Monthly Report

PreCurrent Month

This is a report to complement 
Ontario's Independent Electricity System Operator (IESO) monthly report . The IESO report has many figures that are either of interest primarily to wholesale market participants, or are from external data sources I have not attempted to replicate (such as weather, and prices in adjacent markets).  

The IESO's monthly report is generally available midway through the following month, which is also the time-frame the Global Adjustment figures are finalized.   This report will provide preliminary figures, based on the second estimates of the global adjustment, until it gets updated following the IESO's release of final global adjustment figures generally by a couple of weeks.  Figures will change after the preliminary report is posted.

The data structure is revised frequently, with the most significant changes occurring May 2016. Particularly fickle are estimates on solar, primarily due to poor data quality slowly improving.

Hourly Ontario Energy Price (HOEP)

This is the first section of the IESO's Monthly Market Report, and it's a good example of why an alternate/complimentary/shadow report can be helpful.

The IESO provides two graphs of HOEP, which they introduce as being:
"the hourly price that is charged to Local Distributing Companies [LDC's] and other non-dispatchable loads....
HOEP becomes the basis of the commodity charges in the Retail electricity market if customers receive their electricity from their [LDC]"
They've introduced the HOEP section the same way since  their first report for May 2002.  HOEP is now a small component of the commodity charge (see the Supply Costs page for more on components of current pricing)
This site's Weekly Reporting shows HOEP graphed with the comparable week.

The IESO monthly reporting provides a views of the HOEP figures for "On-Peak" and "Off-Peak" periods, as it has since May 2002.  The hours the IESO is referencing are entirely different than the hours that end customers in the "retail electricity market" have come to know as On, Off, and Mid-peak as smart metering enable time-of-use billing.  Estimated figures for TOU categories are:


The IESO also provides a graph illustrating the frequency the HOEP was within a range; for example the percentage of all hours the HOEP was between $10 and $20/MWh (1-2 cents/kWh).  The implication of time-of-use rates is that costs are high during higher demand periods of the day, and low during lower demand periods of the day, so another 'indicator" of a market's health may be the range of pricing as demand rises and falls.  The HEOP's Figure 2 is altered here to add the frequency range of the HOEP over a number of years (for the same month in each):

2. Market Demand

The IESO defines demand for both the "Total Market", and Ontario:
Total Market Demand represents the total energy that was supplied from the IESO-Administered Market.
The IESO calculates Total Market Demand by summing all output from generators registered in the Market plus all scheduled imports to the province. It is also equal to the sum of all load supplied from the Market plus exports from the province, plus all line losses incurred on the IESO-controlled grid.
Ontario Demand represents the total energy that was supplied from the IESO-Administered Market for the sake of supplying load within Ontario.
The IESO calculates Ontario Demand by subtracting exports from the Total Market Demand quantity. It is also equal to the sum of all load within Ontario which is supplied from the Market, plus all line losses incurred on the IESO-controlled grid.

These definitions have been consistent since the market opened in May 2002.  They are also not entirely correct when examined from a perspective outside of the market.  Distributed generation (DG) is the term for generation outside of the "IESO-Administered Market," 'distribution connected' generation includes the vast majority of solar power that is, or will be, part of the supply that meets Ontario Demand.  

The IESO reporting will become increasingly less indicative of the actual supply in Ontario, and the definitions mean that will increasingly distort the actual demand reporting too.  Note the IESO's definition of Ontario demand excludes measurement of demand in Ontario.  It is all supply (except it isn't - due to DG) plus all imports, less all exports.  This captures all line losses, whereas a more complete balance sheet allocation of all supply would provide line losses as a balancing entry.

The IESO has been reporting Ontario Demand in a manner derived from supply statistics, instead of as a sum of metered consumption (metered statistics are available, on the IESO site, for 1994-Market opening in 2002!). The following table reproduces figures that should match the monthly IESO reporting, but adds estimates for load - meaning the actual metered consumption of electricity the costs of supply will be distributed to.
Load is increasing as a percentage of the IESO's reported demand (which it has now surpassed), as the IESO figure is actually the generation on their grid, but most solar and some wind is embedded within local distribution companies (and therefore acts to reduce demand for generation from the grid).

The relationship between the difference in the changes between Ontario demand and total demand indicate whether trade is increasing or declining.  

2. Imports and Exports

The IESO presents the hourly import and export graph for the month - for some context the following graph includes the same data for the prior year.

Viewing the imports and exports separately may not be as meaningful as looking at only the hourly net exports - this is, in part, because many imports may be on a pass-through basis (ie.  bought in Quebec for consumption in Michigan):

Longer-Term Trends

The longer-term trends section of the IESO's monthly report was set-up in 2004, with relatively little history since market inception in May 2002.  The decision was made in preparing the reports for 2004 to show weekly figures in some cases (presumably to increase the data points to graph), and the first graph, in particular shows a trend line average data from 2002 on, while the graphed data is only for the previous 12-months.
Updating the graph from a consumer perspective, I've graphed 12-month moving averages to display the long-term trend, along with the monthly data points , starting after the rate freeze was unfrozen in 2005.

The IESO's Figure 12 shows "On Peak" and "Off Peak" averages for the HOEP based on the definition of those periods for market participants; definitions for the time-of-use billing categories residential and small business customers are different.  
I display estimates of the weighted averages for residential TOU period for the same 13-month period shown in the IESO's figure 12.

The 13-month graph gives a nice overview of the past year and offers the comparison to the same month a year earlier.
A moving 12-month average graph better communicates the trend.  When the first time-of-use rates were introduced in 2006, the ratio was essentially 1:2:3 (Off peak 3.5 cents/kWh, mid 7.5 and on-peak 10.5).  Since then the ratio has contracted reflecting a market ration closer to 1:1.5 (with little difference in mid and on-peak rates)

Market Demand Trends.

The IESO provides a graph of weekly data points (56) showing maximum, minimum, and average hourly values for 'Total Market Demand' - which is all generation plus all imports. I find this of limited utility as the variance is likely to indicate hot and cold weeks, making a trend difficult to spot.
A 10-year dataset of 12-month running average, minimum, and maximum 'Total Market Demand' figures provides a better view of trending (with the exception of the figures impact by the 2003 blackout).

The total market references the size of trade - the market can expand by producing more supply in Ontario for export, or by importing more for one neighbour while exporting to another.  The same data for Ontario demand only shows the trend for only the Ontario market - production figures are shown, which indicate Ontario has been a net exporter for a number of years now.

The IESO shows "Monthly Energy Totals" as Ontario demand and exports; illustrating the total on a stacked bar chart for the past 13 months (Figure 18).
On the bottom of the same page they show the corresponding supply (generation plus imports (Figure 19).  Together these provide a picture of supply and demand over the past 13 months.

Again, due to seasonality of demand that doesn't establish trending as well as comparing to the same month in past years, or the running 12-month total.

The same month for the past 11 years is simple from the market side, as these are derived for the .txt files the IESO has for demand and import and export.  The supply side requires improvisation.   
I have hourly output data, by generator, since September 1, 2010.  This data is not complete, as the IESO does not report on all generators.  There are self-scheduling smaller generators, which I assume can be measured as the [Total Market Demand] less [Imports] less the sum of the generators that do report.  These comprise much of the "other category, along with some gas/biomass combination facilities.  There is another set of generators that are not included in the IESO reporting in any way, including most solar generation (embedded).  Reflecting on the IESO definition on Ontario demand noted earlier, this means demand, coinciding with the embedded generators, is also not reported.  This is a rapidly expanding category and so far Ontarians are receiving essentially no reporting on the production contracted, at their expense, with commitments/liabilities taken on for 20-25 years.
To generate production data prior to September 2010, I transposed IESO graphs (Figure 19) to get estimates of each "Fuel Type" ... making the data after September 1, 2010 more accurate than the data preceding it.  I did check the totals, and was not satisfied with 2003 ... so the following charts, of the same month over a number of years, start in 2004.  The data accuracy is further impacted by the fact the IESO's graph (Fig 19) changed to include "Gas/Oil" only in February 2009, before which it was included in the graphing as "other."  I have assigned 90% of the "other" fuel type to "Gas/Oil" for the months prior to February 2009.  
The figures are therefore not perfect - but suffice, as estimates, for illustrating the trends.

12-month running totals illustrate longer term trends.

The next graphs are from data sets including my estimates on both generation and costs by 'fuel'.  Figures released by the Ontario Power Authority confirm a lot of what will drive price changes is "embedded" generation - which doesn't show in the IESO's generator reporting (or in their "demand" figures).



The IESO does not report on emissions.  Emissions are, I believe tracked by source, which is why they are not reported on for long after the event.  
Estimating emissions is a simple process though.  I have used the same figures the Ontario Society of Professional Engineers did in their recent "Wind and the Electrical Grid: Mitigating the Rise in Electricity Rates and Greenhouse Gas Emissions" - which they reference as sourced on Natural Resources Canada RETScreen Clean Energy Project Analyse Software.
The figures are 973 g/kWh for coal generation, and 398 g/kWh for gas generation.  

I'd suggest the figure for gas generation my be particularly optimistic as Ontario's fossil fueled generation will need to run less efficiently as it increasingly serves peaking duties.  

Import/Exports per Intertie Zone

Section 2.10 of the IESO report shows a graph that depicts imports as positive values and exports as negative values.  I have reproduced the graph for the past 13 months.  There is occasionally a variance, on the export side, between the IESO hourly intertie values and the hourly export values in their weekly .csv file (investigated here).
The vast majority of imports come when Ontario is a net exporter.  During the first six months of 2011 Ontario was a net importer for only 37 hours, or less than 1% of the time.  There are many issues there (transmission zones, constraints, etc.) - but also a market reality than Ontario interties can function to move supply from one jurisdiction to another, via Ontario.

Surplus Baseload Generation

Surplus Baseload Generation (SBG) is a term that came into frequent use in 2009.  In longer term planning SBG is forecasted supply from nuclear, baseload hydro, committed generation (non-utility generators) and self-scheduling generators, which significantly include most wind suppliers.  The IESO does not include SBG information in it's monthly reporting (it does forecast SBG events on it's website).
The following graph displays total nuclear and wind output, as well as the output from hydro, natural gas and 'other' generators that data indicates run at all times - the hydro includes large regulated OPG operations that run at one level consistently, but can provide additional output to meet demand (thus the line is not flat).   

The IESO requires, at times, the baseload generators, that comprise the totals shown, to curtail production when consumers cannot be found for the supply.  Maneuvering includes steam bypass at the Bruce B nuclear units, extended outages at the Non-Utility Generators (NUGs), allowing water to flow over the falls (spilling water using spillways is rarely done), and utilizing the ability to direct output directly into Quebec's grid.   All of these things are difficult to quantify - but this report is about estimating, and my estimates of monthly curtailments are graphed here:

Global Adjustment

The global adjustment is the difference between the total payments made to certain contracted or regulated generators/demand management projects, and any offsetting market revenues. The adjustment may be positive or negative.

Figure 25 of the IESO's monthly reporting illustrated the monthly global adjustment as a total total dollar amount, and as an average monthly rate for one group of customers, for the past 13 months.  
A better presentation of the data is to stack the global adjustment along with the market value.  This is because what primarily drives the global adjustment is the contracted value of commitments to generators.  If the Hourly Ontario Energy Price (HOEP) averages $70/MWh, and that is the average contracted cost of all supply, the Global Adjustment would be near $0.  It's really the combination of the HOEP and the GA that is most relevant, with the GA acting largely as a measurement as to how well the market is functioning, or, perhaps, how the current market varies from the anticipated value of the market as the contracts with generators were established.

In this graph, the IESO's total value for the global adjustent is shown along with the total market value (Ontario and export demand) at the HOEP rate.  

The cost/MWh is not indicated here as it differs among different market segments.  The figures for the Global Adjustment are provided on the IESO's website

Summary of Electricity charges in Ontario

The final section of the IESO's monthly reporting is titled, "Summary of Wholesale Market Electricity Charges in Ontario's Competitive Marketplace" - as it was in 2003.
Very little of Ontario's marketplace is competitive - with the Global Adjustment demonstrating that.
The market on the consumption side is more complex than the IESO's reporting indicates.  Exports are not charged the global adjustment (and are likely sold slightly above the market rates).  The best available estimate on export pricing must be the weighted average HOEP rate.
The residential rate varies as each individual is billed on the usage based on either TOU rates or the older two-tier regulated pricing plan (RPP).   The two rate plans are priced prior to consumption, and should be essentially equal.  Therefore the best available estimate is the average RPP price listed by the Ontario Energy. Board.
Residential pricing should eventually equal pricing for commercial customers, but only through the use of variance accounts.  Commercial rates, up until 2011, were comprised of the charges based on the HOEP, plus the global adjustment charge applied as a price per MWh; until 2011, the same global adjustment charge would apply to all directly or indirectly.  The global adjustment was divided into two categories for January 2011; Class A and Class B.  The best estimate of commercial rates is the average HOEP plus the Class B global adjustment.
Industrial customers is a category that should roughly coincide with the Class A global adjustment customers (although some of Ontario's learning institutions quality).  Class A customers are defined by consumption level (greater 5MW).  The IESO provides the dollar allocation for class customers, but not a consumed kWh, or a rate per kWh.  However, using class B figures, it is possible to estimate the average rate for the global adjustment over the class A category.  Not all Ontario Consumption is applicable, but not all consumption that is applicable is included in the IESO definition of Ontario Demand (embedded generation, which should be growing along with solar capacity in the province), so the best estimate of an average industry rate I consider to be [Ontario Demand] less (Class B$ divided by Class B rate).

The Charges for the market segments in Ontario, for only the electricity consumption portion of their bills, is estimated in the following table:

2016 Addendum

The following charts display data for the same month (ie. May) during the period since I began tracking hourly generator data (September 2010). Showing the data for the period can demonstrate changes in supply mix and the cost of electricity supply to the various market segments.

The supply demonstrated here includes estimated distribution connected (Dx) generation as well as IESO grid-connected (Tx) and curtailed generation. Not estimated is curtailed public hydro.

Variances between these estimates and actual global adjustment charges is expected for a couple of reasons:
  • the global adjustment mechanism shifts costs for distributed generation forward into other months
  • the global adjustment mechanism includes charges, such as those for conservation, that are not included in my estimates
  • the IESO's first and second estimates of the global adjustment are not simply predictors of the final rate, but are set to adjust for previous months under/over charges.

The total cost of the supply charted above is estimated as:

The supply priced above either services "Ontario Demand", export markets, or is curtailed (generation is cut). The chart below reflects the same data as the chart above. Note that Ontario Power Generation reports 3.2 million megawatt-hours of hydro-electric generation was curtailed in both 2014 and 2015. I do not estimate that curtailment, so the charted value is very conservative:

Consumption of supply is slightly different. "Ontario demand" includes generation lost in transmission, and generation that powers generators. Monthly "Consumption" is provided by the IESO upon requests, and is something I estimate as it is necessary both for rate calculations and to determine the cost impact of "Class A" consumers (background here). These consumers were limited to consumers with a monthly peak demand over 5 megawatts, but the threshold was lowered, for some industries, to 3 MW as of July 2015.

Costs are not evenly distributed. Exported supply gets what the market can attain while Ontario consumers pay the full cost of supply through the global adjustment mechanism - a mechanism designed to transfer costs from Class A consumers to everybody else (Class B).

Rates can vary greatly between consumer classes:

Class B consumers, which include residential consumers on the regulated pricing plans that reflect forecasts of Class B commodity costs, pay the average cost of supply plus an amount to compensate for exporters, and Class A consumers, generally paying less than the average cost of supply:

Monthly reports are not archived, but spreadsheets with the data producing the graphics are, in preliminary  and final folders.