An important part of any local distribution company’s (LDC) activity is connecting new customers to the local grid.  New connections create demands on the existing grid in terms of the utilization of existing capacity.  They also provide additional revenue for the LDC.  There are a number of existing regulations that help guide LDCs in what and when they can charge for new customer connections, what the timelines should be and what the process should be.  In Ontario, each LDC has summarized these regulations into their processes which are documented as their Conditions of Service.  A copy of NOTL Hydro’s condition of service can be found here:  https://www.notlhydro.com/customer-service/corporate-policies/conditions-of-service/. 

The Government of Ontario is reviewing three aspects of how new customers are connected to the grid.  I will review each of these.

New Large Loads

The first change relates only to large new loads.  Any load that is directly connected to the transmission grid or is over 10 MW, no matter how connected, must get prior approval from the Independent Electricity System Operator (IESO).  The IESO reviews these applications from a capacity perspective and from the perspective of the impact on ongoing grid operations.  Traditionally, these were on a first-come, first-served basis. 

Under Bill 40, the Government of Ontario is creating a new regulatory body that will prioritize new connections.  The details around which connections will be reviewed by this body and what their decision criteria will be are still to be announced.  The reason for this change is that the Government views the capacity of the transmission system as a scarce good and wants to ensure it is used for good projects, like those that create a lot of jobs, and not for projects considered less beneficial.  Data centres and crypto-currency mining centres are the prime targets of this legislation. 

Critics of this legislation argue that it politicizes a currently independent process and makes it subject to potential abuse.  While this is undoubtably true, I would argue that this industry is already political, as it is largely run by the government, and this new process may be making transparent what might be happening already.  I am more concerned with the creation of a new regulatory body.  These have a tendency to grow over time (see the Ontario Energy Board (OEB)) creating further regulatory impediments.  This legislation is likely to further slowdown the time it takes for approval of a new connection; and this already takes too long.  Despite my concerns with their process timelines (separate subject), I would rather this prioritization be built into the IESO processes and not create a new regulatory body.

Customer Connection Costs

Beyond the basic residential or small commercial connection, there is a cost to the customer for connecting.  There is some subjectivity in who bears this cost.  Some LDCs will charge the customer as much as they are allowed as their view is that existing customers should not have to pay for the new customer connections.  This approach helps keep rates down.  NOTL Hydro falls into this category.  Other LDCs may be willing to contribute more in order to promote growth in that municipality or in order to grow their own asset base and thus their ability to make a higher profit. 

With the current focus on trying to reduce the cost of housing, the Government of Ontario has been looking at how these costs are shared.  So far, they have largely just tinkered with the formula for how the costs of housing developments are shared between the developer and the LDC.  The formulas for housing developments are already quite prescriptive so there is little leeway in these cases.  Whether the changes will go beyond this is unknown.  As noted, changing the rules just shifts the costs between the new and the existing customers.

Customer Connection Process

The OEB has recently commenced a review of the customer connection process at the request of the Government of Ontario.  I have a lot of concerns with this.

Connection processes vary across LDCs.  It can also vary across different types of connections within an LDC.  This includes how long the process takes, how customer friendly it is and how expensive it is.  The Government’s request for a review is being driven by complaints from customers about this process.  I am not questioning this.  We hear these complaints from customers as well though, thankfully, not in relation to NOTL Hydro.  My concern is that instead of identifying what and who is driving these complaints and requiring improvement, the OEB will try to create standards and enforce measurement of each LDC against this standard.  This approach has two problems:  the standards become the minimum that LDCs must achieve instead of aiming for improvement and the cost of this enforcement is borne by all LDCs regardless of their performance.

There are, unfortunately, a number of recent examples where the costs of the solutions for supposed problems have far exceeded the benefit.  To cite three out of many:

Green Button – The complaint was that LDCs all had different customer facing systems so that a business dealing with multiple LDCs had to get their data from each separately.  However, instead of just mandating a standard, the Government, through the OEB, mandated the nature of the systems each LDC must employ.  The costs were in the millions, and the take-up has been very low; very few businesses actually need this capability.  The customer-facing solutions that each LDC uses for their regular online interactions with customers are much more robust, so the Green Button is not a benefit for the vast majority of customers.

In relation to this and other mandated projects like this, the OEB will allow the LDCs to recover the implementation costs in future rates if they exceed a certain threshold.  If the costs are lower than the threshold then the LDC is expected to write-off the cost.  In other words, LDCs are, in effect, encouraged to spend more on these projects and are penalized if they are efficient.  NOTL Hydro recently had to write-off $35k because of this rule.

Cyber-security Audits – The concern is whether LDCs are taking the appropriate steps to protect their IT and OT environments from cyber threats.  A very real concern in today’s world.  The OEB did a lot of good work developing standards against which LDCs could measure their progress and encouraging LDCs to adopt best practices.  Unfortunately, the OEB also decided the LDCs needed to be audited on this.  In great bureaucratic double-speak, the OEB stated that as LDCs were performing cyber audits anyway this audit should not be an issue.  The cyber audits the LDCs are performing are to test their defenses with phishing tests, penetration tests and operating system reviews.  These provide valuable feedback the LDCs can use to improve their defenses.  The OEB audits are about policy reviews and will provide no practical benefit to the LDC.  They will also cost tens of thousands of dollars for each LDC.

Capacity-mapping – This is the latest.  Some potential high-energy use customers have complained that they cannot easily tell where there is capacity on the distribution grids.  Instead of promoting more communication between the LDCs and these potential customers, the Government has required the OEB to find a solution.  The solution has been to hire a third party, cost unknown, to create one map for all of Ontario using the existing Geographic Information Systems (GIS) of the LDCs.  There are three problems with this: 

• The first is the cost. 
• The second is that there is more to connecting a customer than just having the capacity.  Customers of this size are also concerned as to whether there is redundancy.  The cost to connect will vary at every location depending on the local configuration.  There may also be plans for that capacity that are not yet fully developed.  None of these will show up on a capacity map.
• The third is that different LDCs have different GIS systems and even the same system can be used in very different ways by different LDCs.  The GIS systems have been configured for internal use to map the LDC infrastructure and not for external use.

Where this will end up and what the final cost will be is unknown.

The pros and cons of each of these examples can be debated though it is obvious where I stand.  The problem is the cumulative impact of all of these required expenditures.  In the end, the cost of all of them will be borne by ratepayers and the more of these, one-off, requirements there are the higher this cost will be.  The result of the customer connection review may be one more costly endeavor for LDCs and their customers.

If you want to visit NOTL Hydro, it is simple.  Just come to our building at 8 Henegan Road in Virgil and walk on in.  We are open from 8:30 am – 4:30 pm every business day.  Our customer service staff will greet you and ask how they can be of assistance.  No appointment is necessary.

There is a glass barrier between the lobby and the customer service desks, which was installed during the pandemic.  It is not too much of a barrier with lots of room below for conversations and for the passing of documents as well as lots of room on top for airflow.

Visitors come for a variety of reasons.  Many have a specific electricity issue they need to address (moving, new buildings, late payments, account transfers) but most come to make a payment or to drop off their payment.

If a visitor’s need can be addressed by the customer service staff, it will be dealt with immediately.  This will usually be for bill or account related matters.  If the issue requires technical staff, then we cannot guarantee immediate service.  It will depend on availability.  We may be able to deal with it at that time, or a future appointment may be necessary.

Prior to the pandemic, we were getting well over 200 customer visits a month.  This frequency is now down to around 150 a month though there was a noticeable spike during the postal strike.  I attribute the decline to the change in behaviour brought about by the pandemic.  People became more accustomed to doing things online.

I believe giving our customers the ability to visit us in person as this is an important part of our service.

Unfortunately, this belief is not shared by many of my peers in the Ontario electricity industry.  More and more of the Ontario LDCs no longer have a walk-in service.  An appointment is necessary in some cases and, in others, online or phone services are the only options.  Consolidation greatly accelerated this trend (no local service is available in St. Catharines or Thorold) and the pandemic also resulted in some open office closures.

Defenders of not having an open door service claim that this just brings the electricity industry in line with other utilities.  I do not agree that this is the case.  I will certainly concur that this seems to be the case with natural gas.  From what I can see the only way to contact Enbridge is online or by phone.  This is definitely not the case with water.  Most water operations are run by municipalities and most municipalities have a walk in service for their residents.  It is also definitely not the case with telecom services.  Canadian telecom companies (Bell, Rogers, Cogeco, Telus, etc.) have lots of centres that you can walk in and meet with no appointment.  The difference is that their service centres are located in malls where it is even more convenient. 

Having an open door service can add some extra cost.  In our case it is not much.  Our customer service staff are trained in as many aspects of the service as possible.  When they are not dealing with customers, in person or on the phone, they are working on the other billing and collecting processes.  Dealing with a customer in person is not much different from a timing perspective than dealing with them over the phone and is much more pleasant.  With todays technologies, having a walk in service is more about how working environments and processes are set up rather than about adding additional costs.

I am not taking away from having a robust web-based customer service process.  More and more customers expect and demand this.  NOTL Hydro is in the process of upgrading our web-based customer-facing system.  Rather we should recognize that different customers have different needs and wants and we should respect them all as much as feasible. 

In other sectors there is a realization that a well-designed system that includes walk in services as part of the overall service delivery package is the way to go.  ServiceOntario is an example of providing open door services on an expanded basis by partnering with other retailers.  There is a ServiceOntario location near NOTL Hydro that is part of a convenience store.

NOTL Hydro does not have any plans to discontinue its open door policy. Our customers who visit us at the office thank us on many occasions for this service.

NOTL Hydro will soon start replacing the smart meters that were originally installed in 2009.  Around 7,000 meters will be replaced over the next 3-4 years so most customers will be affected.  2,000 meter replacements are planned for this year.

The impact on each customer will be an outage of less than a minute.  To swap the meters, NOTL Hydro staff simply pull the existing meter, creating a brief power outage, then install the new meter to restore power.  The hard work is not in the removing and installing of the meters but in the organization beforehand to ensure our records will have the correct meters at the correct customer premises.  A lot of work has gone into ensuring these records will be accurate.

Due to the large number of meter replacements, it will not be possible to schedule them individually with customers.  The only ones being scheduled are the limited number of customers we have on file who have a medical alert.  Please do not call to try to schedule.  The outage will be very short.

The existing meters are now 16 years old.  Smart meters were a fairly new technology at that time so no one knows how long they will last.  To hedge against known experience with other electronic based equipment in the industry, NOTL Hydro is replacing the meters now to guard against there being a large number of failures at one time.  Going early also helps get ahead of potential supply chain issues as other utilities start their replacement program since smart meters were mandated and deployed Ontario wide all at the same time.

By failure, I am referring to the meter ceasing to function in a useful manner.  I am not referring to the meters slowing down and not correctly measuring power consumption.  That was an issue with the old mechanical meters the smart meters replaced, but is not an issue with these digital meters.  Measurement Canada requires that all these meters be tested on a sample basis after ten years.  This was done in 2019 with no issues noted.  This testing will be required again after 8 years or 2027.  The goal is to have them all replaced instead.

The Ontario Provincial Government required that the smart meters be installed so that customers could be billed on a time-of-use basis.  These meters allow the measurement of the use of electricity by the hour.  The old mechanical meters only measured how much electricity had been consumed between readings with no measurement of the timing.

Installing smart meters across all of Ontario at one time was expensive, estimates of around $2 billion.  Whether this was money well spent can still be a matter of debate. 

Some arguments in favour of the decision:

• Smart meters are more accurate than mechanical meters since there are no moving parts that can “slow down” and they measure actual time, providing true Watt-hour data.
• The installation of smart meters allowed time-of-use rates which enabled customers to choose when to  use electricity for larger loads like ovens, dryers, air conditioners, hot tubs, pool pumps, etc.
• The smart meters allow for the new time-of-use rates such as the Ultra-Low Overnight (ULO) Rate.  ULO rates are currently only 2.8¢ per kwh at night but are a very high 28.4¢ per kwh at peak times.  This rate is aimed at EV car owners who have a high demand when charging.
• Utilities have come up with a number of valuable uses for smart meters.  These are discussed below.
• Electric utilities in other jurisdictions have made the business decision to install smart meters without there being a government requirement.

Arguments against the decision to install smart meters include:

• The Government never set time-of-use rates with enough of a difference between the low and peak rates to truly change behaviour.  Thus, the potential benefits of the smart meters were not realized.
• The Government of Ontario has now allowed the choice of tiered rates which do not require a smart meter.
• A number of other jurisdictions have chosen not to require smart meters.
• There has not been a proper after-the-fact analysis of the smart meter program to test the assumptions and the actual results.

As noted, smart meters provide some very useful capabilities that are of a big benefit to customers.

1. Smart meters provide what is known as a last-gasp signal that indicates that a customer is losing power.  Utilities build this into their outage management systems to provide outage alerts, determine the location and potentially the cause of the outage.  At NOTL Hydro we get an e-mail alert triggered by the smart meter.  Our staff can also access maps of all the meters showing an outage.
2. Smart meters can also signal when a customer is not getting full power.  The customer may not notice this performance impact but it can be an indicator of underlying problems in the connection to the customer that need to be addressed.
3. Smart meters can be used to estimate the loading on transformers.  NOTL Hydro has used this information to help determine what transformers need to be upgraded to a larger size due to load growth.
4. Smart meters can measure the voltage variations at a customer site.  This can be helpful when a customer is having concerns with their power quality.  It can help indicate if the issue is with the service to the customer or within the customer’s premise.
5. The data collected by smart meters is accessed remotely making the preparation of customer bills more efficient and thereby contributing to keep rates low.

With the current threatened tariff war with the United States, many Canadians are evaluating their purchases and trying to “Buy Canadian” as much as possible.  This is something I wholeheartedly support as makes sense for a number of reasons including the environment, the local economy, the quality of items being purchased and the general quality of living.  As an aside, and for any readers outside of Niagara, let me also recommend Niagara wines and Niagara vacations.

Because electricity is a provincially managed industry, most people in Ontario will assume that their electricity is Canadian…and they are correct.  I think the percentage of the electricity product that comes from Canada is in the high 90’s in percentage terms.

Electricity Commodity

For an average residential customer, the electricity commodity represents about 60% of the monthly bill before HST and before the Ontario rebate.  These percentages are all based on a NOTL Hydro residential customer using 750 kwh.  The allocation of costs will vary depending on the user (location, customer class, consumption) but should all be roughly the same.

97% of the electricity consumed in Ontario in 2023 was generated in Ontario.  The total consumption in Ontario was 137 TWh and the total imports to Ontario was 4 TWh.  Most of these imports are from the Provinces of Quebec and Manitoba so the percentage of consumption generated in Canada is even higher than 97%.

Distribution Costs

The next biggest cost on a customer’s bill is distribution costs at about 28% of the total bill.  Distribution costs cover the annual costs in providing distribution services plus a return on the investment in the distribution infrastructure. 

The annual costs include staff wages and benefits, supplies, software services, interest costs, taxes and profit.  Staff wages are 100% Canadian and benefits will be mostly Canadian other than any prescriptions using foreign-sourced medications.  Supplies will be mostly Canadian.  That was not something we previously looked at in this context except to use local services where feasible.  Some of the software services we use are from US companies (billing system, GIS, Microsoft) though even there most of our costs are for ongoing support which is local.  Our SCADA system and payroll software is Canadian.  Our interest costs, taxes and profits are 100% Canadian.  I would estimate over 95% of our annual costs are Canadian.

Identifying the source of most of our distribution infrastructure is more challenging.  The infrastructure is made up of poles, wire, transformers, meters, conduit and various devices.  Poles are 100% Canadian.  No surprise there.  Our transformers are also mostly Canadian.  The large transformers in our stations were all made in Canada though the materials came from around the world.  The regular transformers on the grid have also been exclusively purchased from a Canadian company for the past number of years.  Our meters all come from the US.  With wire and other devices it is hard to tell.  We purchase through hardware distributors and they would have a mix of US and Canadian suppliers.  We do know that the newer smart grid devices such as switches and reclosures tend to be made in the US.  All the labour installing this hardware is 100% Canadian.  To be conservative I would estimate that our distribution infrastructure is over 75% Canadian.

Annual operating costs are over half of the costs that go into rates so in total I would estimate that distribution costs are around 90% Canadian.

Transmission Costs

Transmission costs make up about 8% of the bill.  Transmission services in Ontario are almost entirely provided by Hydro One; an Ontario based company.  I do not have enough insight into their operations to provide a detailed breakdown, but my guess is that they are not dissimilar from NOTL Hydro in the make-up of their costs so would be around 90% Canadian.

Regulatory Costs

These charges go primarily to the Independent Electricity System Operator (IESO) to manage the electricity grid though there is also a charge to fund subsidies for electricity distribution to some remote users.  As a result, these costs are almost 100% Canadian.

Conclusion

Electricity users in Ontario and all of Canada can comfortably assume that their electricity is almost 100% Made in Canada.  Like our users, NOTL Hydro is also evaluating its purchases to try ensure that they are as Canadian as possible.

Every year I prepare a comparison of the delivery rates across the electricity distributors in Niagara (LDCs).  The comparison for 2025 for the three primary rate classes (residential, small business and large business) is provided.  The rates for Welland are not final as they are nearing the end of their cost of service application.  As this comparison uses the latest rates from that hearing, any additional changes will not affect the arguments in this blog.

I perform this analysis to see if NOTL Hydro’s rates are still the lowest in the Region.  This year they are but they are not every year.  What does not change from year to year is that the three lowest rates are always in NOTL, Welland and Grimsby.  There is a reason for this.

I have talked to the Presidents of both Welland Hydro and Grimsby Power and they have the same mandates from their Boards as I have.  That is to earn a fair return on equity, which is set by the Ontario Energy Board at around 9%, and to have a long-term objective to strike the right balance between low rates and investing for system reliability and performance.

It is this last bit that is important.  This is not the long-term objective of all LDCs.  CNP (part of Fortis) and Hydro One are both parts of large publicly-traded companies.  Their long-term objective is, most appropriately, to maximize the long-term return to shareholders.  As investors we would not have it any other way.  However, the impact is that this also leads to the highest rates. 

This rate impact is not created by anything devious: both CNP and Hydro One earn the same return on equity and are subject to the same regulations and oversight of the OEB.  Rather, if the goal is to maximize the long-term return then it is also to maximize the long-term level of equity on which the OEB set return on equity is earned.  This is accomplished by a variety of decisions that have a cumulative effect.  For instance, NOTL Hydro may sometime make decisions that do not create a return for NOTL Hydro but do for NOTL Hydro ratepayers.  Our actions to reduce the impact of double peak transmission billing are an example of this.  Similarly, if a decision is between investing in assets, which increase fixed assets and therefore equity for rate setting purposes, and incurring operating costs then the differing long-term objectives may lead to different decisions.  Individually, these decisions are not significant but, as stated, over time they accumulate.

Around 20 years ago, Thorold made the decision to sell their LDC while NOTL opted to keep theirs.  The difference between the Hydro One Urban rates used in Thorold and the NOTL Hydro rates is $3 million a year.  This is the annual incremental cost that NOTL Hydro customers would have to pay if they were instead supplied by Hydro One.  This difference would be even higher if Hydro One’s rural rates were to be applied in NOTL which would likely be the case.

The conclusion is that if you are fortunate to be in a municipality that owns their LDC, you want to keep it that way.  A municipally-owned LDC with proper governance, and that is the key, should over time lead to lower rates like has been the case in Welland, Grimsby and NOTL.

Like most companies, the nature of their operations and what they consider most important can be divined from their staffing organization.  The staffing at NOTL Hydro is similar to most local distribution companies (LDCs).  However, as in most industries, as LDCs get bigger they not only have more staff but have more specialized staff.  This can be taken to an extreme.  I remember talking to a tax professional at one multi-national company who did not even know his company’s products.

With a total staff of 20, NOTL Hydro is not very big.  As a result, most members of staff have multiple roles.  For those that like variety and change, this is a benefit.  For those that want to become specialists with a deep knowledge in a given field, this would not be a good fit.

The following is the staffing organization at NOTL Hydro:

Administration

This is the same as any company and consists of the senior management team as well as support functions like finance, IT and HR.  A strong finance department is a requirement for any LDC due to its regulatory reporting requirements and its customer billing function.  NOTL Hydro outsources most of its IT requirements due to its size and the level of sophistication required due to both the nature of its operations and the growing cybersecurity threats.  NOTL Hydro does not have any HR staff but has access to an HR expert as a member of the CHEC group; an association of smaller LDCs.

Regulatory

Unlike most companies, NOTL Hydro does not have a sales and marketing department.  As a monopoly and a utility, NOTL Hydro does not need to seek sales or customers; they come to NOTL Hydro naturally.  Instead, NOTL Hydro is subject to a high level of regulations overseen by a regulator specific to the industry: the Ontario Energy Board.  Most LDCs will therefore have a regulatory department.  NOTL Hydro is not big enough to have its own regulatory department so this is a big part of the workload of the senior management team.

Lines

Every LDC has linemen or powerline technicians (PLT) as they are now called.  PLTs are skilled trades similar to electricians (not the same thing), plumbers or welders.  Becoming a PLT involves an apprenticeship program just like the other trades.  PLTs are required to work on the hydro distribution lines whether they be installing new services, making repairs or engaging in regular maintenance.  Hydro lines have high voltages so nobody should be making any contact with these lines other than PLTs.

There is also a vibrant industry of companies providing lines services on a contract basis.  These are used by both LDCs and by private industry who may need a power line built on private property.  LDCs will use contractors for projects they cannot manage internally, to assist at peak times and to avoid overstaffing internally.  NOTL Hydro uses contractors for larger underground jobs where we do not have the inhouse expertise and for some large overhead jobs that require a larger crew.

Other Outside Services

There are a variety of other outside services required in addition to line crews.  These include locators and civil work on underground jobs such as borers, vacuum truck operators and excavators.  These services will either be contracted or staffed depending on the situation of the LDC.  While LDC size is obviously a big factor it is not the only one; LDCs in more remote parts of the province will not always have access to many contractors so may need to bring certain skills in-house.  NOTL Hydro has hired a locator, an excavator and a labourer in the past few years as the contractor situation changed and the volume of work made this a viable alternative.

Technical and Engineering

All work must be planned and designed before it can be performed.  This is definitely the case for any work done on the hydro distribution lines.  Given the volume of this work, almost all LDCs have a technical engineering department.  This staff deals with planning for both internal jobs (line replacements, voltage conversions, expansions) and jobs done on behalf of customers.  The latter will involve working with the professional representatives (electricians, engineers) of the customers.  NOTL Hydro has a technical engineering department so as much of this work as possible is done in-house.  For very large jobs or for jobs with more complicated features, such as smart grid equipment that is linked to our SCADA system, NOTL Hydro uses an external engineering firm with which it has a long-standing relationship.

Customer Service and Billing

These two services are often two separate departments but at NOTL Hydro they are combined into one.  All LDCs have customer service and billing staff as that is a core competency,

The revenues from LDC bills fund the entire industry and around 80% of the funds collected by LDCs go to pay generators, transmitters, regulators and various other organizations beyond the LDC.  LDCs do not mark-up the cost of electricity generation and these other costs.  Instead, 100% of these costs flow through.  LDCs have their own separate charges that they keep for the delivery of power.  However, LDCs are 100% responsible for the entire amount of any billing errors or any bills not collected.  The billing function is thus very important; especially as billing is getting more and more complicated with all the different options.

The customer service department is necessary to manage the LDCs relationship with its thousands of customers.  This relationship will be a mix of online and personal service.  NOTL Hydro believes the personal service touch remains a very important part of what we deliver which is why our doors are still open to the public.  With the recent postal strike, we have never had more foot traffic.

Other Departments

As mentioned, the larger a company then the more departments they will have as roles become more and more specialized.  Some examples of departments that are commonly found in larger LDCs are metering, safety and property management.  As its name implies, metering takes care of all the customer meters.  At NOTL Hydro this is managed by the Technical and Engineering Department with services related to the larger meters outsourced.  NOTL Hydro does not have a safety department but that does not diminish the importance of this service.  An outside consultant provides support to the Administration that is responsible for this.  LDCs tend to have a fair bit of property.  At NOTL Hydro this is also managed by Administration.

All of these departments work together to keep the lights on and the rates low.

There are three bodies that oversee the regulation of electricity in Ontario: the Ontario Energy Board (OEB), the Independent Electricity System Operator (IESO) and the Ministry of Energy (MOE) itself.   This blog will be a quick look at their operations.

Ontario Energy Board

The OEB is responsible for regulating much of the electricity industry in Ontario.  This includes electricity distributors and transmitters.  It also includes, to a significantly lower degree, sub-distributors, retailers, the IESO and Ontario Power Generation (OPG).  As these are all monopoly service providers this regulatory oversight is appropriate and was created through legislation by the Government of Ontario.

There are two parts to the OEB: the adjudicative and the administrative.  The adjudicative part, formerly called Board members and now called Commissioners, hear the actual rate cases and other hearings and make the final decisions.  The administrative part manages the relationships with all the organizations they regulate and enforce the rules.  They may also participate in the hearings before the adjudicative branch.

The OEB is the most customer-facing part of the government oversight.  Their website has valuable information for customers, they try to support customers with their outreach and there is an ombudsman that tries to deal with customer issues.

Over time the role of the OEB has evolved.  Initially, the focus was on the core regulatory requirement which is approving rates.  As the OEB gained more experience they gravitated to also reviewing the strategic direction of the transmitters and local distribution companies (LDCs). 

There has been some good in this.  By requiring long-term asset plans, by ensuring cybersecurity awareness and by publishing reliability statistics they have helped focus LDCs on customer needs beyond rates.  Other initiatives, such as benchmarks that are statistically irrelevant due to the sample size, and some customer surveys, have missed the mark and not been as effective.

Lately, the OEB has been trying to more directly dictate how LDCs manage their business.  Examples include bill presentation (this is not so recent), disconnection procedures, customer communication requirements and, most recently, capacity management.  This is problematic for four reasons.  First, as a regulator, the OEB does not have the knowledge base to be making some of these decisions. Second, by dictating certain processes the flexibility to respond to some situations is lost which can be to the detriment of some customers.  Third, in a related manner the benefits of potential innovation is lost.  For instance, I am sure LDCs could come up with a better bill presentation if allowed.  Finally, and most importantly, all these mandates add costs which are ultimately borne by the customer.

These changes have not been entirely of the OEBs own volition.  There has been a parallel trend with regards to the independence of the OEB from the Ministry of Energy.  Initially, the OEB operated largely independently.  This is how it should be.  Over time, the Ministry of Energy exerted more and more control through letters of direction.  These letters were initially sporadic and each focused on a specific new or change in responsibility for the OEB.  Now, the letters are issued annually, are many pages long and provide detailed direction to the OEB for the upcoming year.  The OEB has naturally responded by shifting their focus to meeting the directions set out in the letter and not necessarily acting in a manner that may be best for the overall long-term performance of the electricity industry. The increased involvement of the OEB and the lack of independence has had another consequence.  This can be seen in the chart below.  The cost of the OEB has taken off.  They are forecasting another big jump in 2025.  This is concerning and not just because it is another expanding government entity.  As our Chair puts it “regulators exist to create regulations”.  The biggest cost of the growth of the OEB will be with all the organizations they regulate who will have to respond to the increasing demands of the OEB.  These costs will inevitably end up with the customer.

Independent Electricity System Operator (IESO)

The IESO has a number of responsibilities but the primary ones are operating the electricity market in Ontario, ensuring that supply meets the demand for electricity at all moments and overseeing the safety and capacity of the transmission grid.  There are two other responsibilities which are funded separately and are discussed further below.

Most of the electricity sector revenues flow through the IESO.  This includes all revenues for transmitters, most generation and any other government programs.  The LDCs collect all their billings from customers and then remit over 80% of it each month to the IESO.

The IESO is not customer-facing unless you are a participant in the electricity market or a generator.  The closest they get to regular customers would be in dealing with those with MicroFIT contracts.  Even then, the month-to-month payments are handled by the LDCs and customers only deal with the IESO if they are moving or selling their contracts.

The problem with the electricity market in Ontario is that it has become largely irrelevant.  Some years the market covers less than 20% of the cost of electricity.  The rest is Global Adjustment (GA).  Given this it becomes difficult to assess if the IESO is doing a good job or not.  Unfortunately, this is out of the IESOs control as the Global Adjustment is the responsibility of the MOE.

The IESO gets a similarly detailed letter of direction as the OEB.  This is less a concern as the IESO is clearly a government agency with no expectation of independence.  The IESO is not showing the same level of increase in costs.

MOE

The MOE is currently called the Ministry of Energy and Electrification but the name seems to change every time there is a new Minister so I will stick to MOE for simplicity.

If there is a theme running through the comments above, it is clearly one of control of the industry by the MOE.  To some degree this is inevitable.  Electricity is a key industry for business development and for the standard of living Canadians expect.  If something goes wrong with electricity in Ontario it is the government that gets the blame.  It is also one largely owned by government players including most LDCs, OPG and a chunk of Hydro One.  This is not an American state where the majority of the assets are investor owned.

It is harder to get a handle of the costs of the MOE though someone with a better understanding than me of financial reporting by the Government of Ontario may be able to.  First, the ministry changes over time.  Under Minister Rickford it was the Ministry of Energy, Northern Development and Mines.  The costs thus included the Northern Development and Mines bureaucracy.  Second, the costs include the various subsidies and these are not always separated from the administrative costs.  Unfortunately, I suspect an analysis would reveal a growing government agency.

The Government of Ontario has been very transparent in its energy policies with its vision paper, its policy announcements and the opportunities for input on proposed regulations and legislation. 

The concern is not with these big picture decisions.  Those are policy decisions that rightfully belong with the government.  The concern is at the next layer which is the actual management of the industry.  With the top-down approach that is currently being displayed, the government is losing the benefits from independent decision-making by the agencies under their control.  Agencies which, for all their faults, are closer to the action. 

More importantly, the MOE is straying into trying to manage various aspects of the industry.  This never works well.  What sounds good in an office often does not work well in the field.  This is particularly the case when the decisions are about “guiding” the industry based on an often unrelated government objective (more housing, faster broadband) rather than just finding the most efficient course of action. 

Just like with the OEB, this level of micro-managing can be problematic with the same issues applying.  In addition is the concern with the “law of unintended consequences”.  Regulations intended to guide behavior in one direction can result in unforeseen behaviors.  For instance, the recent regulations intended to assist in housing developments will also allow those LDCs that are so driven to more quickly grow their rate-base and thus charge higher rates.

Conclusion

There is a need for all three of these government organizations and the roles that they play.  However, just like every other organization in the industry, it would be best if they were kept as lean as possible, worked with rather than through the other industry participants over which they have authority, and kept the focus on the long-term best interests of the customer. 

In October the Ontario Government released what they are calling their vision for the energy (really electricity) future.  No new initiatives were announced but this is a good summary of general policy trends and recent announcements. 

https://www.ontario.ca/page/ontarios-affordable-energy-future-pressing-case-more-power

The following is my summary of the highlights:

Increased Demand

The IESO and most prognosticators are forecasting a huge growth in electricity demand due to electrification and data centre power needs.  A 75% increase by 2050 is the figure quoted.  Preparing for this now, with the danger of overspending, is better politically than not preparing and risking being short of power.  This report is primarily about how this will be achieved without the cost of power skyrocketing.

Subsidies to Continue

The report highlighted the existing Ontario Electricity Rebate (OER) and Comprehensive Electricity Plan (CEP).  We can expect these to continue with their annual cost of $6-7 billion a year.  The CEP makes sense as it offsets the costs of the Green Energy Act.  The OER is just a subsidy paid for by tax revenue.

Nuclear Power

Nuclear power represents the best path for meeting this demand.  Ontario does not have a competitive environment to be relying on solar and wind.  With nuclear, Ontario has the experience, expertise and talented workforce to be competitive.  With the small modular reactors, a new build at Bruce Power and refurbishments at Darlington, Pickering and Bruce, Ontario is relying on nuclear power to meet its growth needs.

Hydroelectric

The current hydroelectric generation will be maintained and refurbished; but there is little opportunity for growth.

Renewable Energy

Investments in renewable energy will continue but they will be limited and will all be sourced through competitive procurements.  I believe there are opportunities with solar and wind that are being missed due to regulatory constraints.  Wind and solar will not provide the growth in electricity needed but they can be used to provide cheaper electricity at the right times.  The current ban on community solar is an example.

Energy Efficiency

The new name for the old Conservation and Demand Management (CDM) programs.  These will be expanded.  The achievements of these programs have usually been overstated but remain beneficial. 

Transmission

New investments have been approved particularly in Southwest Ontario and up around the Ring of Fire.  I expect these investments to continue as growth shows up constraints in the system.  There is recognition that the current processes for new transmission and for customers to connect to the transmission grid are too slow and cumbersome.  Hopefully, this will result in some changes. 

Natural Gas

Natural gas will continue to be a source of electricity.  This is appropriate.  The report highlights the need for natural gas to manage changes in demand while nuclear and hydroelectric handle the baseload.  The danger is that the declining price of natural gas makes its marginal costs quite low so that it becomes attractive to use as baseload energy to keep rates low.  This could put to the test the Governments boasts about how clean its electricity system is.

Electrification and Energy Transition Panel

This report was released in February 2024.  It was referred to in passing.  I suspect it will be largely ignored except where it suits the Government’s needs.  Not a loss.

Electrification of Transport and Heating

The Government recognizes that if Ontario and Canada are to meet the carbon reduction goals, much of the current energy used for transportation and heating will need to become electric.  This will only happen if consumers voluntarily make these choices.  The new terminology is Beneficial Electrification and plans for subsidies to help this happen are being developed.

Municipal Energy Planning

The report recognizes the benefit of this and integrating these with the regional planning by the IESO.  The Niagara Region has started work on an energy plan for all of Niagara.  Much of local energy planning is largely superfluous but it can become a venue for real decision-making when needed.

IESO and OEB

Better information for business and quicker decision-making by both the IESO and OEB are mentioned.  Hopefully, some action is taken on this.

Carbon Tax

The Government is strongly opposed to the carbon tax but does not offer any real alternatives.  No mention of the rebates households are currently receiving.

Electric Vehicles

The vision calls for supporting EV adoption and supporting the growth of the EV charging infrastructure.  The government has put and continues to put significant efforts into developing an EV infrastructure. 

Local Distribution Company – LDCs

Unfortunately, the report promotes further consolidation of LDCs.  This despite the clear evidence that the smaller LDCs are more efficient, provide better service and have lower rates.  I continue to believe that this is driven not by the mentioned efficiencies, which are not real, but by the desire of the government to have only a handful of LDCs to manage.  This is how bureaucracies like to work and why they allowed Enbridge and Union Gas to combine creating one gas company serving almost the entire province.

Affordability Programs

Programs like the OESP will continue. 

The Ontario Energy Board (OEB) recently released the Regulated Price Plan (RPP) rates for 2025.  The rates declined, which is good news.  However, the amount of the subsidy under the Ontario Electricity Rebate (OER) also declined from 19.3% to 13.1%.  To see if there is a net benefit, I performed the following analysis using the NOTL Hydro 2024 rates and the time of use (TOU) rates.

As can be seen there is a drop in the cost of power of 10% or $8.52.  The delivery charge also drops slightly due to the drop in the cost of line losses as the cost of power has fallen.  However, this is more than offset by the $9.69 reduction in the OER subsidy.

This net impact is intended.  The goal of the subsidy is to moderate the increase in the price of electricity from year to year.  Also, there will be changes to the other non-cost of power rates.  Transmission charges are expected to increase by 11%, NOTL Hydro’s net charges will be flat but only because we had some large one-time charges in 2024 and we do not yet know if there will be any changes to regulatory rates for 2025.

Even though the benefit of the lower cost of power is being kept by the Government of Ontario, that is not necessarily a bad thing.  The OER is a subsidy so is being paid for out of tax revenues.  The lower the subsidy the lower the impact on the provincial deficit.

The OEB report gave two reasons for the drop in the cost of power, a $259 million surplus collected in 2024 and a decrease in global adjustment payments to nuclear and natural gas generators. 

The 2024 surplus is nice and not unusual.  The setting of RPP rates is always an estimate so there will always be a surplus or shortfall.  In 2023 there was a deficit of $342 million.  Given the uncertainties the estimates are usually quite good.  The swing from a deficit to a surplus has a combined impact of 9% of the cost of power of $6.8 billion so is the cause of most of the rate reduction. The other cause of the rate decline is more interesting and has nothing to do with global adjustment.

This table shows the expected cost and contribution to electricity supply in 2024 and 2025 as used to estimate the RPP rates.  Of note is the contribution of natural gas.  The cost is expected to fall 25% from $114 to $85 per MWh while its use is expected to climb to 17% of all sources of generation.  This has helped reduce the total cost of power on a per unit basis even though the cost of nuclear and hydro, the dominant sources of supply, are both rising.  This has contributed a further 0.6% to the decline in the cost of power.

A declining cost of power is always a good thing and a comparatively low cost of electricity is necessary for electrification.  However, the growing use of natural gas in Ontario’s electricity supply mix, as shown in the chart, creates a few concerns:

1. The Province has consistently touted its “green energy” as a benefit when attracting industry.  This was mentioned in a presentation I recently saw by one of the new electric battery manufacturers that is building a new plant.  This claim becomes problematic as the use of natural gas grows.
2. The carbon benefits of electrification rely on switching from carbon-based fuels to greener electricity.  These benefits decline as the amount of carbon fuels used to generate electricity grows.

The Province has claimed that the increase in the use of natural gas is temporary and needed until the new nuclear generation comes into operation.  While I do not dispute this, it feels there is a little more the Province could be doing to encourage more renewable energy.  This would not be by overpaying like the Green Energy Act but by adjusting regulations to make the use of some renewable energy more competitive.  Some examples include:

• Allowing community solar.  These are large solar projects that are collectively owned by community members who can use their share of the solar output for net metering.  This provides solar to consumers for whom it would not otherwise be possible (condo and apartment dwellers) and large solar installations have a lower cost per kW.
• Allowing wind farms in the Great Lakes.  Obviously, there is much more to this example that would need to be examined but the growing success of off-shore wind farms around the world make this look attractive.
• Make net metering simpler and more understandable for customers to encourage more to make this investment.

We held an open house the other day (October 9, 2024) with presentations on Heat Pumps and Electric Vehicles.  Over 40 customers turned up to hear the presentations and engage with the presenters and NOTL Hydro staff.  Thank you to those customers for their interest and participation. 

The idea is to provide information so as to make informed decisions.  Everybody should still do what is right for them and this will depend on personal circumstances. 

Copies of the presentations can be downloaded at:  https://www.notlhydro.com/open_house/ .

The heat pump presentation was provided by Mike Peddle of Environmental Heating & Cooling.  Some of the key takeaways in my mind were:

• There are different types of heat pumps for different weather environments.  Make sure what you get is a match.
• Heat pumps work by extracting the ambient hot (for heating) and cold (for cooling) air from outside and transferring it to your house.  They do not actually heat or cool the air.  This process makes them more efficient. 
• In Canada, you will most likely need a back up source of heating for the very cold days when the heat pumps will not be able to keep up.  This could be a legacy gas furnace if you have one or an electric heater for a new installation.
• Heat pumps are competitive with natural gas and less costly than other alternatives such as oil, electric heat and propane.  Heat pumps use electricity for all their energy.

The electric vehicle (EV) presentation was provided by Plug’n Drive.  They also had two vehicles (a Chevrolet Equinox and a Polestar 2) available for test drives.  Some of the takeaways from this presentation included:

• North America is moving to the Tesla charging connection as the standard.  Conversion kits will be available for those using the other current charging connection.
• The variety of EV models and their range continues to improve with all new EVs having a range over at least 300 km.
• There is a developing used car market for EVs.  An EV battery should last the lifetime of the car, is simpler to maintain as it has fewer moving parts and can get software updates during its life.
• EVs are currently 12-13% of new cars sold in Canada (this is lower in Ontario) and this is still growing.

One of the common themes with both EVs and heat pumps are the rebates that are available.  These are both federal and provincial and are constantly changing.  If you are thinking about either of these purchases, make sure you talk to the vendor about the rebates.  It should be in their best interest to provide these to you.

At the event, a few customers spoke to me about all the outages over the summer.  Most of them had seen the article in the Lake Report https://lakereport.ca/  on page 15 of the September 19, 2024 edition.

As per the article, the number of outages was the highest we have seen in a three-month span.  The charts below, which can be found on our website at https://www.notlhydro.com/outages/outage-statistics/ , show this.  SAIDI measures the average duration of outages while SAIFI measures their frequency.  On each chart the horizontal line is the five-year average.

As reliability is a key part of our service, we track our outages closely.  We have examined the summer results and there is no consistent pattern.  The outages are in different parts of the town and, as reported in the article, had different causes.  Either this is some manifestation of climate change or, more likely, just a string of bad luck.  We will continue to monitor the situation closely and implement the changes discussed in the article.