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.