By Chris Bonasia

As Prime Minister Mark Carney releases his first official list of large infrastructure projects of “national interest,” a broad wave of building retrofits could better meet his goals and stimulate the economy, decarbonization experts say.

“Simply speeding up approvals for a few infrastructure projects does not build us a new country,” write Chris Severson-Baker and Monica Curtis, the Pembina Institute’s executive director and senior director for communities and decarbonization, in a recent op-ed for The Hill Times. “Going bigger and broader—focusing on infrastructure that could directly improve the lives of literally every Canadian and aiming to help solve numerous crises at once—now that’s smart, strategic, and forward-thinking nation-building.”

Their suggestion comes as the Carney government establishes processes to advance major infrastructure projects deemed in the national interest by streamlining their approval. Via the Building Canada Act, the government can designate such projects, and then issue a single federal authorization that replaces other federal permits, decisions, and authorities that would normally be required.

Passed on June 20 within a month of being introduced, the act has drawn criticism from environmental groups and First Nations, all warning that it risks bypass protections for ecosystems and Indigenous rights.

Severson-Baker and Curtis say the government should think differently about nation-building, especially when “there’s a nation-building initiative waiting in the wings.” Retrofitting homes and buildings affects how Canadians use energy every day, they argue, while delivering healthier, safer indoor spaces, more resilience to severe weather, and lower heating and cooling costs.

“Great big single projects and megaprojects have their place, and they are important, but we do want to make sure that we’re thinking about nation-building as more than megaprojects,” Curtis told Green Energy Futures. That means smaller, less time-intensive projects that can have a more direct impact on Canadians.

Retrofits and energy efficiency investments align with the goals of the Building Canada Act, Severson-Baker and Curtis add. They support “made-in-Canada” energy resources like rooftop solar and battery storage while creating long-term, local jobs. “Investments in retrofitting buildings can generate $7 in GDP growth for every $1 invested.”

“What if we looked at nation-building not only via single projects, with a primary proponent, location, and outcome? What if we developed nation-building programs—like retrofits for multi-family units—addressing many societal needs at once, and in the process creating a wave of economic activity, including new Canadian industries and supply chains?”

Efficiency standards and federally supported retrofit programs meet the criteria for projects of national interest, including strengthening autonomy, resilience, and security, providing economic or other benefits, bearing a high likelihood of successful execution, and contributing to clean growth and to meeting Canada’s objectives with respect to climate change, they add.

“We see residential building retrofits as a nation-building opportunity—exactly the kind of project the Cabinet has been tasked with prioritizing,” write Raidin Blue and Sarah Snowdon, Pembina analyst and senior communications lead, in a separate op-ed.

A Canada-wide renovation wave focused on deep retrofitting building stock can lower heating and cooling bills, improve housing affordability, and create up to 200,000 jobs, they say. And ramping up retrofits could deliver $48 billion in annual economic development over 20 years—paying for themselves “twice over through increased tax revenue.”

Neither post specifies how retrofits will advance the interests of Indigenous peoples, one of the criteria for identifying national interest projects. However, organizations like Indigenous Clean Energy have advanced building retrofit programs—like the Bringing it Home Project—as a way to address health and housing affordability issues in First Nations, Inuit, and Métis communities.

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External expectations have framed Africa’s role in the energy transition for years. Despite facing different realities, such as limited infrastructure, restricted access to capital, and less influence in global energy policy, it has been assumed that Africa will follow the same decarbonization path as developed economies.

This way of thinking is misaligned with today’s realities. Africa’s priorities—improving access, promoting industrial growth, and building resilience—must be reflected in its energy strategy. The continent is actively involved in the global shift. It is, however, doing this on its own terms.

At the African Refiners & Distributors Association (ARDA), we believe the continent’s energy transition must be designed in Africa, for Africa, balancing three urgent imperatives: expanding energy access, driving industrial growth, and prioritizing energy security for the continent That means shaping policies, financing mechanisms, and partnerships that work for Africa rather than copying models that do not.

Across Africa, governments and private sector players are investing in diversified energy portfolios that reflect both local needs and global sustainability goals. In Angola, construction is progressing on a 35MW solar project, part of a broader pipeline exceeding 3GW of planned solar, wind, and hydropower developments.

In Uganda, the 250MW Bujagali hydropower plant continues to play a vital role in stabilizing the national electricity supply. Meanwhile, South Africa is advancing a 316MW solar PV installation paired with 500MWh of battery storage.

These projects indicate a significant move toward energy independence and long-term resilience. The continent is not only catching up with global energy trends but also accelerating them, with locally-led solutions and designed with long-lasting impact.

Bold vision, however, is not enough. To scale Africa’s energy transition, there will need to be structural follow-through. Three crucial factors will determine if the continent can move from prospective projects to transformative change: sustainable finance, regional integration, and investor-friendly policy frameworks.

1. Sustainable Finance

The African Development Bank estimates that Africa’s energy transition will cost around $100 billion per year between 2020 and 2040.

Current capital flows fall significantly short, and the financing that does exist often comes with higher risk premiums, shorter loan terms and limited flexibility.

ARDA is championing innovative financing models that blend public and private capital, lower investment risks, and align global climate finance with Africa’s development priorities. To attract serious investment, Africa needs to utilize smart financing strategies that utilise public and private money, reduce risks for investors, and encourage global institutions to support energy projects. This approach can minimize risks for investors and encourage institutions to back energy projects. It’s also vital to prioritize initiatives that merge renewable energy with storage systems. Not only do these projects help cut down emissions, but they also ensure a steady electricity supply, support various industries, and ultimately, strengthen the economy.

2. Regional Integration

Many African countries remain reliant on fragmented, underpowered national grids that struggle to attract large-scale investment. Regional integration is essential, and it depends on harmonized regulations, cross-border infrastructure, and shared power resources. Initiatives like the African Single Electricity Market (AfSEM) and the African Continental Free Trade Area (AfCFTA) lay the groundwork for collaboration. What we need now is political unity and focused investment to transform these initiatives into platforms for energy security and economic growth.

3. Policy Frameworks

Africa is catching the eye of global investors, but what it needs is predictability. Governments must consider implementing policies that simplify the process of permitting, financing, and running energy projects. Whether it’s through feed-in tariffs, tax incentives, or local regulations, the aim remains the same: to cut down on uncertainty, reduce costs and attract long-term investments. ARDA works with policymakers to design frameworks that enable private participation, ensuring that energy projects are not only bankable but also deliver lasting local value.

The countries that will lead the continent’s energy shift are those that provide a stable and transparent environment, allowing both public and private players to collaborate with confidence. Most importantly, this energy transition must create local value. It should focus on building skills, transferring technology, and sparking new industries, from battery production to green hydrogen. Every megawatt generated should be viewed not just as electricity produced, but as a job created, a business empowered, and a supply chain bolstered.

Africa’s energy transition is about making smart choices. Cleaner fuels like natural gas will continue to play a vital role in the short to medium term, particularly in replacing high-emission diesel and fuel oil in power generation and transport. Mozambique, through its significant gas reserves and ongoing LNG initiatives, plays an increasingly important role in shaping Africa’s transitional energy future. These transition fuels are essential to maintaining reliability while building capacity for a low-carbon future.

The investments we make today must be forward-thinking, aimed at speeding up the transition to a diverse, low-emission energy economy that promotes inclusive growth and progress. The global community stands to gain immensely from the continent’s transition. The real question isn’t whether Africa will make this shift; it’s about how quickly and decisively the world is ready to back that journey.

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By Lana Goldberg

The leaders of three major federal political parties have raised the prospect of resurrecting failed pipeline projects such as Energy East and Northern Gateway, which were once intended to carry oil from the Alberta oilsands to our two coasts.

Pierre Poilievre has outright committed to building a pipeline from Alberta to New Brunswick. Mark Carney has put both pipelines on the table and Jagmeet Singh says they could be acceptable under certain circumstances.

In the context of U.S. President Donald Trump’s tariff war, it makes sense for Canada to reassess our energy needs and plan for energy independence. But it makes zero sense to expand oil and gas infrastructure in the midst of growing worldwide climate chaos, especially when we have clean, affordable, job-creating alternatives.

We must use the current crisis to wean ourselves off fossil fuels.

The next federal government should invest in green infrastructure, energy and transportation, as well as health care and other social services, while providing relief for workers hit hard by the trade war. This will both help people today and build a sustainable future.

Whatever reasoning politicians and industry officials use to whip up pro-pipeline sentiment – such as meeting domestic needs or exporting to international markets – none stand up to scrutiny.

We’re already on a green path

Domestically, we won’t need to be flooded with oil and gas in the near future because we’re already on a green trajectory and can smoothly complete the transition with readily available technologies. As well, it would take 10 years to build these pipelines – too late to address current needs.

Rather than using oil for gasoline and diesel fuel, we can further embrace electric vehicles (EVs) and invest in extensive green public transportation systems, such as an east-west high-speed rail link which would take cars off the road.

In the place of burning gas or oil to heat the air and water in our buildings, we can hasten the switch to clean alternatives such as electric heat pumps.

To power all of these alternatives, we can replace all gas-fired power plants with renewable sources such as wind and solar, pairing them with existing battery storage technologies that allow the energy to be used anytime. These clean solutions are ready to be deployed today.

They are better economically too. Wind and solar are now the lowest-cost new source of electricity generation. The cost of using renewable energy on the consumer side is lower than the fossil fuel options. The price of EVs is now almost on a par with gasoline-powered versions while the cost to run them is lower than their gas-guzzling counterparts.

It’s a similar story for heat pumps, which are falling in price and cost much less to operate than gas or oil furnaces. All of these more modern technologies also provide stable prices, whereas natural gas and gasoline prices are volatile in response to geopolitical events.

Eliminating the use of gas for building heating and electricity generation would go a long way in decreasing our use of the fuel. Getting off of gasoline and diesel for transportation would do the same for our consumption of oil.

We can also decrease the industrial use of gas, which represents more than half of its use in Canada. The largest gas-consuming province is Alberta and the biggest chunk of its use there is for powering oil extraction in the oilsands. Decrease oilsands production and you’ve significantly diminished the need for gas. Other industries can do a lot to reduce fossil fuel reliance as well.

By making smart commitments now, we won’t need a large amount of fossil fuels in the future and we certainly don’t need to dig more out of the ground just to send overseas.

Currently, almost all of our crude oil exports go to the U.S. and a big chunk of natural gas does too. This is clearly an export-oriented enterprise.

Global demand for oil is already waning

With the current trade war uncertainty, fossil fuel producers are now looking for international markets other than the United States. But global demand for oil is thought to be on the decrease and is already waning in China and Europe, which are the supposed export targets for the pipelines in question.

The world is rightly moving towards clean energy. So, the only beneficiaries of fossil fuel extraction and export are industry executives and wealthy investors. In 2023, the net income of Canada’s oil and gas companies was $37 billion. These companies are largely foreign-owned, particularly by American entities.

Pipeline construction creates relatively few and only temporary jobs. Jobs in the extractive process are also limited and mostly in the construction phase. We can generate many more good jobs in the green sector.

Oil and gas projects also often undermine Indigenous rights and sovereignty while harming traditional lands.

Oilsands projects, for example, destroy vast swaths of ecosystems and poison people who live nearby. As well, the pipelines that transport the fuels that are produced are prone to spills, fires and explosions with adverse environmental impacts on communities across the country.

Fossil fuel extraction also has detrimental effects on our climate goals. Oil and gas production is responsible for the largest portion – one-third – of Canada’s overall emissions. The oilsands are the single biggest contributor.

Now, fossil fuel companies are trying to use the tariff crisis to open the door to even more extraction and more pipelines, resulting in additional pollution and destruction.

Enbridge says it could be open to revisiting the Northern Gateway project if the federal government were to scrap the oil and gas emissions cap, environmental assessments and the industrial carbon price.

But some scholars and experts have shown that the pipeline projects are not economically viable under any circumstances. Perhaps that is why industry backers are calling for the federal government to step in once more with taxpayers’ money to build the pipelines.

We should not again go down the path of the Trans Mountain pipeline, which cost an eye-watering $34 billion of taxpayers’ money. New pipelines could also end up being stranded assets, which would result in wasted and possibly additional costs from public coffers.

Instead of temporarily propping up fossil fuel profits, public funds should go toward developing important infrastructure and creating more jobs. This includes building a green manufacturing sector, training people to enter it, constructing affordable green housing, investing in public and electric transportation, and building east-west electricity transmission lines.

Investing in health care and other social services would also create new jobs while ensuring people are getting the support they need in these turbulent times. Most urgently, we need to allocate public funds to provide relief to workers who are being impacted by the tariff war.

Rather than reviving unnecessary pipelines, let’s use this moment as a wakeup call to get ready for the future and build a sustainable, resilient and just society.

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School’s out in Canada, and not a moment too soon for students sweltering in classrooms that urgently need heat adaptation and resilience upgrades.

As extreme heat days from late spring to early fall overheat Canada’s schools more often, experts, educators, and parents are urging greater awareness and investment to help cool things down, reports CBC News.

Exhibit A could be Sts. Cosmas and Damian Catholic School in Toronto. Built in the 1950s, the building doesn’t have air conditioning.

“You’re always sweating a lot and you’re always focusing on: ‘Oh my God, I want to cool down,’” 13-year-old Carmine Pantano told CBC. “I can feel a little bit dizzy when it’s too hot.”

The school is trying hard to keep its students comfortable and safe: Lowered window shades, open windows where possible, lights off, and a cooling centre in the library. Tower fans in every classroom also pitch in, but it isn’t enough. Twelve outdoor misting centres are being used at various schools as a pilot project.

Sara Concordia, whose young daughter attends another Toronto Catholic District School Board (TCDSB) school, told CBC that classroom temperatures at the school have gone as high as 30℃—without factoring in humidity.

That’s far in excess of what is considered safe, Caroline Metz, managing director of climate resilience and health at the University of Waterloo’s Intact Centre on Climate Adaptation, told CBC. Ideally, indoor temperatures should sit below 26℃. Above that, health risks grow, and sustained exposure to indoor temperatures about 31℃ “can be dangerous for everyone,” Metz said.

High indoor temperatures are particularly hazardous for children, said Eric Coker, senior scientist for the B.C. Centre for Disease Control. Children have higher metabolic rates, so “their demand for cooling off is going to be higher.”

Children who regularly move from overheated schools to homes that are themselves sweltering are at even greater risk because their bodies (and minds) get no reprieve from heat, Metz told The Energy Mix.

Further danger lies in the fact that children may not understand that the sudden onset of heat stroke symptoms—dizziness, stomach cramps, nausea—means they need urgently to find a place to cool down.

“Schools need to be ratcheting up the resilience to environmental conditions that are clearly being impacted by climate change,” Coker added.

But school boards are currently expected to pay for those upgrades out of their current, severely limited budgets.

“School boards have the autonomy, accountability, and responsibility to ensure their facilities meet regulatory requirements and to ensure programming and operations are responsive to extreme weather conditions to ensure students are best supported,” is how Kevin Lee, press secretary to Alberta Education Minister Demetrios Nicolaides, put it, in response to a query from the CBC.

Such expectations mean many schools across Canada will not be able to afford air conditioning, said longtime TCDSB trustee Maria Rizzo.

“It’s too expensive,” she told CBC. “We have to replace roofs, we have to replace boilers, we have to replace windows. We have to do all of the maintenance that needs to be done” from the same budget, she said.

While she confirms that those most at-risk do need air conditioning, Metz said much can be done through passive cooling methods like painting school roof tops white, opening windows at night, installing window shades or awnings, and planting shade trees and other greenery. Those measures are inexpensive and far more sustainable than air conditioning, since they require no electricity.

Efforts at adaptation will offer considerable return on investment, Metz added.

“When considering physical damage to property and infrastructure (which is not at all the same as human health and lives), the generally accepted ratio is, every dollar invested in adaptation today saves $3 to $8 in avoided physical damages over a 10-year time period,” Metz told The Mix.

“It would be expected that investing in adaptation that protects human lives would yield returns far exceeding this,” she added, pointing to the profound ethical questions when one begins to consider “the cost of a life and lost quality of life.”

And then there is the power that schools hold as educators.

“Schools could launch an education campaign on extreme weather risk—including extreme heat—and then highlight the solutions that would help ensure people are safe in their indoor spaces,” Metz told CBC.

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“Making the switch to an electric vehicle (EV) means less pollution, cleaner and healthy communities, and savings on fuel costs. We know that British Columbians want to have confidence they will be able to charge up easily when travelling across the province,” said Josie Osborne, Minister of Energy, Mines and Low Carbon Innovation. “That’s why we are working with BC Hydro and other partners to expand B.C.’s public charging infrastructure and build an economy powered by clean, affordable electricity.”

In order to ensure that every community in B.C. has access to a fast-charging station, the CleanBC Go Electric Public Charger Program is prioritizing applications for projects that fill geographic gaps in B.C.’s charging network, that are located in rural, northern and First Nation communities, or that are located in urban areas with high EV uptake. The program will also prioritize applications for locations highly accessible to the public, including community and recreation centres, libraries, highway rest stops and park-and-ride stations.

“Transportation accounts for 40 per cent of B.C.’s emissions. That’s why it’s so important that we make it easier and affordable for people to drive zero-emission vehicles,” said George Heyman, Minister of Environment and Climate Change Strategy. “In addition to rebates, we’re investing in the charging infrastructure people and businesses need to switch to low-carbon and more affordable travel options, as we work to build a clean and sustainable future for all British Columbians.”

The program provides as much as 50 per cent of the cost of equipment and installation, and a maximum of $80,000 per fast-charging station for communities and companies in B.C. Increased rebates up to 90 per cent of projects costs to a maximum of $130,000 per station are also available for Indigenous-owned fast-charging stations.

Ron Burton, board member of the Vancouver Electric Vehicle Association said “making EV charging more available, accessible and reliable are critical steps in supporting EV adoption and furthering our Clean BC goals of reducing greenhouse gas emissions through electrification of transportation.”

B.C. has one of the largest public charging networks in Canada. At the end of 2023, there were approximately 5,000 public charging stations in B.C., an increase from approximately 1,500 stations in 2018. The Province is on track to complete B.C.’s electric highway in summer 2024 with coverage along all highways and major roads and also working toward an overall target of 10,000 public charging stations by 2030.

CleanBC’s Go Electric EV Charger Rebate program offers rebates for as much as $2,000 per charger (as much as 50 per cent of costs) toward the cost of buying and installing eligible EV charging stations for multi-unit residential buildings (condominiums and apartments) and workplaces.

British Columbians are already adopting EVs at high rates across all regions of the province. The Province’s suite of Go Electric programs are exceeding original targets and B.C. has the highest rate of EV adoption in the country. In 2023, approximately 23 per cent of light-duty vehicle sales were EVs, an increase from 18 per cent of sales in 2022.

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Summary: Markham interviews Ben Kujala, director of power planning for the Northwest Power and Conservation Council based in Portland, Oregon. They discussed the extent to which natural gas should be relied upon as a “bridge fuel” as the Pacific NW considers the right mix of wind, solar, storage, nuclear and hydropower to provide carbon-free energy at an affordable and reliable level.

Related links:

This interview has been lightly edited for clarity.

Markham Hislop: Welcome to another episode of Energi Talks, the podcast where we discuss global energy issues with experts from around the world. In this episode, I’ll be talking to Ben Kujala director of power planning for the Northwest power and conservation council based in Portland, Oregon, we’ll be discussing the extent to which natural gas should be relied upon as a bridge fuel as the Pacific Northwest considers the right mix of wind, solar, storage, nuclear, and hydropower to provide carbon-free energy at an affordable and reliable level.

To set the stage here, your organization, which is a federal agency, created under an act of Congress, is preparing its next five-year plan. That’ll come out next year. And your area that you’re dealing with is around the Columbia River. As I understand it, which has 31 hydroelectric dams that produce 22 gigawatts of power and meet 30% of the Pacific Northwest
Northwest electricity needs. Is that correct?

Ben Kujala: Mostly. So we are actually an interstate compact. The federal government did form us through a piece of legislation, but we’re a combined entity that is a cooperation between the States of Oregon, Washington, Idaho Montana. So we’re not exactly a federal agency, although we were enabled by federal legislation, one of those confusing little sort of intricate government things.

Markham Hislop: Your organization is preparing this regional plan. And I think this is a fascinating topic because, federal, national and subnational governments around the world are grappling with this issue. And part of it is that if you invest in a natural gas combined cycle today in an attempt to bring down GHG emissions, effectively you’ve committed to a 30 to 50-year investment because that asset isn’t going to be mothballed after 10 or 15 years, and that locks you into GHG emissions. Is that something that your organization is considering?

Ben Kujala: Absolutely. We are in the very initial stages of looking at results. I should say that everything that we’ve seen thus far is just very early on in our planning process. What we have definitely seen is, of course, you build a new plant and it has multiple impacts on the system.

It adds some capacity for those times where you really need energy and they can respond with dispatchable electricity to that capacity need. It also tends to displace older natural gas systems. If you do build a new plant, it doesn’t necessarily mean that you’re just adding emissions on top of all the existing emissions we have in the system because a brand new plant is way more efficient than an old plant. It tends to run when those old plants would have otherwise and in those cases, it’s reducing emissions. But there are some times where you need a lot of plants altogether and they’re all going to work in concert to meet capacity needs. And then in those times, you would have some increased emissions then maybe alternatives that you could have done instead of building a natural gas plant.

Markham Hislop:  Now, I would imagine that your organization was looking south to California this summer with the issues that came up with its blackouts and the conversation that followed about the role that renewable energy played in those blackouts. Did that influence your thinking at all?

Ben Kujala: Yeah, we and everyone else in the West were certainly looking to California. I would say that we have always been very kind of cautious about how much we rely on the exchange between the Northwest and California. When we look at resource adequacy and what we need to do to ensure that we have reliable power in the Northwest, we have some limits that we put on what we’re willing to take from California from out of our region.

I think that that just emphasized that practice is something that has always been something common in the Northwest. We tend to have more generation than node. We tend to be a long region where we produce more power than we use. But I think that’s clearly something that we’re very cautious about. And so certainly looking in there and looking at, of course, the characteristics of the generation that did put California in that spot, what was happening with imports and exports is something that everybody continues to kind of mull over.

The challenge of these things is, of course, there’s no right answer. There’s a lot of things that were going on with that situation: really high loads, extreme heat, imports and exports were pretty high during that time. A lot of it was kind of internal problems that they had. But there’s still stuff that we’re learning today and there’s the stuff that I think we’ll continue learning as we dissect that event.

Markham Hislop: Now I picked up on your comment about limiting the amount of power that your region imports. And I know that other Canadian provinces like BC, for instance, are comfortable in the 7% to 10% range of their total usage. Is that the kind of range we’re talking about for the Pacific Northwest?

Ben Kujala: We get together a bunch of experts in an advisory committee panel and we ask, what makes you sort of feel comfortable in terms of the ability to import and export? We’re still vetting that information for our current plan again.

Generally, we haven’t had a percentage. It’s been kind of at what times of the year are we more comfortable and to what level? It might be that during the off-peak hours, we’ve always felt like there’s more power available, so we’re willing to import power during the off-peak hours and back off the hydro system so that we can produce more energy in our hydro system during the peak hours.

We have different levels per season and kind of per hour load shape that we’re seeing. And that’s something that’s very dynamic with solar coming on in California, which is changing the hours that we think are going to be the ones where there’s a lot of available imports. So, we don’t have a percentage per se. We just have kind of an expert informed, ability to import that we build into our models for our analysis.

Markham Hislop: Well, let’s talk about California solar. A little shout out to our friends at Utility Dive (see Related Stories above) for an excellent article that they did on your planning process. In that article, it was mentioned that cheap California solar might be one of the things that the Pacific Northwest West relies upon. But, British Columbia is saying the very same thing. There’s only so much cheap California solar to be had and quite a bit less that can actually be transmitted out of California. All of these competing interests in the Western electricity market adds I would think another layer of complexity to your job?

Ben Kujala: I would say it kind of depends on how you see the future playing out in California. If you’ve heard of [consulting firm] E3, they’ve done a bunch of studies on the increased penetration of solar that say curtailing renewables is cheaper than having to build a lot of infrastructure like batteries to store the energy and then use it at a later time.

Now there might be other things driving you to build batteries. Certainly, California has some efforts going in that direction too, to try to build batteries for capacity. But I think most scenarios show that they’re going to build resources well ahead of the ability to store. So there’s probably going to be some renewable curtailment during different parts of the day.

If that’s the case, then as much as they cannot ship the power out, California will be perfectly happy with that result. Based on the policy that they’ve passed, it’s to their advantage to get as much power built as possible, whether California is the one using it or not. I do think you’re right. It comes down to the limits on the transmission system and the ability to export solar power out of the state. If you believe the sort of build projections that they’re putting together in the state agencies down there.

Markham Hislop: Not that long ago, I interviewed professor Lucas Davis who’s an economist at the Haas Energy Institute at Berkeley. He said that a lot of the solar that has to get curtailed is because of problems with transmission. That there are regional issues with transmission. And in California, building new transmission capacity is very difficult for environmental reasons and permitting reasons. And it takes a long time it’s very expensive. And so, you know, there was a very good chance that some of the solar will be trapped because of transmission issues.

You did mention batteries within the California context. Let’s talk about it in the Pacific Northwest context. What role do you expect batteries to play in your power system going forward?

Ben Kujala: That’s a really complicated problem in a system that has a lot of hydro, which has some ability to store power and then to produce that power at a different time. So how batteries compliment that is something that we continue to be working on. And I don’t think we’ve got a full picture of it yet. We’re still trying to refine our approach, how can batteries be complementary to the hydro system. That’s a pretty big and dynamic question, one that is not easy to answer.

So I would say that if you’re looking at a future where you’re not going to build natural gas it seems clear that batteries have some sort of role or some sort of storage has a role, whether it’s batteries or pumped storage or something else. But I still think that figuring out when, and to what extent you bring them into our system is going to be complicated. It’s something that we are working on. And I will tell you, I don’t have a simple answer for you on that one right now.

Markham Hislop: Fair enough. Batteries have really only seriously entered the power grid conversation in the last 12, 18 months, let’s say. A lot of that is driven by the really dramatic decreases in costs in lithium-ion and the dramatic costs that are being forecast between now and 2030. I think we’re talking about it just with battery packs, EV battery packs for $137 a kilowatt-hour today to maybe as low as $57 a kilowatt-hour by 2030. That’s a tremendous decrease and I would assume make batteries more attractive for organizations like yours.

I want to talk about an issue that I find fascinating, and that is how planners like yourself and your organization, take into account the electrification of the economy due to climate policy? That depends on extensive electrification. Again, using the British Columbia example, if the climate targets of the current government are met by 2050, it could mean a doubling and perhaps a tripling of power consumption in the province. That would be a tremendous amount of new generation.

I assume because we’re talking about the Western part of the US where the climate is a big issue, that similar kinds of policies are likely in place in the States that you serve.

Ben Kujala: There are some active conversations going on in the state of Washington. The governor’s got an agenda on electrification. I think the City of Seattle has some things going on as well. And I think there have been some other conversations in Oregon and some of the other states too. It’s definitely something that we are watching.

I will say our projection is considering switching from natural gas to electricity – for example, space heating like homes and commercial buildings, but also other commercial uses like commercial cooking – because it’s an immense electric load.

When you look at buildings and the way that they could add load onto the grid if you change over new construction [from gas to electricity], you’ve got stock turnover, it takes a little while. A you remove buildings and you add new ones, it adds an extra sort of increment to the electric load that could really build to be pretty amazing. If you start retrofitting buildings – taking out natural gas infrastructure and adding electric, that would be a whole nother level of electrical load on the grid.

So I think it is definitely something that could have a huge impact on electric load.

Climate is something that is going to be underlying most of our work. Since in the Northwest we worry about hydro a lot [because of water levels], it’s another thing that is impacted by climate change. We see that in the sort of initial studies that have been done in the Northwest about climate change. We see an increase in generation in the winter from the hydro system and then a decrease in the summer. And so that kind of changes the dynamics of what we’ve been traditionally used to seeing come from the generation on the hydro system.

You have to take that into account as well when you’re looking at if electrical heating increases the winter load [on the grid].

If you really start aggressively going after what is currently served by natural gas, it’s just going to go beyond our current generation fleet, no doubt.

Markham Hislop: While we’re on the subject of policy and regulation, the Utility Dive article made a very interesting point that Washington is a little more aggressive than Oregon and the other two states have an even more uncertain regulatory landscape. That makes financing of new natural gas-fired plants more difficult because you’re not certain that a plant designed to last 30 to 50 years will be around to recover its costs and be profitable. Has that come up in your considerations?

Ben Kujala: Absolutely. I will say we did our best to collect [information about regulations] not just in the Northwest, but throughout the entire West, looking at where it’s possible to build new natural gas plants. And it’s not just about regulation. I think a lot gets laid at the feet of regulators or state legislators, but there’s a lot of corporations out there with similar corporate policies. And we tried to do our best to understand that as well.

So in our region, for example, Idaho Power doesn’t have a regulation saying that it’s not going to build gas plants, but it is the main utility and it has a goal to be carbon-free by 2050. When you consider the aggregate of the regulations and the corporate goals, it does seem like it’s going to be really hard for people to build new natural gas plants in the entire West.

There’s just a few places that you could anticipate maybe seeing a couple in northwestern Montana. One of our states as well does have a in its IRP [integrated resource plan]. I think some, some plans for building gas. There seems to be some potential in Wyoming or maybe Utah, but it’s pretty limited across the West.

Markham Hislop: Let’s talk about offsets because I understand the Washington Clean Energy Transformation Act requires that all electricity sold in that state be greenhouse gas neutral by 2030, but it allows emissions or credits. What role will offsets play in your plan going forward?

Ben Kujala: I think it’s a pretty narrow set of things you can use for those offsets. It’s not just go online and find a carbon offset, sort of what you can buy if you’re a business traveller your plane’s greenhouse gas emissions. So in, in that case, one of the main things you can use is the rec’s that are created by the RPS generation. So I think it creates an extra sort of, pressure on the rec market to have more RPS qualified generation that basically can use to retire those racks so that you can continue having that kind of carbon-neutral emissions. And that’s probably going to be the most common, I think, element that they would go after. So the end result is of course you have more renewable generation being added into the system because you want more of those recs to be able to both qualify for the RPS requirements, but also offset the existing system. If you have to continue doing emissions at 2030.

Markham Hislop: I’ve been doing quite a few interviews with economists and utility policymakers about electricity markets. It’s a very hot topic these days because those jurisdictions – Alberta in Canada, a number of American states and to  certain extent in Europe – have markets that are operating efficiently to a greater or lesser degree. There’s been all sorts of lessons learned and still more fine-tuning to do. Regional electricity markets have become a hot topic lately. There are already regional markets in your area, with BC and Alberta being part of those. Is there any part of your plan that includes expanding those markets and further developing them, bringing in different types of markets to fill in gaps in the current regime?

Ben Kujala: We’re focused on long-term planning, whereas obviously markets tend to be about short-term operations. We have some ways to simulate what would happen in the West if we did have more efficient markets that we’re going to be work into our planning.

A good example is the planning reserve margin. We need to build enough generating capacity for our peak load plus some percentage, just in case. We’re very comfortable about that approach. If our forecast is wrong, we’ve got extra generation to make sure that we meet that peak. One of our theories is that with more efficient markets, we might be able to lower that planning reserve margin. That reduces the need to build new resources provide and provides some diversity as well.

But of course, any specific market is so detailed that I think to say, this is an organized market and this is not. And just be able to do a scenario and say, this is what it would be. It doesn’t work because

Every organized market I know of has different rules of engagement, different ways they’re set up, and different secondary markets (for example, ancillary services). The details matter a lot in terms of what you would project would happen in terms of planning. The best we can do is say, well, here are some things that an organized market could have an impact on and we’ll look at those areas.

Markham Hislop: I interviewed Severen Borenstein, who’s an economist at Berkeley and also sits on the board of the California independent system operator. Kind of a unique perspective that he has and he’s a big proponent of demand management. For example, allowing utilities to turn people’s air conditioning down when the system is strained. so they use less electricity when there’s high demand. He says demand management is being enabled to a large degree with new technologies and I’m wondering the extent to which those technologies are playing into your planning process.

Ben Kujala: We always start with a  world where we have a potential for demand response or demand management, as you’re talking about, and the potential for conservation or energy efficiency. Demand response in our last power plan was a great resource. It provided capacity in a system where you had a lot of surplus energy, but you needed capacity, when you’re building a lot renewables. And that tends to be the way systems are going especially prior to retiring a lot of traditional thermal generation. You will have a system with a lot of energy in it and you need capacity and demand response is an excellent resource for that.

Because of course our system, depending on the water year can have a very different amount of hydrogeneration in it. And so it might be in a really wet year, you know, we’re not going to use these programs at all, but we want to make sure that they’re available for that dry year. And I think it’s shown a lot of value because it’s, it’s not super expensive to build, it’s way cheaper than building a peaking gas plant and letting it sit there for 10 years without ever being used.

Demand response also has the ability to easily scale up and scale down.

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CN announced plans to invest $320 million across Alberta in 2018 to expand and strengthen the company’s rail network throughout the province, according to a CN press release.

“We are investing for the long haul with these projects to boost capacity and network resiliency to meet growing demand in grain, energy, forest products and other markets so important to Alberta’s economy,” said Doug Ryhorchuk, VP of CN’s Western Region

“Our investments in new double track and yard expansions, combined with new equipment and more people, will help us deliver superior service to our customers in Alberta and North America. Additionally, our substantial investments to renew our existing railway infrastructure underscores our commitment to operating safely.”

The Alberta investments are part of CN’s record $3.4 billion capital program for 2018.

They include more than 30 miles of new double track in four locations along CN’s busy transcontinental corridor across the province and rail yard expansions that will improve efficient movement of rail cars into and out of Edmonton.

Other capital program elements will focus on the replacement, upgrade and maintenance of key track infrastructure to improve overall safety and efficiency.

Planned expansion projects include:

• Construction of 12 miles of double track west of Edmonton across Parkland County
• Construction of about seven miles of double track near Wainwright, east of Edmonton
• Construction of about seven miles of double track near Tofield, east of Edmonton
• Construction of about 11 miles of double track near the Alberta-Saskatchewan border
• Installation of a new bypass track at Walker Yard in Edmonton, to increase efficiency of train movements through the yard
• Building new storage and bypass tracks at Scotford Yard northeast of Edmonton for additional car storage and improved operational efficiency
• Building new track capacity at CN’s yard in Swan Landing

Maintenance program highlights include:

• Replacement of approximately 130 miles of rail
• Installation of more than 270,000 new railroad ties
• Rebuilds of approximately 40 road crossing surfaces
• Maintenance work on bridges, culverts, signal systems and other track infrastructure

CN’s Alberta rail network includes key terminals in Edmonton and Calgary, serving customers in forest products, intermodal, agricultural and energy markets across the province.

CN investing for the long haul

Across its network, CN continues to invest in trade-enabling infrastructure and equipment.

Earlier this year, CN announced plans to acquire 350 new box cars to serve forest products and metals customers and to purchase 350 new lumber cars to meet growing demand to move wood products.

In May, CN announced that it plans to acquire 1,000 Canadian built, new generation, high-cube grain hopper cars over the next two years to rejuvenate the aging equipment needed to serve increasing annual crop yields.

This month, CN is taking delivery of the first of 60 new GE locomotives due in service in 2018. The balance of a multi-year, 200-unit order will be brought online in 2019 and 2020.

After adding hundreds of conductors to the field so far this year, CN continues to hire with a particular focus on crews in Western Canada. Approximately 1,250 new qualified conductors will be in the field network wide before next winter, compared to heading into the previous winter.

CN is also pleased to announce the establishment of a new, two-year Management Trainee Program designed to provide a solid operational background for the railway’s next generation of leaders. Over the course of the program, trainees will learn how CN operates and gain exposure to the Company’s business agenda of operational and service excellence for its customers across North America.

Successful graduates will be placed in full-time, permanent management positions aligned with individual educational background and experience.  The first 50 trainees, from both Canada and the United States, will start in July 2018.

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The United States is on pace to becoming the world’s top oil producer by 2023, thanks mainly to the phenomenal growth of shale production. The IEA estimates that by then, US output will expand by 3.7 million b/d, more than half of the world’s expected production capacity growth.

One region in particular stands out – the Permian basin in West Texas. But as Permian and Eagle Ford crude oil production doubles, growing by 2.7 million b/d by 2023, investments in new pipeline and port export capacity will be critical to getting this oil to market.

The period 2012-2014 was marked by historical supply expansion in the Permian but also lower-than-expected revenues for producers as pipeline constraints contributed to local prices $20 per barrel below the WTI benchmark. Since then, crude pipeline capacity has more than doubled and constraints have eased, as lower oil prices reduced oil supply growth.

However, Permian production expanded rapidly last year, reducing the amount of available pipeline capacity to just 160,000 b/d in Dec. 2017, or around 4 per cent of total Texas crude production.

This small capacity cushion is likely to come under pressure this year, despite capacity expansions of the Midland to Sealy, BridgeTex and Permian Express 3 pipelines.

Ultimately, Permian and Eagle Ford takeaway capacity is likely to become insufficient by mid-year, with a deficit possibly reaching as much as 290,000 b/d during the first half of 2019.

While new pipelines in Texas do not typically face much resistance from local residents, they remain complex pieces of infrastructure that take years to build. Over the next year or so, the key question for Permian producers is whether or not the planned 550,000 b/d EPIC pipeline will be up and running in 2019.

Beyond 2019, there are more than enough projects (including Sunrise, Permian Express 3, Cactus 2, and Gray Oak) to ensure plenty of takeaway capacity from the region, even if most of these are still on the drawing board. If all planned investments come to fruition, Permian nameplate capacity will more than double from its current 2.8 million b/d to 5.8 million b/d by the end of 2020.

It remains unclear at this stage whether the steel tariffs proposed by the Trump administration at the beginning of March 2018 will affect pipeline operators who have applied for an exemption. They certainly have the potential to slow down project completion, but are unlikely to derail the projects altogether.

Further down the export route, the United States also faces limitations to its ambitions of becoming an even larger crude exporter including a lack of storage in some locations and competition from product exports for infrastructure.

More critically, Gulf Coast terminals were built as import, rather than export facilities, and due to their limited depth cannot currently accommodate the largest oil tankers.

One port stands out, Corpus Christi, which is being targeted for upgrades thanks to its deeper channel and potential to accommodate larger tankers. It also has less refining capacity and doesn’t face as much competition from other oil products as Houston does, meaning it could operate as a dedicated crude-export terminal.

Over time, the US pipeline and export limitations are likely to be erased with additional investments. As a result, the IEA forecasts that export capacity will rise from 1.9 million b/d at the end of 2017 to 4.7 million b/d in 2020, and reach nearly 5 million b/d in 2023.

In the process, Corpus Christi will solidify its position as the largest crude export hub in North America.

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About half of the new US shale oil will come from the Permian Basin

Growing US shale output will soon put a strain on the country’s refining capacity and shipping facilities, including the Port of Corpus Christi which must expand its shipping channel to accommodate larger tankers.

A study by consultancy Wood Mackenzie highlights the impact of US shale on global markets and the lack of refining capacity to handle rising crude output.  Researchers with the firm say unless new infrastructure is built, the new crude could bottleneck at US Gulf Coast ports.

According to the study, US refineries can absorb up to 1 million barrels per day (b/d) of the expected 4 million b/d of additional production from US oil output.

Three-quarters of the new crude and ultra-light oil known as condensate will be sold to non-US buyers in the coming five years and will compete with Middle East and African crudes on the world markets.

US refiners run medium and heavy crudes and are unable to handle the additional light crude.  With gasoline demand expected to flag in the future, the US is slow to add processing capacity.

ExxonMobil Corp has considered expanding its light-crude refining capacity at its Beaumont, Texas refinery, however, the company has not yet approved the project.

Through 2022, most of the additional crude and condensate exports will be shipped to Europe, following that, it will be exported to Asia.

The Permian Basin will supply about half of the new, mostly-light US oil, according to Wood Mackenzie’s senior analyst for North American crude markets, John Coleman.

Coleman says he believes most of the 1.9 million barrels per day of Permian crude will be shipped to the South Texas petroleum export hub, Corpus Christi.  Currently, two pipelines which will transport crude from the Permian to Corpus Christi are under construction.

In October, the Port of Corpus Christi contracted the US Army Corps of Engineers to expand the ship channel to accommodate larger tankers.

Occidental Petroleum tested loading a very large crude carrier (VLCC) at its terminal in Ingleside, Texas, located near Corpus Christi.  The ship, capable of carrying 2 million barrels of oil, was unable to travel the Corpus Christi ship channel fully loaded.  Loading had to be completed in the Gulf of Mexico.

At this time, the Louisiana Offshore Oil Port, or LOOP, is the only US Gulf Coast facility capable of directly loading and unloading VLCCs, leaving researchers unsure if there is enough US marine terminal capacity and docks to meet the new flows.

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