If limiting greenhouse gas emissions is the goal, the system is increasingly designed to fail.
Ontario fell into paying capacity payments over time. The key moments were a 2004/05 decision to offer "net revenue requirement contracts" to natural gas-fired generators - primarily to encourage market entrants to displace coal-fired generators. The enormous Lennox Generating station became less utilized and uneconomical - but the system operator felt it was necessary to the system and it started to receive contingency support payments soon after. In 2008/09 demand dropped with the recession, and the coal-fired generators (also felt necessary by system operators) also began receiving contingency support payments.
 |
| Graphic from Behind the Switch .... | The Pembina Institute |
Traditionally, all numbers related to producing electricity are thrown into a calculation and out pops a levelized unit cost. The graphic displays some estimated ranges for these costs (they aren't reflective of costs in Ontario for legacy hydro and existing wind contracts)
Looking at the data from May-July 2013, and the same months in 2012, reveals the magic impact of capacity payments as replacing high cost generation with low-cost generation drives up Ontario's electricity rates.
The average cost of a unit of electricity in Ontario is up 19% over the same period in 2012 [1]: export customers, and perhaps large "Class A" consumers are protected from much of the increase, so the average Ontario consumer will see rates up approximately 23.5% for the period [2]
.png)
In 2013 overall production drops (not as much as demand), but hydro shows strong growth, with nuclear showing the second largest MWh growth.
While the two lowest cost domestic generator types showed the strongest growth, the largest declines came in the far more expensive - using levelized costs - natural gas (primarily) and coal-fired generators.
There are other notable changes between the periods in 2013 and 2012, including lower exports (the cheapest supply), a suspected large, but unreported increase, in solar generation, and continuing government interference with the sector likely seeing costs of their bungled political gas plant cancellations passed onto ratepayers - but the 23.5% wholesale rate increase is partially due to a decrease in production from the higher carbon emissions, higher priced, fuels we wish to move off of.
This is due to capacity payments.
During the 3-month period in 2012, units with net revenue requirement contacts produced approximately 3.6 million MWh of electricity [4]; their payments would have been comprised of approximately $220 million guaranteed by the net revenue requirement and $32.33/MWh for the production (the average HOEP weighted to the generators' production). The average cost was ~$93/MWh.
In 2013 the production for May, June and July dropped 56%, to ~1.6 million MWh, but the net revenue requirement changes little, and the average cost received from production (HOEP) moved up only ~$5/MWh. The average, levelized, cost nearly doubled in climbing to ~$174/MWh.
During the 3-month periods being compared, I estimate the output of solar, wind, nuclear and hydro generators increased by 2.6 TWh (2.6 million MWh) while the output of coal and gas generators dropped by 2.8TWh [5] - so I will assume a zero-sum game, where every unit of production with one source displaces a unit of production from the NRR gas generators, with a value of $37.41/MWh (my estimate of the actual weighted average HOEP for the NRR gas generators for the period in 2013):
During the 3-month period in 2012, units with net revenue requirement contacts produced approximately 3.6 million MWh of electricity [4]; their payments would have been comprised of approximately $220 million guaranteed by the net revenue requirement and $32.33/MWh for the production (the average HOEP weighted to the generators' production). The average cost was ~$93/MWh.
In 2013 the production for May, June and July dropped 56%, to ~1.6 million MWh, but the net revenue requirement changes little, and the average cost received from production (HOEP) moved up only ~$5/MWh. The average, levelized, cost nearly doubled in climbing to ~$174/MWh.
During the 3-month periods being compared, I estimate the output of solar, wind, nuclear and hydro generators increased by 2.6 TWh (2.6 million MWh) while the output of coal and gas generators dropped by 2.8TWh [5] - so I will assume a zero-sum game, where every unit of production with one source displaces a unit of production from the NRR gas generators, with a value of $37.41/MWh (my estimate of the actual weighted average HOEP for the NRR gas generators for the period in 2013):
- Hydro production increased 1.4 TWh - at a $39/MWh rate that adds $2.2 million to costs
- Nuclear production increased 0.85 TWh - at a $59/MWh rate that addes $18.4 million
The hydro figure, in particular, indicates the absurdity of the market design, where replacing supply at half the levelized cost, and 0% of the emissions, causes a rate increase. The same mechanism likely prevents customer demand management programs from achieving expected savings.
- Wind production increased at least 0.165 TWh - at a $135/MWh rate that adds $16 million
- Solar production increased an estimated 0.189 TWh - at a $500/MWh rate that adds $87 million.
No surprises with the variable renewable energy sources (vRES). The higher the rate is above the fuel required to generate the same amount of electricity, the harsher the rate impact.
Ontario's system will probably lead to high emissions, eventually, as the value proposition to consumers, also known as voters, is structured to encourage the use of facilities guaranteed revenue and therefore only having fuel costs as an incremental expense.
Ontario's system clearly demonstrates some truths being stated more often, exemplified by Schalk Cloete in The Fundamental Limitations of Renewable Energy:
Ontario's system will probably lead to high emissions, eventually, as the value proposition to consumers, also known as voters, is structured to encourage the use of facilities guaranteed revenue and therefore only having fuel costs as an incremental expense.
Ontario's system clearly demonstrates some truths being stated more often, exemplified by Schalk Cloete in The Fundamental Limitations of Renewable Energy:
...renewables need to overcome the following two challenges in order to displace fossil fuels in a fair market:
- Solar panels and wind turbines need to become cheaper than raw fossil fuels. This is the challenge posed by the diffuse nature of renewables.
- Storage solutions need to become cheaper than fossil fuel refineries (e.g. power plants). This is the challenge posed by the intermittent nature of renewables.
Ontario's procurement contracts have made all generators need to be cheaper than "raw fossil fuels" - which is simply bizarre.
If one were to think of designing mechanisms to reduce carbon, due to the perceived cost of externalities from burning carbon, taxing carbon would be a better approach. Carbon taxes are not going to do much to spur wind and solar generation - nor should that be the intent. The intent should be on enforcing a discipline to cost the externalities of the concern driving policy, and to align an economic desire to reduce cost with the desire to reduce emissions. Without pricing, the desire to reduce emissions is not economical, but only political.
Fortunately for the bulk of the people struggling with energy questions, it is possible to learn from a bad example. Annual 20+% inflation in Ontario is one more indication must-take power purchase agreements for the politically preferred, combined with capacity payments for the operationally required, are bad policy.
Endnotes
[1] The average cost is estimated, from IESO data, by multiplying the hourly "total market demand" by the "Hourly Ontario Energy Price", summing the value for all hours, adding in the total value of the global adjustment, and dividing the total by the sum of "total market demand" for the period.
[2] The increase is in the Class B customer "commodity charge" which is indicated in the IESO's monthly reporting (on the second to last page). Most residential consumers will not immediately pay this rate, but the regulated price plans attempt to be set to match the Class B totals for a 6-month period; the big increases this summer were not indicated by the summer's RPP rates, so significant increases are likely to be felt as new rates are set for the winter.
[3] The estimates are explained on the supply cost page of my data site
[4] The sites I've included in estimating "unites with net revenue requirements" are: Brighton Beach, East Windsor, Goreway, Greenfield, GTAA, Halton Hills, Portlands, St. Clair CGS, Thoronld CGS and York.
[5] The majority of the reduction, 2 TWh, was at the generators listed in endnote 4
If one were to think of designing mechanisms to reduce carbon, due to the perceived cost of externalities from burning carbon, taxing carbon would be a better approach. Carbon taxes are not going to do much to spur wind and solar generation - nor should that be the intent. The intent should be on enforcing a discipline to cost the externalities of the concern driving policy, and to align an economic desire to reduce cost with the desire to reduce emissions. Without pricing, the desire to reduce emissions is not economical, but only political.
Fortunately for the bulk of the people struggling with energy questions, it is possible to learn from a bad example. Annual 20+% inflation in Ontario is one more indication must-take power purchase agreements for the politically preferred, combined with capacity payments for the operationally required, are bad policy.
Endnotes
[1] The average cost is estimated, from IESO data, by multiplying the hourly "total market demand" by the "Hourly Ontario Energy Price", summing the value for all hours, adding in the total value of the global adjustment, and dividing the total by the sum of "total market demand" for the period.
[2] The increase is in the Class B customer "commodity charge" which is indicated in the IESO's monthly reporting (on the second to last page). Most residential consumers will not immediately pay this rate, but the regulated price plans attempt to be set to match the Class B totals for a 6-month period; the big increases this summer were not indicated by the summer's RPP rates, so significant increases are likely to be felt as new rates are set for the winter.
[3] The estimates are explained on the supply cost page of my data site
[4] The sites I've included in estimating "unites with net revenue requirements" are: Brighton Beach, East Windsor, Goreway, Greenfield, GTAA, Halton Hills, Portlands, St. Clair CGS, Thoronld CGS and York.
[5] The majority of the reduction, 2 TWh, was at the generators listed in endnote 4
No comments:
Post a Comment