By Mark Winfield

The acceleration of federal approvals for “nation-building projects” was the major theme of this week’s first ministers meeting in Saskatoon. A rush to streamline approvals for resource development and infrastructure projects has been central to the Canadian response to United States President Donald Trump’s profound disruptions to longstanding trade and security relationships.

At the provincial level, Ontario’s Bill 5 and British Columbia’s Bill 15 also propose to move aggressively to fast-track mining and infrastructure projects.

These fast-tracking efforts are fuelling debate, particularly in terms of the implications for Indigenous rights and the implicit trade-offs pertaining to the environment and climate change.

Read more: Mark Carney wants to make Canada an energy superpower — but what will be sacrificed for that goal?

Regulations often a minor factor

Project review and approval processes in Canada have already been aggressively streamlined over the past decade. The 2019 Federal Impact Assessment Act, also known as Bill C-69, was largely modelled on Conservative Prime Minister Stephen Harper’s 2012 Bill C-38 rewrite of the Canadian Environmental Assessment Act.

It’s important to determine why projects are delayed in the first place. Most move through assessment processes with little delay or controversy. Problems emerge when proposals are poorly designed, face serious technical or economic doubts, raise major environmental, climate or safety concerns, and spark significant social, political or legal conflicts over their costs, benefits and impacts.

A recent study on mining approvals in B.C., for example, found that far more mines were approved than ever actually developed. The main cause of delays was changing economic conditions. Regulation was found to be only a minor factor.

While there are always potential ways to improve review processes, the results of previous streamlining efforts suggest the need for caution about the potential for these initiatives to backfire.

Impact assessment and similar processes emerged as more than a way to accurately assess projects and their risks and benefits. They also provided a framework for managing intense social and political conflicts those projects may generate.

If these processes are streamlined too much, the conclusions of these assessments may seem illegitimate. There could be a trade-off between clear, certain outcomes and ensuring the approval process is fair and trustworthy.

Exacerbating conflict

The Harper government’s Bill C-38 reforms were intended to facilitate the construction of more oil pipelines. In the end, they only escalated the spiralling political and legal conflicts around projects like the Northern Gateway and Energy East pipelines.

The accompanying Alberta-to-B.C. Trans Mountain Expansion pipeline was only approved after a tortuous process. That culminated in the federal purchase and completion of the pipeline at a cost to taxpayers of $34 billion.

Read more: Why the Trans Mountain Pipeline expansion is a bad deal for Canadians — and the world

A similar process unfolded under Ontario’s 2009 Green Energy Act. The legislation’s aggressive bypassing of local approvals reinforced a backlash against renewable energy projects in rural communities. The end result was a nearly decade-long de facto moratorium on renewable energy development. The situation has only recently eased.

The political consequences of these efforts at streamlining are noteworthy. The Bill C-38 episode was seen as playing a role in the Harper government’s defeat in 2015. Ontario Premier Dalton McGuinty’s loss of his majority government in 2011 was also partly attributed to the rural response to the Green Energy Act.

Checks and balances

Aside from the political aspects, it’s important to recognize the value of thorough reviews for projects that are likely to be high-risk, high-cost and high-impact.

When past reviews have been rushed or cut short, they’ve undermine confidence in the decisions made — especially when even faster processes could increase the risks and costs passed on to taxpayers.

The Muskrat Falls and Site C hydro projects in Labrador and B.C., respectively, stand as testament to those risks. Both projects ran years behind schedule and billions over budget and continue to face major technical, environmental and economic challenges. Review processes can be important checks on poorly conceived, politically motivated projects.

It’s also important to think carefully about the long-term economic rationales being presented for projects. Canada is a relatively high-cost fossil fuel producer, making it unlikely to be among the last standing in a decarbonizing world.

That should raise serious questions about major investments in new fossil fuel export infrastructure. The irony of developing such projects as major wildfires, widely attributed to the impacts of climate change, burn in northern Saskatchewan and Manitoba cannot be overlooked.

Global markets for commodities like critical minerals are also uncertain and in deep flux.

The high costs of nuclear projects, as demonstrated by recent experiences in the U.S., the United Kingdom and Europe, also make them unlikely candidates to form the foundation for clean energy superpower status.

Read more: ‘Elbows up’ in Canada means sustainable resource development

‘Special economic zones’

Ontario’s Bill 5 represents the most aggressive streamlining proposal seen so far. The legislation would exempt designated “special economic zones” and even trusted proponents — such as mining companies assigned to lead projects — from all applicable provincial and municipal laws and regulations.

The province’s approach has raised fundamental questions about the rule of law, democratic governance and Indigenous rights, and jurisdictional boundaries.

Some commentators have pointed out that these zones are common in authoritarian regimes like China’s, or in jurisdictions in deep economic distress.

Others have accused Ontario of racing to the bottom in terms of health, safety and environmental standards, respect for the rule of law, Indigenous rights and basic democratic values.

All of this suggests a need for caution in further streamlining review and approval processes for major projects. These are undertakings with risks and costs that could stretch far into the future and must be properly understood before they proceed.

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Western Canadian natural gas production⁽¹⁾ hit an all-time high in November 2022, averaging 17.9 billion cubic feet per day (Bcf/d). The previous record was 20 years ago, at 17.2 Bcf/d in April 2002. In fact, 2022 included at least⁽²⁾ eight of the top ten producing months since January 2000.

Early 2000s production increased, and technology improved

Production was strong in the early 2000s, because natural gas prices were reaching historical highs and U.S. demand for natural gas imports were rising at the time. The natural gas market increasingly believed that, while gas production was growing, a lot of the accessible gas resource was already so developed, it would struggle to supply growing North American natural gas demand in the future. Because of this belief, some companies built marine terminals, mainly in the U.S., to import liquefied natural gas (LNG) on ships from overseas. Others experimented and improved existing technology to increase gas production by learning how to better hydraulically fracture horizontally drilled wells, which is called multi-stage hydraulic fracturing.

Low-cost gas production changed U.S. exports

Around 2006 to 2008, multi-stage hydraulic fracturing started increasing tight and shale natural gas production in Canada⁽³⁾, as well as shale gas and gas produced with tight oil in the U.S.⁽⁴⁾ As of 2022, gas production is again hitting record highs in both countries. Gas production is now relatively low-cost and the gas resource so large that production could continue to grow well into the future⁽⁵⁾ under some scenarios. Growing low-cost gas production also caused several U.S. LNG import terminals to convert to LNG export terminals, increasing exports of LNG⁽⁶⁾ from the U.S. and making it the largest LNG exporter in the world in 2022⁽⁷⁾.

Tight gas production has increased in western Canada

Nearly all production in Canada is from Alberta and British Columbia (B.C.). Both provinces have increasing shares of tight gas production.⁽⁸⁾ Production increases have also been supported by increasing demand over the last two decades,⁽⁹⁾ particularly from the oil sands and for power generation⁽¹⁰⁾ in Alberta. Future production growth could be supported by rising gas demand from hydrogen, ammonia production, and LNG exports.

Production costs limit most production to a few companies

In 2021, around 540 companies operated⁽¹¹⁾ natural gas production wells in western Canada. However, more than half of production in 2021 came from only eight operators. The top operators are listed in figure 2 below. Most tight and shale gas wells are more expensive to own, because they are deeper, have long horizontal legs, and because multi-stage fracturing is expensive. Smaller operators generally cannot afford to drill or buy these more costly new wells, and as a result, only a few companies operate most of the production. Smaller companies in western Canada tend to own relatively inexpensive vertical gas wells and have fairly small production volumes. In general, the more expensive wells result in much higher volumes of production, making the cost per unit of gas production from expensive wells much lower than gas production from inexpensive wells.

Figure 2: Western Canadian natural gas production shares by gas operator in 2021

Footnotes

1. Marketable natural gas is the volume of gas that can be sold to the market after impurities are removed and volumes used to power surface facilities are subtracted.
2. Not including data for the last month of 2022, because not all provincial data was published at the time of writing.
3. CER. Canada’s Energy Futures 2021 Fact Sheet: Natural Gas Production. 2021.
4. EIA. U.S. Natural Gas Gross Withdrawals from Natural Gas. 2023.
5. CER. Canada’s Energy Futures 2021 Fact Sheet: Natural Gas Production. 2021.
6. EIA. Liquefied U.S. Natural Gas Exports. 2023.
7. EIA. The United States became the world’s largest LNG exporter in the first half of 2022. 25 July 2022.
8. Download the Data and Figures file in Canada’s Energy Futures 2021 Fact Sheet: Natural Gas Production. 2021.
9. CER. Canada’s Energy Future 2021: Primary Energy Demand. 2021
10. Retirements of coal-fired electricity generation units has led to more gas-fired electricity generation in Alberta. Exploring Canada’s Energy Future: Electricity. 2021.
11. An oil and gas well in western Canada is always operated by a single company, though it can have more than one owner. Therefore, “operated production” means production by the operating company. The CER does not have data about well ownership and cannot calculate “owned production.” See Market Snapshot: Fewer natural gas companies operating in western Canada due to technological changes. 2017.

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Trudeau government stands firmly behind Trans Mountain decision

By Jim Carr and Catherine McKenna

Our government approved the Kinder Morgan Trans Mountain expansion project because we know we can – and must – grow the economy and protect the environment at the same time.

We stand firmly behind that decision, and our government continues to be a champion of Canada’s energy sector. We deliver the same message in Vancouver, in Calgary, in Ottawa, or in St. John’s: this project has been approved by the federal government and we are committed to seeing it built.

We understand that, to overcome the price discount Canadian crude currently faces, we must get our resources to global markets and diversify beyond the United States – the destination for 99 per cent of our oil exports. Thousands of jobs for middle-class families hang in the balance, and our international reputation as a good place to invest is on the line.

But we also understand that, in the 21st century, getting our resources to market requires more sustainable practices, and it means working in partnership with Indigenous peoples and the communities who could be affected by resource development. We cannot afford to take a short-sighted approach that ignores how resource extraction and consumption contribute to a changing climate that puts Canada’s communities and competitiveness at risk.

Expectations around the world are changing and we must change with them. That’s why we worked with the provinces and territories – building on real leadership from Alberta and British Columbia – to develop Canada’s first national plan for clean growth and climate action. In fact, Alberta Premier Rachel Notley’s work to establish a credible climate plan (which accounts for emissions from oil and gas development and puts a price on carbon pollution) provides assurance that the Kinder Morgan pipeline is compatible with our overall efforts to fight climate change.

The top companies operating across the country already recognize that strong environmental performance and corporate social responsibility are key to their competitiveness. Our government’s approach to regulating projects, reducing carbon pollution, and encouraging clean innovation aims to build on their example and set a high bar for all resource development.

Simply put, any natural resource development needs to demonstrate how it will fit within our national climate and clean growth plan – because meeting our climate targets is non-negotiable. Our interim principles for environmental reviews, as well as our proposed changes to the impact assessment system, are designed to restore confidence that good projects will move forward in a more predictable, timely, and transparent process that not only protects our environment and respects Indigenous rights, but provides the certainty that businesses need.

Recently, the B.C. government announced it would consult on restricting oil exports from its coast due to a perceived lack of oceans protection.

Our oceans are valued by – and are essential to – all Canadians. We share British Columbians’ concerns about safeguarding our coast. In 2016, our government launched a world-leading Oceans Protection Plan, committing $1.5 billion to better care for our coasts and oceans, including the largest investment in years in the Canadian Coast Guard and our emergency response capacity.

If the B.C. government wants to explore how it can further support these efforts to protect our waters and coastal communities, we welcome that.

But let us be clear: the federal government will not allow any province to infringe on federal jurisdiction over making decisions about resource development in the national interest. The impacts and benefits of the Trans Mountain expansion project reach beyond the borders of any single province. It stands to benefit Canadians across the country, just as the existing Trans Mountain pipeline has done since 1953.

No one wins if we approach resource development as a trade-off between the environment and the economy. Canadians learned that lesson the hard way under the Harper government. That’s why we’re taking a new approach that provides more certainty, better protects our climate, oceans, and the environment, and makes it possible to get our resources to market through safe and sustainable practices.

Our government will continue working with every province and territory to build a stronger economy and a more sustainable resource sector – because that’s what Canadians expect and deserve.

Jim Carr is federal minister of Natural Resources. Catherine McKenna is the federal minister of Environment and Climate Change.

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The bomb cyclone weather event in early Jan. 2018 resulted in record levels of U.S. natural gas demand and elevated wholesale natural gas and power prices around the country as reported in a special EIA analysis.

A constrained natural gas pipeline network led to a significant increase in oil-fired and dual-fuel generation in New England and New York, and, to a lesser extent, in the Mid-Atlantic.

Day-ahead daily average peak-period power prices for January 5, 2018, one of the coldest days of the weather event, reached $247 per megawatthour (MWh) in New England and New York and $262/MWh in the Mid-Atlantic, compared with $30MWh–$50/MWh average prices in the preceding six weeks.

Power markets in the Northeast and Mid-Atlantic have become more reliant on natural gas over the past several years following the retirement of electricity generators that use fuels other than natural gas.

However, the relative moderation in power price spikes during this year’s cold snap—despite higher natural gas prices—reflects a host of market rule changes and winter preparedness actions taken by the region’s grid operators to improve winter reliability.

In New England, retirements of the Vermont Yankee nuclear plant, the Brayton Point coal plant, and the Salem Harbor coal- and oil-fired plant (which is currently being converted to natural gas), as well as expansions of the natural gas pipeline network, have led the region to become more reliant on natural gas over the past couple years.

The Independent System Operator of New England’s (ISO-NE) Winter Reliability Program has provided incentives for generators to procure adequate onsite fuel supplies for winter and spurred 1,774 megawatts (MW) of natural gas-fired generators to add dual-fuel capability, which allows them to switch fuels or co-fire multiple fuels simultaneously.

More than one-third of New England’s natural gas capacity has dual-fuel capability with oil as their secondary source, while about 40 per cent of oil capacity can switch to natural gas and about 50 per cent of coal capacity can switch mainly to oil.

Natural gas dropped at one point to a low of 17 per cent. One of the region’s three nuclear plants, Pilgrim, experienced an unexpected outage for six days during that period.

ISO-NE has also made market design changes to improve winter reliability, including allowing generators to submit and update supply offers for each hour of the day as opposed to a single supply offer for an entire day.

Dual-fuel generators can now specify the percentage of fuels they plan to use and the costs for each fuel.

These changes allow generators to offer their resources into the market with more accurate representations of their operating costs.

The breakout by fuel for dual-fuel generators is not currently reported. Nuclear generators accounted for about 30 per cent of total generation, and dedicated natural gas and renewables accounted for the remaining 35 per cent.

In New York, natural gas makes up more than half of the state’s total generating capacity, and about 70 per cent of natural gas capacity can switch to oil.

About 20 per cent of oil capacity can switch to natural gas, and 13 per cent of coal capacity can switch to oil or natural gas.

NYISO has taken actions similar to those in ISO-NE to improve winter reliability. NYISO increased generator fuel surveys and site visits, used generators with higher-priced offers when units committed in the day-ahead market could not run, and developed a streamlined process with New York state agencies for generators to request temporary emission waivers if needed for reliability.

NYISO made several market design changes, including increasing the system’s total operating reserve requirement from 1,965 MW to 2,620 MW and implementing new pricing methodologies that allow energy and ancillary service prices to rise higher to more accurately reflect costs for maintaining reliability, especially during reduced supply periods.

PJM in the Mid-Atlantic region is a much larger system that relies on natural gas to a lesser extent than ISO-NE and NYISO.

About 40 per cent of the market’s natural gas generators can switch mainly to oil, while 15 per cent of coal capacity can switch to natural gas or oil, and 4 per cent of oil capacity can switch mainly to natural gas.

Oil generation peaked at 9 per cent of the generation mix on Jan. 7 and averaged 4 per cent during the 12-day period from Dec. 28 to Jan. 8.

Coal generation averaged 40 per cent during the same time period, compared with about 30 per cent the week before.

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Batteries can help balance electricity supply and demand on multiple time scales

Driven largely by installations over the past three years, the electric power industry has installed about 700 megawatts (MW) of utility-scale batteries on the U.S. electric grid, according to the U.S. Energy Information Administration.

As of Oct.  2017, these batteries made up about 0.06 per cent of U.S. utility-scale generating capacity. Another 22 MW of batteries are planned for the last two months of 2017, with 69 MW more planned for 2018.

New energy storage information available in the 2016 edition of EIA’s Annual Electric Generator Report provides more detail on battery capacity, charge and discharge rates, storage technology types, reactive power ratings, storage enclosure types, and expected usage applications.

Batteries, like other energy storage technologies, can serve as both energy suppliers and consumers at different times, creating an unusual combination of cost and revenue streams and making direct comparisons to other generation technologies challenging.

The decision to build a new power plant depends in part on its initial construction costs and ongoing operating costs.

Although battery projects have a relatively low average construction cost, they are not stand-alone generation sources and must buy electricity supplied by other generators to charge and cover the round-trip efficiency losses experienced during cycles of charging and discharging.

Battery costs also depend on technical characteristics such as generating capability, which for energy storage systems can be described in two ways:

• Power capacity or rating. Measured in megawatts, this is the maximum instantaneous amount of power that can be produced on a continuous basis and is the usual type of generator capacity discussed
• Energy capacity. Measured in megawatthours (MWh), this is the total amount of energy that can be stored or discharged by the battery

A battery’s duration is the ratio of its energy capacity to its power capacity. For instance, a battery with a 2 MWh energy capacity and 1 MW power capacity can produce at its maximum power capacity for 2 hours.

Actual operation of batteries can vary widely from these specifications. Batteries discharged at lower-than-maximum rates will yield longer duration times and possibly more energy capacity.

Short-duration batteries are designed to provide power for a very short time, usually on the order of minutes to an hour, and are generally less expensive per MW to build. Long-duration batteries can provide power for several hours and are more expensive per MW.

On the revenue side, batteries have relatively low capacity factors because of charging durations and cycling limitations for optimal performance.

Nevertheless, they can uniquely capture a range of value streams, which can sometimes be combined to improve project economics. Some of the uses for batteries include:

• Balancing grid supply and demand.  Batteries can help balance electricity supply and demand on multiple time scales (by the second, minute, or hour).  Fast-ramping batteries are particularly well suited to provide ancillary grid services such as frequency regulation, which helps maintain the grid’s electric frequency on a second-to-second basis.
• Peak shaving and price arbitrage opportunities. By buying power and charging during lower-price (or negative-price) periods and selling power and discharging during higher-price periods, batteries can flatten daily load or net load shapes.  Shifting portions of electricity demand from peak hours to other times of day also reduces the amount of higher-cost, seldom-used generation capacity needed to be online, which can result in overall lower wholesale electricity prices.
• Storing and smoothing renewable generation. Storing excess solar- and wind-generated electricity and supplying it back to the grid or to local loads when needed can reduce renewable curtailments, negative wholesale power prices coincident with wind and solar over-generation, and price spikes related to evening peak ramping needs.  Co-locating batteries with solar and wind generators allows system owners to more predictably manage the power supplied to the grid by combined renewable-generator-and-battery systems.
• Deferring large infrastructure investments.  Local pockets of growing electricity demand sometimes require electric utilities to build expensive new grid infrastructure such as upgraded substations or additional distribution lines to handle the higher demand, which can cost upwards of tens of millions of dollars.  Installing batteries at strategic locations, at a much lower cost, enables utilities to manage growing demand while deferring large grid investments.
• Reducing end-use consumer demand charges. Large power consumers such as commercial and industrial facilities can reduce their electricity demand charges, which are generally based on the facilities’ highest observed rates of electricity consumption during peak periods, by using on-site energy storage during peak demand times.
• Back-up power. Batteries can provide back-up power to households, businesses, and distribution grids during outages or to support electric reliability.  As part of an advanced microgrid setup, batteries can help keep power flowing when the microgrid is islanded, or temporarily electrically separated, from the rest of the grid.

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