Biomass Plant to Tap Bull Market for Clean Energy

Hydrogen Energy Transition advances renewable energy integration via electrolysis, carbon capture and storage, and gas hybrids to decarbonize industry, steel, and transport, enable grid storage, replace ammonia feedstocks, and export clean power across continents.

Key Points

Scaling clean hydrogen with renewables and CCS to cut emissions in power and industry, and enable clean transport.

✅ Electrolysis and CCS provide low-emission hydrogen at scale.

✅ Balances renewables with storage and flexible gas assets.

✅ Decarbonizes steel, ammonia, heavy transport, and exports.

I want you to imagine a highway exclusively devoted to delivering the world’s energy. Each lane is restricted to trucks that carry one of the world’s seven large-scale sources of primary energy: coal, oil, natural gas, nuclear, hydro, solar and wind.

Our current energy security comes at a price, as Europe's power crisis shows, the carbon dioxide emissions from the trucks in the three busiest lanes: the ones for coal, oil and natural gas.

We can’t just put up roadblocks overnight to stop these trucks; they are carrying the overwhelming majority of the world’s energy supply.

But what if we expand clean electricity production carried by the trucks in the solar and wind lanes — three or four times over — into an economically efficient clean energy future?

Think electric cars instead of petrol cars. Think electric factories instead of oil-burning factories. Cleaner and cheaper to run. A technology-driven orderly transition. Problems wrought by technology, solved by technology.

Read more: How to transition from coal: 4 lessons for Australia from around the world

Make no mistake, this will be the biggest engineering challenge ever undertaken. The energy system is huge, and even with an internationally committed and focused effort the transition will take many decades.

It will also require respectful planning and retraining to ensure affected individuals and communities, who have fuelled our energy progress for generations, are supported throughout the transition.

As Tony, a worker from a Gippsland coal-fired power station, noted from the audience on this week’s Q+A program:

The workforce is highly innovative, we are up for the challenge, we will adapt to whatever is put in front of us and we have proven that in the past.

This is a reminder that if governments, industry, communities and individuals share a vision, a positive transition can be achieved.

The stunning technology advances I have witnessed in the past ten years, such as the UK's green industrial revolution shaping the next waves of reactors, make me optimistic.

Renewable energy is booming worldwide, and is now being delivered at a markedly lower cost than ever before.

In Australia, the cost of producing electricity from wind and solar is now around A$50 per megawatt-hour.

Even when the variability is firmed with grid-scale storage solutions, the price of solar and wind electricity is lower than existing gas-fired electricity generation and similar to new-build coal-fired electricity generation.

This has resulted in substantial solar and wind electricity uptake in Australia and, most importantly, projections of a 33% cut in emissions in the electricity sector by 2030, when compared to 2005 levels.

And this pricing trend will only continue, with a recent United Nations report noting that, in the last decade alone, the cost of solar electricity fell by 80%, and is set to drop even further.

So we’re on our way. We can do this. Time and again we have demonstrated that no challenge to humanity is beyond humanity.

Ultimately, we will need to complement solar and wind with a range of technologies such as high levels of storage, including gravity energy storage approaches, long-distance transmission, and much better efficiency in the way we use energy.

But while these technologies are being scaled up, we need an energy companion today that can react rapidly to changes in solar and wind output. An energy companion that is itself relatively low in emissions, and that only operates when needed.

In the short term, as Prime Minister Scott Morrison and energy minister Angus Taylor have previously stated, natural gas will play that critical role.

In fact, natural gas is already making it possible for nations to transition to a reliable, and relatively low-emissions, electricity supply.

Look at Britain, where coal-fired electricity generation has plummeted from 75% in 1990 to just 2% in 2019.

Driving this has been an increase in solar, wind, and hydro electricity, up from 2% to 27%. At the same time, and this is key to the delivery of a reliable electricity supply, electricity from natural gas increased from virtually zero in 1990 to more than 38% in 2019.

I am aware that building new natural gas generators may be seen as problematic, but for now let’s assume that with solar, wind and natural gas, we will achieve a reliable, low-emissions electricity supply.

Is this enough? Not really.

We still need a high-density source of transportable fuel for long-distance, heavy-duty trucks.

We still need an alternative chemical feedstock to make the ammonia used to produce fertilisers.

We still need a means to carry clean energy from one continent to another.

Enter the hero: hydrogen.

Hydrogen could fill the gaps in our energy needs. Julian Smith/AAP Image
Hydrogen is abundant. In fact, it’s the most abundant element in the Universe. The only problem is that there is nowhere on Earth that you can drill a well and find hydrogen gas.

Don’t panic. Fortunately, hydrogen is bound up in other substances. One we all know: water, the H in H₂O.

We have two viable ways to extract hydrogen, with near-zero emissions.

First, we can split water in a process called electrolysis, using renewable electricity or heat and power from nuclear beyond electricity options.

Second, we can use coal and natural gas to split the water, and capture and permanently bury the carbon dioxide emitted along the way.

I know some may be sceptical, because carbon capture and permanent storage has not been commercially viable in the electricity generation industry.

But the process for hydrogen production is significantly more cost-effective, for two crucial reasons.

First, since carbon dioxide is left behind as a residual part of the hydrogen production process, there is no additional step, and little added cost, for its extraction.

And second, because the process operates at much higher pressure, the extraction of the carbon dioxide is more energy-efficient and it is easier to store.

Returning to the electrolysis production route, we must also recognise that if hydrogen is produced exclusively from solar and wind electricity, we will exacerbate the load on the renewable lanes of our energy highway.

Think for a moment of the vast amounts of steel, aluminium and concrete needed to support, build and service solar and wind structures. And the copper and rare earth metals needed for the wires and motors. And the lithium, nickel, cobalt, manganese and other battery materials needed to stabilise the system.

It would be prudent, therefore, to safeguard against any potential resource limitations with another energy source.

Well, by producing hydrogen from natural gas or coal, using carbon capture and permanent storage, we can add back two more lanes to our energy highway, ensuring we have four primary energy sources to meet the needs of the future: solar, wind, hydrogen from natural gas, and hydrogen from coal.

Read more: 145 years after Jules Verne dreamed up a hydrogen future, it has arrived

Furthermore, once extracted, hydrogen provides unique solutions to the remaining challenges we face in our future electric planet.

First, in the transport sector, Australia’s largest end-user of energy.

Because hydrogen fuel carries much more energy than the equivalent weight of batteries, it provides a viable, longer-range alternative for powering long-haul buses, B-double trucks, trains that travel from mines in central Australia to coastal ports, and ships that carry passengers and goods around the world.

Second, in industry, where hydrogen can help solve some of the largest emissions challenges.

Take steel manufacturing. In today’s world, the use of coal in steel manufacturing is responsible for a staggering 7% of carbon dioxide emissions.

Persisting with this form of steel production will result in this percentage growing frustratingly higher as we make progress decarbonising other sectors of the economy.

Fortunately, clean hydrogen can not only provide the energy that is needed to heat the blast furnaces, it can also replace the carbon in coal used to reduce iron oxide to the pure iron from which steel is made. And with hydrogen as the reducing agent the only byproduct is water vapour.

This would have a revolutionary impact on cutting global emissions.

Third, hydrogen can store energy, as with power-to-gas in pipelines solutions not only for a rainy day, but also to ship sunshine from our shores, where it is abundant, to countries where it is needed.

Let me illustrate this point. In December last year, I was privileged to witness the launch of the world’s first liquefied hydrogen carrier ship in Japan.

As the vessel slipped into the water I saw it not only as the launch of the first ship of its type to ever be built, but as the launch of a new era in which clean energy will be routinely transported between the continents. Shipping sunshine.

And, finally, because hydrogen operates in a similar way to natural gas, our natural gas generators can be reconfigured in the future as hydrogen-ready power plants that run on hydrogen — neatly turning a potential legacy into an added bonus.

Hydrogen-powered economy
We truly are at the dawn of a new, thriving industry.

There’s a nearly A$2 trillion global market for hydrogen come 2050, assuming that we can drive the price of producing hydrogen to substantially lower than A$2 per kilogram.

In Australia, we’ve got the available land, the natural resources, the technology smarts, the global networks, and the industry expertise.

And we now have the commitment, with the National Hydrogen Strategy unanimously adopted at a meeting by the Commonwealth, state and territory governments late last year.

Indeed, as I reflect upon my term as Chief Scientist, in this my last year, chairing the development of this strategy has been one of my proudest achievements.

The full results will not be seen overnight, but it has sown the seeds, and if we continue to tend to them, they will grow into a whole new realm of practical applications and unimagined possibilities.

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Great Britain electricity generation spans renewables and baseload: wind, solar, nuclear, gas, and biomass, supported by National Grid interconnectors, embedded energy estimates, and BMRS data for dynamic imports and exports across Europe.

Key Points

A diverse, weather-driven mix of renewables, gas, nuclear, and imports coordinated by National Grid.

✅ Baseload from nuclear and biomass; intermittent wind and solar

✅ Interconnectors trade zero carbon imports via subsea cables

✅ Data from BMRS and ESO covers embedded energy estimates

Great Britain has one of the most diverse ranges of electricity generation in Europe, with everything from windfarms off the coast of Scotland to a nuclear power station in Suffolk tasked with keeping the lights on. The increasing reliance on renewable energy sources, as part of the country’s green ambitions, also means there can be rapid shifts in the main source of electricity generation. On windy days, most electricity generation comes from record wind generation across onshore and offshore windfarms. When conditions are cold and still, gas-fired power stations known as peaking plants are called into action.

The electricity system in Great Britain relies on a combination of “baseload” power – from stable generators such as nuclear and biomass plants – and “intermittent” sources, such as wind and solar farms that need the right weather conditions to feed energy into the grid. National Grid also imports energy from overseas, through subsea cables known as interconnectors that link to France, Belgium, Norway and the Netherlands. They allow companies to trade excess power, such as renewable energy created by the sun, wind and water, between different countries. By 2030 it is hoped that 90% of the energy imported by interconnectors will be from zero carbon energy sources, though low-carbon electricity generation stalled in 2019 for the UK.

The technology behind Great Britain’s power generation has evolved significantly over the last century, and at times wind has been the main source of electricity. The first integrated national grid in the world was formed in 1935 linking seven regions of the UK. In the aftermath of industrialisation, coal provided the vast majority of power, before oil began to play an increasingly important part in the 1950s. In 1956, the world’s first commercial nuclear reactor, Calder Hall 1 at Windscale (later Sellafield), was opened by Queen Elizabeth II. Coal use fell significantly in the 1990s while the use of combined cycle gas turbines grew, and in 2016 wind generated more electricity than coal for the first time. Now a combination of gas, wind, nuclear and biomass provide the bulk of Great Britain’s energy, with smaller sources such as solar and hydroelectric power also used. From October 2024, coal will no longer be used to generate electricity, following coal-free power records set in recent years.

Energy generation data is fetched from the Balancing Mechanism Reporting Service public feed, provided by Elexon – which runs the wholesale energy market – and is updated every five minutes, covering periods when wind led the power mix as well.

Elexon’s data does not include embedded energy, which is unmetered and therefore invisible to Great Britain’s National Grid. Embedded energy comprises all solar energy and wind energy generated from non-metered turbines. To account for these figures we use embedded energy estimates from the National Grid electricity system operator, which are published every 30 minutes.

Import figures refer to the net flow of electricity from the interconnectors with Europe and with Northern Ireland. A positive value represents import into the GB transmission system, while a negative value represents an export.

Hydro figures combine renewable run-of-the-river hydropower and pumped storage.

Biomass figures include Elexon’s “other” category, which comprises coal-to-biomass conversions and biomass combined heat and power plants.

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Ontario Electricity Rebate clarifies hydro rates as OEB aligns bills with inflation, shows true cost per kilowatt hour, and replaces Fair Hydro Plan; transparent on-bill credit offsets increases tied to nuclear refurbishment and supply costs.

Key Points

A line-item credit on Ontario hydro bills that offsets higher electricity costs and reflects OEB-set rates.

✅ Starts Nov. 1 with rates in line with inflation

✅ Shows true per-kWh cost plus separate rebate line

✅ Driven by nuclear refurbishment and supply costs

The Ontario Energy Board says electricity rate changes for households and small businesses will be going up starting next week.

The agency says rates are scheduled to increased by about $1.99 or nearly 2% for a typical residential customer who uses 700 kilowatt hours per month.

The provincial government said in March it would continue to subsidize hydro rates, through legislation to lower rates, and hold any increases to the rate of inflation.

The OEB says the new rates, which the board says are “in line” with inflation, will take effect Nov. 1 as changes for electricity consumers roll out and could be noticed on bills within a few weeks of that date.

Prices are increasing partly due to government legislation aimed at reflecting the actual cost of supply on bills, and partly due to the refurbishment of nuclear facilities, contributing to higher hydro bills for some consumers.

So, effective November 1, Ontario electricity bills will show the true cost of power, after a period of a fixed COVID-19 hydro rate, and will include the new Ontario Electricity Rebate.

Previously the electricity rebate was concealed within the price-per-kilowatt-hour line item on electricity statements, prompting Hydro One bill redesign discussions to improve clarity. This meant customers could not see how much the government rebate was reducing their monthly costs, and bills did not display the true cost of electricity used.

"People deserve facts and accountability, especially when it comes to hydro costs," said Energy Minister Rickford.

The new Ontario Electricity Rebate will appear as a transparent on-bill line item and will replace the former government's Fair Hydro Plan says a government news release. This change comes in response to the Auditor General's special report on the former government's Fair Hydro Plan which revealed that "the government created a needlessly complex accounting/financing structure for the electricity rate reduction in order to avoid showing a deficit or an increase in net debt."

"The Electricity Distributors Association commends the government's commitment to making Ontario's electricity bills more transparent," said Teresa Sarkesian, President of the Electricity Distributors Association. "As the part of our electricity system that is closest to customers, local hydro utilities appreciated the opportunity to work with the government on implementing this important initiative. We worked to ensure that customers who receive their electricity bill will have a clear understanding of the true cost of power and the amount of their on-bill rebate. Local hydro utilities are focused on making electricity more affordable, reducing red tape, and providing customers with a modern and reliable electricity system that works for them."

The average customer will see the electricity line on their bill rise, showing the real cost per kilowatt hour. The new Ontario Electricity Rebate will compensate for that rise, and will be displayed as a separate line item on hydro bills. The average residential bill will rise in line with the rate of inflation.

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Hybrid renewable energy projects integrate wind, solar, and battery storage to enhance grid reliability, reduce curtailment, and provide dispatchable power in markets like Alberta, leveraging photovoltaic tracking, overbuilt transformers, and improved storage economics.

Key Points

Hybrid renewable energy projects combine wind, solar, and storage to deliver reliable, dispatchable clean power.

✅ Combine wind, solar, and batteries for steady, dispatchable output

✅ Lower curtailment by using shared transformers and smart inverters

✅ Boost farm income via leases; diversify risk from oil and gas

Third-generation farmer James Praskach has been burned by the oil and gas sector and watched wicked weather pound his crops flat, but he is hoping a new kind of energy -- the renewable kind -- will pay dividends.

The 39-year-old is part of a landowner consortium that is hosting the sprawling 300-megawatt Blackspring Ridge wind power project in southeastern Alberta.

He receives regular lease payments from the $600-million project that came online in 2014, even though none of the 166 towering wind turbines that surround his land are actually on it.

His lease payments stand to rise, however, when and if the proposed 77-MW Vulcan Solar project, which won regulatory approval in 2016, is green-lighted by developer EDF Renewables Inc.

The panels would cover about 400 hectares of his family's land with nearly 300,000 photovoltaic solar panels in Alberta, installed on racks designed to follow the sun. It would stand in the way of traditional grain farming of the land, but that wouldn't have been a problem this year, Praskach says.

"This year we actually had a massive storm roll through. And we had 100 per cent hail damage on all of (the Vulcan Solar lands). We had canola, peas and barley on it this year," he said, adding the crop was covered by insurance.

Meanwhile, poor natural gas prices and a series of oilpatch financial failures mean rents aren't being paid for about half of the handful of gas wells on his land, showing how a province that is a powerhouse for both fossil and green energy can face volatility -- he's appealed to the Alberta surface Rights Board for compensation.

"(Solar power) would definitely add a level of security for our farming operations," said Praskach.

Hybrid power projects that combine energy sources are a growing trend as selling renewable energy gains traction across markets. Solar only works during the day and wind only when it is windy so combining the two -- potentially with battery storage or natural gas or biomass generation -- makes the power profile more reliable and predictable.

Globally, an oft-cited example is on El Hierro, the smallest of the Canary Islands, where wind power is used to pump water uphill to a reservoir in a volcanic crater so that it can be released to provide hydroelectric power when needed. At times, the project has provided 100 per cent of the tiny island's energy needs.

Improvements in technology such as improving solar and wind power and lower costs for storage mean it is being considered as a hybrid add-on for nearly all of its renewable power projects, said Dan Cunningham, manager of business development at Greengate Power Corp. of Calgary.

Grant Arnold, CEO of developer BluEarth Renewables, agreed.

"The barrier to date, I would say, has been cost of storage but that is changing rapidly," he said. "We feel that wind and storage or solar and storage will be a fundamental way we do business within five years. It's changing very, very rapidly and it's the product everybody wants."

Vulcan Solar was proposed after Blackspring Ridge came online, said David Warner, associate director of business development for EDF Renewables, which now co-owns the wind farm with Enbridge Inc.

"Blackspring actually had incremental capacity in the main power transformers," he said. "Essentially, it was capable of delivering more energy than Blackspring was producing. It was overbuilt."

Vulcan Solar has been sized to utilize the shortfall without producing so much energy that either will ever have to be constrained, he said. Much of the required environmental work has already been done for the wind farm.

Storage is being examined as a potential addition to the project but implementing it depends on the regulatory system. At present, Alberta's regulators are still working on how to permit and control what they call "dispatchable renewables and storage" systems.

EDF announced last spring it would proceed with the Arrow Canyon Solar Project in Nevada which is to combine 200 MW of solar with 75 MW of battery storage by 2022 -- the batteries are to soak up the sun's power in the morning and dispatch the electricity in the afternoon when Las Vegas casinos' air conditioning is most needed.

What is clear is that renewable energy will continue to grow, with Alberta renewable jobs expected to follow -- in a recent report, the International Energy Agency said global electricity capacity from renewables is set to rise by 50 per cent over the next five years, an increase equivalent to adding the current total power capacity of the United States.

The share of renewables is expected to rise from 26 per cent now to 30 per cent in 2024 but will remain well short of what is needed to meet long-term climate, air quality and energy access goals, it added.

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Georgia Power June bill credit delivers PSC-approved savings, lower fuel rates, and COVID-19 relief for residential customers, driven by natural gas prices and 2018 earnings, with typical 1,000 kWh users seeing June bill reductions.

Key Points

A PSC-approved one-time credit and lower fuel rates reducing June bills for Georgia Power residential customers.

✅ $11.29 credit for 1,000 kWh usage on June bills

✅ Fuel rate cut saves $10.26 per month from June to September 2020

✅ PSC-approved $51.5M credit based on Georgia Power's 2018 results

Georgia Power announced that the typical residential customer using 1,000-kilowatt hours will receive an $11.29 credit on their June bill, reflecting a lump-sum credit model also used elsewhere.

This reflects implementation of a one-time $51.5 million credit for customers, similar to Gulf Power's bill decrease efforts, approved by the Georgia Public Service Commission, as a result of

Georgia Power's 2018 financial results.

Pairing the June credit with new, lower fuel rates recently announced, the typical residential customer would see a reduction of $21.55 in June, even as some regions face increases like Pennsylvania's winter price hikes elsewhere.

The amount each customer receives will vary based on their 2018 usage. Georgia Power will apply the credit to June bills for customers who had active accounts as of Dec. 31, 2018, and are still active or receiving a final bill as of June 2020, and the company has issued pandemic scam warnings to help customers stay informed.

Fuel rate lowered 17.2 percent

In addition to the approved one-time credit in June, the Georgia PSC recently approved Georgia Power’s plan to reduce its fuel rates by 17.2 percent and total billings by approximately $740 million over a two-year period. The implementation of a special interim reduction will provide customers additional relief during the COVID-19 pandemic through even lower fuel rates over the upcoming 2020 summer months. The lower fuel rate and special interim reduction will lower the total bill of a typical residential customer using an average of 1,000-kilowatt hours by a total of $10.26 per month from June through September 2020.

The reduction in the company’s fuel rate is driven primarily by lower natural gas prices, even as FPL proposed multiyear rate hikes in Florida, as a result of increased natural gas supplies, which the company is able to take advantage of to benefit customers due to its diverse generation sources.

February bill credit due to tax law savings

Georgia Power completed earlier this year the third and final bill credit associated with the Tax Cuts and Jobs Act of 2017, resulting in credits totaling $106 million. The typical residential customer using an average of 1,000 kilowatt-hours per month received a credit of approximately $22 on their February Georgia Power bill, a helpful offset as U.S. electric bills rose 5% in 2022 according to national data.

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Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

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