Published: February 6, 2024
Overview:
Authorized returns on equity (ROE) have increased for many Canadian electric and gas utilities, as regulators recognize that the cost of capital has risen for all companies, including regulated utilities. The most prevalent signs of shifting financial fundamentals are found in bond markets. Over the past two years, the Bank of Canada ratcheted short-term interest rates to 5.0% (the highest level in 22 years) to combat inflation well above the targeted 1-3% range.
Figure 1: Bank of Canada Overnight Rate
In response, Canadian government and utility bond yields increased by 150 to 200 basis points since 2022 as restrictive monetary policy contributed to tighter conditions in credit markets. While moderating in recent months, 10-year Canadian government bond yields remain between 3.25% and 3.50%, heralding an end to the ultra-low interest rate environment that followed the financial crisis of 2008–2009.
Figure 2: 10-year Canadian Government Bond Yield and Utility Bond Yield1
Deemed equity ratios have also increased for several Canadian gas and electric utilities as regulators acknowledge that public policy mandates related to the energy transition equate to higher business risk for these companies. Despite recent increases to equity ratios for several Canadian utilities, the deemed equity thickness in Canada remains well below the U.S. average, as shown in Tables 1 and 2 below. The following section summarizes recent cost of capital decisions across Canada.
Summary of Recent Decisions:
Alberta – The Alberta Utilities Commission (AUC) concluded a generic cost of capital (GCOC) proceeding in which the AUC implemented an ROE formula tied to changes in government bond yields and utility credit spreads. The base ROE was set at 9.0%, and the formula return for 2024 will be 9.28%. This is the highest authorized ROE in Alberta in over a decade and represents a substantial increase over the previous return of 8.50%. The AUC also heard arguments regarding the deemed equity ratio but did not make any changes in that regard. (Decision 27084-D02-2023, released October 9, 2023)
British Columbia – The British Columbia Utilities Commission (BCUC) also concluded a GCOC proceeding for FortisBC Energy Inc. (a gas distribution utility—FEI) and FortisBC Inc. (an electric utility—FBC). The BCUC increased the authorized ROE for both companies to 9.65% based on the average results for a North American proxy group, as compared to the previous return of 8.75% for FEI and 9.15% for FBC. The BCUC also recognized that the energy transition had caused an increase in FEI’s business risk, and the deemed equity ratio was increased from 38.5% to 45.0% to account for the higher risk. FBC’s deemed equity ratio was also increased from 40.0% to 41.0%. The BCUC has initiated Stage 2 of the GCOC proceeding to review the authorized cost of capital for smaller utilities, including Pacific Northern Gas, and to determine which utility, if any, will serve as the benchmark in British Columbia. (Decision G-236-23, issued September 5, 2023)
New Brunswick – The New Brunswick Energy and Utilities Board, in a Rehearing Decision based on an appeal by Liberty Utilities (formerly Enbridge Gas New Brunswick), approved an ROE of 9.8% on a 45% common equity ratio. The ROE was down from the 10.9% last set for the Company in 2010, while the equity ratio remained unchanged. (Rehearing Decision Matter No. 491, issued November 18, 2022)
Nova Scotia – The Utilities and Review Board (UARB) maintained the authorized ROE for Nova Scotia Power (NS Power) at 9.0% in the first general rate case for the Company since 2012. The UARB recognized that energy transition issues in Nova Scotia (specifically the requirement to retire coal generation facilities and replace the power with renewable resources) increased the business risk for NS Power. Consequently, the deemed equity ratio for NS Power was increased from 37.5% to 40.0%. NS Power’s request for a storm cost deferral account to recover extraordinary storm costs above the level in base rates was also approved. (Decision 2023 NSUARB 12, M10431, issued February 2, 2023)
The UARB also approved a settlement agreement for Eastward Energy (formerly Heritage Gas), which included an authorized ROE of 10.65%, a decrease from the 10.8% last approved for the Company in 2011, and a deemed equity ratio of 45.0%, unchanged from its prior level. (Decision 2023 NSUARB 166, M10960, issued September 20, 2023)
Ontario – The Ontario Energy Board (OEB) recently issued a decision on Enbridge Gas’ request for a higher common equity ratio. The OEB found that Enbridge Gas’ business risk had increased due to the energy transition, although the OEB determined that it was partially offset by the amalgamation of Enbridge Gas Distribution and Union Gas. Consequently, the OEB increased the deemed equity ratio for Enbridge Gas from 36.0% to 38.0%. The OEB sets the authorized ROE for electric and gas utilities under a formula mechanism that adjusts the return each year based on changes in government bond yields and utility credit spreads. The formula return in 2024 will be 9.21%, down from 9.36% in 2023. The OEB has also indicated that it plans to review the formula and the deemed equity ratios for Ontario’s regulated electric and gas utilities in 2024. (Decision and Order EB-2022-0200, issued December 21, 2023; OEB letter, Chief Commissioner Mid-Year Update 2023–24, October 19, 2023)
Prince Edward Island – The Island Regulatory and Appeals Commission (IRAC) approved a settlement agreement for Maritime Electric Company that maintains the authorized ROE of 9.35% on 40.0% common equity. The settlement also included a provision that removed the hard cap on Maritime Electric’s earnings, such that the Company is now allowed to retain up to 35 basis points of actual earnings above the authorized level. (Order UE23-04, released April 24, 2023)
Pending Cases:
Newfoundland and Labrador – Newfoundland Power filed a general rate application in November 2023 that included a request to increase the authorized ROE from 8.50% to 9.85% while maintaining the deemed equity ratio of 45.0%. The application is currently pending, and a decision is expected later in 2024.
British Columbia – A Stage 2 proceeding is underway in British Columbia, where the BCUC will set the authorized ROE and equity ratio for smaller utilities, including Pacific Northern Gas, as well as determine what company will serve as the benchmark utility.
Table 1: Canadian Electric Utilities
| Operating Utility | Deemed Equity Ratio | Authorized ROE | Recent Changes |
| Alberta Electric Utilities | 37.0% | 9.28% | ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented |
| FortisBC Electric | 41.0% | 9.65% | ROE increased from 9.10%; equity ratio increased from 40% |
| Ontario Electric Utilities | 40.0% | 9.21% | ROE decreased from 9.36% under formula |
| Maritime Electric | 40.0% | 9.35% | Raised cap on earnings to 9.70% |
| Newfoundland Power | 45.0% | 8.50% | Pending |
| Nova Scotia Power | 40.0% | 9.00% | Equity ratio increased from 37.5% due to energy transition risk |
| Canadian Electric Avg | 40.5% | 9.17% | |
| U.S. Electric Utility Avg2 | 51.6% | 9.66% |
Table 2: Canadian Gas Distribution Utilities
| Operating Utility | Deemed Equity Ratio | Authorized ROE | Recent Changes |
| ATCO Gas Distribution | 37.0% | 9.28% | ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented |
| Apex Utilities | 39.0% | 9.28% | ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented |
| Eastward Energy | 45.0% | 10.65% | ROE decreased from 11.0% |
| Enbridge Gas | 38.0% | 9.21% | Equity ratio increased from 36.0% due to energy transition risk |
| FortisBC Energy Inc. | 45.0% | 9.65% | ROE increased from 8.75%; equity ratio increased from 38.5% due to energy transition risk |
| Gaz Métro LP | 38.5% | 8.90% | |
| Gazifère | 40.0% | 9.05% | |
| Liberty Gas New Brunswick | 45.0% | 9.80% | |
| Pacific Northern Gas – West | 46.5% | 9.50% | Stage 2 Pending |
| Canadian Gas Avg | 41.6% | 9.48% | |
| U.S. Gas Utility Avg3 | 52.3% | 9.57% |
For more information, please contact John Trogonoski, Jim Coyne, or Dan Dane.
1Source: Bloomberg Professional; data through December 29, 2023.
2 S&P Global Market Intelligence, based on electric rate case decisions from January 1, 2023 through December 19, 2023.
3 Ibid.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
By: Concentric Staff Writer
Published: November 9, 2023
The International Energy Agency (IEA) is exploring different scenarios to reach global targets for greenhouse-gas emission reductions, performing detailed new research on the unprecedented level of build-out and investment that would be needed.
Larger, more robust, and smarter electric grids will be needed worldwide to transition modern societies to clean energy from fossil fuels, but the pace of growth needs to accelerate substantially, according to the new IEA report. The importance of electricity grids is growing, with major transitions happening, such as renewable energy, electric vehicles (EVs), and electric heating, IEA said in the report, “Electricity Grids and Secure Energy Transitions.” The report is meant to take stock of the world’s grids as they now stand and assess any signs that grids are not keeping pace with the new global energy economy, as well as analyze scenarios to meet zero emissions. There is a danger that grids will be bottlenecks to future efforts to move to clean energy and create energy security, the researchers said.
“Clean energy transitions are now driving the transformation of our energy systems and expanding the role of electricity across economies. As a result, countries’ transitions to net zero emissions need to be underpinned by bigger, stronger and smarter grids,” IEA said in an executive summary.
To achieve the energy and climate goals of various countries to be zero-greenhouse gas emitters, electricity usage worldwide must grow at a 20-percent faster rate than now, the report says. Expanded grids will be needed to deploy more EVs, and electric heating and cooling systems to scale up new technologies such as hydrogen production using electrolysis. A total of 80 million kilometers of grid infrastructure, the equivalent of the entire existing world-wide grid, must be added or refurbished to meet climate goals.
In an “announced pledges” scenario in which countries’ national energy and climate goals are met on time and in full, wind and solar must account for 80 percent of the total increase in global power capacity over the next 20 years, compared with less than 40 percent that has been added over the last 20 years, the report says. In IEA’s Net Zero Emissions by 2050 Scenario, wind and solar account for up to 90 percent of the global power supply increase.
“The acceleration of renewable energy deployment calls for modernizing distribution grids and establishing new transmission corridors to connect renewable resources – such as solar [photovoltaic] projects in the desert and offshore wind turbines out at sea – that are far from demand centers like cities and industrial areas,” the report says.
One pressing need is interconnection reform, as about 3,000 GW of renewable power projects—about half of which are in the advanced planning stages—are waiting in grid interconnection queues. This is equivalent to five times the amount of solar photovoltaic and wind capacity that was added globally last year, IEA said. Investment in renewables has nearly doubled since 2010, but global investments in grids themselves have remained at about $300 billion per year.
Delays in grid investment and refurbishment would substantially increase carbon dioxide emissions, leading IEA to develop a “grid delay case” in its research to explore what would happen if there were more limited investment, modernization, digitization, and operational changes.
Regulation of electric grids needs to be reviewed and updated so it supports not only new grids but improving current ones, and incentives should be put in place so grids keep pace with rapidly changing supply and demand, the report says. This means removing administrative barriers, rewarding good performance and reliability, and spurring innovation. Assessments of regulatory risk also need to improve “to enable accelerated buildout and efficient use of infrastructure.”
The 130-page report is divided into four chapters: “state of play,” “regulation and policy,” “identifying the gap,” and “policy recommendations.”
The “state of play” chapter notes that electricity grids have grown steadily over the past 50 years at a rate of about 1 million kilometers (km) per year, overwhelmingly in lower-voltage distribution networks, rather than higher-voltage transmission networks. More recently, there have been challenges in integrating renewable energy resources. Advanced economies are seeing investment but also long lead times for high-voltage transmission development, which signals that there are challenges to completing needed development. Investment has also been falling off in recent years with supply chain slowdowns even as demand and population grow, creating more risks for grid build-out. Grids play a central role in energy security, but grid congestion and delays in connecting renewable projects, including the supply chain issues caused by factors such as the COVID-19 pandemic and the war in Ukraine, are also causing impacts. For example, wait times for 50-MVA power transformers grew from a typical 11 months to more than 19 months due to materials and labor shortages, the report says.
“In short, we find evidence of multiple challenges that will need to be addressed to deliver the grids of the future,” IEA said.
Most grids are alternating current (AC), which has historically been composed of rotating generators such as thermal and hydroelectric plants, while new renewable resources connect to the grid mainly through electrical inverters. AC grids are popular because they are adept at changing voltage using long-distance transmission, which minimizes losses and allows transformers to be used to shift to lower voltages for local or regional distribution grids serving residential, commercial, and industrial customers.
However, direct current (DC) grids have certain advantages, such as in occasions when undersea cables are preferable and are used to serve multiple wind farms or markets, or cross-border interconnections and long-distance transmission from large hydro facilities are needed to reach demand centers. DC also offers grid stability and black-start capabilities.
Emerging markets and developing economies have built about 1.2 million kilometers of new transmission lines due to growing demand and access to electricity. Renewable policies have also led to new generation in places far from major load centers and have led to more countries dealing with interconnection issues. China accounts for one-third of the world’s new transmission facilities over the past ten years, or about half a million kilometers of transmission lines, used for purposes such as connecting energy sources from northern and western provinces to eastern load centers using ultra-high-voltage lines. India and Brazil are also rapidly expanding their grids, adding nearly 180,000 kilometers over the past ten years, about a 60-percent increase.
The age of grids varies by country, depending on historical development and varying levels of investment. The lifespan of grids, which are kept in service much longer than most facilities they interconnect, depends on the overloading and capacity, environmental factors, and the specific component. Transformers generally have a lifespan of 30 to 40 years, as do circuit breakers and other substation switchgear. Underground and undersea cables can last up to 50 years, and overhead transmission lines can last 60 years. More than 50 percent of grid infrastructure in advanced economies has been in service for longer than 50 years, and only about 23 percent is less than ten years old. However, in emerging and developing countries, about 40 percent of infrastructure is less than ten years old, and less than 38 percent is less than 20 years old.
The U.S., Japan, and some European countries have a higher proportion of their grids that are more than 20 years old. More than 50 percent of the countries in the European Union have grids more than 20 years old, which is about half their expected lifespan. Most new transmission in these countries has been built to access renewable generation. In Africa, Ghana, Kenya, and Rwanda have made significant investments in modernizing and expanding their grids.
Digitization of the world’s grids is also becoming “paramount,” according to the report, which says investment in digital technologies rose from about 12 percent of global investment a few years ago to about 20 percent in 2022. This is because of a need to manage distributed energy resources such as EVs, small-scale renewables, and electric heat pumps, as well as new players in the industry such as aggregators and demand response companies. Grid operators need digital technology for real-time monitoring and control of energy flows, especially in distribution grids, which saw 75 percent of global investment in 2022. The rise of distributed energy resources and other new technologies on the grid is requiring more precise study of power flows, the report says.
On the regulatory side, power grids are natural monopolies that are thus heavily influenced by regulations and policy, including entities that manage transmission and distribution systems, market structures, and market restructuring. Energy transitions, including climate change efforts, are driving the evolution of many of these regulations and policies.
Regulatory structures range from “cost of service,” where rules are set for companies to recover costs along with an allowed rate of return, or price-cap renumeration where there is a yearly cap that a grid operator can charge for each service or cluster of services. There is also a “yardstick competition” model where a grid operator’s service is compared with competitors and performance-based penalties and awards are assessed, as well as “output/performance-based” regulation where renumeration is based on monitoring the performance of service in order to encourage improvement in service. These varying regulatory models have different impacts on cost recovery and minimization, performance and operational efficiency, affordability, and quality of service.
Many national energy agencies and ministries are shifting to performance-based regulation since it spurs innovation and operational efficiency, the report says. A traditional regulatory approach, such as the “cost plus” framework, incentivizes capital expenditures even when operational expenditures would be more efficient.
“This shift is mainly driven by the energy transition, which calls for a high level of investment especially in innovative and digital assets. This leads to regulators needing a scheme that promotes the implementation of new technical and market solutions,” the report says.
In the “identifying the gap” section, the report discusses the pathway to future grids, analyzing an “announced pledges scenario” in which countries implement policies to meet their 2030 and 2050 zero-emission goals. In the announced pledges scenario, the electricity sector is a driving force in the clean energy transition and “undergoes deep transitions,” and electrical energy would grow by 20 percent per year. Elements of this scenario included the heavy deployment of EVs, more electric heating and cooling, and the development of hydrogen production using electrolysis. Wind and solar account for more than 80 percent of the total increase in global electric supply capacity over the next 20 years, an increase from the 40 percent seen in the past two decades. This scenario includes demand response—paying energy users to cut consumption in times of tight supply compared to a baseline—and energy storage. These systems will be supported by increased digitization and other modernizations on the grid.
This ambitious build-out of grids will make rapid deployment of supply chains critical, but there are significant risks to supply chains, including weather events attributed to climate change, natural disasters, a limited number of countries producing certain supplies, and surging demand for critical materials and raw materials worldwide.
In the announced pledges scenario, the total length of grids worldwide more than double between 2021 and 2050, reaching 166 million kilometers. More than 90 percent of that growth will be in the distribution grid.
The report also analyzed a net-zero emissions scenario, which it said provides a global roadmap to that goal and accelerates electricity demand growth to 3.2 percent by year by 2050, to a massive 62,000 TWh in 2050. Grid investment under the net-zero-emissions scenario passes the $1 trillion per year mark around 2035. Distribution grid investments maintain their total share of investment in both advanced economies and developing markets. Investment in emerging markets and developing economies are a majority of grid investment in both the announced pledges and net-zero emissions scenarios.
This significant investment calls for the replacement of 80 million km of transmission and distribution lines over the next two decades, which was more than the total length of all grids worldwide in 2021. More than two-thirds of the total line length by 2040 in the announced pledges scenario is yet to be built.
The report noted that failing to accelerate grid development in line with the announced pledges scenario—with “more limited investment, modernization, digitalization, and operational changes than envisioned – there would be a significant risk of stalled clean energy transitions around the world.”
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.