power from solar panels and wind turbines and provide electricity in the evenings when the sun went down or after wildfires and hurricanes, which have grown more devastating because of climate change in recent years. Over the next decade, the argument went, large rows of batteries owned by utilities could start replacing power plants fueled by natural gas.

But that day appears to be closer than earlier thought, at least in California, which leads the country in energy storage. During the state’s recent electricity crisis, more than 30,000 batteries supplied as much power as a midsize natural gas plant. And experts say the machines, which range in size from large wall-mounted televisions to shipping containers, will become even more important because utilities, businesses and homeowners are investing billions of dollars in such devices.

“People are starting to realize energy storage isn’t just a project or two here or there, it’s a whole new approach to managing power,” said John Zahurancik, chief operating officer at Fluence, which makes large energy storage systems bought by utilities and large businesses. That’s a big difference from a few years ago, he said, when electricity storage was seen as a holy grail — “perfect, but unattainable.”

On Friday, Aug. 14, the first day California ordered rolling blackouts, Stem, an energy company based in the San Francisco Bay Area, delivered 50 megawatts — enough to power 20,000 homes — from batteries it had installed at businesses, local governments and other customers. Some of those devices were at the Orange County Sanitation District, which installed the batteries to reduce emissions by making it less reliant on natural gas when energy use peaks.

John Carrington, Stem’s chief executive, said his company would have provided even more electricity to the grid had it not been for state regulations that, among other things, prevent businesses from selling power from their batteries directly to other companies.

“We could have done two or three times more,” he said.

The California Independent System Operator, which manages about 80 percent of the state’s grid, has blamed the rolling blackouts on a confluence of unfortunate events, including extreme weather impacts on the grid that limited supply: A gas plant abruptly went offline, a lack of wind stilled thousands of turbines, and power plants in other states couldn’t export enough electricity. (On Thursday, the grid manager urged Californians to reduce electricity use over Labor Day weekend because temperatures are expected to be 10 to 20 degrees above normal.)

But in recent weeks it has become clear that California’s grid managers also made mistakes last month, highlighting the challenge of fixing California’s electric grid in real time, that were reminiscent of an energy crisis in 2000 and 2001 when millions of homes went dark and wholesale electricity prices soared.

Grid managers did not contact Gov. Gavin Newsom’s office until moments before it ordered a blackout on Aug. 14. Had it acted sooner, the governor could have called on homeowners and businesses to reduce electricity use, something he did two days later. He could have also called on the State Department of Water Resources to provide electricity from its hydroelectric plants.

Weather forecasters had warned about the heat wave for days. The agency could have developed a plan to harness the electricity in numerous batteries across the state that largely sat idle while grid managers and large utilities such as Pacific Gas & Electric scrounged around for more electricity.

That search culminated in frantic last-minute pleas from the California Public Utilities Commission to the California Solar and Storage Association. The commission asked the group to get its members to discharge batteries they managed for customers like the sanitation department into the grid. (Businesses and homeowners typically buy batteries with solar panels from companies like Stem and Sunrun, which manage the systems for their customers.)

“They were texting and emailing and calling us: ‘We need all of your battery customers giving us power,’” said Bernadette Del Chiaro, executive director of the solar and storage association. “It was in a very last-minute, herky-jerky way.”

At the time of blackouts on Aug. 14, battery power to the electric grid climbed to a peak of about 147 megawatts, illustrating how virtual power plants can rapidly scale, according to data from California I.S.O. After officials asked for more power the next day, that supply shot up to as much as 310 megawatts.

Had grid managers and regulators done a better job coordinating with battery managers, the devices could have supplied as much as 530 megawatts, Ms. Del Chiaro said. That supply would have exceeded the amount of electricity the grid lost when the natural gas plant, which grid managers have refused to identify, went offline.

Officials at California I.S.O. and the public utilities commission said they were working to determine the “root causes” of the crisis after the governor requested an investigation.

Grid managers and state officials have previously endorsed the use of batteries, using AI to adapt as they integrate them at scale. The utilities commission last week approved a proposal by Southern California Edison, which serves five million customers, to add 770 megawatts of energy storage in the second half of 2021, more than doubling its battery capacity.

And Mr. Zahurancik’s company, Fluence, is building a 400 megawatt-hour battery system at the site of an older natural gas power plant at the Alamitos Energy Center in Long Beach. Regulators this week also approved a plan to extend the life of the power plant, which was scheduled to close at the end of the year, to support the grid.

But regulations have been slow to catch up with the rapidly developing battery technology.

Regulators and utilities have not answered many of the legal and logistical questions that have limited how batteries owned by homeowners and businesses are used. How should battery owners be compensated for the electricity they provide to the grid? Can grid managers or utilities force batteries to discharge even if homeowners or businesses want to keep them charged up for their own use during blackouts?

During the recent blackouts, Ms. Del Chiaro said, commercial and industrial battery owners like Stem’s customers were compensated at the rates similar to those that are paid to businesses to not use power during periods of high electricity demand. But residential customers were not paid and acted “altruistically,” she said.

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UK Offshore Wind Expansion will make wind the main power source, driving renewable energy, offshore projects, smart grids, battery storage, and interconnectors to cut carbon emissions, boost exports, and attract global investment.

Key Points

A UK strategy to scale offshore wind, integrate smart grids and storage, cut emissions and drive investment and exports

✅ 30% energy target by 2030, backed by CfD support

✅ 250m industry investment and smart grid build-out

✅ Battery storage and interconnectors balance intermittency

Plans are afoot to make wind the UKs main power source for the first time in history amid ambitious targets to generate 30 percent of its total energy supply by 2030, up from 8 percent at present.

A recently inked deal will see the offshore wind industry invest 250 million into technology and infrastructure over the next 11 years, with the government committing up to 557 million in support, under a renewable energy auction that boosts wind and tidal projects, as part of its bid to lower carbon emissions to 80 percent of 1990 levels by 2050.

Offshore wind investment is crucial for meeting decarbonisation targets while increasing energy production, says Dominic Szanto, Director, Energy and Infrastructure at JLL. The governments approach over the last seven years has been to promise support to the industry, provided that cost reduction targets were met. This certainty has led to the development of larger, more efficient wind turbines which means the cost of offshore wind energy is a third of what it was in 2012.

Boosting the wind industry

Offshore wind power has been gathering pace in the UK and has grown despite COVID-19 disruptions in recent years. Earlier this year, the Hornsea One wind farm, the worlds largest offshore generator which is located off the Yorkshire coast, started producing electricity. When fully operational in 2020, the project will supply energy to over a million homes, and a further two phases are planned over the coming decade.

Over 10 gigawatts of offshore wind either already has government support or is eligible to apply for it in the near future, following a 10 GW contract award that underscores momentum, representing over 30 billion of likely investment opportunities.

Capital is coming from European utility firms and increasingly from Asian strategic investors looking to learn from the UKs experience. The attractive government support mechanism means banks are keen to lend into the sector, says Szanto.

New investment in the UKs offshore wind sector will also help to counter the growing influence of China. The UK is currently the worlds largest offshore wind market, but by 2021 it will be outstripped by China.

Through its new deal, the government hopes to increase wind power exports fivefold to 2.6 billion per year by 2030, with the UKs manufacturing and engineering skills driving projects in growth markets in Europe and Asia and in developing countries supported by the World Bank support through financing and advisory programs.

Over the next two decades, theres a massive opportunity for the UK to maintain its industry leading position by designing, constructing, operating and financing offshore wind projects, says Szanto. Building on projects such as the Hywind project in Scotland, it could become a major export to countries like the USA and Japan, where U.S. lessons from the U.K. are informing policy and coastal waters are much deeper.

Wind-powered smart grids

As wind power becomes a major contributor to the UKs energy supply, which will be increasingly made up of renewable sources in coming decades, there are key infrastructure challenges to overcome.

A real challenge is that the UKs power generation is becoming far more decentralised, with smaller power stations such as onshore wind farms and solar parks and more prosumers residential houses with rooftop solar coupled with a significant rise in intermittent generation, says Szanto. The grid was never designed to manage energy use like that.

One potential part of the solution is to use offshore wind farms in other sites in European waters.

By developing connections between wind projects from neighbouring countries, it will create super-grids that will help mitigate intermittency issues, says Szanto.

More advanced energy storage batteries will also be key for when less energy is generated on still days. There is a growing need for batteries that can store large amounts of energy and smart technology to discharge that energy. Were going through a revolution where new technology companies are working to enable a much smarter grid.

Future smart grids, based on developing technology such as blockchain, might enable the direct trading of energy between generators and consumers, with algorithms that can manage many localised sources and, critically, ensure a smooth power supply.

Investors seeking a higher-yield market are increasingly turning to battery technology, Szanto says. In a future smart grid, for example, batteries could store electricity bought cheaply at low-usage times then sold at peak usage prices or be used to provide backup energy services to other companies.

Majors investing in the transition

Its not just new energy technology companies driving change; established oil and gas companies are accelerating spending on renewable energy. Shell has committed to $1-2 billion per year on clean energy technologies out of a $25-30 billion budget, while Equinor plans to spend 15-20 percent of its budget on renewables by 2030.

The oil and gas majors have the global footprint to deliver offshore wind projects in every country, says Szanto. This could also create co-investment opportunities for other investors in the sector especially as nascent wind markets such as the U.S., where the U.S. offshore wind timeline is still developing, and Japan evolve.

European energy giants, for example, have bid to build New Yorks first offshore wind project.

As offshore wind becomes a globalised sector, with a trillion-dollar market outlook emerging, the major fuel companies will have increasingly large roles. They have the resources to undertake the years-long, cost-intensive developments of wind projects, driven by a need for new business models as the world looks beyond carbon-based fuels, says Szanto.

Oil and gas heavyweights are also making wind, solar and energy storage acquisitions BP acquired solar developer Lightsource and car-charging network Chargemaster, while Shell spent $400 million on solar and battery companies.

The public perception is that renewable energy is niche, but its now a mainstream form of energy generation., concludes Szanto.

Every nation in the world is aligned in wanting a decarbonised future. In terms of electricity, that means renewable energy and for offshore wind energy, the outlook is extremely positive.

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Ontario Global Adjustment Appeal spotlights Ontario's electricity fee, regulatory charge vs tax debate, FIT contracts, green energy policy, and constitutional challenge as National Steel Car contests soaring power costs before the Ontario Superior Court.

Key Points

Court challenge over Ontario's global adjustment fee, disputing its status as a regulatory charge instead of a tax.

✅ Challenges classification of global adjustment as tax vs regulatory charge.

✅ Focuses on FIT contracts, renewable energy payments, power cost impacts.

✅ Appeals Ontario ruling; implications for ratepayers and policy.

A manufacturer of steel rail cars is pursuing an appeal after its lawsuit challenging the constitutionality of a major Ontario electricity fee was struck down earlier this year.

Lawyers for Hamilton, Ont.-based National Steel Car Ltd. filed a notice of appeal in July after Ontario Superior Court Justice Wendy Matheson ruled in June that an electricity fee known as the global adjustment charge was a regulatory charge, and not an unconstitutional tax used to finance policy goals, as National Steel Car alleges.

The company, the decision noted, began its legal crusade last year after seeing its electricity bills had “increased dramatically” since the Ontario government passed green energy legislation nearly a decade ago, and amid concerns that high electricity rates are hurting Ontario manufacturers.

Under that legislation, the judge wrote, “private suppliers of renewable energy were paid to ’feed in’ energy into Ontario’s electricity grid.” The contracts for these so-called “feed-in tariff” contracts, or FIT contracts, were the “primary focus” of the lawsuit.

“The applicant seeks a declaration that part of the amount it has paid for electricity is an unconstitutional tax rather than a valid regulatory charge,” the judge added. “More specifically, it challenges part of the Global Adjustment, which is a component of electricity pricing and incorporates obligations under FIT contracts.”

Chiefly representing the difference between Ontario’s market price for power and the guaranteed price owed to generators, global adjustment now makes up the bulk of the commodity cost of electricity in the province. The fee has risen over the past decade, amid calls to reject steep Nova Scotia rate hikes as well — costing electricity customers $37 billion in global adjustment from 2006 to 2014, according to the province’s auditor general — because of investments in the electricity grid and green-energy contracts, among other reasons.

National Steel Car argued the global adjustment is a tax, and an unconstitutional one at that because it violated a section of the Constitution Act requiring taxes to be authorized by the legislature. The company also said the imposition of the global adjustment broke an Ontario law requiring a referendum to be held for new taxes.

The province, Justice Matheson wrote, had argued “that it is plain and obvious that these applications will fail.” In a decision released in June, the judge granted motions to strike out National Steel Car’s applications.

“The Global Adjustment,” she added, “is not a tax because its purpose, in pith and substance, is not to tax, and it is a regulatory charge and therefore, again, not a tax.”

Now, National Steel Car is arguing that the judge erred in several ways, including in fact, “by finding that the FIT contracts must be paid, when they can be cancelled.”

There has been a change in government at Queen’s Park since National Steel Car first filed its lawsuit last year, and that change has put green energy contracts under fire. The Progressive Conservative government of new Premier Doug Ford has already made a number of decisions on the electricity file, such as moving to cancel and wind down more than 750 renewable energy contracts, as well as repealing the province’s Green Energy Act.

The Tories also struck a commission of inquiry into the province’s finances that warned the global adjustment “may be struck down as unconstitutional,” a warning delivered amid cases where Nova Scotia's regulator approved a 14% rate hike in a high-profile decision.

“There is a risk that a court may find the global adjustment is not a valid regulatory charge if shifting costs over a longer period of time inadvertently results in future ratepayers cross-subsidizing today’s ratepayers,” the commission’s report said.

A spokesperson for Ontario’s Ministry of Energy, Northern Development and Mines said in an email that it would be “inappropriate to comment about the specifics of any case before the courts or currently under arbitration.”

National Steel Car is also prepared to fight its case all the way up to the Supreme Court of Canada, according to its lawyer.

“What is clear from our proceeding with the appeal is National Steel Car has every intention of seeing that lawsuit through to its conclusion if this government isn’t interested or prepared to reasonably settle it,” Jerome Morse said.

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