Submitted comment on long term energy planning.

The government of Ontario is doing a planning exercise regarding Ontario's energy sector - as they do.

The big changes since the last time they went through the process is more useless supply is now contracted, the planning agency responsible for producting a long-term plan (the Ontario Power Authority) has been scapegoated at gas plant hearings and targetted for termination (by all 3 parties in the legislature).

The current Minister of Energy responds indignantly to truth with lies, and the Premier's mouthed 7-months of platitudes about conversing seems far more likely to produce a record of hypocrisy than anything else; the implementation of pre-existing bad policy is occurring much quicker under cover of her "conversation" routine.

Most of the submission is copied from my submission on the supply mix directive in January 2011, although there are some updated sections and the submission ends with a quickly written outline of 3 themes I'd meant to get to at some point:

1. Market design
2. Carrbon taxation
3. Promotion of trade/capitalizing on a low-emission electricity sector.

In keeping with Ontario's policy of technical excellence, submission are text only; my submission is posted here in the font choice provided.

I am submitting comments; much of the text pasted below is from my submitted comment on the Supply Mix Directive in January of 2011. It was pertinent then, and ignored, and I suspect it will be treated with the same gravitas now. Thus it is hastily assembled. Should you have a budget, I'd be happy to refine it Comment on the LTEP version 2013 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. I have demonstrated that the best blend of emissions reductions and limiting price increases came out of the first, and only professionally produced and publicly released, integrated power system plan (IPSP 1). Demand 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. Or not To truly address emissions seriously the government needs to consider electrification of more processes, with transportation being a likely candidate. Conservation This straight from my Supply Mix Directive in early 2011 "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." It continues to do so over 2 and a half years later - in the interim approximately $750 million has been sent on couponing and incentivizing central air conditioning. And the concept of an energy plan seldom seems to contemplate the residential and transportation fuels while obsessing on manipulating an electricity sector that is amongst the lowest in the world (for jurisdictions without the luck of having enough hydro sites to supply all their electricity requirements) Nuclear From January 2011 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. Conversely, Ontario’s lowest emissions occur during the time it receives about 2/3rd’s of it’s demand from nuclear (now, and in 1994). Bruce Power does now provide dispatch down capability - and well the nuclear has it’s production profile flaws it does not have the worst flaw, which is an inability to perform during peak periods. The most cost-effective low-emissions strategy is to refurbish Bruce units and Darlington and stipulate flexible nuclear for the addtional 2000MW. Coal Phase-Out (section is obsolete but comments about market commitment and ownership are not) 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. Natural Gas 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. Ontario is deeply into a capacity trap where net revenue requirements dictate that the less gas-fired generation is produced, the higher rates in Ontario. The combination of excess supply, continuing to add low-capacity value renewables and net revenue requirements for natural gas-fired generators that are seldom needed was a poor strategy. --- 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 (for Sept 1, 2012-Aug 31,2013 the figures are little changed at 10765, 15996 and 24927) . 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 1130="" 15943="" 15956="" 16510="" 903="" 907="">799MW, 16362, 1444, $30.93 Added for 2013 Markets Ontario’s unique approach to electricity markets should be, as much as possible, abandoned. A day-ahead market is commonplace throughout the world and urgently required here. All contracted supply should be required to submit quantities on the day-ahead market Excess (generation beyond forecast levels) would have to be bid into a spot market and receive spot market pricing. Shortfalls would need to be purchased on the spot-market Capacity payments would open to bidding by all and penalties for failing to supply capacity when required would meet very stiff penalties (see PJM). Excess supply, from contracted/regulated suppliers, noted in the day-ahead market would lead to a curtailment market, where the starting bid would be at the highest contracted rate (ie. solar if excess is in daylight hours, wind and/or NUGs, usually. Other contracted suppliers could then bid for the curtailments, with the most expensive supplier getting the rate guaranteed to the generator with the winning bid in the curtailment market. If a nuclear supplier is curtailed while Ontario is purchasing $500/MWh power from solar generators, the nuclear supplier would get whatever price was bid for curtailment (maybe $100/MWh), and the solar generator would get the nuclear generator’s guaranteed rate of $60-$75/MWh. This is how markets need to work. The alternative is a return to a fully public power system. Carbon Taxation If you are to have a low-emissions goal, you should have a carbon tax. The argument for one is not particularly difficult in today’s Ontario, where the price of natural gas is often setting a price for electricity which is averaging about 1/3rd of the price required to pay contracted/regulated suppliers. The only supplier exposed to extremely low HOEPs is the public generator’s unregulated hydro fleet; a carbon tax in Ontario’s electricity sector would do nothing but recoup some of the costs of gas-fired generator’s net revenue requirement (revenue neutral) and boost profits and OPG (where average prices have been forced to levels much less than half the average revenue of non-nuclear private suppliers in the province). Having OPG with a renewed profitable business unit would also allow the government to stop lying about the stranded debt charges (which aren’t going to pay down debt - and in fact debt has been rising at the OEFC for years. Execution The only government body to produce coherent work in long-term planning, the OPA, probably no longer can. Having installed an apparatchik to run the professional body some years ago, and a long string of extremely political directives essentially bloating it into a advocacy organization opposing the consumption of power, the government has more recently been trying to legislate it out of existence for some time. The government has been unwilling to depoliticize the process and allow people to function to serve the public and not the party; they should outsource preparation of an Integrated Power System Plan - beyond the borders of Ontario and the sphere of influence behind, I’m sure, thousands of group-think submissions on the LTEP. Carbon Trading (Environmental Attributes) Ontario should indicate it is: a) cognizant in it’s market design of opportunities, and/or protectionist rules, in adjacent jurisdictions to ensure it, or it’s suppliers, can recognize full value in all markets for it’s exports, b) actively lobbying for carbon pricing in neighouring markets (Michigan, Ohio, Indiana) to take advantage of it’s position as a low-emissions jurisdiction.

Ontario's Minister of Energy and 6 gazillion whatevers

Two days after I posted an array of estimates in Ways to estimate Ontario's losses on electricity exports, a Canadian Press article included a very different figure as coming from Ontario's Minister of Energy:

Chiarelli says Ontario is making a net profit of up to $6 billion a year on importing and exporting electricity

I was a little angered dishonesty might be the strategy to respond to fact, but recognized the possibility the minister may have been misquoted.

The next day a slightly different story was told by Bob Chiarelli on the CBC radio program "As It Happens" (3rd segment of 3rd clip here) as he claims, emphatically that the:

"province since 2006 has made between 5 and 6 billion dollars net profit on the sale of it's electricity"

Obviously I disagree, and the reader may not be interested in a prolonged "I said/liar said" exchange,  so I'll only briefly reiterate claims government entities have made on the issue:

Based on our analysis of net exports and pricing data from the IESO, we estimated that from 2005 to the end of our audit in 2011, Ontario received $1.8 billion less for its electricity exports than what it actually cost electricity ratepayers of Ontario
-Auditor General of Ontario annual report 

Since 2006, the electricity market has generated $1.9 billion through net exports compared to 2002 and 2003 when Ontario paid $900 million to import power.
-Ministry of Energy Bulletin, September 13th, 2012

A claim of "6 billion dollars net profit" is billions on the crazy scale.

The Minister also strengthened some other fallacies in the "As It Happens" interview.

On the cost of curtailing industrial wind turbines

Ontario's system operator made a claim early in the year that NOT changing market rules to allow the the dispatching off of renewable resources would result in an additional systemic cost of $200 million (here). 

The claim is irrespective of what payments might exist to generators for curtailments - and it was made at a time generators were appealing to the Ontario Energy Board to claim they should be paid fully for the curtailments.

...new market rules will allow the IESO to operate Ontario’s electricity system more effectively, resulting in about $200 million in savings per year. The OPA is continuing to negotiate with other wind suppliers. Savings resulting from these negotiations will be in addition to IESO’s estimated savings.   - the OPA

Chiarelli's claim on "As I wish it had Happened", of wind generators:

They are not going to be paying them as much ...
"estimated by the system operator that it would be $200 million a year less"

That's not what the $200 million figure was.  If wind generators got paid $200 million less, the rule change would be worth $400 million.
There has been no disclosure of what the payments for curtailment are (the OEB case was abandoned following an agreement between suppliers and the government - via the OPA),  but given the corporatist nature of the Liberal Party of Ontario, full payment is a pretty good bet.

I think the Minister also implies, during the CBC interview, that savings from cutting back a wind energy contract (the Samsung deal) will be used to pay wind generators not to generate.

Where did this guy come from - Escher?

I'll conclude by addressing Chiarelli's claim that it is "much more expensive to ramp down nuclear instead of wind."
Not only can Bruce nuclear ramp down production (through the use of condenser steam discharge valve) the market rules essentially force them to do so, when possible, prior to wind and solar being dispatched down.
However, in this case the Minister is probably right - it's rather silly to alter billion dollar assets while taking wind power onto the grid.

I'm glad the Minister and I might agree on one thing.


P.S.  Here's how I handled smaller, but still ridiculous claims, from a different politician two and half years ago: McGuinty Thinks This is Fun?

NENGO's target nuclear at expense of the environment

Greenpeace Canada and the Pembina Institute have put their names on; Renewable is Doable: Affordable and flexible options for Ontario's long-term energy plan (LTEP).  The document is primarily about criticizing nuclear generation in Ontario, and presenting, "good reasons for Ontario’s next LTEP to keep the province’s options open and not lock into nuclear."

Renewable is Doable basically presents 2 arguments: we don't need new nuclear, and it would be better to build a "cost-effective, low-carbon energy mix" instead of the new, not needed, nuclear units.

The argument questioning the need for nuclear isn't surprising to me, as 30 months ago I wrote in a submission on an aspect of another LTEP:

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...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

That's a negative aspect of a large nuclear component.

Demand

Greenpeace and Pembina put a lot of emphasis on forecast from the the Ontario Power Authority (OPA) and the Independent Electricity System Operator (IESO) - particularly ones that required freedom of information requests to acquire.  Having worked with historical data from a number of sources,tracked the demand trends as best as possible, and reviewed past forecasts, I don't have much interest in the forecasts of either entity.

The IESO has some hard historical data on their site, and I've charted some summary data combining data for metered usage before the market opened in May 2002 with market Ontario demand data from that point forward. [1]

Annual demand has been ~142 TWh (million megawatt-hours) since 2009 and peak summer demand ~25,000MW since 2008.

From 2005 through 2009 the drop in both demand and peak demand came primarily from the wholesale sector - likely due to an industrial sector and driven by the rapid increase in rates from 2002-2005, and an increasing value to the Canadian dollar. 

In recent years changes have been make to the global adjustment scheme to give large wholesale customers the opportunity to lower rates - likely producing an incentive to run generators during peak demand hours instead of consuming power off of the grid.

Failing convincing arguments on why demand would change, the safest assumption is that it won't - up or down - regardless of statements from lettered organizations (or people).

In terms of planning supply for the next decades, the peak figure is as important as annual consumption, and it is not decreasing recently; it's been around 25,000 megawatts for over a decade, and if there was competency in reporting solar generation, it would probably show the actual peak demand was well above that in July 2013. [2]

Conservation

Chapter 1 in 'Renewable is doable' is "Putting conservation first in the long-term energy plan."

Conservation has an inherent appeal, and as such people mention it frequently without understanding the cost implications, or the history of conservation efforts.

This Greenpeace (and Pembina) document pretends conservation efforts haven't been key initiative for years [3], but the Ontario Power Authority (OPA) was created as a planning agency; it has since become largely a conservation agency - in 2012 the OPA spent $59.3 million in operating expenses and $301.1 million on conservation programs.  

Unfortunately, electricity is not actually what is conserved (it's rather expensive to save it for later), and there is already a law about conserving water (a scientific one); coal is being phased out; our minimal biomass joins wind and solar as renewable, and that really leaves uranium and gas as things that might be conserved in reducing electricity consumption.

One issue with the payback on reducing electricity use that minimizes gas-fired generation is the capacity trap Ontario created for itself by offering net revenue requirement contracts.   Currently, even at a cost of 3 cents/kWh, Ontarians lose in purchasing conservation.  That is not due to nuclear, but variable renewable energy sources (vRES).

The "Renewable is Doable" alternative to nuclear

From the Greenpeace/Pembina document:

Table A7 Renewable is Doable ....

Analysis conducted by the OPA in 2012 shows that it is cheaper to build new gas plants at current prices than to refurbish the Darlington or Bruce nuclear stations.  The analysis in this report also shows that at 10 cents per kWh, a portfolio of conservation and green energy is also competitive with nuclear refurbishment.

Some aspects of the report's "green portfolio" are difficult to argue with - and those are probably the least realistic:

• Hydro is most everybody's preferred generator, but locations are probably not readily available, particularly those which would produce the 55% capacity factor (CF) the Pembina/Greenpeace table indicates.   I calculate recently 36% has been about average for the non-regulated hydro in Ontario/
• Biomass, biogas and landfill might be doable, but it begs the question why would non-dispatchable wind and solar be pursued if these dispatchable options are realistically priced in the document (and low-carbon)
• The 450MW of "additional efficiency and conservation" is shown as producing full out 24X7 all year long to get to 3,942GWh - that's not a serious estimate of anything.  Discounting this frivolous negawatt total, and assuming hydro location might be found to produce at the average 36% the total production drops to 9951GWh, and the average cents/kWh rise to 14.19.
• Darlingon's actual capacity factor is far higher than the 85% used to make renewable doable ... it's been 91% over the past 3 years (and 96% in the months of July; 98% in the months of January).

If we let the claim on "Combined heat and power" go, the prices become about the same, but to get those prices the new build option needs to produce about 16TWh a year while the renewable is doable option only needs ~10 TWh to get to that price.  

But we can't let the implied claims on "Combined heat and Power" component go at an estimated 8.5 cents/kWh - or any other price.

Combined heat and power (CHP)

There are very few sources of information on costing combined heat and power projects.  We do know there are CHP generators amongst the "non-utility generator", or NUG, contracts.  These contracts were signed by Ontario Hydro probably because politicians (Peterson/Rae) had decided private supply would be cheaper than mega-projects like the delayed, at the time, Darlington.  When Ontario Hydro was broken up, an "unfunded liability" was one result: of the $19.4 billion in liabilities considered to be unsupported by assets, $4.3 billion was due to the expected losses expected to be incurred during the remainder of the NUG contracts. [4]

Dwight Duncan, as Minister of Energy in the early years of the McGuinty regime (2003-) designed and implemented a hybrid system where "Fixed prices for a large part of the energy consumed in the province would keep the overall blended price for electricity relatively stable.” [5] The fixed prices were on the public generator's large legacy hydroelectric stations, and it's nuclear units.
In 2013 generation from Darlington's nuclear units is reported to be receiving 5.7 cents/kWh, while the NUGs churn away at rates likely far more than double that.  

Newer combined heat and power supply has not been so cheap as double the price of OPG's nuclear output.  During the Darlington new Nuclear Power Plant Project Joint Review Panel hearings [6], Mr. Jennings, "the Assistant Deputy Minister of Regulatory Affairs and Strategic Policy Division at the Ontario Ministry of Energy" said this about CHP:

Newer combined heat and power projects are not so cheap as that it is often suggested that combined heat and power is very cost effective, very easy to do and there is a lot of potential for it. This competitive RFP was for 1,000 megawatts. They ended up only getting 414 megawatts of responses, so those were all taken.
In terms of the cost in that plan, they ranged. The cost of the products procured ranged from about 11.5 cents up to about 24 cents a kilowatt hour, so these are quite expensive projects.
There have been negotiations with some individual proponents since then. They would tend to be at the higher end of that range.

Certainly the claimed 8.5 cents/kWh in "Renewable is Doable" isn't realistic; neither is the implied 80% capacity factor.  The "Green Portfolio" portfolio presented by Pembina and Greenpeace has, basically, 300 MW of dispatchable generation for 2200 MW of vRES capacity - so when it's windy or sunny, the CHP isn't likely to be operating efficiently.

To utilize CHP efficiently, clients are required for electricity, and for heat.  This explains the variety of project pricing.  It dosn't explain why CHP would be added in a summer peaking jurisdiction, which Ontario is - or how it would achieve a high utilization rate without an industrial client for the steam.

Renewable is doable does provide an estimated cost for new nuclear - one I'd expect is high, but not inconceivable.
It does not provide a properly costed and realistic alternative.

Carbon

Renewable is Doable contains the word carbon 6 times; always within a hyphenated term, "low-carbon."  Low-carbon is usually a shorthand for gas.
Renewable is Doable contains another set of words 6 times: "Jack Gibbons."  Jack Gibbons is the principal at the Ontario Clean Air Alliance (OCAA) - another nominally non-governmental organization that seems to leverage donations from the gas industry to procure government funding (as does Pembina).

Anthropogenic global warming/AGW/Global warming isn't in the document.

The relationship: high nuclear production to low emissions

Carbon pricing is not assumed in the document; the concept isn't even broached.  The "low carbon" "green energy portfolio" in the new Greenpeace/Pembina/OCAA could increase emissions from Ontario's electricity sector by 25%. [7]

Renewable is doable does note "greenhouse gas (GHG) emissions" twice; once in noting how they went up when the government took 7 nuclear units off-line late in the 1990's, and once in noting how they might rise during refurbishment outages at Darlington.

If Darlington units are offline for extended periods emissions will rise
If Bruce units are removed emissions will rise.
If 2000MW of nuclear capacity aren't built to replace the 3000MW at Pickering, emissions will rise.
Regional emissions will drop now that Point Lepreau is back operating
International emissions aren't only lowered by CANDU technology in Canada, but in Argentina, Romania, China, Korea and India.

All of these units, including India's domestic heavy-water reactors, flowed from a choice to develop nuclear energy here, in Ontario.

Conclusions

The analysis in the Greenpeace/Pembina/Ontario Clean Air Alliance report does not take environmental externality costs into account, exposing the non-environmental non-governmental organizations as common lobbyists.  
Their "portfolio of conservation and green energy" is not properly costed for Ontario, and does not provide the necessary firm capability to meet peak demand in winter, or the other secondary peak on summer evenings.
Their use of weighted average pricing for vRES (wind and solar) is demonstrably flawed [8], as the value of those sources declines rapidly as their share of generation increases; their costing of dispatchable bioenergies, and CHP, is also flawed in that it assumes high capacity factors for sources presumably existing to operate only when demand exists and wind and solar generation does not meet it. [9] 

Cost, and cost overruns are a valid concern, but if cost really is a primary concern it must be noted the cheapest electricity contracted in recent years are the refurbished/reworked models at Bruce A - as well as emphasizing Darlington's output remains far cheaper than the private, primarily gas, supply contracted from non-utility generators around the same time Darlington was under construction.

These are realities.

It's also a reality that if present trends continue Ontario will have periods of excess generation if today's 13,000 MW of nuclear capacity is reduced to 12,000MW.

If present trends continue summer peaks will likely also rise along with the widely expected increase in temperatures.
If more processes are electrified, Ontario will contribute less to the atmosphere's greenhouse gas component.  In 2011 Ontario reportedly emitted 14,800kt CO2e in generating electricity - less than the 20,000CO2e emitted in residential uses (ie. furnaces, water heater), and far less than the 45,300 kt CO2e from road transportation.

If Ontario is considering the environment in a Long Term Energy Plan, the discussion on energy needs to be broadened beyond how to constrain electricity usage.

The Darlington new build may be a questionable proposition if the discussion is only about what we expect is going to happen to us.
If the discussion becomes about the things we know how to accomplish that contibute to the changes we want to make, we will want more processes electrified.
We should want as much electricity to come from the clean baseload created with a technology developed domestically; one which has put us in a position where the intensity of our emissions from electricity is a fraction of that in the far more expensive states NENGOs would have us emulate.

ENDNOTES

[1]  This is not an "apples to apples" comparison as the metered data would, presumably, not include line loss and the IESO's reporting of Ontario Demand isn't really reporting demand, but supply (thus including line loss).  Compounding data integrity issues, December 2001 was omitted from the metered data set (so I copied over December 2000's total for estimating), and, particularly, the IESO's data quality has been rapidly degrading with the growth in embedded generators - generation that displaces the requirement from the gnerators on the IESO system, and therefore that generation shows as declining demand .
For another view of demand changes see this chart created for Stranded Debt, Abandoned Responsibility.

[2]  One reason to disrespect the IESO's forecasting abilities is their historical provision of low summer peaks under normal weather peak.  For instance, they forecast 22834MW as a normal weather peak for 2014 after forecasting 23,103 as a normal weather peak for 2013's summer last September.  That was exceeded on 5 days, with the peak on July 17th.  The failure is likely that normally July 17th would not be so hot as to demand 25000MW - but some day in July/August would usually be warmer than it usually is, and demand close to 25000MW.

[3]  Greenpeace must know of the efforts in conservation as they had a rookie MPP noting their conservation over nuclear energy policy back in 1991:

Mr McGuinty: You must be aware that the coalition of environmental groups made up of Friends of the Earth, Greenpeace and the Nuclear Awareness Project are strongly opposing your appointment as chairman. I have a letter here dated 2 April 1991 to the Premier and they say, second paragraph, "Mr Eliesen has publicly taken a fundamentally pro-nuclear, anti-conservation position, and has been notably inactive in pursuing the government's proconservation and nuclear moratorium policies." They go on to say, "He has spurned meaningful public consultation."

Presumably the "proconservation and nuclear moratorium policies" were the NDP's, under then Premier Rae.

[4]  The NUG were responsible for 22% of the unfunded liability - and I would guess 6-7% of annual generation.
I wrote on the non-utility generator issue in Wynne should right Duguid's wrong NUG directive

[5]  The reference to, and context for, the quote is in Duncan's Grow-Op Is Stealing Hydro

[6]  Readers of the Greenpeace/Pembina document may be surpised at when Mr. Jennings was called to the hearing on April 7, 2011

Mr. Jennings, over the past several days since you came and spoke to us and gave us your overview of the way the plans for development of energy resources and electrical generation resources in Ontario were put forward, we’ve had interventions from many of our intervenors concerning decisions on energy choices and the energy mix going forward, and the scope of the application brought forward by Ontario Power Generation. And we made reference, on more than one occasion, to the information that you presented to us.
But the concern on the part of many intervenors is that they did not see the rationale for the alternatives being proposed for the energy mix and on the true need for nuclear generation as opposed to alternatives.
So with that as introductory remarks, we’d like to get from you your perspectives on how the decision to go with nuclear as opposed to other choices was reached for the long-term?

[7]  Amir Shalaby, of the OPA, delivered a presentation late in 2012 which showed a forecast for 2015 including only 9 TWh from natural gas (slide 8); the 2.3TWh indicated for CHP in Renewable is Doable would not operate efficiently - at CCGT emission levels it would add about 25% of that figure.

[8]  The diminishing value, and increasing costs, of wind and solar generation in Ontario

[9]  The Real High Price of Low-Value Electricity, and The Capacity Trap: Ontario's Electricity Costs Soar as Emissions Drop

Value messages from data on an Extreme day for Ontario's grid

Warm humid weather moved into the southern Ontario yesterday and sent demand upwards.

The temperatures were very moderate in the earliest hours of the day, so demand was low - so low the pricing was negative for 4 hours and that meant nuclear units at Bruce reduced their output.   It took a while after the IESO banned negatively priced exports but there now seems to be, effectively, a minimum price just below $0/MWh (thus each of the 4 hours was ~$-4.50/MWh).
A unique feature of the day is not only did it experience some essentially minimum pricing levels, it also saw maximum pricing levels (for the 5 minute MCP - IESO report)

By the end of the day the average rate (HOEP) was the second highest daily price of the year, and the 7th highest of the past 5 years (not to worry - at $87.52 it's just about what you've been billed lately)

More unique than the pricing movement was the demand variance between the 12,458MW minimum in hour 3, and the 22,682 maximum in hour 20.  The 10,224MW difference is the most severe in over 3 years and the 9th highest since the market opened (including 2 days for the blackout of 2003).

I pulled some figures for the day as I was posting a report for the IESO week (Sept. 4-10).




Readers of my blog will know peak summer demand as reported by the IESO has been both decreasing, and moving later in the day - and that's because of lousy (non-existent) reporting on the extremely expensive solar energy being generated by Ontario's wealthiest residents and sold to the rest of the province unnecessarily.

It is highly unlikely demand was actually higher for hour 20 than it was for hour 17 (all embedded generation acts as negative load - see At Any Price: Wind as Negative Load, Not Generation)

There's a message going around the 'group think' circles that somehow intermittent variable power is more suited to demand profiles than nuclear (seen as steady baseload).  Keeping in mind that for what the IESO is reporting as the minimum and maximum demand hours on the 10th, solar output was 0.... The last line of the embedded spreadsheets show the difference in production, by 'fuel', between the maximum and minimum demand hours.  The greatest increase to match demand came from gas-fired generation, and then, in declining order, hydro, nuclear, reducing exports, increasing imports, coal, unknown (likely self-scheduling generators, which are likely small hydro), and the only source to offer less at peak, which is wind.

I mentioned my weekly report earlier; one of the graphics I present there is built from my estimates of curtailed power.  It shows the wee hours of the 10th were the 4th consecutive night where increased wind during low demand hours required steam bypass manoeuvres to reduce output from nuclear units.

A final note on the 10th to emphasize that generation not only has a cost (discussed broadly), but a value (rarely mentioned).  For the 10th, taking hourly generation (from here) and calculating value at the hourly price:
Gas      $113.70/MWh
Coal     $113.26
Imports $94.98
Hydro   $86.89 (Not Known $85.18 - much like reported hydro)
Nuclear $75.55
Wind     $66.89

Aside from the positioning of gas and coal, this value order matches the averages in each of the 4 years in my data set.
This indicates dispatchable generators are the best for matching demand, and wind the worst.

Ways to estimate Ontario's losses on electricity exports

I've been crunching numbers related to Ontario's electricity exports again - again in a collaboration with the hopes of having another translate my bombardment of figures into a message that will be broadly communicated.

In working collaboratively, I/we work with a massive amount of data to extract a presentation supporting the point we wish to communicate.

In this data geeky post, I'm going to look at statements on exports over the years, and indicate 4 different methods of estimating the cost to Ontario ratepayers of exporting electricity at very low pricing.

The numbers vary widely between estimates.
The problem exposed by the various estimates does not: increasing exports are now contributing to much higher rates in Ontairo.

Since 2006, the electricity market has generated $1.6 billion through net exports 

-Ministry of Energy, July 12, 2011

This figure can be confirmed with publicly available data.  Simply take the IESO's  2MB HourlyImportExport data and line it up in a big spreadsheet with their 2MB Hourly Ontario Energy Price data (on this page); add a column for (exports-imports)*HOEP  and you'll get $1.6 billion in revenue from Jan.1, 2006 - June 30, 2011.  The problem comes when people think the revenue statement equates to a profit statement.  If you add up net exports (exports-imports) you'd find the $1.6 billion in revenue required exporting 45.6 million MWh, making the average revenue $35.58/MWh.

But what was the cost to purchase the 45.6 million MWh - and did Ontarians need to do so?
Unlikely.  Ontario generated about 100 million megawatt-hour of electricity from coal-fired generators over that period, and another ~44.5 million firing gas, which makes it a pretty sure bet there was at least a fuel cost above contractually committed to expenditures (power purchase agreements).
So the Ministry statement is true, and meaningless.

Section 3.03 of the 2011 Annual Report of the Office of the Auditor General of Ontario did put a meaningful figure to the exports:

Based on our analysis of net exports and pricing data from the IESO, we estimated that from 2005 to the end of our audit in 2011, Ontario received $1.8 billion less for its electricity exports than what it actually cost electricity ratepayers of Ontario

This figure I can't get to - so I'll assume it should have been $1.6 billion;
If you take only the exports (ignore imports) in the file above, total them by month, then multiply those totals by the monthly global adjustment charge, and add up the monthly totals from January 2006 to December 2011, you'll get $1.6 billion.

I refer to this as the "Global Adjustment" (GA) method - and over the most recent 12 full months the estimate cost of exporting it produces is $943 million.

This is a nice simple methodology because the Global Adjustment can't be charged on exports.  The valuation can be defined very simply as it indicates export customers paid ~$1.6 billion less for electricity imported from Ontario than Ontarians paid for the same amount of electricity (89 million megawatt-hours).
A problem is that losses on exports are captured in setting the global adjustment rate, which strikes me as double accounting for the losses.

I've programmed calculations that estimate the cost of Ontarians of selling exports cheaply (output is on this page) by calculating the total market value (the monthly sum of the hourly "total market demand" multiplied by the HOEP) plus the bulk total of the global adjustment, and dividing that by the total market demand produces an "average" market price; one that doesn't double account for export losses.

This approach, which I'll call the "Average Cost" method, produces a lower estimated cost of exporting over the past year: $798 million.

The summer before the Auditor General's report, Parker Gallant and I had estimated the cost of exporting another way:

Based on our analysis of IESO data, the total cost of the exported power since 2006 exceeded $2.5-billion (see table below). That means that Ontario power consumers, who must pick up the difference, suffered a loss of more than $900-million on the exports. As the table shows, moreover, those losses are mounting ...

Ontario's Power Trip: Power Dumping

Former banker Parker Gallant, and I, estimated costs much lower than the Auditor-General did months later because we accounted for revenues, and expenses.  Trying to explain this methodology might demonstrate why the Auditor used a simpler one.

The global adjustment charge cannot be collected on exports, but it is collected on imports.  So imports are assumed to be an expense valued at the HOEP (market price), but the revenue is valued at HOEP plus the global adjustment rate;  Exports are assumed to be an expense valued at the HOEP plus the global adjustment (which is primarily the difference between the revenues guaranteed to suppliers and the market revenue), but the revenue is only the HOEP.

I'll call the method Parker and I used over two years ago the "Balance Sheet" method - and over the past 12 months it produces a lower estimated cost of exporting of $710 million.

In preparing this post I dove deeply into the data to filter out exports that might be attributed to the coal and and gas-fired generators that are receiving capacity payments of one type or another.  The logic is that the incremental cost of these exports is really just the cost of fuel, which is assumed to be captured by the HOEP.  So, assuming a world of perfect information and engineering that doesn't necessitate these plants operating beyond Ontario's demand requirement, it is assumed their generation is the first exported: the HOEP valuation is subtracted from the total cost of the system, and the megawatt-hours of generation are subtracted from the total market demand, and the average cost recalculated.

This method I'll call the "Revised average Cost" methodology and over the past 12 months it is lower again - at $460 million.

All approaches are imperfect.  Data is always imperfect, and electricity data quality has been rapidly deteriorating in Ontario as embedded generation grows untracked.
The lowest estimate from these 4 methodologies is about half the highest estimate - which seems like a significant variance.

And yet, despite a difference in big numbers, all the methods tell the same tale.

Exports are surging, the commodity rate for Ontario's wholesale market customers is up 25% in the summer of 2013 (over the same season in 2012), and a significant portion of that increase is due to dumping excess generation in export markets.

Taking the temperature to Ontario's Electricity metrics

A quick post on some data views I found interesting after linking my personal hydro one data to Ontario's system operator (IESO) data for Ontario's electricity sector.  My data has the average daily temperature (in Penetanguishene), so this post will look at the impact of temperature on the electricity sector.

Most will recognize that heating, and cooling, are drivers of electricity consumption.  In Ontario, heat more than cold drives electricity demand - thus Ontario is a summer peaking jurisdiction for electricity.

But not for energy: natural gas consumption in Ontario is far more variant, increasing roughly 300% in the coldest periods.

Getting the expected demand pattern, let's move to price.

While price does have the same basic shape, the price at the extremes increases much more sharply, although not nearly sharply enough to justify merchant plant initiatives to fill peaking functions (many jurisdiction have a maximum price of $1000/MWh in their market design, and regions trying to maintain a market not driven by power purchase agreements, such as Texas, are looking at ceilings far higher than that).

Now for one that may surprise: Net Exports


The conversation on exports usually deals with Ontario's large baseload supply often exceeding it's demand (or load - thus "surplus baseload generation).  There's justification for this concern, and certainly 2013 looks to have highest exports at the most moderate temperatures.  However, looking at the average (poorly labelled "Grand Total" in the graph), Ontario exports almost decline linearly from coldest to warmest temperature.
This is a reminder that the availability of export customers is a second driver of export.

With the coal shutdown looming in Ontario, it will be interesting to see the impact of being unable to export during cold days on Ontario's ability to export during moderate weather.  If, as seem likely, it requires export markets to develop new supply, it will reduce export opportunities.

---

Two more quick graphs from my data exercise

Industrial wind turbines drop off in productivity as the temperature rises - but there may be an increased chance of performance during extreme heat, and there may also be an increased chance of poor performance during extreme cold.  

However, in working with peak winter and summer demand hours, I've found that wind will have low productivity (below 10% of capacity) approximately 40% of peak summer demand hours, but also during approximately 20% of peak winter hours.

Lastly, a look at hydroelectric output by temperature.

The lesson here is that hydro output is fickle - particularly during the warmer months of the year.

I'd suggest the worst complimentary fit with Ontario's low-reservoir hydro capabilities is industrial wind, which features weak summer performance.

Efficiency in the eye: IESO's latest 18-month outlook

Ontario's Electricity System Operator (IESO) announce it's latest 18-month outlook with a news release humbly titled, IESO Improvements Help Transition to More Sustainable Supply Mix: 18-Month Outlook:

"The IESO is constantly looking for ways to improve the efficient operation of the province's electricity market, while promoting continued reliable supply," said Bruce Campbell, President and Chief Executive Officer of the IESO. 

Uh-huh

A quick look at "efficiency" from the numbers within the forecast itself.

In working on a tool to support planning a supply mix, I concentrated on what the IESO refers to as "Forecast Capability at Peak" - which is an important figure in meeting reserve requirements above demand.. This is more of a concern in the summer because some generation is less productive (wind especially) and demand peaks have been air conditioning driven.

The annual demand peak the past 4 years have been relatively close at 25075MW, 25450MW, 24636MW and 24927MW.

In table 4.4 the IESO claims a "Normal Weather Demand" peak of 22,282 MW for 2013 (actual is 24,927), and in table A1 of the IESO's complimentary spreadsheet, the 2014 summer peak for "normal" weather is 22,834.

Normal peak would seem to be ~2000MW above that - the addition on solar capacity and demand response might have an impact, but not that much of an impact.

It looks suspicious - as if the system operator is meeting reserve requirements by redefining a normal, and much lower, peak summer demand.

The IESO presents a listing of "Committed and Contracted Generation Resources" in Table 4.2, with both "Firm" capacity changes (negative 2,740MW) and planned ones.
Planned projects of 3273MW capacity are comprised of 2574MW of wind capacity, 280 of solar, 212 of water and 205 of biomass.  This references only projects not embedded with LDC's, and the IESO states in the document plan is for "more than 3,800 MW of grid-connected renewables added to the system."

What difference does the 3800 MW of planned, primarily wind and solar, capacity make in terms of meeting reserve requirements?

Well, spot the difference (and similar error) in Figures 4.1 and 4.2 of the freshly posted 18-month outlook.

It doesn't really matter if 4.1 is mislabelled as the "firm" scenario while graphing the planned scenario or not - the difference to the reserve above requirement is minimal during the peak summer period.

And the peak is suspiciously low.

Of course the burgeoning wind turbine capacity - unhindered by intelligent government stopping/delaying it - is not meaningless in all ways, but only in terms of providing needed capacity to meet peak demand.

It's very meaningful in adding to periods of too much supply - which is how "efficient operation" comes to be a term applied to increasing the pool of suppliers that can be paid not to supply.

This 18-Month outlook concludes, as many have before, on the periods of too much supply (surplus baseload generation):

Ontario will continue to experience an increase in volume, frequency and duration of SBG conditions with declining wholesale demand for electricity and significant quantities of baseload generation on the system.  However, the vast majority of SBG is managed through normal market mechanisms including exports and nuclear maneuvering. The IESO will gain another tool to help manage SBG as grid connected wind becomes  a dispatchable resource in Q3 2013.

Ontario Electricity Rate set to rise 30% in August

The total commodity charge for electricity is now estimated to be up 30% from August 2012 to August 2013.

The weighted average market rate (the HOEP) will be around $23.55/MWh and the freshly released 2nd stimate of the global adjustment rate is $68.99/MWh; the combined "Class B" commodity charge of $92.54 is 30% higher than 2012's $71.09.

August's 30% follows 3 months with inflation over 20% (as Parker Gallant and I noted here), so it does not come as a surprise to me, but it appears to come as a huge surprise to the market operator (the IESO).

I put together a short 2 question survey after seeing the initial IESO initial global adjustment estimate for August:

The IESO posted a preliminary estimate for the August Global Adjustment of $40.13/MWh. Do you think this estimate is:

• plausible
• remotely possible
• indicative of a healthy optimism
• indicative of politically directed lowballing prior to the August by-elections
• indicative of incompetence

The few responding were split between "incompetence" and "politically directed lowballing"

The second question was:

Do you think the estimate, assuming it is meant to be of the Class B global adjustment, will be:

• high
• about right
• 10-25% low
• 25-40% low 
• 40-60% low
• more than 60% low

All answers rightly identified the $40 estimate as being far too low, and the most popular answer was "40-60% low."

The second estimate of the global adjustment rate ($68.99/MWh) is, in fact, 70% higher than the first estimate ($40.13/MWh); statistically that means the first estimate is 42% lower.

Perhaps the IESO saw the survey and decided they best up the next estimate to establish something akin to credibility; it's crud ability set September's estimate at 8.72 cents/kWh (or $87.20/MWh) - that's 18% above September 2012's combined HOEP (market) and global adjustment.

How high do you think $87.20 is going to be?