New Nuclear, Replacing Coal, Planning and Prayer

The big news this week on the Ontario electricity front would have to be Bruce Power synchronizing Unit 1 to the grid after a 15 year absence.

"This achievement by Bruce Power is an important step towards eliminating the use of coal fired electricity by the end of 2014.” – Ontario Minister of Energy Chris Bentley

Replacing coal is a mantra in Ontario now.  It's as if one day the Ministers went to Premier McGuinty and said to him
"Premier, teach us to talk to the Press to teach them to perceive intelligence in our energy foibles,"
and the Premier said to them,
When you talk with the press, talk thusly,

"Our actions, which are replacing coal..."

Being genuinely interested in abating carbon emissions, I believe it would be excellent to replace baseload coal plants with nuclear (Alberta), but Ontario does not use it's coal plants as baseload supply; Ontario uses it's coal-fired generators as intermittent, and peaking, power that is withdrawn during low demand hours and ramped up for higher demand periods.  July saw high demand in Ontario and, as the graph shows, nuclear and coal performed much differently - with nuclear output largely dependent on how many reactors were operating, and coal output largely dependent on how many air conditioners were operating.

The traditional spin is that 'clean' natural gas is better mated to both variations in demand and increased variation of required dispatchable generation to compensate for increased renewables.  I've doubted this for a long-time.  One of the first articles on my Cold Air Currents blog was Donald Jones' "More wind means more risk to the Ontario electricity grid" which explained why coal has what Ontario's System Operator (IESO) would probably now call "peaking depth."  This increasingly seems to be a dirty secret of the renewables lobby.

A more recent post on Cold Air Currents noted Germany is currently adding more coal-fired capacity than natural gas capacity - at about a 4:1 ratio.  It sure looked like there was a preference for coal to fit with renewables.

I produce weekly reporting that provides some different views of information than the canned IESO weekly reports.  This week my graphing of the hourly difference in generation, by source fuel, between the week this year, and the same week in the previous year, makes a very strong case that Ontario's dysfunctional market has found coal to be increasingly useful in lower demand seasons - likely because of the peaking depth it provides.

These complex issues could be addressed in the debates that have been occurring in the legislature on a bill (G75) to combine the Ontario Power Authority (OPA), and the Independent Electricity System Operator (IESO); debates I wasted some time reading.   The reason I did was that I stumbled upon a webpage with what I considered a very good contribution to the debate from NDP Timiskaming-Cochrane MPP  John Vanthof.
It was not representative of the quality of the debate.

The debate builds a mythology almost entirely on partisan silliness.  Darlington apparently caused all Ontario debt, Bob Rae insanely cancelled a deal with Manitoba for cheap hydro, there was never any rationale for any OPA planning, Mike Harris sent rates soaring with privatization and shortages caused a big blackout.   All of these things could be argued with a context, but without context they are all unhelpful talking points detrimental to intelligent debate.

Ontario has been dealing with excess supply issues based on disappointing demand for decades.  This is the issue that caused the delays to Darlington during the high interest rate 1980's; that same supply issue resulted in the Manitoba contract cancellation; privatization and de-regulation were in fashion in many jurisdictions late in the 1990's (hardly a specifically Harris, or even necessarily a Conserative, thing).

One of the tabs I have on this blog is "Electricity Planning in Ontario" - which I wrote years ago shortly after starting the blog.  It includes a link to a 2005 OPA article on the history of Power System Planning.  It should be required reading to debaters of  G75 (they might want to add these Empire Club speeches from 1982, 1991, and 1993.  From Maurice Strong in 1993:

In light of our current surplus capacity, which we project will continue for the next 10 years, Ontario Hydro cannot commit to developing new capacity, to extending existing capacity by retubing the Bruce A reactors, or purchasing new supplies from non-utility generators at a time when we don't need the power. To do so would result in unnecessary rate increases at a time when our customers can least afford them. 

With planning time frames I think the case is stronger that Maurice Strong had the greatest impact on the supply situation 10 years later.

19 years later Bruce Unit 1 is now synchronzied to the grid, and Bruce Unit 2 should join it in the next quarter.

1500MW of additional nuclear capacity will contribute to surplus baseload generation, although more sensibly than renewables will -  more sensibly because Maurice Strong's de-emphasis on nuclear lead to an enormous increase in the use of coal, which more than doubled by 2000.  

But neither nuclear nor renewables are intelligent methods to replace Ontario's non-baseload coal-fired generation.

The debate in the legislature has included claims that all parties have long advocated the phase-out of coal by 2014/15.  The McGuinty government was first elected in 2003 on the promise to phase-out coal by 2007, yet it's still unclear how Ontario will maintain the flexibility of the system without the coal that is planned to be removed in two years, without plans for adequate replacement being communicated.

Wind shouldn't replace coal (they are complimentary)

Solar shouldn't replace coal (our highest energy use, including residential gas use, is in the dark)

Nuclear shouldn't replace coal (it has high capital cost so running it for only parts of a day is not economical)

We are replacing coal

We are replacing coal

We are replacing coal

We are replacing the Jesus Prayer.

The IESO Gets the Global Adjustment Wrong - Again

Today the final Class B Global Adjustment was posted as being $41.78/MWh.  At the end of August the second preliminary estimate of $28.94 was provided.

I wrote the issues with $28.94 in a 'better estimate' September 1st;  a month earlier I had noted my concern with July's implausible figures in the second estimates for July.

Graphing the variance between what the system operator (IESO) 'estimates' at the end of a month, and what it ends up being after the abacus work is done a couple of weeks later, there looks to be a total disintegration of ability over the past 2 months.

Big Green, not little white, Lies

"The latest quarterly progress report by the Ontario Power Authority on electricity supply in Canada’s most populous province isn’t destined to be on the bedsides of millions of people. But what this dry, chart-heavy document reveals is the plain fact that starting in 2011 Ontario already had 4,125 MW of renewable energy projects operating and 6,255 MW under development thanks the Ontario’s feed-in tariff (FIT) program."

This statement is bullshit.

It comes from The transformative power of the feed-in tariff - Meet Ontario's Green Energy Act, which is written by David Dodge and Duncan Kinney.   David Dodge is "the former communicaitons director of the Pembina Institute."  Duncan Kinney is the "Editor/Production Manager for Green Energy Futures" ... that's "David Dodge's Green Energy Futures," which "is produced with the generous financial support of TD and Suncor Energy."

OPG Q4 2011 Progress Report, Page 5

This is big oily green... and big oily green is lying.

The 4125MW figure is the figure the Ontario Power Authority (OPA) provided as the amount of renewable generation it has contracted.  They categorize that procurement by the programs under which the contracts were offered.

The feed-in tariff program is indicated, by the OPA, as being responsible for 332MW of the 4125 MW, which is 8% of the total.

• 1556MW, or 38%, of the 4125MW was in service prior to being contracted by the OPA: hydroelectric facilities given contracts under the Hydroelectric Contract Initiative (HCI), and Hydroelectric Energy Supply Agreement (HESA) programs.
• 1549MW, or 38%, came from Renewable Energy Supply contracts: Request for Proposals for supply projects went out in  and in June 2004 and June 2005
• 615MW, or 15% of the 4125, is from the Renewable Energy Standard Offer Program (RESOP), which started in November 2006.
• 246.4MW are Feed-In Tariff (FIT) projects, and 85.7MW are microFIT projects

The offensiveness of the FIT lie is that there is an enormous quantity of contracted supply under the FIT - but the existing figures show primarily what was achieved without the high rates and obliteration of community input of the FIT program.

David Dodge and Duncan Kinney (D and D'er) rhetorically ask how this 4125MW came to be and answer: "You can pin it down to a simple wunder-policy – the Green Energy Act. This bit of law acts like a German style feed-in tariff. Essentially everybody with an electricity bill pays a bit more every month so that renewable energy systems can get established."

That's one opinion

I've got another.

Neither my opinion nor D and D'er's can be relevant to the argument they built on a lie: that there is an existent 4125MW of renewable generation due to the feed-in tariff program.

On our 'green' earth coherent argument may not be particularly relevant.  The FIT program could be cited as the reason for any number of historical virgin births leading to any number of deities and a collection of scandalously credentialed idiots would spread the word.

D and D'er also erred at the start of the sentence I quoted to begin this entry. The "latest quarterly progress report by the Ontario Power Authority" isn't for Q4 2011, it's for Q1 2012.
The Q1 2012 report shows In-Service new capacity for renewables at 2,643MW.
The Q1 2012 report shows In-service new capacity for natural gas at 6,846MW.

Brought to you by Suncor, TD, and the Pembina Institute...
and maybe Gravol.

New US Study on PTC Demonstrates Market Damage of Wind Subsidies

Exelon, the USA's 5th largest generator of electricity was kicked out of the American Wind Industry Association (AWEA) last week, for the crime of opposing the Production Tax Credit.  Today came the release of a study commissioned by Exelon: Negative Electricity Prices and the Production Tax Credit: Why wind producers can pay us to take their power - and why it is a bad thing.  The study has a message for the current 'stakeholder' initiatives being played out in the realm of Ontario's Independent Electricity System Operator (IESO):  Wrong Way.

Exelon, long a champion of a carbon tax, generates approximately the same amount of electricity as the total IESO market, and it does so with the lowest CO2 emissions of any of the top 25 generators in the United States (pages 27 and 28 here).  The emissions intensity of Exelon's production is about half of Ontario's, and Ontario's is about one-quarter of Germany's.


A section from the study's conclusion describes the impacts of the Production Tax Credit on the rest of the participants in the market:

...it is apparent that the distortionary incentives and bidding practices caused by production-based wind subsidies, in particular the PTC, have caused high prevalence of negative prices in recent years. These PTC-distorted price signals create a range of near- and long-term problems for electricity markets. The PTC subsidy for wind generation artificially dilutes the incentives for conventional generation – generation that is critical for maintaining reliability. While the PTC was originally intended twenty years ago to jump-start a nascent wind industry, the wind industry today is a full-scale global industry and the PTC’s primary effect in the current environment is to distort and disrupt incentives for the electricity industry as a whole.

The description of the impacts of the PTC indicates the same damage as the feed-in tariff has had on the Ontario market - but in Ontario we simply moved onto the incentives for conventional generation and without debate or foresight handed out net revenue requirement guarantees to new, and existing, conventional generators.  In that, we are the warning sign for other markets.

Regulated Price Plan Reports, filed with the Ontario Energy Board (OEB) for Spring 2006 and Spring 2012 shows the percentage of supply capacity from 'Market-based' generators dropping from 17% to 9%, and the percentage of total supply cost for the market-based generators falling from 20% to 3%.  After the decision was made to subsidize natural gas-fired generation, the market in Ontario essentially shrunk to 1/6th the size.

From Page 12 of the report

In Ontario, negative pricing hours comprised about 2% of all hours in 2011, and they have remained at that level thus far in 2012.  While this is essentially equal to the lowest incident of negative pricing shown in the Exelon report, for PJM's Northern Illinois Hub,  US jurisdictions, the IESO also recently noted, "Since the start of 2012, out-of-market control actions were required approximately seven per cent of the time to mitigate SBG [surplus baseload generation]."  
The incidence of negative pricing is therefore likely to be artificially low.

I queried the Ontario data to reproduce a chart showing the percentage of negative hours (on the Y axis) at different percentages of wind production as a share of total market size (the X axis).  The Ontario data, for 2011, is similar to the MISO Iowa Zone data.  The report notes that for the entire MISO zone, summer peak demand is 23% higher than annual average demand while wind production at that time is 44% less than average wind production; Ontario's figures for July and August are similar, with daily peak demand 25% above average and wind production, during those hours, 55% below the average.

Considering Ontario's plan is to contract approximately 5 times it's current wind capacity, and the similarities to MISO figures, it is clear that Ontario will, all other things remaining equal, experience many more periods of negative pricing.

The American Production Tax Credit likely does do a better job of limiting the negative pricing amount than Ontario's Feed-In Tariff has been doing, but Ontario's IESO is taking some steps towards that in addressing floor prices.

Last week the IESO board temporarily banned exports at negative pricing, which will eliminate some embarassing stories of payments to other jurisdictions to take our exports, but limits the ability of the market to function.
The US study notes a role for negative pricing:

Some electric generators cannot vary their output from hour to hour, so rather than submit a positive supply bid, they merely specify to the market operator that they must be kept online at a particular level, regardless of price. As a rule, nuclear units, for example, are scheduled in this “must-run” fashion because normally they operate at a set level of output, regardless of market price, due to low marginal fuel cost, equipment limitations and stringent safety guidelines for operation. Many fossil units are flexible within a range of output, but cannot be cycled down below a certain minimum level without shutting the unit off completely, creating an operationally inflexible minimum block of output. In an hour when a system operator has more “must-run” or zero-bid supply than it has demand, it will post a negative price, to give generators a strong economic signal to curtail generation.

The IESO has restricted generators from taking a short-term loss, possibly for sound financial reasons, only until it implements minimum pricing for certain classes of generators: primarily nuclear and wind.  The suggestions for those prices indicate they are also primarily driven by politics, with wind being suggested to restricted to a minimum price of $-10/MWh, lower than nuclear's minimum bid, under the rationale that "some negative amount is seen as reasonable to account for renewable credits and wear and tear avoidance."  

It is unlikely the wear and tear avoidance is a greater issue for wind than for other generators.

It is likely that the IESO's proposal is driven by politics, and not good design principles to encourage a functioning market.

Estimating the Costs of Eliminating Coal-fired generation in Ontario

Ontario has had a policy of eliminating coal-fired generation for longer than most Ontarian's remember.  The election of 2003 saw the Liberals promising to eliminate coal by 2007, while the 2 other main parties looked to 2015.   The Liberals won that election, but we are still working towards eliminating coal by 2014.  Every action the government takes on the electricity sector file is sold as a step to replace 'dirty' coal - whether it is referencing wind and solar feed-in tariff (FIT) programs, the contracting of natural gas-fired generation, or the signing of nuclear deals (Bruce 1 and 2 refurbishments).

Recently the allegedly environmental allegedly non-governmental organizations (ENGO's) have been broadcasting that 45% of the global adjustment is due to nuclear (OEB MSP report) - stupidly, or dishonesly, claiming that means 45% of the increase in your bill is due to nuclear.
The value of Ontario's electricity market, for only the commodity (excluding transmission and distribution) is about $10 billion, and whatever amount of that is not collected through market sales, at the Hourly Ontario Energy Price (HOEP), is collected by the global adjustment (GA).  I'll use the global adjustment as a starting point for discussing the cost of Ontario's methodology of replacing coal.



The figures for production are from IESO data, with the exception of solar.  Solar reporting is almost entirely non-existent in Ontario, with the exception of the Ontario Power Authority's quarterly progress reports.  Using those, and a typical output pattern from the London Ontario area, I have estimated solar production.  There are a variety of methods for estimating contract values; for wind and solar it is the first FIT program rates, as the majority of contracts offered for production entering by 2015 were offered under FIT 1.0.

I recently demonstrated a group of natural gas plants is essentially bidding into the market at the price of fuel and capturing profits through a Net Revenue Requirement (NRR).  From the perspective of policies to replace coal, it is notable that the oldest of those plants, Brighton Beach, entered into operation without a contract - the contracts exist due to policies to expedite the elimination of coal facilities while procuring intermittent generation that will minimize the run-time of the natural gas facilities.  The necessity of capacity payments, in the form of NRRs, lead to NRR's for all.

The first graph looks at subsidies as all NRR payments to the ~4630MW of gas generation procured (Ontario had ~7600MW of coal-fired capacity in 2003 and has reduced that to ~3500MW), as well as the costs of actual wind and estimated solar generation (contracted rate less the market, or HOEP, recoveries).  A frequent refrain is that people have exaggerated the impacts on bills of renewables, but including the capacity charges, as natural gas units achieved operational status, the total annual subsidy, defined as payments above HOEP valuation, has moved from ~$100 million early in 2007 to ~1.5 billion today.

Defining the subsidy by the global adjustment amount (variance from HOEP value) means that as the HOEP drops, the subsidy increases - demonstrated in the rapid increase starting, with the recession, late in 2008.  The full brunt of the impact is disguised because much of the public's hydro production (through Ontario Power Generation) is exposed the HOEP pricing; OPG's revenues have dropped partially because supply continued to be contracted as demand collapsed.  Consequently the limited impact on the household electricity bills has been countered by debt retirement charges being halted since 2009 - $1 billion has been collected each year, but the $5.6 billion on 31/3.2009 climbed to $5.8 billion on 31/3/2011.


By the end of 2016 (perhaps by 2015) today's ~2000MW of wind capacity, and 500MW of solar capacity, are set to grow to 8000MW and 2700MW, respectively.  If the current levels of the HOEP hold, the 'subsidy' (as defined in the previous paragraph) will rise from ~$1.5 billion to $4.4 billion.  This figure should be low - because the current plans don't actually include appropriate replacement supply for the remaining coal generation capacity. There have been well publicized cancellations of natural gas plants in urban locations - but no coherent alternative plans to replace the planned dispatchable capacity.

Numbers attached to the global adjustment are all corrupted by the low HOEP rate, which is averaging just $25/MWh over the past 12 months.  The HOEP is low for some reasons that are universally true; declining/stagnant demand and very low natural gas pricing.  The HOEP is lower again for some distinctly Ontario ones; a large baseload element, and capacity payments for the gas, and to a lesser extent coal, suppliers that set the price when we don't have excess baseload generation.

A useful figure in estimating the costs of replacing coal is probably $52/MWh, which is close to the price of coal-fired generation from OPG in 2007/08, before capacity payments kicked into high gear to keep the plants available despite severely curtailed production.  $52/MWh is also pretty close to the base price guaranteed the production from the Bruce B nuclear units.

Forecasting "subsidies" out by defining the subsidy as the price above $52/MWh, instead of $25/MWh, and leaving the natural gas plant NRR subsidy as is, drops the subsidy level down by the end of 2016, but only to ~$3.7 billion dollars.

These estimates are very rough, and indicate future costs based on the costs of old plant, but they are in line with the best forecasts in Ontario, which I've argued are from Bruce Sharp (here in the press, which references the work here).  There is limited utility in improving forecasts because, as the latest IESO forecast again indicated, there is still no plan to adequately replace the remaining coal capacity.

Revisiting the current accusations of subsidy, and using the $52/MWh as a better indicator than the HOEP of $25, the figures change significantly.  There's an important, counter-intuitive, lesson to be learned: Because $52 is the lowest figure for all generation that is not public, the only cost increase to consumers would be due to paying more for OPG's unregulated hydroelectric production (~11.2TWh over the past 12 months).  Consequently, a 105% increase in the market price would create an actual price increase of a little less than 3% - but that entire 3% should be public generator profit used to pay down the existing debt that the nearly $1 billion a year collected by a debt retirement charge is not being used to pay down.

Using the $52/MWh figure also changes the current view of how heavily different generator groups are subsidized.  At a market valuation of $52/MWh, the 3% of all generation that comes from wind would share a similar subsidy sum as the 54% of all generation coming from nuclear sources ~ and the natural gas sources that provide 15% of all supply collect ~42% of all subsidies.

Coal is included in this table, as subsidized, because there is a cost to using less coal than we used in 2007/2008 (only the costs of the fuel itself are not relatively fixed)

The many assumptions required in these estimates can be argued, but it is clear that policies that create an artificially low market price (HOEP) are problematic in multiple ways - most significantly in avoiding dealing with the public debt while transferring wealth to private owners entirely sheltered from market turbulence.

---

The spreadsheet with the HOEP figures in this post is here.
The spreadsheet calulating some figures with the HOEP at $52/MWh is here.

At the End of The IESO 18-Month Outlook: Updated

In a previous post I noted the final paragraph of the previous 4 18-month outlooks from the Ontario's Independent Electricity System Operator (IESO).  Here I add final sections of the 2 outlooks released since that post.
Nothing has changed: the current outlook notes ~3000MW of capacity to come online, none of which shares the 'flexibility' attributes of the coal Ontario is committed to replacing - despite not coherently planning to meet that commitment.

September 2012 - February 2014

...With the forecast increase in SBG, we foresee an increase in out-of-market control actions, such as minimum hydro dispatch and nuclear maneuvers, to be required in order to manage the surplus, extending beyond the typical market action of exports. With wind and solar becoming more prominent resources on the electricity system, the need for maximum flexibility from all resources becomes integral for the reliable and efficient operation of the grid. When variable generation becomes dispatchable, additional flexibility will be available to diminish the frequency of out-of market control actions for SBG.

The existing coal fleet, though running at vastly reduced levels from previous years, provides the IESO with desirable flexibility, such as quick ramping and operating reserve, under all market conditions. As Ontario’s coal-fired generation is shut down over the next two years, its associated flexibility will be lost. Therefore, future capacity additions should also possess this flexibility to help facilitate the management of maintenance outages, provide effective ramp capability, supply of operating reserve and even provide regulation when necessary.

June 2012 - November 2013

graphic from IESO report

One of the greatest variations seen in the first quarter of 2012 from last year is a decrease in imports. This difference was due to lower demands and prices, caused by a mild winter and record-breaking high temperatures in March.
Another large variation was in the frequency and energy volume of manual actions, such as nuclear unit maneuvers or import transaction curtailments, for surplus baseload generation conditions. In Q1 2012, there were 73 GWh of curtailments versus 32 GWh in Q1 of 2011. The rise in manual action is a result of lower minimum demands as well as a growing portfolio of baseload generation.  The ability to dispatch renewable resources may help mitigate the need for these actions moving forward.

March 2012- August 2013

The retirement of two Nanticoke units during the past quarter not only removed 980 MW of installed capacity from our system but also removed the associated flexibility. The existing coal fleet, though running at vastly reduced levels from previous years, provides the IESO with desirable flexibility, under all operating conditions, from low load SBG to high peak periods. Units with flexible dispatch facilitate the management of maintenance outages, provide effective ramp capability and can even provide regulation, when necessary. These characteristics are important and are desired in new capacity. With the changes to gas‐fired generation projects in the GTA, and until the future of the Pickering Nuclear station is determined, decisions must be made over the next 18 months to ensure adequate supply beyond the middle of the decade.

December 2011 – May 2013

The other large variation seen from the previous year was the frequency by which a nuclear unit had to be either maneuvered or shut down. So far in 2011, nuclear units have been maneuvered 113 times for a total of 364 hours. Compared to 2010 which had nuclear units maneuvered 14 times for a total duration of 64 hours, this represents a significant increase. This rise in manual action is a result of a lower minimum demands as well as a growing portfolio of inflexible generation. The ability to dispatch renewable resources may help to mitigate the need for these actions moving forward

September 2011 – February 2013

Ontario can expect periods of SBG similar to 2009 and 2010, with a brief reprieve during the higher demand winter months, followed by a re‐appearance in spring 2012. During these periods of SBG, , beyond typical market actions such as exports, minimum hydro dispatch and nuclear manoeuvers, some out of market control actions are expected to be required in order to manage the surplus condition.

June2011 – November 2012

The biggest variation from the previous year is that in 2010 we saw lower hydroelectric production during the summer months. The major factor that contributed to this variation is the decrease in precipitation levels from previous years. We also saw an increase in wind capacity during the early months of 2011.

The things the IESO notes as requiring attention aren't the things we hear about.

As drones continue stupidly repeating,  "Ontario is replacing dirty, coal-fired plants with cleaner sources of power like wind," the system flexibility is being lost as gas plants that can act 'like' coal are ignored and sources that aren't "flexible" - sources unlike coal - are recklessly pursued.

There is no value in Gipe's FiT Tripe

Nowadays people know the price of everything and the value of nothing

-Oscar Wilde 

This week renewables' advocates were citing the German Renewable Energy Agency's compilation of the cost of wind energy across selected countries demonstrating wind energy was cheapest where feed-in tariffs were utilized to procure electricity from wind turbine companies (as opposed more market oriented renewable energy standards/RES quotas).

This shouldn't come as a surprise.  Suppliers in competitive markets need to price risk, and guaranteeing a return on investment clearly removes much of the risk.   That may have provided value to consumers if the risk didn't serve any purpose - but risk is fundamental in how a market establishes value.  The risk to wind suppliers in an RES environment is the uncertainty of pricing, including the possibility of not finding buyers at positive pricing,  For the grid utilities serving customers, the expense from committing to intermittent renewables is not maintaining suppliers to meet demand when called on.

Slide 7, Power Markets of the Future

The German Renewable Energy Agency promotes only renewables; the German Energy Agency (dena) ensures electricity can meet demand.  The German Energy Agency is currently looking closely at capacity mechanisms to ensure that there is enough generation to meet demand.  The graphic shown here was part of dena's presentation at a recent conference on Capacity Mechanisms - meaning how to pay to ensure there is the traditional generation to provide power when it is neither windy or sunny.


A better measurement of value is not what one element of supply costs, but the impact of total costs of supply procurement policies on the end consumer.  I have added to the data table produced by the German Renewable Energy Agency and reproduced by Paul Gipe on wind-works, with additional data collected primarily from ENTSO-E and Eurostat.

• Germany is tops for wind generation, and they ended 2011 with a price of over 25 euro cents/kWh (second highest of the listed countries), which is still growing rapidly,  The EEG charge (the surcharge through which the FIT costs are recovered) is forecast to escalate up toward 6 cents/kWh next year and towards 8 the following year (10 cents/kWh Canadian).
• The highest price on the list belongs to Denmark (~30 cents/kWh).  The percentage of generation from wind is higher than in Germany, as is end user expense.
• Spain generates a great share of their electricity with renewables, and Eurostat shows the average cost there only slightly above the continental average.  Unfortunately that is not because the costs of that system are just slightly above the continental average, but due to subsidy via an ~25 billion euro tariff deficit.
• Portugal also receives much of their total generation from renewables, and the price there was actually slightly below the European average. The market is much smaller than in Spain; the tariff deficit of ~1.8 billion euros also means the costs there are artificially low due to subsidy.
• Ireland is the last country on this list with a double digit share of production coming from industrial wind turbines.  Eurostat figures show the cost to consumers there to be 30% above the cost to consumers in the UK.

The price paid to wind generators is not particularly relevant.  The many other costs of wind within a supply system would be relevant in a market; feed-in tariffs are designed to distort markets. Looking at the costs of the systems with the greatest share of wind demonstrates that additional costs exist - and many of those cost exist specifically because of the damaging economic tool of guaranteed payments for unlimited amounts of dated technology.

Canada's ENGO's Offensive Response to New Regulations for coal-fired generators

Yesterday the Canadian government announced new regulation for coal-fired electricity generators.

The rules, promulgated under the Canadian Environmental Protection Act, 1999 (CEPA, 1999), set a performance standard of 420 tonnes/GWh, which is the emissions intensity level of Natural Gas Combined Cycle technology, the government said—but it is much higher than the of 375 tonnes/GWh limit proposed in the draft rule....
Federal Environment Minister Peter Kent on Wednesday admitted the new rules are "at the high end" of the 360 to 425 tonnes/GWh range that had been considered, but he defended the decision, saying it would avoid putting the "consuming public at risk of inadequate power supply." The 375 tonnes/GWh performance standard “would have been applicable only if, in the coal-fired electricity sector, plants operated at a steady productivity," Kent said. "In reality, plants go up and down in the generation of energy depending on demand."

Power Magazine: Canada Finalizes GHG Rules for Coal-Fired Power Plants

That all sounds reasonably aggressive to me, as Germany's latest coal plant will reportedly emit 13 million tons of CO2 annually, on production of 16 million MW (~800 tonnes/GWh).  This for a plant the German environment minister references as 'state-of-the-art' as he viewed a demonstration of the plant's ability to ramp up and down to match the variation in the output of renewable wind and solar generators (reference here)

The reaction of the groups Canada's mainstream media considers green didn't mention their pet projects necessitate higher emissions from the fossil fuel plants that must accompany renewables.

Sierra Club Canada:  Coal Regulations: Not enough is still not enough!

“Mr. Kent has never explained how he will enforce regulations 50 years from now,” said Mr. Bennett. “Kent’s announcement is a either a bad joke or an insult to the intelligence of Canadians. It’s amazing he can make these announcements with a straight face!”

Thus spoke John Bennett.
Speaking is not something he does in noting the real Sierra Club's Beyond Coal campaign (US), which was funded by the natural gas industry.
Nor does he note the 398 tonnes/GWh that natural gas generators are estimated to emit, in Ontario, isn't really different. [1]
He seems incapable of noting that a Minister does not speak on behalf of himself.  It isn't a joke to think Canada will exist in 50 years as an entity capable of enforcing regulation.
Mr. Bennett appears to be a joke.

Pembina Institute:  Pembina reacts to federal climate change regulations for coal-fired power

“These changes mean Canada has gone from moving at a tortoise’s pace to a snail’s pace when it comes to regulating coal. We are missing some of the lowest-cost opportunities to curb climate change pollution and are committing Canada to a dirty electricity grid for decades to come.

Slower?
Nonsense.
As stated earlier, the emissions adjustment makes perfect sense in recognizing the higher emissions intensity of generators sharing a grid with industrial wind turbines - the turbines the Pembina Institute generates revenues promoting.
Pembina's Tim Weis tweeted "its hard to believe these regs do anything"
It's hard to believe the Université du Québec à Rimouski granted him a PhD.

Both Weis and P.J. Partington seem aghast that the regulations recognize a 50 year life for coal plants.  While the average age of a US coal unit is less that 50 years, most are still operational (reference).  The average age of a unit being decommissioned is over 50 (reference)

Environmental Defence:  Statement by Gillian McEachern, Campaigns Director on federal coal regulations announced today

50 years is too long to wait to stop pollution from coal. Burning coal creates pollution that has been linked to hundreds of premature deaths from smog every year, causes the accumulation of toxic mercury in fish and wildlife and is the single largest source of global warming pollution in Canada.

More convincing, but:

• scrubbers and other pollution reduction technology can reduce the emissions that contribute to poor air quality.  In Ontario, where 'death' stats are fabricated, they are a minor contributor (references here and here).
• global warming is a global problem.  Remaining cost competitive while reducing emissions is highly relevant in actually impacting global emissions, instead of simply exporting high-emissions activities (reference)
• regarding mercury, just today Mitt Romney is shown as stating the "Utility MACT” rule is purportedly aimed at reducing mercury pollution, yet the EPA estimates that the rule will cost $10 billion to reduce mercury pollution by only $6 million (with an “m”)."   

Very few people are going to promote coal, but the most recent Canada GHG Inventory report (1990-2010) shows Nova Scotia with a generation intensity of 810 g CO2 eq / kWh (up from 760 20 years earlier), Saskatchewan at 770 (down from 810 over the two decades) and Alberta at 840 (from 980).

Clearly the pace of reductions is quickened with flawed, but implemented, regulations.
I don't see what is environmental about ignoring that.

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UPDATE September 8th

Pembina Institute: Addressing "misperceptions" about Canada's coal power regulations

P.J. Partington's follow-up seems to respond to some of the criticism I had.  Specifically he calls "untrue" the move to 420 from 375 (tCO2/GWh) reflects operation intermittently instead of as baseload, but rather the 375 was set to equate to the levels promised by a "modern natural gas plant."

Both are true - intermittency fires up the heat rate, increasing emissions, and 375 is promised by modern natural gas plants.  What is achieved by modern natural gas plants is an entirely different matter.  Analyses of actual heat rates, and therefore emissions, has been done throughout electricity systems with increasing intermittency/renewables, contentiously (Bentek, C. le Pair, Udo, CEPOS).    

It's clear plants don't run as cleanly as possible when not in baseload mode - it is not clear what that performance difference is, in CCGT units or coal units.  

The Pembina study notes possibilities for low emissions from pulverized coal plants - with a link to a 2009 paper touting the possibilities with Carbon Capture and Storage (CCS).   Google "cancelled CCS project" and it will become quickly apparent the technology is not being implemented either due to price, or technological, failings.  On the day the regulations Pembina is criticizing here, another CCS project was being announced in Canada (by Shell, with funding from multiple levels of government).  

Pembina feigns arguing the point that these regulations are among the world's most ambitious.  They change the channel from nations to provinces, noting high-emissions Nova Scotia and Ontario as exemplary.  Since Ontario's emissions peaked in 2000, coal-fired production is down about ~38TWh while nuclear production is up ~25TWh (gas-fired generation up ~12TWh, and demand is down ~11TWh).  If Mr. Partington is impressed with Ontario's current mix of generation he should say so.  

The aggressive 375 tCO2/GWh he is arguing for is 3.5 times greater than what is achieved in Ontario's current supply system where over 50% of the generation comes from nuclear power.

Endnotes:
1:  Ontario Society of Professional Engineers use the figure in "Wind and the Electrical Grid: Mitigating the Rise in Electricity Rates and Greenhouse Gas Emissions" - which they reference as sourced on Natural Resources Canada RETScreen Clean Energy Project Analyse Software.

Ontario's Billion dollar subsidies of Gas-fired Electricity Generation

 "I am against blanket subsidies for fossil energy, which would only increase power prices."

-German Environmental Minister Peter Altmaier, in opposing capacity markets

Subsidies are a difficult thing to define, and quantify.  There are many jurisdictions throughout the world seeking out structures to ensure adequate capacity to meet society's demand.  The issue is of particular importance in jurisdictions that have introduced significant quantities of intermittent solar and wind generation.

When the sun shines and/or the wind blows, wind and solar generators generally have priority on the grid, but even if they did not, they have no fuel costs and could therefore underbid most competing technologies.  Economically, this takes away the visibility of revenues, and operating costs, for the traditional generators that are needed to ensure demand is met.   Some generating systems, such as Texas' ERCOT, are compensating for the lack of visibility by allowing higher spot prices (now above $3500/MWh, or $3.50/kWh) to encourage merchant plants to build for only a few hours of production a year.  Nord Pool is a Scandinavian market that has a strategic reserve mechanism, and a number of American markets contain competitive capacity markets.  Ontario has no open market mechanism, but primarily hidden contracts with private suppliers.  The province - my province - is an example of the damage done by abandoning market principles in secret deals that attempt to outsmart functioning markets.



Capacity payments, in the form of Net Revenue Requirement (NRR) guarantees included in contracts, are a form of subsidy I've previously explored.   Under the Liberal governments headed by Premier Dalton McGuinty, Ontario has seen it's fledgling electricity supply market damaged largely through the subsidies provided private natural gas generators and, to a lesser extent, Ontario's public coal-fired generating stations.

To emphasize that they do constitute subsidies, it's instructive to look only at fuel cost, and market revenues, meaning sales at the Hourly Ontario Energy Price (HOEP).

The recession that brought reduced demand in 2009 saw Ontario Power Generation (OPG) production severely curtailed in the unregulated thermal sector, which is primarily their coal-fired operations.  Largely as a consequence of the lowered demand, which saw some penalties incurred for cancelling coal orders, revenue from spot market sales dropped below fuel costs (by $20 million).  A very dry 2010 saw some improvement as spot market revenues again exceeded fuel costs, but by 2011 fuel costs were again $52 million higher and in only the first six months of 2012 fuel costs doubled spot market sales revenue ($37 million more).

Whatever the arrangements made to fund OPG's coal plants to ensure they are available when required (as they are at times), it is apparent the arrangements allow for coal-fired production to be bid into the market below even the fuel costs.

Since 2009, natural gas has been the dominant fossil fuel in electricity generation, and now about 6MW are generated with natural gas for every MW generated with coal.

Natural gas-fired generators include a group of non-utility generators that essentially have 'must run' contracts (most for sane reasons), combined heat and power (CHP) generators, and the newer generators that were contracted in order to procure intermediate and peaking power sources capable of replacing coal in Ontario's generator mix.  This last group includes Portlands, Goreway, Greenfield, St. Clair, Halton Hills, York Energy Centre, and Brighton Beach.  We can call the group the OPA's Group of 7, as the Ontario Power Authority is the body that contracts the generation.  This group has a capacity of ~4631MW, with a guaranteed Net Revenue Requirement averaging $13,187 per MW month; the NRR's therefore guarantee payments of approximately $733 million annually, regardless of supply.

Because the OPA's Group of 7 are generators specifically contracted to provide intermediate and/or peaking supply, it seems logical that this supply should frequently set the market rate (Hourly Ontario Energy Price, or HOEP).  In fact the market works on 5 minute intervals and has many factors involved in determining supply, but estimation is possible with the HOEP and hourly generator output.  These suppliers should, frequently, be the supply on the margin which sets the HOEP price.  To look at how much of that $733 million could be considered subsidy, comparing the fuel costs to the HOEP value should provide an idea of whether or not the OPA's Group of 7 are attempting to earn a profit on market sales.

The dominant gas supply is from the Union Gas Dawn hub.  I've assembled daily closing pricing for that supply, but this should not be the delivered cost to generators.  The American Energy Information Administration provides monthly natural gas pricing for 'Wellhead', 'CityGate' and the Electricity sector.  The electricity sector pays almost exactly the average of the wellhead and citygate pricing, which is ~$1/MMBtu more than the well head price.  Dawn pricing is higher than the wellhead price, but not as high as the electricity sector pricing.  I have taken the middle ground and added 50 cents/MMBtu to estimate the delivered cost of natural gas to the OPA's group of 7 generators.

The chart demonstrates that only in the higher demand of the summer has this group of generators sold generation at a price exceeding their estimated delivered fuel costs.  Of the $733 million annual net revenue requirement, I estimate $27 million may come from the sale of generation above fuel costs.

The other $706 million is paid through the global adjustment mechanism (GA,or GAM).  The GA recovers the full costs of contracted supply by recovering from Ontario ratepayers whatever amount sales at the HOEP market rate do not.  Because the group of 7 gas generators are frequently the marginal supply, and therefore should be the price setter, their comfort at selling into the market at, and possible below, the cost of fuel, is particularly problematic.

The HOEP is, in some ways, not relevant.  Only exports fail to recover the full cost of contracts, and most suppliers are guaranteed rates.  In fact, essentially the only supplier exposed to selling at the artificially low HOEP is Ontario Power Generation (OPG).  The lowest price for private suppliers is likely Bruce B (nuclear) , with a floor price of ~$52/MWh.

Impacts of the HOEP lower than $52/MWh are subsidizing exports (which the GA is not applied to), and dropping the revenues of OPG.   OPG's revenues on it's unregulated hydroelectric segment is ~$250 million lower than it was before the OPA began it's contracting of renewables and natural gas supply, so profits have stagnated and the oustanding debt has ceased to be paid down.  Despite the temporary Debt Retirement Charge on Ontario bills for over a decade, the government's latest figures shows the residual stranded debt the DRC targets increased from March 2009 to April 2011.  The primary difference in doubling of the HOEP, which has now sunk to a 12-month average of ~$25/MWh, would be higher profits at OPG eliminating the Debt Retirement Charge in our lifetimes instead of decreasing profits at OPG extending the Debt Retirement Charge indefinitely.

The figures I provide in this post are not a comprehensive accounting of payments to natural gas suppliers.  The Group of 7 generating stations examined produce approximately half of all natural gas-fired generation, and the other half is more expensive.  I've tried to pick the group that should be driving the market pricing, but is not.  Having concluded the net revenue requirement guarantee there is a $700 million a year cost the suppliers do not attempt to recover through the market, it is impossible to determine the estimated $110-$120/MWh must-take price contracted from other natural-gas fired generator (the NUG's) is not also a very large subsidy.

Ontario's electricity market mechanisms are complicated, incluiding the contracting of private gas generation and the accounting involved in calculating the global adjustment.  It seems increasingly likely that the complexity, and opacity, is designed to disguise a system designed to benefit only a small group of special interest groups in conning the majority of Ontarians out of not only a larger share of their disposal incomes, through increasing electricity rates, but the value of their public generation assets.
The public generator is receiving approximately 5 cents/kWh, while non-nuclear private generators receive twice that.

Ontario has an electricity market bereft of competition, absent of risk, and incapable of balancing supply and demand efficiently.  Instead of creating more obscure rules and mechanisms to address that, revisiting a very old question would be worthwhile:

Why?

Better Ontario Electricity Estimates For August

The IESO has posted updated estimates for August's Global Adjustment.
As with July, the 2nd preliminary estimates are unlikely to provide good guidance on the final figures due in a couple of weeks.

The posted 2nd estimate for August 2012

Unlike July, August's mistake appears to me to be a typo, with 38.94 ($/MWh) being entered as 28.94.

July's big discrepancy was in the total pool of money.  A $599 million estimate was reduced to $421.7 million in the final charges.  The reason for the discrepancy being the costs of cancellation of a gas plant in Mississauga, promised during the previous election campaign.  Ontario's Finance Minister noted the costs of cancelling that plant would hit neither electricity rate payers nor tax payers due to the existence of a magical contingency fund (adjective added), but perhaps he did so only in the the proper Liberal government channel (The Toronto Star) without notification of the bureaucracy.

The average market price, or HOEP, for August 2012 was approximately $29.31.  If the estimated GA is correct, the Class B customer price would be $58.25, the lowest price since April 2009.

I suggest counting on $68.25/MWh as a basis for the bills of those not on the regulated price plan (RPP).  This remains far below the regulated rates as the average RPP customer pays over $80/MWh.  The RPP rates are set by the Ontario Energy Board based on estimates from Navigant Consulting.  Navigant has become a favourite source of studies for the American wind industry, and actively promotes services for the solar industry.  Both seem like lovely new businesses, but might explain a lack of attention to updating the old RPP templates, explaining why the summer 2012 estimates are performing so poorly.

August 2012 consumption was up slightly over August 2011.
My data estimates of rates are here (and preliminary monthly report here) - some queries use the IESO's 2nd estimate, so the calculations using the GA rate will be off.  As usual hydro and nuclear, primarily public, receive low prices so as to pay higher rates for, in order of impact to your bill for August, natural gas, conservation, solar and wind.

Wind is particularly low the past 2 months due to the fact it produces very little in the summer months.  Total wind production was up over July, but Dillon, Gosfield, Port Alma (both 1 and 2), and Spence wind generators all saw their least productive months (in terms of capacity factor).