The Rising Cost of Electricity in Ontario

The rising cost of electricity in Ontario has been a contentious issue for decades. Most people are aware that costs have increased but few have an understanding of the drivers and how much each of them impact our bills. The largest portion of the average consumer’s electricity bill is for energy, making it a good starting point for a closer look at cost. For some ratepayers the cost of energy has doubled in the last 11 years. While the average cost of energy has increased some forms are actually declining. Wind and solar energy have been dropping dramatically. Competitive capacity bidding like the Large Renewable Procurement (LRP) program administered by the IESO from 2014 to 2016 resulted in a decline in cost of 23% for wind and 62% for solar. Generation from all other fuel sources is becoming more expensive (Lazard – 2019).

No single cause

There is no single cause that can account for the rate increase over the last 11 years. In fact, it is a combination of many. While it may be desirable to attribute the increase to one single factor, it would be a misrepresentation of the reality. In order to understand what happened you must look at how the energy pool costs have changed, followed by a look at the cost-allocation process that determines what is recoverable from different ratepayer groups. Unfortunately it’s quite complicated which is why most people tune out and alternate narratives kick in.

If you want to know where the additional supply costs came from over the last 11 years but don’t want to engage in all of the details involved, here is what you should know in two interactive visuals – Figures 1 & 2.

If you are part of the Regulated Price Plan (RPP) the top two incremental cost factors (Figure 2) are not solar and wind as some would like you to believe.

The Supply Mix

Figure 1 – Supply Contribution to Incremental Costs from 2009 to 2019

The Regulated Price Plan

Figure 2 – Incremental Cost Factors for the Regulated Price Plan from 2009 to 2019

• Creation of Class A and Class B customers in 2010 which shifts costs to the RPP to reduce industrial rates
  
• The decline in the market price of electricity (HOEP)
• The increase in the Global Adjustment (GA) cost
• Protocols used to forecast rates in the RPP

The result is a 103% increase to rates in the RPP from 6.1 cents/kWh in 2009 to 12.4 cents/kWh in 2019 (OEB).

The incremental cost of energy

The discussion which follows is only about the cost of energy (supply) – not delivery or regulatory items. The total cost of supply is spread across all energy consumers. Those costs are not shared equally based on consumption but rather by complex regulatory rules applied to each ratepayer group.

Ontario has over 30,000 generators which contribute to the electricity supply every day. Analysis presents a significant challenge because of the volume of data involved. The energy supply could be broken down in various ways, however this analysis looks at a high-level summary over an eleven year period to show how supply costs have changed, highlighting the incremental cost. It then shows how the costs filter down to ratepayers. The summary will break out costs by fuel type and customer rate plan with specifics of how the costs find their way to the Regulated Price Plan where the greatest number of customers are.

The time period chosen for the discussion is important because of changes that happened in the industry in 2010 to create two different customer classes. The data from 2009 captures costs before the change. The most current year with complete reporting available is 2019.

11 years in review

Looking at IESO and OEB data from 2009 and 2019 the following average rates apply.

Table 1 – Average Rates 2009 & 2019

*Since Class A & B customers didn’t exist in 2009, the average pool cost applies: Information source: IESO and the OEB

Not all ratepayers have seen an Increase in energy costs as high as in the RPP

Energy rates for consumers that are part of the Regulated Price Plan (RPP) have more than doubled in the last 11 years but the energy pool costs have not. How can that be?

The shifting of energy costs from the Class A ratepayer group to Class B accounts for above-average rate increases on the RPP.

RPP customers are part of Class B. I’ll explain what RPP and customer classes are in the article under their own headings.

Accounting for exactly what contributed to the increase and by how much is far from simple due to the complexities of Ontario’s energy market, industry restructuring, contracts and regulatory oversight. The explanation of cause is tedious and the math is even more so.

The acronyms

The industry is riddled with acronyms that may be confusing to some. Here is the glossary of what appears in the article.

Table 2 – Acronyms

Baseline: Pool Energy, Cost and Average Rates

The discussion is based on the following numbers

Table 3 – Baseline energy consumption, cost and rates 2009 & 2019

The numbers are reported by the IESO and OEB with some interpretation required.
* Embedded generation is estimated by extrapolating actual hourly data as reported by the IESO
Sources: IESO 2005 to 2015 10-Year Report (for 2009 data), Auditor’s 2019 IESO Annual Report, OEB Regulated Price Plan Price Reports April, 2009 and May, 2019

The baseline numbers require interpretation due to source limitations. They include the market cost as the Hourly Ontario Electricity Price (HOEP) and the Global Adjustment (GA) as reported by the IESO. They do not include costs associated with delivery or regulatory charges.

Supply-mix energy quantities are the only values which – by law – require reporting of consolidated industry data. Determination of costs and rates requires a considerable amount of data mining and interpretation. In 2019 Ontario produced 155.2TWh of energy, however the IESO only reports Global Adjustment for 139TWh, generator output for 147.3TWh and output by fuel source of 148.4TWh. The discrepancies are due to jurisdictional demarcation (grid-only or market participant) and minimum generator output reporting practices (20MW is the minimum) for some data. Global Adjustment does not apply to exports. The baseline numbers for 2019 in Table 3 include estimated values for the 5% of generation which is not reported by the IESO. The missing energy is mostly from embedded generation which is under the jurisdiction of Local Distribution Companies (LDCs). The estimate is obtained by extrapolating the 5% of energy by fuel-type based on actual generator hourly output and the HOEP as reported by the IESO.

In 2009 the embedded generation was small enough at 2TWh to ignore in the baseline.

The short explanation

The short explanation for the 103% RPP rate increase – that portion of cost which is over and above what you paid in 2009 – is because of

• increased supply share of new, above average cost generation,
• cost of refurbishing existing generating facilities,
• the impact of electricity market pricing,
• shifting of Global Adjustment costs,
• protocols for forecasting RPP rates

The incremental costs are split almost equally between sustainment of legacy, regulated supply owned by Ontario Power Generation and the cost of new generation under contractual agreements.

Energy pool (supply) cost increase

Here is the visual representation of the supply-mix contributions to the energy pool cost increase. The industry does not provide this specific type of report, so the values are estimated from multiple reports which are publicly available.

Figure 1 (repeated) – Supply Contribution to Incremental Costs from 2009 to 2019

The total amount of the chart represents the $5.7 billion cost increase over the last decade (Table 3). The ‘Other’ category represents the sum of conservation, biomass, energy storage and financing costs.

Fossil fuels are not shown because of the net decrease in cost over the last decade with the elimination of coal and reduction of natural gas use. The Non-Utility Generators (NUGs) managed through the OEFC are mostly natural gas and also showed a cost reduction over the last decade due to the gradual expiration of their contracts. Some of the NUG contracts transitioned to IESO management under confidential terms. Ontario spent almost $1.7 billion less on fossil fuel generation in 2019 than a decade previously. The savings have been deducted from the categories shown using energy-weighted proportions.

The energy pool and Individual supply mix elements have detailed explanations under their own headings below.

A temporary reprieve

While the electricity costs continue to rise, most ratepayers are not experiencing the reality on their bills due to various government subsidies. The largest of the subsidies is the former Fair Hydro Program or now the Ontario Electricity Rebate which cost $1.2 billion in 2019 and trims approximately 30% off the energy portion of the RPP bill. The Ontario Government holds the accumulating debt from the Ontario Electricity Rebate. The Financial Accountability Office prepared an assessment of the plan in 2017 here.

The energy pool or supply cost

When I refer to the ’energy pool cost’ I mean the sum of all charges that are recoverable through the electricity commodity charge in Ontario. It includes the payments to over 30,000 generators through electricity market settlements (i.e. the HOEP) and the Global Adjustment (GA). It may also be called the supply cost.

Over the last decade, the following items have been factored into supply cost:

• Market Priced Generation
• OPG Regulated Assets
• NUGs
• Contracted Renewables
• Other Contracted Generation
• Conservation and Demand Management Costs
• IESO Interest Costs
• Smart Meter Charge
• Early Movers
• OPG Non‐prescribed Asset Rebate
• Variance Clearance
• Environmental programs to reduce emissions

Some of the elements of the supply cost have decreased or disappeared entirely over time due to regulatory changes. While some of the items may not be mentioned specifically they are rolled up in the cost categories of this analysis.

The IESO reports on annual energy production cost, the HOEP, the GA and average unit-energy cost in different publications with values that do not reconcile. I have used data from the IESO’s 2005-2015 10-Year Report for 2009 based on direction provided by the Ministry of Energy, Northern Development and Mines. I am grateful to the Ministry for being gracious enough to respond to my inquiries. It provides a starting point for the 2009 pool cost. The report discloses that generation cost was $10 billion (including conservation) for 151TWh of production. That makes the 2009 average unit-cost of energy 6.61 cents per kilowatt hour (kWh).

In 2019 the average price reported by the IESO in their year-end data is not relevant since they only provide the Class B average, meaning we must look elsewhere for the actual average pool cost. In 2019 the IESO had a comprehensive audit on their operation in which they account for the energy-market cost and the Global Adjustment as $15.7 billion. Performing a secondary check, calculations based on generator hourly output and estimating embedded generation sums to $15.8 billion. The 2019 system-wide report shows 155TWh of generation which makes the average unit-cost of energy 10.1 cents/kWh (forgiving the rounding errors).

The average rate for the pool increased by 53% over the 2009 to 2019 period.

The Ontario supply mix

Reporting system wide energy supply is required by Ontario Regulation 416/99. The 2009 data is provided in the IESO’s 2005 to 2015 10-Year Review. The 2019 information is widely available from the OEB and many local Distribution Companies as follows:

The yearly statistics are:

Table 4 – Supply Mix by Fuel-Type 2009 & 2019

Note: this is not the information provided by the IESO in their Media Year-End Summary. The IESO typically reports on grid level statistics which exclude embedded generation.

Supply Mix – cost, energy share, capacity factor, curtailment and trend

Energy pool cost increases are due to the combination of rates, supply share, resource utilization, market rules and contractual terms. The supply mix has changed dramatically over the last decade with the elimination of coal-fired plants and the rise in renewable energy. Ontario’s supply-mix share of fossil fuel has decreased by 65%. The increase of wind and solar has been so large that it completely dwarfs the changes to other supply-mix sources. Wind energy has increased 5-fold and solar went from being almost non-existent to 2% of our total supply.

An explanation of capacity factor (CF) can be found in my articles on solar and wind energy. It is basically an indicator of how often a resource is utilized over time – in most cases, a year. CF has a major impact on how a power producer earns revenue. Low CF generators must either charge high rates or seek other contractual mechanisms to recover their costs and make a profit. The lowest CF supplies are natural gas, solar and wind. The highest CF supplies are nuclear and hydro. Ultimately, CF impacts our energy pool cost.

In the last decade we have seen changes to the supply and demand that have created times where Ontario has excess generation capacity. The grid has always managed contingencies where circuit capacity limitations require generators to limit their output. These situations require curtailment of generator output (dispatch down). Grid Operators impose requirements on power producers through dispatch instructions. Under situations where generators are curtailed they are compensated through market rules for congestion management or contractual terms for dispatch. Congestion management represented a $106 million cost to the energy pool in 2019. Dispatching costs for wind and hydro are not disclosed, however an educated guess would put them somewhere between $300 and $400 million in 2019. They would be part of the $12.9 billion Global Adjustment cost.

Nuclear

Pickering Nuclear Station – photo courtesy of OPG

Nuclear generation is a mix of regulated (Pickering and Darlington) and contracted (Bruce Power).

Table 5 – Regulated Nuclear Supply (OPG)

The largest generating facility under contract in Ontario is the OPG-owned Bruce Nuclear plant which has been leased to Bruce Power since 2001. The rate for Bruce Nuclear is provided by the OEB in their RPP reporting in 2009 and obtained by IESO hourly data for 2019 as follows:

Table 6 – Leased Nuclear Supply (Bruce Power)

*Calculated from hourly generator output, HOEP and GA published by the IESO

Although Bruce Power’s rates have increased over the last decade they remain the lowest cost contracted energy supplier. They have increased their annual output over the last decade as some generator units came back on line following extended outages for refurbishment. The Bruce Power business model is unique in that they are not owners but lease from OPG. Their costs are different from other power producers who own and operate their facilities. The overall impact of the Bruce Nuclear contribution was to lower the average rate increases for contracted energy since it displaced other more expensive sources.

Total nuclear generation curtailment due to Surplus Base Generation (SBG) conditions was 0.7TWh (2019 IESO Year-End Report) or less than one percent of annual energy.

Capacity Factor: 2009 – 82%, 2019 – 85%

Curtailment: 2009 – 0, 2019 – less than 1%

Future cost trend: UP; no new supply in the planning horizon; declining supply due to Pickering closure and refurbishment of Bruce and Darlington.

Coal-fired generation

Nanticoke Coal Generating Station – photo courtesy of OPG

In 2009 the IESO reported a 9.8TWh or 6.5% contribution of coal-fired generation to the supply mix. Coal plants were completely shut down by the end of 2014. The 2009 cost of coal generation based on the published rate of 3.9 cents/kWh was $386 million or 4% of the pool-cost. Effective January 1, 2009, OPG’s coal generation incurred costs due to a greenhouse gas reduction strategy which were paid by the OEFC and subsequently all ratepayers as part of the Global Adjustment. Those costs do not appear as part of the published coal-fired rate of 3.9 cents/kWh. The period from April 1, 2009 to March 31, 2010 the cost reported by the OEFC was $455 million. Approximating for the 2009 calendar year based on OEFC financial reporting, the subsidy was $380 million which doubles the unit cost published by OPG. The OPG support charges ended in 2014 with the shutdown of coal-fired generation.

Table 7 – Coal-Fired Generation Supply Data (OPG)

Capacity Factor: 2009: 18%, 2019 – N/A

Curtailment: N/A

Future cost trend: N/A; all coal facilities retired as of 2014.

Hydroelectric generation

Des Joachims Generating Station – photo courtesy of OPG

Regulated hydroelectric rates have increased over the last decade. The OEB approved rates are as follows:

Table 8 – Regulated Hydroelectric Rates (OPG)

Contracted hydroelectric generation supplied 6.7TWh of grid energy in 2019 at an average 13.7 cents/kWh based on IESO data.

Table 9 – Contracted Hydroelectric Rates

*Based on published rate by OPG
**Calculated from hourly generator output, HOEP and GA published by the IESO

In 2009 the hydroelectric contribution to Ontario’s supply mix was reported as 38.1TWh or 26% of total energy. OPG-owned hydro stations supplied 36.2TWh or 95% of hydro energy at published rates. Contracted capacity provided 1.9TWh at undisclosed rates. For the purpose of this report I approximated the unregulated 2009 hydroelectric cost by using the regulated rate. In 2009 regulated and non-regulated rates reported by OPG were within 15% of each other. Any error from the assumption will be less than 1% of the total energy pool cost estimate.

In 2019 the hydroelectric contribution to Ontario’s supply mix was reported as 37.2TWh or 24% of energy. The regulated generation produced 30.5TWh or 82% of hydro energy at published rates. Contracted hydroelectric generation accounted for 18% of the total hydro energy. Procurement programs such as FIT, Hydroelectric Contract Initiative (HCI) and the Hydroelectric Standard Offer Program (HESOP) paid 12.1 – 24.6 cents/kWh. The Feed-in Tariff (FIT) hydroelectric pricing peaked in 2014 at 24.6 cents/kWh but only attracted 3% of the contract capacity. The 2019 estimated rate for contracted hydro was obtained by using generator output data available for 86% of reported energy and extrapolating the remainder.

In 2019, 3.3TWh or 11% of production from OPG’s regulated hydroelectric stations was forgone due to SBG conditions (OPG 2019 annual report).

Capacity Factor: 2009 – 56%, 2019 – 46%

Curtailment: 2009 – N/A, 2019 – 3.3TWh or 11%

Future cost trend: UP; 56MW new supply in the planning horizon; continued refurbishment of existing infrastructure.

Natural gas

Halton Generating Station – natural gas

Compensation for natural gas generation is determined by contracts whose terms are confidential. They are typically structured with a minimum payment to cover fixed costs for sitting idle. Additional terms will likely include compensation for synchronizing, ramping up or down and energy production. The 2009 natural gas rates must be estimated since there was no generator output data or GA breakout available for that year. In 2019, transmission connected gas generation had a capacity factor of just 11%, dropping from 32% in 2009. Natural gas currently has the lowest utilization of all sources supplying the grid, however it is extremely versatile and essential for reliability. The rates for natural gas energy can be accurately estimated in 2019 since the IESO provides all of the necessary hourly data and Global Adjustment share.

Table 10 – Natural Gas Rates

*Extrapolated from total energy cost due to the lack of data for 2009
**Calculated from hourly generator output, HOEP and GA published by the IESO

Capacity Factor: 2009 – 32%, 2019 – 11%

Curtailment: N/A

Future cost trend: UP; 951MW new supply in the planning horizon; declining supply due to contract expiration.

The increase in rates over the last decade is likely due to contract terms and the substantial decrease in capacity factor of natural gas supply. On average, gas generation in 2019 sat idle 89% of the time. Generators are paid based on their contract terms when they sit idle.

Gas generators are also subject to excess emissions charges under the Greenhouse Gas Act ($20.00/tonne of CO₂e in 2019). Natural Gas generation in 2019 produced 9.5TWh of energy. OPG commissioned a report by Intrinsik which estimated that natural gas generation produces approximately 525g of CO₂e/kWh. That amounts to $100 million dollars in 2019 which was most likely passed on to ratepayers through the Global Adjustment. The total Global Adjustment cost for 2019 was $12.9 billion and pool costs were $15.8 billion. The emission charge was less than 1% of the energy pool cost. Imported energy from Natural gas sources is charged a carbon tax.

Wind

Wind Farm – Image courtesy of Pexels.com under creative commons license

In 2009 the energy contribution from wind was approximately 2.3TWh or 1.5% of the total supply. Most of the capacity was contracted through RESOP at an average rate of 11.08 cents/kWh. In 2019 wind supplied 12.7TWh or 8.1% of energy at an estimated cost of 15.8 cents/kWh. Wind energy procurement under the LRP program had a weighted average cost of 8.56 cents/kWh. The increased rate for wind energy is largely due to the curtailment of 2.6TWh of energy or 18% of the total wind output. Generators are compensated for the curtailed energy which drives up the unit-cost.

The Auditor General 2011 Report section 3.03:

“if the IESO instructs wind generators to shut down under a surplus-power situation, the generators still get paid under the FIT program”

The rate increase from 2009 to 2019 is due to the combination of contracted rates and curtailment costs. The impact on the cost increase of the energy pool is primarily due to the large increase in supply share over the 11 year period.

Table 11 – Wind Rates

*RESOP 2009 rate
**Calculated from hourly generator output, HOEP and GA published by the IESO

Capacity Factor: 2009 – 28%; 2019 – 26%

Curtailment: 2009 – 0; 2019 – 2.6TWh or 18%

Future cost trend: NEUTRAL; 160MW new supply in the planning horizon; declining rate due to competitive procurement process offset by inflation adjustment and output curtailment for generators under contractual terms.

Solar

Solar Farm – Image courtesy of Pexels.com under creative commons license

In 2009 the solar energy contribution was ramping up from an estimated 40MW of capacity by year end. The capacity was contracted through RESOP at an average rate of 42 cents/kWh, however the overall energy contribution and cost to the pool is too small to be considered. In 2019 solar supplied 3.7TWh or 2.4% of energy at an estimated weighted cost of 46.6 cents/kWh. The increased rate for solar energy is largely due to the weighted average across programs that procured capacity at a wide range of rates.

Table 12 – Solar Rates

*RESOP 2009 rate
**Calculated from hourly generator output, HOEP and GA published by the IESO

The solar energy impact is significant because of the high unit-cost and compounded by the increase in supply share over the last decade.

Capacity Factor: 2009 – N/A; 2019 – 16%

Curtailment: N/A

Future cost trend: NEUTRAL or DOWN; 32MW new supply in the planning horizon; declining rate due to competitive procurement process offset by inflation adjustment for generator under contractual terms. New supply is net-metered, meaning the compensation is equivalent to the average plan rate. The most expensive solar energy will begin to reach end of life and contract expiration in 2030.

Other supply-mix elements

In the ‘Other’ category, small costs include bioenergy, non-contracted generation, conservation and financing charges. They amount to approximately $400 million in increased costs.

Imports and Exports

In 2019 Ontario exports would have earned $304 million based on 19.4TWh of exports and the posted HOEP. Revenue shortfalls based on contractual or regulatory terms for generators are made up by the Global Adjustment. Since we compensate generators when they are dispatched down, it is better to export their energy as long as the transaction’s rate is above the marginal cost of generation. The marginal cost of generation is largely attributable to the cost of fuel. Since wind and solar have zero cost for fuel, it makes sense to export when they are part of the supply mix rather than dispatch-down. Revenue from exports are most likely to lower the average energy rate, however the amount is small and not broken out this analysis. The Environmental Commissioner of Ontario explained the principles in their 2018 ‘Making Connections’ series of reports.

Ratepayer Groups – Class A & B

In 2009 the industry relied on the electricity market to determine the price. In 2010, two different categories of load customers were created to provide price incentives tied to conservation initiatives. They are referred to as Class A and Class B. The Class A category gets a discount on the Global Adjustment based on meeting conservation targets set out in the Industrial Conservation Initiative (ICI). Average discounts for Class A customers are approximately 30%. The plan is administered by the IESO. The incentive has increased the Class A energy-pool share to greater than 25% in 2019.

Figure 4 – Class A & B Supply Share

Class B customers include wholesale metered and retail contracts. The Class B customers pay the remainder of the Global Adjustment after the discounted Class A portion is determined. Class B customers are charged based on the market price plus the Class B Global Adjustment. RPP customers are a subset of Class B and pay for energy based on Time of Use (TOU) or tiered pricing formulas.

The Class A discount shifted $1.4 billion of the Global Adjustment to Class B customers in 2019. The RPP portion of that was $854 million.

The Regulated Rate Plan (RPP) – part of Class B

The main focus of this article is on customers who are part of the Regulated Price Plan. Unfortunately, members of the plan pay a premium to subsidize industrial rates.

Note: The rates shown are average – not the tiered or Time of Use (TOU) values. Tiered and TOU rates are determined by calculations described in the Ontario Energy Board Price Plan Reports, however an average customer will wind up paying the average price on a year-over-year basis.

Figure 5 – The Regulated Supply Plan Share of Total Supply

Table 13 – Regulated Price Plan Rates 2009 & 2019

The RPP rates apply to almost 5 million residential and general service customers. From 2009 to 2019 the RPP share of total energy supply has been between 38 and 39%. In 2019, they accounted for 61% of the Class B load.

The reasons why RPP rates rose more than the pool are: decline of market price (HOEP), increase in Global Adjustment (GA), creation of A&B customer classes and the terms of the OEB forecasting model.

The price for electricity in this plan is based on forecasts done twice a year. Being a forecast, it is never 100% accurate. The forecast compensates for variances from the actual cost of the previous time period to keep the books balanced. Variances stay within the plan and may be positive or negative. In 2009 the RPP plan had a positive variance from the previous time period which reduced the average rate by 0.25 cents/kWh. The forecast is published as the “Regulated Price Plan Price Report” or “Regulated Price Plan Supply Cost Report” in the spring and fall on the OEB website. The IESO publishes data which is based on actual measurements which makes their reports slightly different from the forecast of the OEB. If you reference the IESO data it will be slightly different than the RPP report. The RPP rates over the long term should track closely to the Class B average as posted by the IESO. Consumers in the RPP always pay their bills based on the OEB forecast.

There is an additional cost impact to RPP customers because their energy use patterns differ from the rest of the supply pool. RPP customers tend to use their energy at times when the energy market price – the HOEP – is higher than average. The different use pattern increases the RPP’s forecasted share of the HOEP by approximately 10%. The HOEP has decreased significantly over the 11 year period which has reduced the overall impact of energy use patterns. The reduction of HOEP results in an increase in the Global Adjustment to compensate. RPP customers are hit by the combination of a rising GA and having to pay a greater share of it.

The 11-year RPP summary:

Table 14 – Regulated Price Plan Data 2009 & 2019

* based on Spring OEB RPP Price Report

**based on the forecasted load of 59TWh at 12.4 cents/kWh

By 2019 the RPP share of the Global Adjustment increased by 31% from 2009. The global adjustment now accounts for 85% of the average RPP cost.

The forecast of the Regulated Price Plan rate is based primarily on the HOEP and GA

In 2009 there was no distinction between ‘classes’ of customer. RPP customers paid the forecasted average pool cost of 6.1 cents/kWh. In 2019 the average pool cost can be calculated from IESO and supply-mix reporting as 10.1 cents/kWh, however RPP customers paid 12.4 cents/kWh. The difference in average pool cost from 2009 to 2019 is due to the factors underlying the cost of generation and changing supply mix (see Figure 1):

• increased supply share of new, above average cost generation,
• cost of refurbishing existing generating facilities,

The factors that increased cost from the pool average of 10.1 cents/kWh to the RPP forecasted average of 12.4 cents/kWh are:

• the impact of electricity market pricing,
• shifting of Global Adjustment costs,
• protocols for forecasting RPP rates

Here is how the RPP cost increase breaks out based on those numbers:

Figure 6 – Factors Impacting the Regulated Price Plan Increase from 2009 to 2019

The supply cost increase accounts for 53% of the incremental cost in the RPP. The other roughly 47% is the RPP premium due primarily to the creation of Class A&B customers and the behaviour of the electricity market. The market has experienced a steady decline in the electricity price during a time when energy costs are rising. The lower market price results in an increase in the Global Adjustment of which Class B customers are paying an increasing share.

The Hourly Ontario Electricity Price (HOEP) and Global Adjustment (GA)

The Hourly Ontario Electricity Price (HOEP) is determined by the wholesale electricity market where participants buy and sell energy. The market price is updated every 5 minutes to the Market Clearing Price (MCP) and averaged out every hour to become the HOEP which is posted by the IESO.

The Global Adjustment (GA) is primarily an amount required to true-up the difference between the HOEP and the contractual or regulatory amount which must be paid to generators. Some additional items are funded through the GA and are identified in Figure 8.

Table 15 – Hourly Ontario Electricity Price and Global Adjustment Rate 2009 & 2019

*Estimate based on average pool-rate of 10.1 cents/kWh in 2019

There are some basic facts that ratepayers should be aware of when it comes to understanding the HOEP and GA as it pertains to electricity costs in Ontario. The HOEP is determined by the wholesale market and the GA compensates for the contractual or regulatory shortfall of those prices.

No load customers pay the HOEP even though it is the price bid in the wholesale market. They pay the sum of the HOEP and GA. The formula may be different for specific groups, however everyone pays a share of both.

No power producer gets paid the HOEP (or the MCP) even though it’s the price offered in the wholesale market. At the end of each month their compensation is trued-up to meet the contracted or regulated compensation. The only exceptions are for bilateral contracts and power producers that do not have a contract. Those exceptions are too small to consider in this discussion.

The GA is primarily for making up the shortfall created by an artificially low HOEP. It has other components lumped in, however it is more like a generation adjustment than a Global Adjustment.

There are cases where special terms apply:

• generators and load customers that have entered into bilateral pricing agreements
• dispatchable generators and loads settle based on the 5 minute MCP instead of the HOEP.

These are not broken out in the results as presented because they don’t have a significant impact on the high-level findings in this analysis.

Figure 7 – The Global Adjustment – Generation vs all other costs 2019

The detailed breakdown of the GA for 2019 as provided by the IESO looks like:

Figure 8 – Global Adjustment – all components

The HOEP and GA are published in the IESO’s Quarterly Energy Report. The report shows the Class A and B rates which are referred to as the commodity cost.

The main stakeholders in the dynamic behaviour of the HOEP and GA are those who participate in the IESO’s physical market bid/offer process and those who have opted-out of the RPP in favour of a retail energy contract. The rest of us are just along for the ride as protocols are in place to determine how we share costs and what rates apply. It cycles back to the total pool costs and who-pays-what share of them.

Rate calculations are not well understood by anyone outside of the industry. The explanation and formula used is available from any RPP Price Plan Report by the OEB for those who feel the need to pursue the subject.

The environmental impact of 11 years of change

The decision to reduce the environmental impact of electricity energy production is part of the reason costs have risen. It is the driver behind the supply-mix change over the last 15 years.

In June of 2005, the McGuinty government announced a plan to clean up energy production by eliminating coal-fired generation and expand the use of cleaner-energy alternatives. Electricity sector emissions have since dropped by 90%.

In the 11 year period from 2009 to 2019 there was a decrease of 65% in fossil fuel generation. Annual greenhouse gas emissions declined from 14.9 Megatonnes of CO₂e in 2009 to 4 Megatonnes in 2019.

Other emission reductions included sulphur oxide (SOx), nitrogen oxide (NOx), Mercury emissions (Hg) and fine particulate matter emissions less than 2.5 μm (PM2.5) as follows:

Table 16 – Emissions from Ontario’s Electricity Supply 2009 & 2019

Sources: Ontario Energy Quarterly Q4 2019 – Electricity; IESO’s State of the Electricity System: 10-Year Review

According to the government’s 2017 Long Term Energy Plan:

“In 2003, the electricity sector represented about 20 per cent of Ontario’s total greenhouse gas emissions. As a result of phasing out coal-fired electricity generation in 2014, emissions for Ontario’s electricity sector are forecast in 2017 to account for only about two per cent of the province’s total greenhouse gas emissions.”

It is possible (although not scientific) to attribute the incremental pool cost of $2.5 billion in 2019 for wind and solar energy to the policy decision to clean-up our electricity supply.

The next decade – 2020 to 2029

There is plenty of information out there telling us a great deal about what to expect in the coming decade. The government of Ontario is required to publish a long term energy plan at least every 4 years. The last one was published in 2017. A new energy plan is due any time but must be published before the end of 2021. The IESO publishes 18 month, 10 and 20 year outlooks. The OEB publishes their roadmap although they are continuously engaged in reviews and forecasting.

It doesn’t take much industry insight to predict that costs will continue to rise, but the extent to which they do depends on government policy. The 2017 published plan forecasts the average residential customer using 750kWh a month will see their cost go from $128 to $191 per month. That represents a 49% increase in rates.

The factors driving cost increases over the coming decade are going to change substantially. We have already taken the hit for renewable energy and there isn’t much likely to happen in the coming decade that will push rates up from this driver.

The cost of refurbishing the nuclear plants will likely be the single biggest factor in our rising costs. We will see the impact of Darlington and Bruce refurbishment. Darlington costs are forecasted at $12.8 billion. The Bruce refurbishment cost forecast starts at $2.2 billion in 2020 for the first of 6 units to be completed by 2033. The refurbishment costs are capital investments which would be recoverable through energy rates over the estimated service life of the assets.

Refurbishment and upgrades of hydro generators will continue causing rate-creep.

According to the IESO’s Annual Planning Outlook for 2020, our surplus base generation will decrease significantly by 2023 as nuclear units go off line and more expensive gas generation will take its place. Reducing surplus base generation will increase the capacity factor of grid connected generators which tends to lower rates.

A large portion of contracted generation will end in the coming decade which presents an opportunity to negotiate more competitive rates and shut down expensive surplus capacity. Unfortunately, Ontario has a poor track record when it comes to negotiating competitive contract rates for generators.

The Ontario Electricity Rebate is accumulating billions of dollars of debt and could be phased out at any time. Rate impact depends on whether the debt is left with the Ontario government to be paid by taxes or moved back into the energy pool to be paid by ratepayers.

Overall, rates will be increasing substantially over the next decade. The next Long Term Energy Plan will need to address the strategy to manage increasing cost pressures.

The takeaway

Over the 11-year period 2009 to 2019:

• Class A customer rates increased by an average of 17%
• Class B customer rates increased by 91%
• Regulated Price Plan customer rates increased by 103%

The top 2 factors in the Regulated Price Plan increase were not solar and wind energy although they were significant contributors

If you are part of the Regulated Price Plan your electricity rates doubled from 2009 to 2019. Approximately 53% of that increase was due to the increased cost of generation over that period as follows:

The remaining 47% (see Figure 6) of the cost increase is a result of

• creating Class A&B customer classes in 2010 and shifting of Global Adjustment costs to Class B (RPP) customers
• the impact of electricity market pricing,
• protocols for forecasting RPP rates

Table 17 – Incremental Regulated Price Plan (RPP) Cost Increases from 2009 to 2019:

RPP customer rates are based on forecasts and should track closely to the Class B rates published by the IESO over time. See the Ontario Energy Report Quarterly (requires Microsoft Edge browser). Time of Use and Tiered rates in the plan are calculated from the average cost so that the average customer pays the average rate on a yearly basis.

Fossil fuel use declined by 65% over the last decade contributing to a massive decline in emissions from the electricity industry. The switch to higher efficiency natural gas, introduction of solar and wind energy played a significant role in emission reduction.

Energy rates will continue to rise over the next decade. The 2017 Long Term Energy Plan (latest) produced by the government forecasts a 49% increase. Exactly how much the increase will be depends on the success of the nuclear refurbishment projects, management of expiring generating contracts and the fate of the Ontario Electricity Rebate.

Fasten your seatbelts, we are in for a rough ride.

Derek
Updated October 23, 2020 – changes to RPP cost increase charts including figure 6 to show 53% impact of supply increase and 47% due to RPP premium factors.

Updated October 28, 2020 – changed the order of sections and renumbered tables & figures. Added the statement of fact that the two greatest impacts on RPP rates are not from solar and wind.

Author: Derek Hughes

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