For anybody wishing to pursue commenting on the directive, or reviewing it, the online format is simply an online text box . The timeframe ends on January 7th . I therefore rushed this a bit, and didn't bother creating my usual, informative, graphics for the text box.
The combination of supply sources should be recognized as requiring expertise, and the Minister should be aware of his own limitations in directing electricity system engineers, and other professionals, in getting too specific. I would hope the intention of the Minister is to present the parameters for professionals to operate within.
This should be relatively straightforward as there is a long trend (60 years) of a slowing in the increase in demand which has transitioned to a decline in Ontario – the US EIA's long-term outlook concurs with the draft directives demand level.
This section is not based on anything that is measurable. In the Ontario Energy Board's ruling on Hydro One's rate application, EB-2010-0002 , it is clear that the Conservation and Demand Management (CDM) is not a very precise science. After a lengthy discussion, the ruling states; "Accordingly, the Board directs Hydro One to work with the OPA in devising a robust, effective and accurate means of measuring the expected impacts of CDM programs promulgated by the OPA. It is important that the terms of reference for the development of this methodology should, to the extent possible, be devised with input from and consultation with a sufficiently broad range of stakeholders so as to ensure that the resulting product has credibility within the sector." The accomplishments frequently attributable to CDM should not be. 2008 and 2009 both saw reduced consumption in the United States, according to the EIA – and the EIA's forecast matches the middle growth scenario in Ontario.
People do improve efficiency. There is little in the world as ridiculous as noting a fictitious number for CDM, and having the Ontario Power Authority then break that figure down to CDM MWs per FTE.
The Conservation section can adds nothing to the forecast for demand.
The OPA is likely to determine that 8 Bruce units, and 4 Darlington units, will be able to supply 50%, of total electricity generation necessary to meet demand within Ontario, under the demand scenario noted in the Draft Directive. Depending on the capacity factor, it may very well be prudent to add approximately 2000MW more to this, but I would suggest the minister revise the wording of the directive to nuclear generation should be targeted to account to meet 50% of Ontario Demand. Looking back on statistics back to 1990, that is the level above which we become major exporters of electricity – a problem that grew with nuclear power in the early 1990's and has re-emerged with the developing supply mix since 2006's Ministerial directives to the OPA regarding that, failed, IPSP.
Or the decision could be made to become mass exporters – not likely with our current cost concerns.
There are no examples of 'retrofitting' coal generation to natural gas – and I can only find evidence it is cheaper to tear down and build the new gas plant anew. The draft notes gas distribution, and the transmission capabilities from existing sites must also be factored in, but the largest need is to determine whether OPG will retain the assets, or the privatization of generation, began in 1998, is to continue. Significantly, the government needs to assess whether it wishes to abandon the move to a competitive market given the absence of consumer benefits from the current supply, and regulatory, structure.
The directive is to stay the course. I would note there is a cost concern on these plants as well – combined cycle plants are cleaner, but also need to be run more often to be cost effective.
Let's revisit where the proposed levels for 2030 of conventional sources, which are little changed from today's levels, will have us. In terms of the viability of the overall system, key figures are the minimum, average, and the maximum reliable production. These numbers are debatable, but I've used 70%, 80% and 85% for nuclear, 20%, 35%, and 65% for hydro, and I've used 15%, 40%, and 80% for natural gas generation. These figures, applied to the 2030 figures in the LTEP, yield a minimum of 11580, an average of 16430, and a maximum of 23410MW.
The actual figures for 2010 are 10618MW, 16232MW, and 25075MW. Add 15% and the long term plan should address a 12000MW minimum, 18666MW average, and a peak near 29000MW. So … in terms of today, traditional sources meet minimum and average requirements, but there is a shortfall on peak demand.
Going forward, the main concern would be the peak demand, which will require about 5500MW more of dependable supply. Before the removal from service of the 4 coal units in fall 2010, this number coincides with the existing coal capacity in the province.
Renewables other than hydroelectric
The draft directive lumps sources with very different attributes together in calling of 10700 MW of renewable capacity, excluding hydro, by 2018 (and notes 10-15% of generation should be this category of renewable). Using the figures from the 3rd quarter OPA report, I tried the same approach of assigning realistic capacity factors as expected averages, minimum capability, and dependable supply at peak.
The peak is already in the summer, and presumably we are attempting low carbon emissions to combat AGW – which we expect to have a warming impact in Ontario. So for solar, I would assume it is 0% as a minimum (because minimum demand is overnight), I'd assign it a high capacity factor of 70% for peak (that may be optimistic, but peak periods are now, and should increasingly be, hot summer days). I assumed an average capacity factor around 16%.
Wind capacity factors I am more familiar with. In the summer wind is frequently below 10%, and it was so for the hottest hours this year. At most 5% can be expected during peak demand. Minimum is also an irrelevant figure for wind, but the minimum demand will likely be in the shoulder seasons, and wind is operating around it's normal capacity factor then, which is about 28% here.
Bio-energy I've assumed can be as low as 0%, counted on to be available at an 80% capacity factor in a peak use situation, and I've used 40% for an average.
Using these percentages against the current contracted and committed wind/solar/biomass figures totaling 4789MW (3392/1262/135MW), we would exceed the minimum demand set 15% higher than 2010's minimum (and minimum is the most likely figure to continue declining – at 6 am January 1st, 2011, the IESO reported Ontario demand at 11835MW, which is lower than at any time in 2004 and 2005).
The average demand still needs another 800MW of supply based on the average capacity factors, but peak demand is still almost 4000MW short.
So from the remaining almost 6000MW of total renewable, you only need about a 15% capacity factor, but the ability to run at a 67% capacity factor when called upon.
I've skimmed over the math as quickly as possible, but any rational examination would yield the same conclusion: To replace coal generating capacity, you need a source with the same attributes as coal.
Neither wind nor solar fit that bill, and the directive, whatever it is, will do a disservice to the people of Ontario if the renewable category is left as one, very inappropriate, lump.
The only possibility is biomass. Germany is one jurisdiction noted for its policies regarding Green energy. It is noteworthy that preliminary BDEW reporting for 2010 shows 2010 annual wind production of 37.5TWh, which compares to 39.7 TWh in 2007 and the peak of 40.6 reached in 2008. Conversely, PV has soared to 12TWh from only 3.1 in 2007, and Biomass to 28.5TWh from 19.1TWh in 2007.
The need for supply, and the need for competitive pricing, must provide the parameters for developing the supply mix. In the previous IPSP the OPA appeared to suggest wind be procured only because the minister's directive set a green supply target, and IWT groupings were the cheapest way to meet it: "Large wind sites were used to provide the remaining resources needed to meet the goal. The sites were included on the basis of lowest "all-inclusive unit cost" (in which the cost of associated transmission is included)."
That approach has had predictably bad outcomes. Adding supply without regard to matching it to demand has been destructive of a competitive market for supply, and has led to export levels above 10TWh each year since Pickering 1 joined Bruce 3 and 4 in returning to service – at market rates below 5 cents/kWh for the past 5 .
The 2011 directive must be more coherent to halt the spiraling costs, and wind cannot play a greater role in our supply mix . It is also important to note the role it played in 2010 – you should review the numbers, and there you'll find that wind production had a greater impact on the broken market price mechanism, the HOEP, than Ontario Demand did:
Wind MW, Ont Demand, Net Export, HOEP price, # of hours
<200MW, 16510, 903, $41.12
<400MW, 15943, 907, $37.71
<600MW, 15956, 1130, $34.19
>799MW, 16362, 1444, $30.93
Transmission, and Smart Grid
I will again quote from December's OEB decision on Hydro One: "It is clear that the pace at which significant system expansions and enhancements are to be undertaken is a matter of concern to all participants in the Ontario market at this time ...Accordingly, in the circumstances of this case, the Board will not approve the overall Green Energy Plan on a conceptual, or any other basis."
I would suggest it is inappropriate to provide a bureaucracy with a direction lacking a business plan. In this case it appears the Minister issues a political directive that may or may not benefit Ontario's electricity system, the OPA is then to be tasked with creating a business plan to support the direction given without a business case, then task Hydro One with implementing that plan, which Hydro One will need to get the OK to fund from the OEB based on the OPA's business plan for the ministerial directive.
Why not start with a business plan?