INTRODUCTION

This article considers the economic regulators’ review of integrated resources planning (IRP) for gas and electric utilities in Canada. The IRP process has typically been conducted by each regulated utility considering only the energy demands of its customers without consideration of other available energy types. However, the move towards net zero greenhouse gas emissions by 2050 is driving new behaviours that include “fuel switching”, thereby placing new demands on the IRP planning process.

This article begins by looking at the historical context of public utility growth in Canada, the role of the economic regulator in the IRP process and how IRPs have historically been prepared and reviewed. It considers the role of IRP planning in both “vertically integrated” jurisdictions and in provinces that are “unbundled” thus having a wholesale electricity market. Although public utilities have a key role in the preparation of an IRP, the focus of this article is on the review of the IRP and the role of the economic regulator in that review.

The preparations underway for net-zero are profoundly affecting the IRP review process. Increased electrification and fuel switching from natural gas to electricity are affecting investment decisions in both the natural gas and the electricity sector, presenting challenges in both. A significant portion of fuel switching activity is policy driven which comes with attendant uncertainty.

Fuel switching between electricity and natural gas is largely zero-sum overall with respect to the demand utilities face. However, switch results in a loss of load for the natural gas utility and a proportionate gain in load for the electric utility this results in a coupling of electricity and natural gas demand forecasts and increases the risk of over-forecasting. As a result, this discussion paper concludes that instead of preparing and reviewing gas and electricity plans separately, they should be considered together. Further, potential net-zero impacts on the IRP planning process include the use of electricity as a transportation fuel.

The article also considers how in many cases the energy transition is significantly increasing the exposure of regulated utilities to competitive markets is — an emerging regulatory challenge as economic regulators review investment decisions in this competitive marketplace. Economic regulation was never intended to apply to this competitive market situation that public utilities find themselves in and economic regulators may not have the tools to deal with this emerging phenomenon.

The increasing occurrence of fuel switching adds risk to infrastructure investments in all sectors of the energy system. One of these risks is the risk of stranded assets. While many think this risk is confined to the natural gas infrastructure investment, the article also considers the risks to investments in the electricity sector.

In the petroleum fuels sector these risks are largely taken by the investor, or shareholder of the companies that participate in the sector. In the regulated electricity and natural gas sector, a greater proportion of the investment risk is taken by customers. While the IRP process is a key tool to mitigate these risks, imperfect forecasting methodologies and the inherent imperfections of the economic regulatory system that misalign risk and reward may still not satisfactorily mitigate these risks.

The article then questions how to leverage the competition that is emerging in the regulated utility sector to better align investment risk and reward. Other questions about the IRP process, include: Is there a plan for how an electrification scenario unfolds? Is a long-term plan needed? What is the role of market forces in the planning process and what is their impact on the role of the economic regulator?

In the absence of answers to some of these questions, we risk placing at the feet of economic regulators the responsibility to approve increasing amounts of capital (at-risk to ratepayers) in both the electricity and natural gas sectors. It also requires regulators to understand the assumptions implicit in the trajectory towards electricity — the plan that both electricity and natural gas utilities are working towards. We could also potentially turn energy planning for net-zero into a large, comprehensive — and consequently unwieldy — planning exercise.

CANADA’S ENERGY SYSTEM – THE STATUS QUO

The evolution of Canada’s energy system has generally been incremental and organic, driven largely by market forces with some significant provincial and federal government policy nudges. Technology improvements brought enough value to consumers to provide the economic impetus for most of those changes. The system evolved into — for the purpose of this analysis — an economically regulated component (delivery of electricity and natural gas) and all the rest.

While the delivery of electricity and of natural gas were considered monopoly activities that arguably justified economic regulation, there was still potential for competition between these energy sources at the margins — specifically as heating fuels — although, at least theoretically, it didn’t stop there. One could purchase a natural gas (or diesel, gasoline or other fuel) powered generator for their building, skip the connection to the monopoly electricity supplier and generate one’s own electricity. Although many hospitals and other large buildings do have such generation, it is largely for emergency back-up. It turns out generating your own electricity isn’t for the faint of heart, especially for the small user, so much that these other fuels never got much traction as a serious electricity competitor, at least where and when grid electricity was available. Where natural gas is available, it has historically often enjoyed a significant price advantage over electricity so became the fuel of choice for heating.

WHAT IS AN IRP?

An IRP is a comprehensive, long-term (typically 20+ years) plan conducted by a utility to ensure it can meet future energy demand reliably and cost-effectively. It evaluates a mix of supply-side resources (e.g., power plants or gas supply) and demand-side strategies (e.g., energy efficiency or demand response) to balance system needs. IRPs consider economic, environmental, and regulatory factors, often involving stakeholder input.

The economic regulator has no role in the development of the IRP but typically reviews it. The regulatory review of a utility’s IRP is intended to ensure that a utility’s long-term forecasts and its plans for meeting that forecast future energy demand are in the public interest, align with policy goals, and balance reliability, affordability, and environmental sustainability. The IRP review also contributes to regulatory efficiency as it provides important contextual background for any future application to build facilities that are included in the IRP.

ELECTRICITY IRP IN VERTICALLY INTEGRATED JURISDICTIONS

In British Columbia, Saskatchewan, Manitoba, Quebec, the Atlantic Canada and the Territories, most electricity is supplied by what are termed vertically integrated utilities — the utility owns and operates generation, transmission and distribution and typically operates in a monopoly franchise area and customers receive a single bill for the generation and delivery of their electricity.

Historically the electricity utility’s IRP process in these provinces has focussed on generation and transmission infrastructure, with little to no attention paid to distributing the energy to retail customers. Transmission is generally considered those lines operating at 100 KV and higher. Distribution is considered the lower voltage system (less than 100KV) along with local utility infrastructure to step voltage down before entering houses and other buildings.

IRP planning is a two-step process. The regulated utility develops a forecast for the medium to long term demand — typically about 20 years — showing what load they expect to serve and how they will serve it, in particular what new infrastructure they will need to build.

The process is fairly straight forward. First, predict medium to long term energy demand and then figure out how you are going to meet that demand. The first part is largely a macroeconomic forecasting process on the part of the utility. How big is the population of customers going to grow in my service territory and how much are they going to spend on new TVs, toasters and refrigerators. Utilities are typically required to provide more than one scenario to allow for different exogenous events, such as levels of growth or electrification.

Large lumpy loads are obtained through a bottom-up process in discussions with account managers of large commercial and industrial customers. Given the lead-time on the development of the resources to meet these loads, utilities are typically aware of these demands well in advance. Regulators review these forecasts and their underlying assumptions for reasonableness. A very interesting, but to date not particularly controversial exercise.

Next comes the “planning” part. What new infrastructure is required to meet the load forecast? The importance of an accurate forecast can’t be overstated. Capital investment is a significant driver of utility rates, and the load forecast drives capital investment decisions. Under-forecasting may leave a utility short of energy or the means to deliver it, potentially necessitating more expensive market purchases. Over-forecasting can result in overbuilding plant and equipment that may not be needed or would only begin to be needed much later in the future.

This long-term plan is filed with their economic regulator for review and approval or acceptance, often after the utility has consulted with its stakeholders.

UNBUNDLED ELECTRICITY MARKETS AND IRP PLANNING

The IRP process differs in jurisdictions that aren’t vertically integrated. In Ontario and Alberta, the electricity system is “unbundled” with separate responsibility for generation, transmission and distribution. A key aspect of an unbundled jurisdiction is the presence of a competitive wholesale market.

Multiple distribution companies, which in many cases are owned and operated by a municipality, deliver retail electricity to customers. In both provinces, the high voltage transmission system is operated by separate entity either. A separate entity, owned by or directly accountable to the provincial government, an Independent System Operator (ISO).^[2] They are responsible for planning and ensuring the adequacy of the electricity supply over the long term. The ISO is also responsible for real-time balancing of supply and demand, overseeing the wholesale market and ensuring mandatory reliability standards are maintained.

Independent owners of generation assets sell their electricity into the wholesale market where it is purchased by local distribution companies and in some cases large industrial users.

In an unbundled system, customers may receive multiple bills (or a single bill with multiple segments), including for the provision of transmission services and distribution services. If they contract directly with a generator, they are billed separately for that also.

Typically, the ISO has responsibility for IRP planning, or its equivalent in those jurisdictions. As with a vertically integrated utility, it must assemble a load forecast and ensure that there will be sufficient generation to meet that demand. In addition to ensuring sufficient generation, the ISO is responsible for transmission planning.

The ISO’s plans are often reviewed by an economic regulator. However, typically in unbundled markets investment in generation assets is not at the risk of retail and wholesale customers,^[3] and, at least in Alberta’s case, are not economically regulated. While this can still leave a role for the economic regulator, allocating the risk of generation investment between the shareholder and the ratepayer is not part of it.^[4]

In the next, we will further consider the implications of utility infrastructure built to serve a competitive market and the implications for the review of an IRP.

NATURAL GAS UTILITY IRPS

Companies that deliver natural gas to retail customers are typically not involved in the extraction, processing and transmission of the commodity. They usually obtain the commodity from someone who is involved in those activities and usually pass on its costs to obtain and transport the gas to their own system with little or no markup.

However, like electricity, natural gas supply can also be unbundled. When that is the case, customers can choose which supplier of the commodity of natural gas they will purchase from. They then pay the commodity separately from the delivery costs, which include costs for transmission (high pressure pipelines) and distribution (low pressure and local delivery infrastructure).

In either a bundled or unbundled scenario, the natural gas delivery company is typically responsible for preparing an IRP to provide the regulator with a window on its forecast demand and plans for capital investment in distribution system infrastructure.

The natural gas IRP typically focusses on investments required to the distribution system along with evaluating sources of natural gas supply, including long-term contracts, storage facilities, and transmission pipeline capacity.

THE IMPACT OF NET ZERO

The impacts of net-zero policy on the energy system are profound. Energy production and consumption is a significant driver of CO₂ emissions, and as a consequence much net-zero policy is directed at the sector. The resultant changing energy landscape impacts the IRP process in a number of significant ways.

With the adoption of net-zero policies, active competition for customers is developing between electricity and natural gas utilities. In B.C. for example, there was a Twitter war between Fortis Gas and BC Hydro about what kind of fuel you should heat your house with: “clean” electricity or “dirty” renewable natural gas.

The British Columbia Utilities Commission (BCUC) recognized in 2020 that IRP planning is no longer business as usual. Instead of looking at gas and electricity as two separate markets, they must be considered together and how the actions of the gas utility affect the electric utility — and vice versa. Fuel switching between electricity and natural gas is largely zero-sum, in that a switch results in a loss of load for the natural gas utility and a proportionate gain in load for the electric utility and vice-versa.

However, if utility forecasts only reflect the demand they expect to gain, or keep, at the expense of their competitor this increases the challenges and risks the economic regulator faces when reviewing forecasts. Therefore, the BCUC reacted by asking its major gas and electric utilities to share forecasts along with the underlying assumptions and encouraged them to also take the assumptions of the other utility into account when developing their own forecasts.

Other jurisdictions took similar measures. In the United Kingdom, on October 1, 2024, after a public consultation process the government created the National Energy System Operator (NESO), a new, public corporation responsible for planning Great Britain’s electricity and gas networks and operating the electricity system. In so doing it transferred over 2,000 employees from the investor-owned utilities that were formerly responsible for planning the electricity and gas networks and operating the electricity system.

Given the NESO’s mandate, it is clear that the “energy” in its title refers to electricity and natural gas. But is it sufficient to plan only the electricity and natural gas systems together? The IRP planning process no longer just involves the two solitudes of electricity and natural gas. Energy for transportation has always been a competitive market and hasn’t competed in any material way with electricity. However, electricity is now in the competitive zone, thereby requiring economic regulators of electricity to evaluate the potential of electricity increasingly serving a market that has always largely been served by petroleum.

Much uncertainty remains over what is the best and most cost-effective path to net-zero. For some policymakers, increasingly, the path is becoming synonymous with electricity and consequently, electrification is being pursued. Conventional wisdom suggests that electrification of the natural gas sector and of transportation fuel will result in a drop in, and, depending on the rate of electrification, a collapse of demand in those sectors.

In the natural gas sector in particular, a reduction, or collapse, in demand will result in billions of dollars of stranded assets which will impact the viability of natural gas utilities and their cost of doing business, particularly their cost of capital. To say this will be a headache for regulators is an understatement.

However, what if conventional wisdom isn’t quite right. If, on the electricity side, “they build it and no one comes,” it is electricity assets that may become stranded. While many may consider this to be an unlikely scenario, there are many factors that could affect the demand for electricity, including supply chain issues, technology breakthroughs in combustion-based fuel processes that reduce their greenhouse gas (GHG) footprint, regulatory delay on permitting electricity projects that make it difficult to sustain the pace of buildout and shifting policy and consumer uptake.

Economic regulators have an important role in overseeing a smooth transition and reviewing utility planning in a holistic way is a good start.

NET-ZERO AND THE DISTRIBUTION SYSTEM

An additional consideration in the utility planning process generally, which primarily affects the electricity sector, is the considerable investment required in the distribution system to meet increasing electrification load. A key example is the electricity infrastructure required to provide Electric Vehicle (EV) charging. While a considerable amount of attention is given to the need for more EV charging facilities, the distribution infrastructure to support that additional load is significant.

Other changes to the distribution system, such as demand response, virtual power plants and rooftop and community solar generation all serve to blur the line between distribution and generation.

These profound changes to the distribution system are resulting in the need for increased public utility investment. How does the economic regulator review these investment plans? As discussed in the previous section, this has not historically been the case. However, there is increasing recognition that is driving a more integrated approach. Incorporating distribution considerations into IRPs is becoming essential to enable economic regulators to better manage the allocation of risk and costs between shareholders and customers.

We will further examine the issue of distribution system planning in a future article.

WHAT IS A REGULATOR TO DO?

This phenomenon of competition shaping markets served by companies that are subject to economic regulation because they hold a “natural monopoly” arguably requires a complete rethinking of the regulatory framework. However, that requires legislative attention that is simply not forthcoming in most jurisdictions. In the meantime — what’s a regulator to do?

In short, it seems that the IRP process is broken. What worked well when electricity and natural gas utilities were siloed and each operated in a separate but relatively stable environment suddenly has a lot of shortcomings in the current environment. How can economic regulators navigate this challenge?

To be successful, regulators need to adopt a different approach to evaluating IRPs, in particular the load forecast. And given the range of uncertainty concerning things like heat pump and EV adoption, implementation of distributed energy resources, the change of industrial processes as they adapt to different fuels, there is a lot to evaluate.

Many don’t want an economic regulator to be making determinations on these issues. Not government, not utilities, and in many cases not even the regulators themselves — although there are regulators that see this as an opportunity to “accelerate the transition”. Perhaps nowhere is it truer that governments don’t want regulators involved in the planning process, than in jurisdictions where government owns electric utilities. And, in those jurisdictions, if regulators are involved, government can be quick to second guess, direct and/or reverse regulators’ decisions. In a future article, we will look further at the implications of government ownership and control of the electricity sector.

A number of approaches to IRP planning are possible. Perhaps it could be viewed as a spectrum, with comprehensive planning at one end. At the other end, is allowing market forces to drive investment decisions to serve as a substitute to or perhaps as a way to reduce the complexities of a comprehensive planning process. If so, what are the options in between? In the following sections, we consider this spectrum, and its implications, in a bit more detail, starting at the planning end.

WHERE’S THE PLAN?

Perhaps the first question a regulator should ask when an electric utility comes in with, say, a request to increase capital investments to provide electricity to replace natural gas, is — what’s the plan? Demonstrate that natural gas will become, and remain, unviable for the life of these new electric assets; that the pace of the conversion is achievable, that customers will behave in a way we expect them to and that electricity and/or natural gas assets are not going to end up stranded, and if they are, what are the implications for both the utility and its customers.

Similar questions should be asked about investments in electrification of transportation and other sectors. They should also be asked of natural gas utilities that want to make significant investments in their infrastructure or to experiment with lower CO₂ emitting fuels.

To answer these questions in any kind of determinative way requires a broader bigger plan — a plan with a capital P. In the parlance of the previous section, this is the “planful” end of the spectrum. The more far-reaching the impact is on the economy, the more comprehensive the plan needs to be if regulators are going to rely on it in their decision making.

However, detailed plans involving complex and far-reaching markets are notoriously difficult to prepare, and they are inevitably out of date before they’re complete. The broader the scope of the planning exercise, the more linkage is required between the plans of different sectors of the economy. Clearly, this is an extremely difficult plan to develop. While examples of planned energy transitions of this magnitude are difficult to find, perhaps one of the better comparators in complex economic planning is Soviet style central planning. That didn’t work for the Soviets — do we have reason to believe it will work any better for us?

Currently there is a paucity of any actual plans for how Canada is going to meet its international net-zero commitments. The regulator must instead look to governments’ collection of targets, carrots and sticks and evaluate the IRP’s underlying assumptions against them.

That said, an important question to ask is: Is a plan even possible? Especially a comprehensive plan that will see large sectors of the economy retooled, converted and transformed. Everybody that uses energy is being asked to consider changing the way they use it, how much they use, when they use it and what kind they use.

As a result, if net-zero emissions are to be achieved through policies of electrification, entire industrial subsectors will need to be replaced — the sector that makes parts for internal combustion engine vehicles for example. These changes involve multi-national corporations, supply chains that span borders and government industrial policy.

Assuming a plan is possible leads to other questions. The energy utility world in Canada is largely balkanized, with each province exercising jurisdiction over its own utilities, so we must ask the following:

• Who will prepare a plan?
• How many plans will there be?
• Who will coordinate multiple plans and how will multiple plans be coordinated? Will there be planning lead?
• In the absence of an overall national plan, what planning assumptions should be used in provincial or municipal plans?
• What is the scope of the plan?
• On what and whose models will the plans be developed?

These are big questions that are not easily answered. However, we will address them in a future article.

COMPETITIVE MARKETS AND CREATIVE DISRUPTION 

Creative destruction — the kind that changing fuel mixes and electrification may cause — is neither new nor necessarily undesirable. A very recent example of creative destruction, albeit not in the energy sector, is the rise of the smart phone and its impact on not only land-line based telecom, but also cameras, calculators, watches, computers, etc. — and a wide range of “apps” that have transformed the daily lives of billions of people.

That transition was far reaching and transformed many market sectors, created many new ones and destroyed others. And, importantly for this discussion, it wasn’t planned — it occurred largely organically. This example, then, could be said to represent the other end of the spectrum described in the previous section — the market driven path.

Will a market driven transition work better for the energy transition than a planned, policy-driven approach? Perhaps. However, what is different about the energy transition is a lack of a sufficient value proposition to drive it organically — at least at a pace necessary to meet governments’ international net-zero and GHG reduction commitments — and therefore a more aggressive policy-driven approach is advocated by many.

However, regulators need more than policy to make some of the decisions needed when reviewing resource plans. Particularly when there is significant uncertainty generated by regulated utilities participating in competitive markets and making what could be considered speculative investments for aggressive electrification.

WEAVING COMPETITIVE FORCES INTO THE PLANNING PROCESS 

In the absence of a plan, and given a reluctance of policy makers to let the market decide, is it possible for regulators to encourage the market to shape at least some energy system investment? And if so, do regulators have a role in so shaping? As we have seen, a transition shaped by market forces doesn’t need economic oversight and therefore requires a much different IRP planning process. If market forces shape some investment, the burden on the economic regulator is reduced.

Turning again to the BCUC, we see recent examples of an economic regulator that purposefully took steps to forbear from regulating what would otherwise be public utility activities when there was sufficient evidence that competition is present.

Approximately 15 to 20 years ago, British Columbia saw the introduction of novel alternative energy offerings, including Liquified Natural Gas/Compressed Natural Gas (LNG/CNG) for transportation and in-building, campus and district energy scale “clean” thermal systems that utilized sources such as ground source heat pumps, waste data centre heat and sewage heat recovery. The BCUC, acting on complaints that these offerings constituted markets had significant competitive attributes, so in response it conducted a landmark inquiry called the Alternative Energy Services (AES) Inquiry. This was followed by an inquiry into how best to regulate Thermal Energy Systems and a third to consider the regulation of EV charging.

The AES Inquiry found that although the Utilities Commission Act^[5] required the BCUC to regulate these offerings, in many cases it was actually in the public interest not to because they were offered into a competitive market. The Commission later applied the same principles when it requested the provincial government to exempt EV charging from economic regulation.

The example of the success of thermal energy systems in BC also illustrates the potential benefits of a more holistic approach to energy and utility planning. Thermal system, including Combined Heat and Power systems are a complementary approach to the traditional electricity vs natural gas dichotomy for building heating. Other jurisdictions have recognized this and, for example, in June 2022, New York state enacted a law opening the door to allowing utilities to build and own networks that distribute thermal energy.

Are these examples, along with the example of planning generation in unbundled jurisdictions useful to economic regulators as they oversee the IRP process? Why does competition matter so much?

Economic regulation is, at best, an imperfect tool. Competitive markets almost always provide a better outcome than even the best economic regulators can provide. Competition better aligns reward with risk. When an economic regulator approves an infrastructure investment and the demand is slower than expected, customers end up paying higher rates. Effectively the regulator has derisked the investment for the utility shareholder at the expense of the ratepayer, thus providing an incentive for the utility to overbuild.

In the regulator’s defence it is hard to get it exactly right, so this outcome is considered acceptable in a regulated monopoly environment. However, a competitive market ensures that reward follows risk.

This issue will be further explored in a companion article.

THE FUTURE OF IRP PLANNING IN CANADA?

Perhaps at least in part as a response to this additional planning complexity, Ontario and Quebec have taken steps to broaden the scope of the IRP process to ensure energy planning is integrated and considers all forms of energy including electricity, natural gas, hydrogen and other energy resources, as well as energy efficiency, storage and demand management.

In December 2024, Ontario’s Electricity Act^[6] was amended, in particular to enable the Minister to issue an integrated energy plan, and setting out several elements of that integrated energy plan to balance the Government of Ontario’s goals and objectives respecting energy for the period specified by the plan.

This change replaced previous wording that required the Minister to issue an “energy plan”, which in practice was focused on the electricity system. It also effectively removed the Ontario Energy Board’s (OEB) jurisdiction over certain aspects of the review and implementation process, This shift centralizes energy planning authority within the Ministry of Energy, reducing the OEB’s direct oversight and formal review functions concerning the development and implementation of integrated energy plans.

Bill 69^[7], tabled in the Quebec National Assembly on June 6, 2024, proposes several changes to Quebec’s Integrated Resource Planning (IRP) process, including the requirement for the Minister of Economy, Innovation and Energy to develop a 25-year IRP that includes targets for electricity and other energy sources. It also proposes an expanded role for the Régie’s to promote meeting energy needs and facilitating the energy transition. The bill also aims to streamline the Régie’s decision-making processes to accelerate the approval of new renewable energy projects.

The plan will be based on public consultations and must be submitted to the government for approval by April 1, 2026. The IRP will be updated every six years.

CLOSING THOUGHTS

The IRP process provides economic regulators with the opportunity to ensure that energy utilities’ capital projects are in the public interest and fairly apportion costs and risks between customers and the utilities’ shareholders. While historically this process has been, for the most part, relatively straight-forward and successful, an increasing number of challenges are arising as we move toward net-zero.

This article has largely looked at this process through the lens of the economic regulators role in apportioning costs and risks, making observations about the increasing role of competition between energy sources and types. These market forces fundamentally change the way that economic regulators should look at IRP planning.

While letting markets decide may be an effective approach, given the realities faced by government policy and the environment in which public utilities operate, it is not a panacea. However, there is similarly no magic bullet available that will provide economic regulators with a firm plan.

An alternative is, where possible, to let markets decide and utilities respond. This could lead to slower organic growth — unless a “killer app” comes out of unforeseen technological advances and another “iPhone revolution” catapults us to our net-zero future.

• ¹ This article is the first in a series of Positive Energy discussion pieces on energy system planning. The need to reform planning processes is a core recommendation of Positive Energy’s recent study on how to strengthen public and investor confidence in government decision-making for energy projects (see “Energy Projects and Net Zero by 2050: Can we Build Enough Fast Enough?” by Michael Cleland and Monica Gattinger profiling this research, online: <energyregulationquarterly.ca/articles/energy-projects-and-net-zero-by-2050-can-we-build-enough-fast-enough>).
• ^* David Morton is a professional engineer with over 45 years of experience. He specializes in utility regulation and energy policy. He led the British Columbia Utilities Commission (BCUC) for eight years where he, among other responsibilities, he conducted several significant inquiries for the British Columbia government. He remains involved in international energy regulatory associations and frequently participates in global conferences and mentoring sessions.
• ² In Ontario it is the Independent Electricity System Operator (IESO) and in Alberta the Alberta Electric System Operator (AESO). In the US, where wholesale markets can cover more than one state the generic term is Regional Transmission Operator (RTO).
• ³ While this is generally true in Alberta, in Ontario, a significant amount of generator contracts with the IESO are “take or pay” which transfers risk from the investor to the customer.
• ⁴ In Alberta, for example, the Alberta Utilities Commission must approve generation facilities and applies a public interest test which may include environmental considerations and whether the project enhances or maintains grid reliability and stability.
• ⁵ Utilities Commission Act, RSBC 1996, c 473.
• ⁶ Electricity Act, SO 1998, c 15, Schedule A.
• ⁷ Bill 69, An Act to ensure the responsible governance of energy resources and to amend various legislative provisions, 1^st Sess, 43^th Leg, Quebec, 2024.