Build Things Faster, 2023

Executive Summary

Canada's federal government has committed Canada to building a net zero electricity system by 2035 to achieve a net zero economy by 2050. Along the way, Canadians' vehicles, buildings, and industries will rapidly transition from being powered by fossil fuels to being largely electric-powered. Electricity Canada and its members are proud to support this goal.

This is a challenging task. To meet our goal, we must build faster than we have before.

Electricity Canada engaged Dunsky Energy + Climate Advisors to

• Identify the barriers to building infrastructure quickly in Canada

• Examine what is working well in other jurisdictions.

Dunsky interviewed 16 experts from across Canada. These experts represented utilities, regulators, governments, and civil society. Dunsky also completed a scan of best practices in seven jurisdictions with distinctive regulatory approaches, and provided case studies from Texas, Norway, Brazil, Australia, the European Union, India, and New York.

Those that were interviewed consistently identified five barriers to building large electricity infrastructure projects in Canada.

The first barrier is planning. Interviewees cited a reliance on traditional deterministic planning processes that struggles with uncertainty, that will not meet the needs of a rapid net-zero energy system transformation. Inter-provincial and inter-jurisdictional projects require more planning and agreement on funding to mitigate rate increases and ensure benefits for all parties. Furthermore, most jurisdictions need a clearly-defined, net-zero-aligned, strategic energy plan that integrates electricity planning into a broader economic and industrial strategy.

The second barrier is the existing regulatory and approvals process. Provinces and territories give direction to energy and electricity regulators in order to maintain grid reliability and ratepayer affordability. But without a clear mandate from their province, regulators cannot prioritize investments based on their alignment with net-zero goals. Interviewees described an overlapping web of provincial and federal agencies, ministries, and departments that are responsible for various parts of the approvals process. These overlaps can lead to duplication within and between federal and provincial jurisdictions.

Complicating matters, the approval processes of several federal acts were lengthy and uncertain. Interviewees also spoke about the lack of clarity around federal requirements for Indigenous consultation – not specifically the need or value of consultation itself, but rather that proponents are unclear about how to satisfy federal consultation requirements.

The third barrier is the limited capacity of permitting and regulatory bodies to assess and approve applications. Interviewees noted that federal and provincial bodies need more staff and expertise to move through processes promptly. This is especially true when it comes to approvals of less-mature technologies such as many renewables. Further, Indigenous communities face capacity constraints regarding their ability to engage effectively with these processes. Increased capacity for Indigenous and permitting bodies would reduce pressures and speed the deployment of needed infrastructure.

The fourth barrier identified by interviewees is the persistent shortage of skilled labour across Canada. Interviewees spoke about the need for more skilled workers to fill critical roles in project development and the lack of trained personnel to handle regulatory roles, such as permitting, impact assessments and Indigenous engagement processes.

The fifth barrier is capital. Projects need financing of credit-worthy parties and an effective market structure to facilitate returns over the long term. Further, investors must be mobilized during the project's early conceptualization, as financing is a precondition for successful permitting processes, regulatory applications, labour and supply chain. But a slow and uncertain process deters investors and encourages investment in other jurisdictions. To that end, interviewees pointed to the United States landmark Inflation Reduction Act as further evidence of a widening gulf between Canada and the U.S.’ competitiveness for capital. Electricity Canada notes that respondents were commenting primarily before the release of Budget 2023, and the new federal budget offers significantly more incentives to investors. We are encouraged by this positive signal from the government.

Addressing these barriers is achievable and critical to meeting Canada’s Net Zero goals. The government needs to improve clarity, consistency, capacity, and speed to improve outcomes in approvals and permitting.

Canada is not the only country that must adapt to the new energy transition. We fortunately have the benefit of learning from the experiences of others. Dunsky’s jurisdictional scan revealed other places that have successfully improved their processes. See the full report for these case studies

Our top recommendations directly address permitting and approvals processes in the electricity sector, which is the focus of this report. They are:

1. Implement the "One Project, One Approval" framework described in Budget 2023.

2. Coordinate federal project permitting and approvals through a single central federal office.

3. Build regulators' capacity to deliver on net zero goals in their decisions promptly and effectively.

Accelerating approvals and permitting are a necessary piece of achieving the broader societal net zero goals. We also offer supporting recommendations linking this report to the broader policy context. These recommendations cover Indigenous partnerships, strengthening supply chains, encouraging labour and investment, and developing standards.

Lastly, we need a strategy to successfully transition Canada’s energy system. Public policy must support the vision for a net zero Canadian electricity system. To that end we need a Canadian Electricity Strategy to clearly define where we are going by 2035 and 2050 and how we plan to get there.

Recommendations

1. Implement the “One Project, One Approval” framework described in Budget 2023

a. Harmonize permitting and approvals for projects horizontally (between ministries or departments in the same level of government) and vertically (between levels governments).

b. Implement a framework that gives proponents clear requirements for permitting applications, that adheres to permit approval timelines of 12 months from application to decision. Budget 2023 included investment in the Impact Assessment Agency of Canada and other agencies to increase capacity and accelerate permitting. This is a positive signal that the federal government is already working toward improving permitting processes.

c. Provincial assessments should be considered equivalent to federal assessments, unless the federal duty to consult Indigenous Peoples is triggered.

2. Coordinate federal project permitting and approvals through a single central federal office.

a. Manage all federal permitting and approval processes through a single federal office responsible for moving from application to decision within 12 months.

b. Make use of Strategic and/or Regional Impact Assessments, or Class Impact Assessments to standardize permitting and approvals processes for classes of projects and regions across Canada.

c. Establish a Canadian interregional transmission planning framework to accelerate processes around inter-provincial transmission line development.

d. Facilitate collaboration with Indigenous partners to address concerns early in project and strategic planning to avoid regulatory delay.

3. Support capacity building for economic regulators to:

a. Incorporate the achievement of net zero goals into the decision-making and approval processes into economic regulatory processes.

b. Align the need for accelerated decision-making speed with the regulatory goals of prudent management of affordability and reliability, and the protection of the environment and Indigenous rights.

c. Render net zero-aligned decisions under conditions of greater uncertainty from working and planning over long time frames to 2050 and rapid technological change.

Supporting Recommendations:

4. Indigenous Partnerships

a. The federal government has a duty to consult and accommodate Indigenous Peoples when their rights might be adversely impacted by resource projects. Thus, the government should play an active role to identify affected Indigenous communities as soon as projects are conceptualized to help facilitate meaningful early consultation, incorporation of Indigenous knowledge, risk mitigation and potential for partnerships and benefit-sharing opportunities.

b. The federal government should strengthen the capacity of Indigenous Peoples to more effectively participate in consultations and as partners in electricity projects.

c. The federal government should increase Indigenous access to capital.

d. The federal government should expeditiously provide comprehensive guidance and best practices on Free, Prior, Informed Consent (FPIC) for project proponents.

5. Standards development

a. Support the development of standards for net zero-aligned technologies and their deployment to reduce or eliminate the need for regulators to understand or rule on technical merits. Technology standards should be set in a way that satisfies decision making criteria to eliminate the need for additional approvals by economic regulators.

6. Supply chains

a. Continue to work to ensure the security of supply chains for equipment and materials needed to meet the net zero goals. This should include assessing and addressing the need to on-shore or “friend-shore” certain supply chain links. There is promising work happening today with the cross-border task force with U.S., and the National Supply Chain Task Force and upcoming Supply Chain Strategy.

7. Labour

a. Today, companies are limited by the availability of workers to fulfill key roles to meet current needs. Meeting net zero goals will require even more skilled workers. The federal government should define a path for ensuring that training and immigration policies, including specific training and support for Indigenous peoples, are aligned with meeting the need for skilled labour in the electricity sector.

8. A Canadian Electricity Strategy

a. Create the vision for how Canada’s electricity sector transitions to net zero by 2035 and supports the rest of the economy by 2050.

b. Define the public policy changes required to enable that vision, that considers both the constraints and opportunities regarding labour, supply chains, permitting, consultation, finance and others, as well as how to address gaps and realize opportunities.

Held Back.

Barriers to accelerating the build-out of electricity infrastructure in Canada

Prepared for:

Electricity Canada

Submitted to:

Prepared by:

Electricity Canada

275 Slater Street, Suite 1500

Ottawa, ON, K1P 5H9

Alex Kent

Director of Distribution & Regulatory Affairs

kent@electricity.ca

Dunsky Energy + Climate Advisors

50 Ste-Catherine St. West, suite 420

Montreal, QC, H2X 3V4

www.dunsky.com | info@dunsky.com + 1 514 504 9030

About Dunsky

Dunsky supports leading governments, utilities, corporations and others across North America in their efforts to accelerate the clean energy transition, effectively and responsibly.

With deep expertise across the Buildings, Mobility, Industry and Energy sectors, we support our clients in two ways: through rigorous Analysis (of technical, economic and market opportunities) and by designing or assessing Strategies (plans, programs and policies) to achieve success.

Dunsky is proudly Canadian, with offices and staff in Montreal, Toronto, Vancouver, Ottawa and Halifax. Visit dunsky.com for more information.

Executive Summary

The electricity industry across Canada is at a turning point. With two urgent and overlapping goals – to decarbonize grids by 2035 and to decarbonize the economy by 2050 – the “need for speed” in building out essential electricity infrastructure has never been greater With this in mind, Dunsky was tasked with consulting stakeholders and defining key barriers that may be holding us back from building electricity infrastructure quickly enough

From our stakeholder interviews, four broad categories of barriers emerged:

Four Barriers to Critical Electricity Buildout

1. Internal planning and strategy. Internally, planning and strategy suffer from limited consensus on key objectives and constraints. Further, planners and regulators often lack the mandate to explore options outside of their jurisdictions.

2. Regulatory processes. A growing set of unclear – and sometimes overlapping –regulatory approval processes are hindering Canada’s ability to move forward in a timely fashion. Inconsistent rules across provinces only add to the challenge.

3. Regulatory capacity. In a world of rapidly-changing technology – and faced with a sudden upward inflection in demand for electricity system investments – regulators often find themselves inadequately resourced. A history of aversion to risk can further clash with the quick and nimble decision-making required to meet climate goals.

4. Supply chain. Recent global supply chain issues are compounded by fierce international competition for both electricity-related equipment and capital. Additionally, skilled labour has not grown commensurate with the scale of need.

The barriers identified all reflect three consistent themes: a lack of clarity, a lack of consistency, and a lack of capacity. The result is simple: a lack of speed that impedes our collective ability to act, despite broad recognition of the urgency to do so

It is worth noting that these barriers play out in different ways at different levels:

• Federally, many stakeholders indicated that new and evolving regulations can be either more onerous than, or duplicative of, provincial equivalents The resulting inconsistencies can put a strain on regulatory capacity and timelines The duty to consult First Nations, while not called into question, is considered unclear for proponents to navigate, leading to additional delays and uncertainty.

• Provincial and territorial regulatory barriers vary across Canada, but a consistent theme is that goals, mandates and incentives are misaligned between regulators, utilities, and governments. Historically, regulators and utilities have held to a dual mandate of ensuring reliability (including by enabling or incenting utility infrastructure

investment) and doing so at reasonable cost. Going forward, mandates should be restated as a three-legged stool: ensuring reliability, keeping costs reasonable, and achieving climate targets Without this, regulators and system planners are hindered in their ability or will to pursue solutions at the scale, risk, and timeframe needed

• Utilities, developers, and proponents face project-level barriers. Proponents have to contend with multiple layers of bureaucratic and regulatory inertia in order to build their projects, adding delays and financial uncertainty. Labour shortages and supply chain concerns – both temporary and forward-looking – can further slow the process and add additional uncertainty to costs and timetables. Finally, many suggested that governments often set long-term goals without any clear strategies or plans to execute them.

Finally, while this report stops short of recommending specific changes, it does point to and present brief case studies of international practices that appear to address at least some of these barriers. These include:

• Australia, where a higher level of predictability with permitting and regulatory processes is in place through the proposed-respond approach to regulation

• New York, where performance-based regulation has updated and broadened utility mandates to pursue innovative ideas and projects.

• Norway, which provides reliable funding and clear long-term direction for project costs.

• The European Union, which provides renewable energy projects with preferential treatment in regulatory processes and accelerated treatment in permitting.

• Texas, which has implemented locational zoning, preferential permitting, and clear signals to renewable energy developers.

• India, where economies of scale for solar park developers are enabled through clear, long-term direction.

• Brazil, where renewable energy auctions provide financial guarantees for developers, centralized permitting to clarify the process for developers, and a long-term vision for transmission planning.

These case studies can provide inspiration for decision-makers tasked with addressing the barriers to accelerated investment in Canada’s critical electricity infrastructure.

Background and methodology

Study background

The electricity industry across Canada is at a turning point. With two urgent and overlapping goals – to decarbonize the grid by 2035 and decarbonize the economy by 2050 – regulatory delays must be limited when conceiving, siting, permitting, and constructing the infrastructure that Canada needs for this transition.

To this end, Electricity Canada engaged Dunsky to consult with stakeholders and define the key barriers that may be holding us back. The purpose of this study was to identify the barriers to building electricity infrastructure quickly in Canada

Methodology

Dunsky interviewed stakeholders from across Canada to better understand and outline the barriers to building large electricity infrastructure projects. We conducted sixteen, one-hour semi-structured interviews with stakeholders from utilities, regulators, governments, and civil society. We started each interview with four general questions, followed by several questions specific to the interviewee’s organization, and ended with an open discussion session. The opening questions asked of all interviewees were:

1. How is your organization adapting to and planning for the pace and scale of infrastructure needs to meet the 2035 net-zero electric grid and 2050 economy-wide net-zero emissions targets?

2. In your more recent experience, have you faced delays in building infrastructure due to regulatory slow-downs or faced difficulty in siting clean electricity infrastructure because of environmental regulations? Similarly, how might utility regulations and the regulatory environment shape investment decisions?

3. What are some of the interprovincial and inter-jurisdictional challenges that your organization has faced? Are any of these challenges particularly due to the roles and responsibilities of the provincial and federal governments?

4. As part of this study, we are conducting a jurisdictional scan outside Canada to identify best practices and paths forward. Are there any jurisdictions outside of Canada that you would suggest are moving in the right direction to help the sector move at the speed and scale needed?

From the stakeholder interviews, four broad categories of barriers emerged, relating to insufficient internal planning and strategy, unclear regulatory processes, inadequate regulatory capacity, and constraints with labour and capital deployment.

While we present our findings using these categories, we note that many barriers are crosscutting and/or inter-related. Within the descriptions of the barriers, we present case studies that highlight best practices from other jurisdictions around the world.

Federal Government 2023 Budget

The interviews for this study were conducted prior to March 28th, 2023, when the Federal Government released its 2023 budget. The budget includes significant investments for Canada’s clean transition, including:

• $20 billion to support the Canadian Infrastructure Bank to prioritize clean electricity investments ($10 billion for clean power; $10 billion for green infrastructure)

• Investment Tax Credits (ITC) to support investments in priority areas including clean technology, clean electricity, clean manufacturing, and clean hydrogen.

• Recapitalization fo the Smart Renewables and Electrification Pathways with an additional $3 billion to support indigenous-led projects.

The barriers presented in this study represent the views of stakeholders before these announcements were made. While we cannot speak on behalf of stakeholders, we note that at least directionally these new investments would appear to address some of the key barriers raised herein, most notably as they pertain to limited federal funding for electrificity infrastructure projects.

Barriers to building electricity infrastructure projects

1. Planning and strategy

1.1 Lack of consensus on which long-term plans to pursue to achieve net-zero targets.

Most stakeholders interviewed suggested that a major barrier to achieving net-zero targets is that most jurisdictions lack a clear strategic energy plan, and that system plans are designed to maintain the status quo but are not ready for the rapid changes needed for the energy transition.

Stakeholders indicated they cannot take certain actions as they are bound within regulatory mandates set by governments. Compounding this, many stakeholders suggest net-zero targets were set without considering the flexibility needed to align the different provinces and territories; while some provinces and territories already have nearly carbon-free grids, others are starting from a different point and will need transitional sources

Stakeholders further expressed that when plans do exist, they can be contradictory. They also expressed frustration at the lack of guidance, as there are alignment gaps between the various federal, provincial, and territorial ministries with oversight of the environment and climate change, energy and electricity systems, and economic development As one stakeholder put it, “we need clear roadmaps to 2050 that give utilities and regulators the political mandate to act in a new way that is not just maintaining the grid but is instead fundamentally transforming it – we need to know where we want to go”.

Governments’ and system operators’ energy plans, according to some stakeholders, commonly do not consider the long-term needs to decarbonize and are not aligned with 2035 and 2050 net-zero targets. Nor, they suggested, are these plans aligned with economic strategies in most provinces and territories, many of which are quickly evolving as a result of global energy transition needs.

One stakeholder referred to the decision in Quebec to build large hydropower projects in the middle of the 20th century, anticipating demand ahead of industrial development, and considering it an economic driver. Another stakeholder felt instead that supply cannot lead demand, but that regulators and utilities must have a mandate to consider the coming demand from rapid electrification.

Regulators and system planners suggested that they lack the policy and regulatory certainty of future demand to justify building out the grid. When provincial/territorial governments have not laid out a clear energy strategy and plan to reach net-zero targets, regulators and utilities are left unable or unwilling to act.

1.2 System planning models do not sufficiently account for uncertainty.

Some utilities interviewed for this study indicated that they are shifting their decision-making strategy towards probabilities rather than basing decisions on deterministic models. They continue to plan for a baseline expansion plan but are now adding in flexibility for uncertain outcomes such as load growth extremes, electric vehicle deployment, and customer defection to distributed energy resources. The utilities suggested it allows them to easily make a least-regret decision; one stakeholder suggested that system planners need to shift towards a multi-value planning practice.1

The uncertain future for most jurisdictions was a major concern raised in the interviews. One stakeholder indicated that while they had determined the size of investments needed to decarbonize their jurisdiction, they lacked the regulatory permission or certainty for pursuing all efforts towards decarbonization. Instead, they have chosen to act just within their regulatory purview and work within the regulations, which constrained and limited the options for decarbonization projects

Another stakeholder suggested that the only way to justify the system expansion is to gain a deep understanding of their grid. They prioritized monitoring and control systems to identify system changes and get better data on electrification rates in order to justify targeted system upgrades. System planners understand that they must have a deeper and more comprehensive understanding of the range of outcomes in the long-term to plan for the future energy transition.

JURISDICTIONAL CASE STUDY

Texas – Renewable Energy Zones

Since 2020 Texas is the largest renewable energy producer in the United States, passing Washington State and California. As a result of its significant growth, Texas produced over 26% of all wind power generated in the United States for 2021 (117 TWh) and 2022 (139 TWh).2

This success can be attributed to 2005 state legislation introducing Competitive Renewable Energy Zones (REZ).

This legislation connected five dedicated REZ zones with significant renewable potential (totalling 32,000 square miles) to densely populated areas3 with high-voltage direct current (HVDC) transmission. The legislation was approved by the Public Utility Commission of Texas and began construction in 2008.4

Through a competitive bid process, over 3,600 circuit miles of HVDC were installed, which allowed 18,500 MW of incremental transmission capacity for ERCOT. The project was completed by late 2013, with costs in line with historical averages.

By building ahead of demand – creating a transmission system capable of handling substantial capacity additions – IPPs and investors no longer worried if their generation would have the necessary takeaway capacity. Since project construction timescales for utility-scale renewavble are as little as 2 to 3 years, solving for transmission in advance provided developers with greater certainty regarding the financial viability of installing wind and solar capacity, as shown in Figure 1 7

Jeff Billo, ERCOT’s Manager of Transmission Planning, felt that the success of the program “worked because all of the decision-makers, stakeholders, and interested market participants were aligned” .8

In the coming years, Texas could seek to repeat its REZ success by deploying large scale transmission projects across state lines, thereby improving the resiliency of its currently isolated state grid.

2 “Electricity Data Browser,” U.S. Energy Information Administration. Retrieved from: https://www.eia.gov/electricity/data/browser/

3 “Transmission & CREZ Fact Sheet,” Powering Texas. Retrieved from: https://www.poweruptexas.org/wpcontent/uploads/2018/12/Transmission-and-CREZ-Fact-Sheet.pdf

4 “Texas CREZ Lines: How Staekholders Shape Major Energy Infrastructure Projects,” Rice University’s Baker Institute for Public Policy. Retrieved from: https://www.bakerinstitute.org/research/texas-crez-lines-howstakeholders-shape-major-energy-infrastructure-projects

5 Ibid.

6 “CREZ: Bringing Wires to Wind,” Energy, Technology, and Policy Retrieved from: https://webberenergyblog.wordpress.com/2013/03/02/crezbringing-wires-to-wind/

7 “Renewable Energy Zones: Delivering Clean Power to Meet Demand,” NREL. Retrieved from: https://www.nrel.gov/docs/fy16osti/65988.pdf

8 “Texas CREZ Lines,” Baker Institute.

Figure 1: Net renewable generation in California, New York, Texas, and Washington 2001-2022

1.3 System planners are limited in their ability to consider solutions outside of their jurisdiction.

A common theme from the interviews was that there is little clarity or coordination of policy between the federal and provincial/territorial governments. Stakeholders expressed frustration that too many approaches exist that may conflict with each other and that there is no one-size-fits-all approach.

This lack of cohesion around planning was expressed from two dimensions: inter-provincial planning and federal-provincial planning. While stakeholders generally agree that they can navigate this barrier, most agreed that projects would be built more efficiently and at a lower cost if there were greater planning coordination and integration between grids

One stakeholder referred to a study undertaken by the Transition Accelerator in 2020 which found that the fractured nature of Canada’s electrical system boundaries reduces the ability to minimize total system costs and greenhouse gas emissions.9 While the study idenfied limited inter-provincial planning of transmission, which also requires approval from the Canada Energy Regulator, as the most obvious challenge, the study also suggested that lack of harmonization across borders also restricts generation planning and siting.

Many stakeholders suggested that provincial/territorial system planners only plan up to the edge of their grid. Instead of working cooperatively and encouraging greater power trading, provincial and territorial utilities and system operators were said to plan for their system in isolation. Stakeholders expressed that provincial and territorial governments do not give utilities and system operators the mandate to cooperate with each other.

Energy regulators in the provinces and territories also said that they do not have the mandate from their government to conduct inter-regional planning. The provinces and territories, according to stakeholders, often do not lay out clear energy procurement schedules that would signal the demand needs for the long-term planning by system operators.

Several stakeholders raised the proposed Atlantic Loop Project as an example of a lack of coordinated planning between jurisdictions. Some stakeholders suggested that misaligned visions and expectations for cost allocation among the federal government and the three provincial governments is creating a barrier to moving to project forward. The problem they identified is that the provincial governments and regulators all have vested interests in the project but do not effectively cooperate, while the federal government does not supply sufficient funding to develop inter-regional planning and guide the project through

9 “A Collaborative for Greater Coordination and Integration Among the Electric Grids of Eastern Canada and the Northeastern United States: Assessment and Recommendations,” Richard Cowart, Richard Sedana, Frederick Weston, Dr. Jonathan Raab, Philippe Abergel, & Paul Burke. Submitted to the Assessment Advisory Committee of the Northeast Electrification and Decarbonization Alliance (NEDA).

Retrieved from: https://transitionaccelerator.ca/wp-content/uploads/2020/10/NEDA-Assessment-Report-October-2020-2.pdf

1.4 The need for large capital investments runs up against a deep concern for power rates (not total energy cost).

Stakeholders agree that Canada’s energy transition will require, as elsewhere in the world, significant scale-up of investment in electricity infrastructure. Yet they expressed concern that governments, utilities and regulators are both unaccustomed to the scale and pace required going forward, and ill-prepared to enable or accept them.

Specifically, stakeholders are concerned that many utilities may be hesitant to move substantial increases in investment forward due to the political sensitivity of power rate increases This can arise out of fear either that legislators – including the owners of Crown corporations – would balk at the implications, or that regulators – similarly concerned by the political sensitivity or simply accustomed to the go-it-slow approach of years past – may reject requests that are otherwise well-founded.

Stakeholders suggested that while there can be technical consensus on investment needs, there is less alignment on who – among the electricity system (i.e. ratepayers), provincial/territorial governements, federal government - should be responsible for paying what share of that cost. Some worry that such a lack of clarity can become a convenient justification for rejecting proposals.

Several stakeholders indicated a desire for substantial public funding to ease the impact on electricity rates. Many stakeholders indicated that this could be done using federal funds to reduce rate impacts and to share the costs of decarbonization, arguably a public good.

As indicated on page 2, these comments were made prior to the federal government’s recent 2023 budget

JURISDICTIONAL CASE STUDY Norway – An Enviable Economic Enterprise

Norway and Canada are both major energy exporters with ambitious climate goals. Norway also has one of the cleanest electricity grids in the world at 30 g CO2e/kWh (2021) and one of the highest electric vehicle (EV) adoption rates globally, with 86% of new car sales being EV’s in 2021.10 Norway banned routine gas flaring in 1971, implemented a carbon tax in 1991, and has recently been included in Sweden’s Electricity Certificate Market in 2012.11 12

Norway’s grid is 98% renewable energy, with hydropower feeding 92% in 2020.13 While most of Norway’s hydropower was developed in the 80’s and 90’s, it recognizes the value in installing excess renewable generation to offset nonrenewable electricity generation in its neighbouring export markets (2).14 Over the last 10 years (2012-2021), Norway has been a significant net exporter of electricity, exporting 10% of its average yearly excess generation.15

This success comes from the significant increase in wind generation since integrating with the Swedish-Norwegian Electricity Certificate Market. Governed by the Electricity Certificate Act, the market aims to increase investment in renewables by mandating annual increases in distributors certificate electricity consumption.

A certificate is 1 MWh of renewable energy from newly constructed or upgraded assets since September 2009 and since January 2004 for hydropower assets. Certificates are awarded to a generator for 15 consecutive years and can be sold on the open market or banked for future consideration. Proceeds are a value-added revenue stream for a generator’s regular income.

This acts like a cap-and-trade program but for renewable generation. It is different from more common renewable energy credits (REC) popular in North America as the latter’s pricing is subject to voluntary purchasing incentives and is unregulated in most jurisdictions.

As shown in Figure 2, increased wind generation has displaced 51% (1.7 TWh) of thermal generation while increasing its own output by 660% (10.2 TWh) over the last 10 years.16

Technological improvements and cost efficiency supported this rapid growth, but there is little doubt that a significant driver is the implementation of electricity certificates.17 The program was so successful and oversubscribed that it was cancelled to new participants in January 2022, as Norway exceeded the targets it had originally set for the certificate scheme.18

10 “Electric Vehicles Deep Dive,” IEA. Retrieved from: https://www.iea.org/reports/electric-vehicles

11 “Norway 2022: Energy Policy Review,” IEA. Retrieved from: https://iea.blob.core.windows.net/assets/de28c6a6-8240-41d9-9082a5dd65d9f3eb/NORWAY2022.pdf

12 “Background and the Role of Reductions in Meeting Environmental and Economic Objectives,” World Bank Global Gas Flaring Reduction Partnership. Retrieved from: https://flaringventingregulations.worldbank.org/norway

13 ”Norway Energy Policy Review,” IEA

14 “Norway’s hydroelectric development 1945-1990,” Torodd Jensen, Kjell Erik Stensby, Inge Vognild, & John Brittain. Retrieved from: https://publikasjoner.nve.no/rapport/2021/rapport2021_28.pdf

15 “08037: Production, Imports, exports and consumption of electric energy 1950-2021,” Statistisk Sentralbyra. Retrieved from: https://www.ssb.no/en/statbank/table/08307

16 Ibid.

17 The effect of regulatory uncertainty in green certificate markets,” Kajsa Ganhammar. Retrieved from: https://www.sciencedirect.com/science/article/pii/S03014215210045

18 “Sweden, Norway seal end of joint green subsidy scheme in 2035,” Nora Buli, Reuters. Retrieved from: https://www.reuters.com/article/usnorway-sweden-electricity-idUSKBN26922B

Figure 2: Norway’s annual generation mix 2012-2021

1.5 Governments and regulators have insufficient resources to properly track and account for emerging technologies, nor the systems to adapt and update plans accordingly.

Stakeholders from governments and regulators expressed concerns similar to those from utilities and project proponents about the ability to plan for the future and set a direction. They suggested that the wide range of outcomes and deep uncertainty around technological deployment leaves them unable to set a path. They often indicated an inability to get consensus between different levels of government with different levels of information.

In the absence of better information sharing between governments and regulators, the risks and uncertainties of some technologies may also be overstated and underappreciated. As one provincial stakeholder put it, “the risk is that prudence and good governance will get in the way of doing the best thing right now.”

Stakeholders suggested that there is insufficient data to properly evaluate new and emerging technologies, meaning government and regulators decisions have higher risk and uncertainty. This extends beyond just the electricity and energy regulators; other relevant stakeholders that are integral to developing large-scale electricity projects, like insurance regulators, financial institutions, and trade commissioners and diplomats often lack the context and knowledge to support these projects. Regulators recognize the need to give better guidance to utilities or licensed entities so that they can push the industry in the right direction.

2. Regulatory processes

2.1 Regulators do not always have clear mandates to support the investment needed to achieve net-zero targets.

Energy and electricity regulators must prioritize prudence when weighing and considering applications. Regulators are directed to focus on reliability and affordability, but this was seen by some stakeholders to create tension with longer term goals of meeting Canada’s net-zero targets for 2035 and 2050.

Several stakeholders do not believe the regulators are acting objectively In the view of these stakeholders, while the role of regulatory processes is to ensure project proponents “do their homework properly,” their experience is that these processes are more typically quasi-judicial process where regulators and agencies are incentivized to find problems in the project rather than determining if all appropriate considerations have been taken and to encourage solutions. Many stakeholders acknowledged a trade-off between prudence and speed from regulatory agencies, in which they do not have the mandate to act with the speed necessary for the clean energy transition In 2021 this arose in BC when advocacy groups pushed the government to broaden the BC Utilities Commission mandate to better support the clean energy transition.19

The government grants the regulator their mandate and discretion to approve and act, but stakeholders said this slows the process. However, stakeholders expressed that regulators should not be expected to put out technical requirements and that their role should only be to develop processes and accountability requirements to develop approval frameworks.

Utility regulators and approval agencies play a defensive role in Canada but lack the focus and direction to align their mandates with clean energy goals, according to stakeholders Without a directive or an order-in-council from the government, stakeholders suggested that the regulatory agency cannot have the mandate to consider climate targets. Stakeholders expressed that guidance from government must set a vision for the energy system and cannot simply be an open mandate, as our interviewed stakeholders indicated they instinctively know this would be overturned on appeal. Regulator mandates, they suggested, must give the process rigour and cannot be a rubber-stamp

Regulators and system planners said that they lack certainty from the demand-side for electricity, but they are bound to plan for system developments only when they have policy certainty. There is a lack of clear policies and regulations to conclude with total confidence that demand will exist, and instead system planners suggested that they work on the basis of what is current. The prudence of the regulator creates a conflict, they say, between their existing plans and the long-term targets when there is no clear policy means to get there.

In Ontario and Alberta, some stakeholders suggested there are complications in decentralized markets. While system operators and/or regulators are directed to pursue social policy objectives by government, stakeholders suggested that this is more difficult to coordinate when operating in a decentralized market with many licensed entities. Many stakeholders expressed that system operators are bound within a clear mandate and yet should play an integral role in facilitating greater investment in renewable energy projects.

Brazil – Renewable Energy Auctions and Centralized Project Licensing

Brazil reformed the electricity regulatory structure in 2004, using energy auctions to secure new capacity tied to long-term agreements with distributors.20 The first purely wind power auction was in 2009, kickstarting demand for wind energy development in the country.21 Renewable energy auctions provide stable revenue guarantees for generators while also ensuring that sustainability goals are met. These increase investor confidence in the long-term returns of renewable energy projects.22

With over 108 GW of installed capacity in 2021, Brazil has the second largest hydropower capacity in the world. Brazil’s vast landscape of river flows over elevation changes has been instrumental in helping it become one of the world’s largest hydro producers, producing over 60% of the country’s electricity.23

Centralised Project Licensing

Like Canada, Brazil has a notable indigenous population, and thus has dedicated Indigenous lands which are mostly concentrated in the Amazon.24 Central to reforms was a special scheme for the selection of large hydropower project sites. While site selection is usually by project developers, large hydro projects have higher technical and environmental complexity, which involve negotiations with different levels of government and consultations with indigenous peoples. Through the auction scheme, the Government of Brazil intends to provide a steady stream of new hydro projects so that the supply of proposed hydro

20 “Brazil Renewable Energy Auctions,” International Energy Agency & International Renewable Energy Agency Renewables Policies Database. Retrieved from: https://www.iea.org/policies/5750-brazil-renewable-energyauctions

21 “Brazil Net Metering for Distributed Generation,” International Energy Agency & International Renewable Energy Agency Renewables Policies Database Retrieved from: https://www.iea.org/policies/5752-brazil-net-metering-fordistributed-generation

22 “Renewable Energy Auctions: A Guide to Design,” Clean Energy Ministerial & IRENA. Retrieved from: https://www.irena.org//media/Files/IRENA/Agency/Publication/2015/Jun/IRENA_Renew able_Energy_Auctions_A_Guide_to_Design_2015.pdf

23 “Electricity Regulation in Brazil: Overview,” Thomson Reuters Practical Law. Retrieved from: https://ca.practicallaw.thomsonreuters.com/8-5457207?transitionType=Default&contextData=(sc.Default)&firstPa ge=true

24 “Indigenous Peoples are essential to forest conservation and the bioeconomy,” Helcio Souza & Edenise Garcia, The Nature

sites exceeds the total demand for these projects. This results in competition between project sites, resulting in only the most favorable locations chosen. A noted caveat to this approach has been the lack of human resources and a complex licensing process that has been challenging for the government. This has resulted in slower growth of large hydropower projects in Brazil. Despite this, the auction process and allocation of site selection to the government has still shown to be a net benefit to renewable development by easing developers’ work and decreasing consumer costs (3).25

Forward Planning & HVDC Transmission

In 2006, Brazil published the first 10-year Plan for Energy Expansion (PDE).26 Under direction of the Ministry of Mines and Energy, the PDE is an annual report that details Brazil’s energy generation and transmission needs for the next ten years.

Transmission expansion through Proactive Transmission Studies aim to anticipate the planning, dimensioning, and recommendation of proposed generation.27 The Ministry published the plan in English 2021 to increase the visibility to foreign investors within the energy sector.28 The 2021 report outlined generation and transmission requirements to meet the growing electricity load, which is projected to increase by 4% annually from 2021 to 2031.29 Within this period, numerous large transmission projects will be commissioned, increasing installed transmission capacity by 28%.30

Conservancy. Retrieved from: https://www.nature.org/enus/about-us/where-we-work/latin-america/brazil/stories-inbrazil/indigenous-are-essential-to-forest-conservation/

25 “Renewable Energy Auctions,” Clean Energy Ministerial

26 “Plano Decenal de Expansao de Energia,” Empresa de Pesquisa Energetica Retrieved from: https://www.epe.gov.br/pt/publicacoes-dadosabertos/publicacoes/plano-decenal-de-expansao-de-energiapde

27 “2031: Ten-Year Energy Expansion Plan,” Ministerio de Minas e Energia. Retrieved from: https://www.epe.gov.br/sitesen/publicacoes-dadosabertos/publicacoes/PublicacoesArquivos/publicacao245/Relatorio_PDE2031_Cap04_EUS.pdf

28 “MME Launches English version of the Ten-Year Energy Expansion Plan,” Empresa de Pesquisa Energetica. Retrieved from: https://www.epe.gov.br/en/press-room/news/mmelaunches-english-version-of-the-ten-year-energy-expansionplan-pde-2031

29 “2031: Ten-Year Energy Expansion Plan,” Ministerio de Minas e Energia.

30 Ibid

2.2 Too many different permits, processes, and timelines that add needless uncertainty and delays.

Stakeholders suggested that the barriers listed above are further complicated by the range of regulatory and approval agencies that project proponents must navigate.

Every province and territory has separate ministries dealing with different components of the approvals process; the functional areas of the environment, climate change, energy, and economic development are typically under separate, un-coordinated ministries. Many stakeholders expressed frustrations that they feel many of the approval processes are duplicative, whether between separate ministries (horizontally) or between the federal and provincial/territorial government31 (vertically) – they often expressed that they wished these separate government entities would have confidence in each other to effectively review and assess projects.

One stakeholder interviewed even indicated this creates a simply practical barrier to the approval process, as they must deal with inspectors from seven different agencies arriving at the site for their own independent assessments. Coordination adds complexity and cost to the project assessment. Some stakeholders questioned the value of additional environmental and consultation requirements when these factors are already well understood.

2.3 Federal regulatory requirements are increasingly becoming burdensome and unpredictable.

At the federal level, stakeholders consistently expressed that specific regulations slow the timelines for approvals and construction. Four requirements came up frequently: requirements for land consultations, the Migratory Birds Regulations, 2022, the Fisheries Act, 2019, and the Impact Assessment Act, 2019. However, stakeholders also very consistently expressed that they are able to build these delays into their timelines – it simply adds costs and reduces the speed32 .

Stakeholders lack clarity around consultation requirements – their frustration is not with the duty to consult, but the uncertainty of who to consult They indicated that the consultation requirements for Indigenous groups33 adds further uncertainty because the responsibility to identify the required groups falls on project proponents.

One stakeholder indicated that on their transmission project, they were required to consult with over thirty indigenous groups but they had to first identify the groups themselves. Stakeholders indicated the government is not resourced to do consultation directly and there is no defined timeline for the consultation process. Project proponents indicated that this coordination effort is manageable, but it adds a deep layer of uncertainty to the process. The governments have not identified specifically which groups must be consulted and project proponents say that leaving this to them adds not only significant costs and timeline delays,

31 The Regulatory Cumulative Impact Study prepared for Electricity Canada in 2019 discussed similar concerns in the transmission pain point "Redundancy and Overlap of Provincial and Federal Regulations"

32 The Regulatory Cumulative Impact Study prepared for Electricity Canada in 2019 identified similar concerns in the generation pain points "Environmental Assessment Rework, Lack of Clarity, and Over-production" and "Environmental Assessment Conflicts, Waiting, and Delays due to Public Consultation"

33 The Regulatory Cumulative Impact Study prepared for Electricity Canada in 2019 identified a related transmission pain point "Conflicts and Waiting due to Inefficiencies in the Consultation Process"

but continued uncertainty whether the consultations have been comprehensive and complete.

Some stakeholders suggested that a meaningful way to ensure smooth consultation processes is to enable First Nations ownership of projects. This has been proposed for many energy sector projects across Canada. But while ownership can lead to a smoother, less adversarial process, one stakeholder noted that financial capacity building in indigenous communities is a prerequisite, and that participation by one First Nation may not negate concerns of other nations with nearby or overlapping territorial claims.

Several stakeholders interviewed expressed that the Migratory Birds Regulations, 2022 adds construction delays, particularly to transmission projects. They suggested that it creates a barrier when planning the construction and requires crews to frequently inspect lines and place bird deterrents; one stakeholder indicated that a single nesting cavity would delay a transmission project by three years.

The Fisheries Act, 2019 was brought up as a barrier to any further development of hydropower projects. The Department of Fisheries and Oceans (DFO) has purview over any fish-bearing body of water and they are now required to authorize any upgrades or refurbishments to facilities. Further complicating this, stakeholders characterized the amendment to apply to the level of the individual fish rather than fish habitats. Stakeholders indicated that this effectively blocks most work being done on hydropower facilities, as the DFO does not coordinate with provincial/territorial ministries with similar assessments and approval processes.

The Impact Assessment Act, 2019 is also said to create a high degree of uncertainty through the Minister’s power of designation through Section 9 of the Act. This allows any stakeholder to request the impact assessment switch from the provincial/territorial to the federal level with the Impacts Assessment Act, 2019 If this gets called for, it is at the discretion of the Minister to designate it, which stakeholders suggest leads to a high degree of uncertainty on project timelines and eventual costs.

2.4 Proponents with larger portfolios have to navigate very different regulatory requirements across the country.

Canada has thirteen separate electricity systems34 and a corresponding thirteen unique electricity regulatory structures, ranging from decentralized markets (e.g. Alberta) to vertically integrated crown corporation utilities. Stakeholders we interviewed suggested that jurisdictions on both ends of this spectrum are facing the same fundamental challenge: the mandate of the regulator is prudence and vetting decisions at the cost of speed and responsiveness.

Stakeholders expressed that the provinces and territories have very different difficulties when navigating regulatory approvals. On one end, several stakeholders expressed that BC has particularly onerous approvals and that the federal approvals processes are considered much easier. On another end, some stakeholders indicated that there is a high degree of similarity

34 Detailed analysis of the different regulatory approaches is detailed in the Starting a conversation: Is there flexibility to adapt Canada’ s current utility regulation landscape? report prepared for Electricity Canada in September of 2018.

between some federal and provincial/territorial approval processes, and they expressed frustration at the duplication of efforts and assessments needed.

2.5 Regulators approval timelines delay construction, which increases costs and risks for project proponents.

Overall, the stakeholders interviewed for this study consistently indicated that they build into their construction planning cycles the delays caused by approvals, but that federal permits often significantly lengthen the timelines.

One stakeholder suggested that the timeline nearly doubles when federal approvals are required, from up to two years for their provincial/territorial processes compared to four years for federal processes; however, another stakeholder suggested that their provincial/territorial approvals process takes 3.5 years for a 500kV transmission line, with only an additional sixmonth delay from federal approvals.

Stakeholders indicated they can develop creative construction processes to deal with these potential delays. A delay of a few months in regulatory approvals might be a much longer delay if the weather window for construction is missed. They too often rely on luck to meet reasonable construction timelines when regulatory approval delays happen – and luck cannot be their strategy to build these projects faster.

Australia – Predictable Permitting

Both Canada and Australia are geographically large, with low population densities, and remote communities that pose unique challenges to developing, maintaining, and growing an electricity grid that aims to achieve a net-zero economy by 2050. Australia has differentiated itself with a more streamlined regulatory process and unique incentives to encourage permitting and building infrastructure projects.

Based on discussions with stakeholders, there is a notable difference between Australia and Canada’s regulatory approval process for large electricity projects. Canada and the United States are described as quasi-judicial, while Australia is described as a proposed-respond approach. The proposed-respond approach is more objective and transparent by weighing an application’s guidelines against pre-determined conditions known by the applicant ahead of time, reducing the uncertainty for project proponents. 35

In March 2021, the Australian Energy Regulator (AER) released a guidance note on its approach to regulatory assessments to reduce the risk of actionable Integrated System Plan (ISP) projects.36 The National Electricity Market is a large, interconnected grid which supplies 80% of the country’s electricity needs; in this context, large electricity infrastructure projects have increased financial certainty.37

The most notable consideration in the guidance note is Staging Contingent Project Applications (CPAs). A project is taken through the regulatory process in stages by breaking it down into multiple CPAs that are lodged with the AER sequentially. This reduces the risk for actionable ISP projects and increases flexibility to respond to changing market conditions or project risks as they arise. This is ideal for large projects where more time is invested in the planning and design phase to properly identify and quantify risks without having completed a holistic application

Also notable in the Australian electricity market is the recent announcement of the Capacity Investment Scheme (CIS). With a vested interest in developing its renewable electricity grid, the scheme highlights that the Government will underwrite AUD 10 billion in private and public sector investments related to new clean dispatchable storage and generation projects.

The goal of the CIS is to incentivize renewable energy development by implementing project revenue floors to cover operating costs and debt repayments. The Government pays the difference if revenues are short while also allowing the government to obtain a share of the profits whenever revenues exceed an agreed ceiling.38

35 The Western Australia Case Study previously done for Electricity Canada by Gattinger and Associates provided substantial background in our scan. Retrieved from: https://www.electricity.ca/files/reports/english/Net-Zero-IntlRegulation-and-Policymaking-Report_Gattinger-Assoc_April2022.pdf

36 “Regulation of large transmission projects,” Australian Energy Regulator. Retrieved from: https://www.aer.gov.au/networkspipelines/guidelines-schemes-models-reviews/regulation-oflarge-transmission-projects/final-decision

37 “National Electricity Market,” AEMC. Retrieved from: https://www.aemc.gov.au/energy-system/electricity/electricitysystem/NEM

38 “Capacity Investment Scheme to power Australian energy market transformation,” The Hon. Chris Bowen MP, Minister for Climate Change and Energy. Retrieved from: https://minister.dcceew.gov.au/bowen/media-releases/capacityinvestment-scheme-power-australian-energy-markettransformation

3. Regulatory capacity

3.1 Staffing levels at some government agencies are inadequate, leading to long queues and delays in approvals.

The stakeholders interviewed for this study were consistently concerned with the increasing delays with regulatory and permitting decisions39 The most consistent reasons cited were a lack of capacity to assess applications and a limited risk appetite to decide on applications. While project proponents said they build these delays into their timelines, this increases costs and slows the speed of project development. Interviewees indicated that the delays are most acute with permitting processes but are also increasingly becoming a problem with regulatory approvals.

Stakeholders suggested that some federal and provincial/territorial siting and permitting processes are redundant and overlapping, further delaying their applications. Some delays, according to stakeholders, are caused by the permit assessments, where the agency responsible for reviewing the application is understaffed. One provincial utility indicated that their regulator only has one person responsible for licensing of transmission and distribution projects.

39 The report Net Zero: An International Review of Energy Delivery System Policy and Regulation for Canadian Energy Decision Makers prepared for Electricity Canada in 2022 highlights similar concerns stating, "With multiple players in complex systems, behaviour and outcomes are hard to predict, far less control – all the more so in the face of a policy driven transformation of unprecedented scale, nature and speed."

JURISDICTIONAL CASE STUDY India – Energy Parks and Corridors

In October 2021, India set an ambitious target of 450 GW of renewable energy capacity by 2030. This commitment will require almost tripling the installed capacity in 2022.40 To reach this goal, the Ministry of Power implemented numerous schemes, including the Green Energy Corridors and the creation of Ultra Mega Renewable Energy Parks.

Ultra-Mega Renewable Energy Parks

Categorized as renewable energy installations exceeding 500 MW, India currently has nine ultra-mega solar parks with a combined capacity of 14,693 MW.41

In the renewable resource rich province of Gujarat, where about half of upcoming solar installations are planned, new land policy has mandated that all future solar and wind installations be sited inside dedicated solar-wind parks.42 There are two reasons for this:

1. Mega parks involve a state government or distribution company which provides the zoned land and a central grid connection for a park’s projects which shields developers from land risks and permitting delays.43

2. Grouping renewable projects together provides significant economies of scale which attracts global capital and enables mega parks to be cost-competitive when compared to other low-cost generating sources. The recently completed Bhadla Solar Park in India is the largest solar installation in the world with a capacity of 2,245 MW and a record low tariff of $US 32/MWh. Multiple smaller projects within a park can also benefit from operations & maintenance cost economies of scale..44

Green Energy Corridors

Sanctioned by the Ministry of New and Renewable Energy in 2015-16, the Green Energy Corridor project aims to connect India’s renewable energy rich provinces (and their renewable energy parks) to conventional power stations on the grid. Within this evolving project, Intra State Transmission System (InSTS) phases are proposed and implemented to help achieve India’s sustainability goals.

Conducted in two phases, Phase 1 of the InSTS led to the installation of 8,700 circuit km (ckm) of transmission across 8 provinces creating 20 GWA of substation capacity for renewable assets.45 Phase 2’s announcement in 2022 outlined similar goals, with 10,750 km of transmission creating 27.5 GWA of substation capacity. Phase 2 is due to be completed in less than five years, two years faster than Phase 1 and with a smaller budget.46

The Indian central government can continue to build on the success of the Energy Park & Corridor programs because it has a financial and public interest in the projects. By doing so, it can continue building projects that work towards its long-term sustainability goals quickly and economically – to the benefit of not only its people, but the planet.

40 https://www.iisd.org/story/mapping-india-energy-policy-2022update

41 https://www.pv-magazine-india.com/2020/05/13/ieefa-ultramega-solar-parks-driving-indias-clean-energy-transition/

42 https://www.pv-magazine-india.com/2019/01/28/new-solarwind-hybrid-parks-mooted-in-gujarat-land-policy/

43 https://www.pv-magazine-india.com/2019/01/28/new-solarwind-hybrid-parks-mooted-in-gujarat-land-policy/

44 https://www.pv-magazine-india.com/2020/05/13/ieefa-ultramega-solar-parks-driving-indias-clean-energy-transition/

45 https://mnre.gov.in/green-energy-corridor

46 https://www.gktoday.in/topic/green-energy-corridor-phase-ii/

3.2 Misaligned and uncertain timelines for regulatory approvals and permitting adds risk and uncertainty to project development.

There is wide variation between provinces, territories, and the federal government, which according to stakeholders depends on whether there are timeline requirements for the permitting agencies. One provincial stakeholder indicated that, while federal permitting is more onerous and difficult to comply with, there are nonetheless timeline requirements for the federal permitting, while their own province has indeterminate timelines. This does not allow for any timeline planning for the project proponent, further delaying the process.

Managing the uncertainty around indigenous consultation processes was also frequently brought up by stakeholders as a challenge because of the volume of consultations. These delays also vary by jurisdiction, with the various stakeholders interviewed in this study indicating that from “tip-to-tail” the timeline can take as little as four years and as many as ten. One stakeholder interviewed referred to the recently approved Champlain-Hudson Power Express, a $6 billion transmission project running from Quebec to New York City. This project was ultimately chosen over a less expensive option because it was understood to drastically reduce complaints and objections from local communities, which significantly increased the likelihood of the project being successfully built 47

47 https://www.eenews.net/articles/how-a-6b-transmission-project-made-it-in-new-york/

The European Union – Renewable Energy Acceleration

While most infrastructure permitting decisions take place at the regional or federal level (or a combination thereof), the EU has shown that opportunities for streamlined permitting can also exist at the international level. In late 2022, the European Commission tabled and adopted new temporary emergency regulation, titled: Laying

Down a Framework to Accelerate the Deployment of Renewable Energy

In addition to its title, the goal of this regulation is to also reduce natural gas demand, increase resilience of the electric system, and help the Union achieve its renewable energy targets. Under the proposal, renewable energy generation is presumed to be of overriding public interest which reduces delays in the permit-granting process in renewable generating projects by setting strict timelines for approval. The emergency measure only applies to specific measures which are deemed to pose no additional environmental risk or threat. Hence, the regulation broadly applies to the following areas within renewable energy development: Rooftop solar, repowered renewable plants, and heat pumps.

Accelerated Permitting for Rooftop Solar

Within the regulation, a three-month deadline for permitting approval is outlined for solar, colocated storage, and their associated grid connections. The condition of this accelerated regulation requires that:

• Solar installations and its related assets are not installed on natural ground.

• Installations need to be installed on an elevated surface for which its main function is not to produce power (I.e., office buildings, residential dwellings, etc.).

• Solar energy equipment has 50 kW capacity or less.

48 “Proposal for a Council Regulation laying down a framework to accelerate the deployment of renewable energy,” Council of the European Union. Retrieved from: https://www.consilium.europa.eu/media/60326/st15176en22.pdf

Streamlined Permit-Granting for Repowering Renewable Plants

The commission outlines a maximum permitgranting deadline of six-months for the repowering of renewable energy projects. This application process includes all relevant environmental assessments. Key beneficiaries related to this measure include the following projects:

• Onshore Wind Farms: 38 GW of onshore wind capacity is expected to reach the end of its normal operational life between 2021 and 2025. By repowering these assets, capacity and efficiency gains can be made while minimizing permitting work related to zoning and environmental impacts.

• In the case of capacity or blade sizing changes for wind assets, environmental assessments should be limited to assessing the potential impact resulting from the change in capacity or size from the original project – not from their existence.

• Onshore Solar Farms: repowered solar farms can benefit from advancements in photovoltaic efficiency and capacity gains without increasing the space occupied by these assets. Thus, resulting in no changes related to potential environmental impacts.

Accelerated Permitting for Heat Pumps

The accelerated permitting of heat pumps below 50 MW shall not exceed one-month for air source heat pumps and three-months for ground source heat pumps.48 49

49 “

content/EN/TXT/?uri=CELEX%3A52022PC0591&qid=16690209 20010

EU Council Regulation laying down a framework to accelerate the deploymen of renewable energy,” The European Commission. Retrieved from: https://eur-lex.europa.eu/legal-

3.3 Regulators lack the resources for complex risk assessment in an era of rapid change and uncertainty.

The agencies and regulators indicated that they often do not have the full amount of information and data needed to efficiently review project applications and permits. Particularly with new and less mature renewable energy technologies, they suggested that the data does not exist to evaluate proposals at the same speed as traditional technologies. Some stakeholders responsible for approvals and regulations indicated that they lack the capacity to keep up-to-date data in order to evaluate technologies due to the accelerating speed of innovation.

3.4 Regulators have not evolved their appetite for risk despite changes in the pace of investment and innovation required.

Some stakeholders indicated that delays are caused by a lack of appetite by regulatory agencies to evaluate risk differently

Stakeholders expressed frustration that renewable energy projects seem to be over-regulated when considering their lower environmental and financial risks While they are treated with the same scrutiny as traditional fossil-fuel generation, renewable resources tend to be delivered close to the original budget and with limited unanticipated expenses, in the view of some interviewees.

One stakeholder expressed frustration that it appears that all projects are evaluated equally despite large variations in the environmental risks between projects. They suggested many permits could have been approved much faster if they were evaluated on a more risk-based criteria. The scrutiny that regulators apply to these projects is not adapted to the lower inherent risk for renewable resources, according to stakeholders.

4. Labour and capital

4.1 Insufficient skilled labour to meet fast-growing needs.

Most stakeholders identified a well-known need for the Canadian economy – Canada needs more skilled workers to build the electricity infrastructure needed to support the clean energy transition. Several stakeholders also indicated the need for more training in environmental assessments, as this has been identified as a bottleneck during the permitting process for projects.

Since the demand to build infrastructure is not certain, skilled labour is not always easily ready for construction; mobilizing capital would send the necessary signals in the system to encourage the right allocation of skilled labour Other stakeholders also suggested that the role of the provinces and territories should be to lay out clear procurement timelines for projects so that the demand for labour is apparent. Similarly, the federal government was seen to not play a large enough role in funding major projects that can de-risk and ensure viability of projects, thereby giving more certainty for the demand for labour. Regulators and system operators need to also signal the demand for labour through clear planning. Without all levels of government signalling to labour markets this need, it will not materialize.

4.2 Lengthy permitting processes add significant risk to projects by exacerbating supply chain uncertainty, pricing and timelines.

Many stakeholders cited an inability to effectively mobilize capital for large electricity projects as a barrier to reaching net-zero targets. However, it is likely as much an outcome as it is a barrier. While a huge project can be conceptualized and planned, the project also needs credit-worthy parties for financing and an effective market structure to facilitate returns over the long-term to recoup the investment. However, stakeholders still often suggested that all project development begins first with mobilizing capital, as that feeds into the eventual permitting processes, regulatory applications, and labour and supply chain sourcing.

Project proponents indicated that they face financial risks and uncertainty when they have to scope their timeline for construction and permitting. One stakeholder interviewed indicated that with a two-year construction window and a three-year permitting process, there is a high degree of uncertainty about future costs even though the price must be committed when the contract is awarded. Project proponents interviewed said that a three-year risk during the permitting process before the construction window, without knowing the supply chain issues or labour costs, leads to increased uncertainty and higher project costs overall.

The inherent aspect of mobilizing capital concerned many stakeholders. With so many moving parts to the project development cycle, stakeholders expressed worry that it becomes harder to encourage investors to choose Canadian jurisdictions over other jurisdictions that are deemed easier to operate in. As suggested, an investor must commit to prices when the contract is awarded, but then deal with three to four years of risk from price volatility during the permitting process. This volatility in supply chains and component costs is a problem that is shifting the risk perception of power purchase agreements, say stakeholders.50 Compounding this is the uncertainty around permitting approvals and

timelines due to multiple layers of regulatory agencies between different jurisdictions. Stakeholders often suggested that the uncertainty translates directly into cost.

4.3 The IRA incentivizes global companies to focus limited time and resources on the US market, potentially reducing competition and driving prices up in Canada.

Throughout the interviews, a consistent theme was that the Inflation Reduction Act will draw capital away from Canada into the United States. It was often suggested that the IRA inherently offers a higher rate of return. The IRA and other guidelines by FERC have signaled improved governance structures for large DC transmission projects in the United States. One stakeholder suggested that while Canada is currently leading with DC transmission projects, the United States will catch up quickly and the supply chains will reorient accordingly.

The federal and provincial and territorial governments may not be not sending sufficient signals to mobilize capital, according to stakeholders. They often suggested that the federal government does not fund enough of the large projects to sufficiently send the signal to the industry of the direction they intend to take. As already suggested, stakeholders are concerned that the federal government does not sufficiently indicate the direction or plans needs to shift the energy system. While the federal government may have aggressive tools to push projects and set the direction, it does not mean that they can effectively use them without significant political strain. Without substantial financial incentives from the federal government, stakeholders that were interviewed are worried that the sector will continue to lack direction.

JURISDICTIONAL CASE STUDY

New York – Performance Based Regulation

Utilities and regulators have had a mandate to provide safe, reliable, and lowest-cost electricity for over a century. However, the industry is also starting to acknowledge that prudence and reliability must be paired with environmental and social governance mandates in some jurisdictions. With over 30 years of experience, the state of New York has successfully designed and implemented Performance Based Regulation (PBR) programs for utilities across New York State to better align incentives with policy objectives and customer benefits.

In April 2014, New York’s Public Service Commission (PSC) announced its Reforming the Energy Vision (REV) initiative. Central to the PBR initiative is that utilities can act as a Distributed System Platform. Utilities can pilot their own projects to spur innovative approaches to their generation and distribution problems, rather than resorting to potentially costlier but tested solutions. REV also puts distributed energy resources (DERs) on a level playing field with traditional investments. It provides incremental financial incentives such as shared saving mechanisms and accelerated depreciation schedules to enable faster recovery of REV related investments.51 Most notably, the financial enticement for REV related investments consists of up to 100 basis points in performance incentives above a utility’s authorized rate of return.52

A PBR Success Story

In December 2014, the PSC approved incentives to reward the use of cost-effective DERs through a Con Edison (Con Ed) led project titled the Brooklyn Queens Demand Management (BQDM) program.53 The project is based on the growing electricity demand in Brooklyn and Queens which would have led to capacity constraints on a portion of the grid in 2018. One proposed solution used the traditional RFP process and was expected to cost $1 billion. It also outlined the need for a new

51 “Brooklyn Queens Demand Management Program Employing Innovative Non-Wire Alternatives,” AEE Institute. Retrieved from: https://info.aee.net/hubfs/NY%20BQDM%20Final.pdf

52 “Next Generation Performance Based Regulation,” Littell, Kadoch, Baker, Bharkivar, Dupuy, Hausauer, Linvill, MigdenOstrander, Rosenow, & Xuan. Retrieved from: https://www.nrel.gov/docs/fy17osti/68512.pdf

53 “Utility Performance Incentive Mechanisms,” Melissa Whited, Tim Woolf, & Alice Napoleon. Retrieved from:

substation and transmission upgrades. This approach was shelved for a more innovative approach undertaken in the BQDM which included solutions from 89 responses in Con Ed’s request for information related to potential innovative approaches it could employ.

With the stakeholders proposed solutions, Con Ed outlined their plan to lower the projected rise in peak demand by 69 MW through non-wire alternatives, consisting of: customer side demand reduction solutions (41 MW), utility-side demand reduction solutions (11 MW), and capacitor & load transfer solutions (17 MW). The solutions were expected to defer the need for traditional infrastructure investment until at least 2021 and were approved by the PSC with a $200M budget.

This win-win scenario for the utility and customers encouraged performance incentives of up to 100 basis points to be made available by achieving specific BQDM project milestones. Within this, 45 points were tied to achieving the proposed customer-side demand reductions, 25 points were linked to increasing diversity of DERs in the marketplace, and 30 points were tied to achieving a lower cost per megawatt compared to traditional investments.

A project update in 2017 outlined that the total projected net benefits of the BQDM program was $748M from delaying load transfers further out to 2026 (principally due to lower-than-expected demand load growth) with Con Ed also only using $70M of its $200M budget.54

Overall, the project was hailed a great success and serves as an example of what non-traditional solutions spurred by performance-based regulation can accomplish with adequate incentives and stakeholder engagement.

https://www.synapseenergy.com/sites/default/files/Utility%20Performance%20Incenti ve%20Mechanisms%2014-098_0.pdf

54 “BQDM program demonstrates benefits of non-traditiona utility investments,” Coley Girouard, Utility Dive. Retrieved from: https://www.utilitydive.com/news/bqdm-program-demonstratesbenefits-of-non-traditional-utility-investments/550110/

Conclusion

While we cannot anticipate every future barrier to building out Canada’s clean electricity system, understanding where recent projects have been delayed and the uncertainties they have faced is the first step in identifying the action that can be pursued today to make achieving the decarbonization targets more likely. This report is based on extensive interviews and conversations with a wide range of people and organizations across Canada. It collects the key barriers and describes them to enable informed consideration of future policy that targets simplifying and streamlining the process necessary for building electric infrastructure.

Our four broad categories of barriers can help guide future discussions. While some barriers are more substantial and far-reaching than others, to achieve the clean energy transition that meets the net-zero targets, we must address these barriers with actions that can mitigate the delays and concerns that have been brought up in this whitepaper.

When addressing labour and capital constraints, all levels of government must continue to proactively address the current and anticipated needs of the sector. The Canadian economy has seen supply chain bottlenecks and limited skilled labour in recent years, but this cannot continue to be a barrier to developing the clean electricity grid that Canada needs.

The barrier of regulatory capacity at first appears to have a straightforward solution –capacity-building within regulators. This is certainly one element, but it cannot be the only solution. Partnerships will play the greatest role here – partnerships between jurisdictions to share best practices, partnerships with suppliers and labour to smooth the building process, and partnerships with communities and indigenous groups to ensure buy-in and support.

When dealing with barriers related to regulatory processes, there is an obvious need to develop standards and processes for greater coordination of permitting and approvals. We heard and saw the acute need to better manage the permitting and approvals process within and between different levels of government. Establishing clear policy frameworks and regulatory processes is crucial to the strategic deployment and construction of infrastructure.

Finally, when planning and strategy barriers arise, we see the need for greater harmonization of the permitting and approvals processes across different levels of government and between jurisdictions. This can ensure consistency for project proponents when siting and developing the clean electricity infrastructure that Canada needs, which will reduce the timeline delays and uncertainty of outcomes that are so often faced.

The electricity industry across Canada is at a turning point. With two urgent and overlapping goals – to decarbonize grids by 2035 and to decarbonize the economy by 2050 – the “need for speed” in building out essential electricity infrastructure has never been greater. Canada has a long history of expanding its electric system, but the need to build infrastructure to meet these decarbonization targets is a daunting compared to the development of the system until now. Meeting the necessary pace of electric system expansion will require understanding key processes that could slow down planning, permitting, and construction of building transmission, distribution, and generation that will move Canada toward clean electricity.

NO DISCLAIMERS” POLICY

This report was prepared by Dunsky Energy + Climate Advisors, an independent firm focused on the clean energy transition and committed to quality, integrity and unbiased analysis and counsel. Our findings and recommendations are based on the best information available at the time the work was conducted as well as our experts' professional judgment. Dunsky is proud to stand by our work.