It was an honour to work with Parker Gallant on “Ontario's Power Trip: Power dumping.” I wanted to follow-up on some of the comments now attached to the article. I don't do this necessarily as a response to the commentators, but some of the arguments recur frequently in government and ENGO releases, so I have worked on some responses.
Kevin Hryclik noted we should be thinking about storage solutions. While this is outside the scope of the article, I'll note here that the IESO's December 2009 “The Ontario Reliability Outlook” noted challenges both in storage technology and the economic ability to integrate it:
“System operators and regulators alike are contemplating how to integrate new storage technologies into the system: how to dispatch them, who should own them and how to pay for them; whether storage facilities should pay the same uplifts and tariffs as other loads when they withdraw energy from the grid; and then whether they should receive the same payments as other producers when they inject it.”
I did not find the word 'storage' in the IESO's 18-Month outlook from this June, 18 months after that quote was printed. I suspect the reason for that is there is little reason to have storage support renewables – if you need some gas, or coal, or nuclear, supply, all run cheaper when not following load, and storage would make as much sense for running coal in baseload mode as it would for supporting wind. Arnold Guetta is therefore right to be dubious.
Michael Tiffe wondered why you wouldn't just hold off on hydro sources while it is windy, and suggests this may be a management issue. Because we don't have reservoir hydro here, so you largely lack that ability – but there is a broader answer encompassing other markets too (see Quebec trade later in article). As with storage, my response would be when you introduce intermittent sources you reduce the efficiency of other sources – if that is Beck it means water over the falls, as it can mean with other falls elsewhere.
Oriel Mendeovitz points out some research that could be done in introducing other “fat cat” contracts, 'deemed' generation, etc. The figures in this article for wind and exports are far less than the total 'subsidy', which is the Global Adjustment (essentially). Other investigations into cost are on my blog - I'd suggest the review of May's record for an overview.
Geoff Olynyk joins in the wish emissions are being reduced by renewables. Maybe yes but certainly not during periods, which are frequent, when steam bypass is implemented (at Bruce B), or water goes over Niagara Falls instead of through turbines. There's a difference between peaking generation and intermediate generation these posters should explore.
Alan Fox's suggestion on the possible redemption through electric cars, might be partially in jest, but increasing consumption is a solution, and doing so by replacing fossil fuels in transportation is a laudable way to do that. Unfortunately some forecasts have us in a shortfall for generation by 2017 as renewables/gas hope to displace nuclear. It's less than clear that electric cars will be an affordable way to electrify transportation – which is again related to 'storage' technologies.
Rick Coates knows more than I do about the operation of the IESO – I hope his comments corrected the misperception that the grid operator's mismanagement is a significant issue in the overall cost escalation.
Tom Adam's made some valid points, which I responded to on another site. Most of the criticisms deal with omissions or, in his opinion, oversimplifications. Complex issues are presented in a brief article, so both are somewhat true. The attempt, on my part, was to communicate increasing supply that does not, and cannot, follow demand is driving up exports, and driving down price, and is planned to do so increasingly throughout another half of a decade. The lower market price drives up the cost of exporting, and the higher price paid for the increased imbalance in our supply chain further drives Ontarians' pricing higher.
Martin Laplante did get the point of the figures, but is predisposed to misinterpret them. Low demand and high supply mean dumping on external markets. The reason Ontario consumers are now paying about 7.3 cents/kWh, for only the electricity, is because the government signed contracts that pushed the price there. The reason we have too much supply is because the government pushed the price there - government contracted supply lacking the ability to follow demand.
Nuclear exists at OPG and Bruce Power. I have gone through reporting for each, crunched some figures, and the contribution of nuclear to the GA is high when the HOEP is low – as Mr. Laplante notes. Yet the big growth in the GA even in years such as 2010, where the HOEP recovers slightly and demand is slightly higher, is not nuclear at all, nor is it the poorly compensated public hydroelectric. It's the 'other' category, which contains natural gas, renewables, demand reduction programs, etc.
That deals with Mr. Laplante's first deflection, which has enough truth to be stated but not enough to be correct.
Mr. Laplante continues to state that imports/exports exist to ensure every jurisdiction has a “cushion” in the right places. This is an important point that is also kind-of-true. The broader the market the greater the ability to withstand the sudden loss of a significant generation source. But it remains true that on some level, amongst many connected markets, supply must equal demand, so one would assume sometimes Ontario would be an importer, and sometimes an exporter. Yet so far this year there is one singe occurrence of Ontario ending a day as a net importer – and that was April 7th, a date including an hour where Ontario's 1400MW of wind capacity produced 1 MW of output and on the day wind's capacity factor was under 4%. That is no coincidence.
Mr. Laplante also states that exports exist to recoup revenue that would be lost when you have sources you can't turn off and state,
“What the prices tell you is that power is being exported at non-peak periods, at night. That hourly data is part of the IESO data that's not being quoted because it contradicts the desired conclusion.”
Here it is. It's wasn't quoted because it isn't the key driver of the changes spiking the cost. The figures in the article starts in 2006, in which nuclear production was as high as it has been ever since – and one reason it starts there is to refute the propaganda from the ministry.
I have charted the hourly averages, and the trend is similar – with just the amplitude changing.1 The first complete year, compared to the last complete year actually shows a flattening of the curve. 2010 is notable for its flattened curve.
This blog started with an entry concerned about a supply mix short on load following capability, and also includes comments on the supply mix critical of the same features. My other blog has many articles on how to increase the responsiveness of nuclear to account for supply curtailment too.
More recently I started capturing the hourly production figures by source, and the intertie data by destination. These are very instructive as to why the line is flattening.
This chart shows the averages for each hour of day, for July 2011 as of the 21st. Two things are notable. One is that the movement is generally one way or the other - with the predicted export from Ontario at night, and import from Quebec in the day.
But for everybody else (largely Michigan and New York), Ontario's exports have really kicked in during the peak demand periods.
During our winter peak, at 7pm on January 11th, we were net exporters of 2,721MW. It seem Ontario's operators are taking advantage of any instance where the market price (we'll use the HOEP) is above the marginal cost of production for coal and gas, over a period of time. Rick Coates comments later that nuclear is not the only source that needs to produce output aside from a brief demand period. All of our CCGT, contracted, will run better for more hours, and the price of starting a coal unit I've seen quoted as high as $80,000 (including equipment depreciation from wear)– so once they are hot, you want to keep them hot. The HOEP averages, by hour, so far this month, therefore reflect the trend in non-QC exports:
We are driving up the price through contracting supply that cannot follow demand, and we are masking the total costs of that policy during peak pricing periods by running coal and gas production whenever it can be exported above the cost of production.
Martin Laplante ended with “Oh, and if you want the actual IESO figures, in 2010 we exported 567.4 million dollars worth of electricity at 3.7 cents per kWh, and imported 247.6 million at 3.8 cents per kWh.” This continues the fantasy that there isn't a cost of production to the exported product, so I'll reiterate the figures he gives are correct, but his thinking incorrect.
Following is a database query result, with the calculations by hour, but here's how to get similar figures with summary figures. The Global Adjustment (GA) plus the Hourly Ontario Energy Price (HOEP) is defined, by the IESO2, as 'the cost' of electricity. Exports are sold without the Global Adjustment, so exports multiplied by the GA estimates the loss (the HOEP is used in my hourly method). Imports are purchased at what is considered their cost in Ontario, but end consumers pay the GA on this power. So that could be considered a profit. The figures shown in the table within the article are more accurately derived from query of hourly figures, with total revenues (the HOEP on exports, both the GA and HOEP on imports), subtracted from the costs (the GA and HOEP on exports, only the HOEP on imports). The query output here includes an additional week of data for 2011 than that in Thursday's article.
| Year | Imports (TWh) | Import Revenue ($M's) | Import Expense ($M's) | Exports (TWh) | Export Revenue ($M's) | Export Expense ($M's) | Revenues ($M's) | Expenses ($M's) | Profit/Loss ($M's) |
| 2006 | 6.2 | $341.30 | $318.22 | 11.4 | $502.81 | $548.83 | $844.11 | $867.05 | -$22.94 |
| 2007 | 7.2 | $410.46 | $381.25 | 12.3 | $570.37 | $618.34 | $980.83 | $999.60 | -$18.77 |
| 2008 | 11.3 | $659.72 | $593.17 | 22.2 | $1,096.46 | $1,234.22 | $1,756.18 | $1,827.39 | -$71.20 |
| 2009 | 4.8 | $309.90 | $163.46 | 15.1 | $461.50 | $912.63 | $771.40 | $1,076.10 | -$304.70 |
| 2010 | 6.4 | $417.88 | $247.75 | 15.2 | $549.18 | $973.60 | $967.06 | $1,221.36 | -$254.30 |
| 2011 | 2.2 | $166.92 | $81.14 | 7.9 | $239.97 | $563.09 | $406.89 | $644.22 | -$237.33 |
1I could map the data as YTD which would likely show the hump from 2011 in all years, as I assume it reflects our spring freshet coinciding with our weakest demand period.