2012 Ontario Wind Production Impacts Exports and Price

I've run some data analysis and noting a couple of metrics that indicate characteristic impacts on an electricity market of increasing intermittent generation guaranteed priority access to the grid.

For each of the main sources of electricity generation in Ontario, I found the minimum and maximum levels of the past couple of years and then grouped the production into 8 levels, calculating average HOEP (Ontario market price), and net export volume for each.

As expected, net exports were much higher during hours of higher wind generation.  This is in stark contrast to hydro, coal and gas generation.

The price relationship is, as expected, the opposite: the higher the wind production, the lower the price.  In 2012, this was unlike all other sources, including nuclear

Substituting the actual grouped production levels and average HOEP pricing and net export volumes, it's clear that as wind ouput increased in 2012, so did exports, while pricing declined.

Fortunately, 50% of the time wind output was less than 400MW.

A shared spreadsheet containing the figures behind these graphs also includes the data in monthly format, which may be informative to those interested in the data and comfortable with pivot tables.

Ontario's Electricity Exports Surge: Are they killing us?

I noticed some large export volume moving out of Ontario yesterday, and took a couple of minutes to see how often, in the past, we had been exporting at this level.

Not often.  
The answer is instructive as to the nature of Ontario's reporting of statistics in it's generation of electricity.

IESO Intertie Schedule and flow data summarized by state/provinde

The immediate data indicating import/export activity is the Independent Electricity System Operator (IESO) Intertie Schedule and Flow Report.  I've been capturing the hourly data from that report since April 1, 2011; Hour 14's 3707 MW is the highest net export level since I started collecting the hourly data from this report in April, 2011.  The fact this record occurred at 2 pm will surprise many as the very common opinion is that Ontario's high export levels are driven by excess production from baseload plants during low demand periods.

The second piece of data I get on import/export figures is the Daily Market Summary from the IESO.  The summary for the January 21st indicates the IESO will now report much lower exporting activity than indicated in the intertie schedule data; it indicates an average net export of 2269MW, which is 420MW lower than the average net export in the intertie schedule report.

The third data source will provide the hourly data behind the Daily Market Summary, and is inclusive of all dates back to market opening in 2002; the Hourly Import Export Schedules .csv file which is updated each Friday.

I've listed the top 15 net export hours as per the intertie data - where the data exists in the .csv file, I've shown it, and indicated the difference.

Note that the variance is a constant 514MW on November 12th.  I've explained the difference previously, arguing it is due to the output of generators on the IESO grid that is bound for Quebec.  The specifics are vague, but Quebec's transmission lines are high voltage direct current lines, and Ontario's are not: there are grid connections that can alter the flow accordingly, but there also appear to be generators that can change their connection from Ontario's grid to Quebec's.  The largest of these is the R.H. Saunders Station, on the St. Lawrence river at Cornwall; Cornwall's electricity consumers are one of the very few exceptions that don't have their rates set by the Ontario Energy Board, as they purchase their power from Hydro Quebec.

There's nothing necessarily improper in the arrangements: Quebec has the ability to store energy in it's, and Labrador's, reservoirs, and Quebec is a winter peaking jurisdiction while Ontario is a summer peaking jurisdiction.

It does greatly distort reporting on electricity in Ontario.  The IESO is not reporting generation in Ontario in a number of ways, excluding embedded, self-scheduling and generators feeding directly to other grids.  
The IESO doesn't report actual demand, but rather defines demand as generation (plus imports) ... so not reporting on supply also doesn't report on demand.
The full increase in net export levels is already being disguised in their reporting, and the growth in embedded generation will increasingly understate supply changes and therefore underestimate demand in Ontario.
These data issues aren't the type of stuff that receives attention.

What does receive discussion as politicians and lobbyists work a "coal kills" messages through the press is that we are eliminating coal-fired generation.  This "information smog" presented itself recently as Ontario's Minister of the Environment connected "smog-heavy coal-fired" generation with 10000 deaths a year.

Yesterday Ontario's production from coal-fired generators was ~0.7% of 2012's production.
At no time did that generation exceed net exports

Maybe those who implied coal killed 10000 people last year should be asked why another 60 or 70 were sacrificed, to export electricity, yesterday.

Hundred of millions of dollars kept by Ontario's Ratepayers

The price of the electricity commodity in Ontario was only 2% higher in 2012.  The figure is a lot lower than anticipated, and it's worthwhile reviewing why that might be.

Sometimes I think it's a sin
When I feel like I'm losin' when I'm winnin' again. 

-an incorrect recollection of Sundown

According to the year-to-date "commodity charge" noted on the Independent Electricity System Operator (IESO) Decembers' reporting, the commodity charge was $73.3/MWh in 2012, up from $71.95 in 2011 (for a class B customer).

The increase is far less than anticipated in Ontario's Long Term Energy Plan.  The introduction of the Green Energy Act, in 2009, was accompanied by claims the impact on bills would be "about 1% per year of additional rate increase associated with the bill’s implementation over the next 15 years."  Expert analysis, such as that performed by Bruce Sharp, would soon show the costs would be much higher, and the government's November 2010 Long Term Energy Plan revealed "residential electricity prices are expected to rise by about 7.9 per cent annually" for the next 5 years.

With a market value of approximately $10 billion, total cost inflation in 2012 amounts to approximately $550 million less than anticipated.

The drop in the Hourly Ontario Energy Price (HOEP) continues, and that continues to indicate overcapacity.  The most recent release of the Ontario Energy Board (OEB) Market Surveillance Panel (MSP) notes:

612 MW of new capacity was installed in the 2011/12 Annual Period, principally from large-scale wind projects and a new gas-fired facility.  However, Ontario still experienced a net reduction in generating capacity due to the removal from service of two coal-fired generation units in January 2012, representing a loss of 975 MW of capacity. [see endnote 1]

The IESO notes only one industrial wind generator achieving commercial operation in 2012 - along with two nuclear units that entered service late in the year.  In fact the IESO didn't introduce a single wind generator to it's hourly reporting in 2012, although 2011's 3 additions drove up generation totals in 2012, their first full year of service.  Similarly, the impacts of the 2012's additional nuclear units are likely to have a much larger impact in 2013.

It is notable that 2 wind generators that started reporting in 2011 continue to avoid achieving "commercial operation" status even now - the only two "on grid" feed-in tariff (FIT) contract holders. Pointe-Aux-Roches and Comber both appear to be avoiding achieving commercial operation, and I'd suggest that is due to worries about the ability of the system operator to curtail their production once they do so.  I wrote a series of posts in 2011 which forecast over 40% of all wind generation, in upcoming years, was likely to bump hydroelectric and nuclear production, or to be dumped on export markets.  I neglected to note it may simply be curtailed.

In the summer of 2011 I had co-written an article with Parker Gallant on the cost of dumping surplus generation in export markets.  In that article we cited projections from a report Clearsky Advisors Inc.had prepared for the wind industry.  Comparing that report's forecast for 2012 to the actuals reported by the IESO, the growth in wind output, since 2010, is 1/3rd less than expected and net exports are 9.7 TWh less than Clearsky projected.

• At $135/MWh, the 800 GWh reduction in the wind output equates to ~$108 million.
• At a subsidy cost of $45/MWh, the 9.7 TWh reduction in net exports equates to $437 million (see endnote 22]).

The total is close to the $550 million not charged to ratepayers as the inflation rate was held to 2%.

Some of the savings may be short-lived.  The two nuclear units returned to service late in 2012 - not early in 2012 as had been expected.  That will put some pressure on export levels in 2013.

Nonetheless, it's hard not to assume some success in restraining supply.

The combined themes of continued surplus generation and uncertainty about payment requirements  under the FIT contracts appear to have led to the Canadian Wind Industry reducing expectations to an additional 2500MW of capacity by 2016; while that sounds impressive, contracts exist for approximetely 3000MW of additional wind without accouning for the "Samsung" deal's 2000MW (of which only 870MW have firm plans).

Nevertheless, there have been no announcements in changes to Ontario's electricity sector plans.
Parker Gallant recently estimated the cost of those plans at over $2000 per ratepayer.  Perhaps 2012 indicates those costs could be held to half that level.
That would be a win, of sorts, for ratepayers.

But it would feel like losin' ... again.


Endnotes:
[1] The OEB MSP report is not correct.  They include Point Aux Roches in this total, which did enter reporting, but did not officially become "operational" during the time period, while omitting Comber, which also entered reporting but did not officially become operation during the time period.  Both Comber and Point Aux Roches are early feed-in tariff (FIT) contract recipients, and I presume the exceptionally long period during which they have been producing power without acquiring commercial operation status is due to a dispute over the requirement to pay suppliers during periods of curtailment.
Also of interest from the MSP report is this helpful discription of 'embedded' generators and their treatment in reporting:

In addition, 283 MW of renewable generation capacity (a combination of wind, solar/photovoltaic and bioenergy) under the feed-in tariff (or FIT) program came online in the 2011/12 Annual Period, as did 66 MW of renewable generation capacity under the micro-FIT program (for projects that are 10 kW or less).
  These generators are embedded with the service areas of distributors and are not directly connected to the
IESO-controlled grid.  They are not counted as additions to Ontario’s installed generation capacity as reported by the IESO, nor are they generally included in the analyses set out in this report.  Rather, when a generator that is embedded within the service area of a distributor produces power, the distributor’s demand for power from the IESO-controlled grid decreases.  Embedded generation capacity is therefore reflected as a reduction in Ontario demand.

[2]  From the IESO's .csv files for HOEP, demand, and import-export schedules:  Total HOEP value is estimated as "total market demand" multiplied by HOEP plus the sum of global adjustment dollars; that total then divided by the "total market demand" yields an averag cost/MWh of $65.49 in 2012.
The value of 1 MWh of net exports is hourly exports less imports, multiplied by HOEP.  Summarized to the year, the average revenue on is $20.44/MWh.

Ontario's Decision to Close Coal Plants: Air Quality/Emissions Savings Likely Overstated

The Ontario government has finally announced the closure of the remaining coal-fired units at Lambton and Nanticoke.  For some time the message has been that the government was on track to meet it's revised goal of 2014 (initially 2007 - then 2009), and yet there are no generation projects planned that make the ability to turn off the plants any greater in 2014 than they have been since September of 2012.

Premier Dalton McGuinty was in Newmarket today to announce the Lambton and Nanticoke coal plants will stop burning coal by the end of 2013. The early closure is a result of Ontario's strong conservation efforts, a smarter electricity grid and a diverse supply of cleaner energy. Shutting down the last coal plants in Southern Ontario will significantly reduce greenhouse gas emissions and save the province $95 million.

I think the move will save money, and I'll not question $95 million.
The reducing greenhouse gas emissions I will question.

Background on why the coal-fired generators weren't already retired 

In 2006 the promise to phase-out coal by 2009 was abandoned/delayed.  Activists claimed the delay was due to lobbying by the Association of Major Power Consumers in Ontario (AMPCO) and the IESO's Ontario Reliability Outlook of June 2006 which included a "Coal Replacement Policy."  The document argued Lambton was required to stay online later due to delays in "project and site approvals" for replacement facilities.  The arguments for Nanticoke were more complex:

Studies underway on the shutdown of the Nanticoke units indicate that significant delays will also be required. In addition to being subject to the impacts of in-service delays for replacement generation and changes in planning assumptions discussed above, the Nanticoke station provides voltage support necessary for power flows to the GTA. Not only is replacement generation required on-line, but substantial transmission changes are also required to facilitate the shut-down of Nanticoke.
The IESO is continuing to assess the need and timing for some Nanticoke units to be converted to operate as synchronous condensers, which provide reactive power without burning coal to operate.

The engineering I can't address beyond noting there were unique attributes at Nanticoke, and serious claims it has better peaking depth and is therefore a better companion on a grid with fluctuating generating sources (renewables).

I will address the numbers from the non-engineering perspective from which I can assume we could produce exactly the amount of electricity demand requires (all outputs above Ontario's demand level thus being treated as superfluous).

Usually, Ontario is a net exporter of more electricity than it's coal-fired generators are producing.  In 2012, there were 1976 hours where coal production exceeded net exports (roughly 20% of all hours, down from ~24% in 2011).  However, the hours are heavily skewed to the peak demand summer season.  In July 2012 coal-fired generation exceeded exports 51% of the time (down from  ~76% in July 2011)

If we did need coal, the chance is we would need it in the summer.  Based on summer 2012, we didn't appear to need coal based on a simple test of whether enough capacity existed to replace the peak coal production.  Coal output maxed out at 2377MW on July 23rd, when natural gas-fired generators likely had another 600+ MW potentially 2000+ MW remained available at OPG's Lennox plant (oil/gas - likely dirtier than Lennox not counting CO2).  

In 2011, coal maxed out at 3585MWh - not having coal would have made supply very, very tight.  Notably that was at 9 pm on July 17, 2011, when solar would not be productive and 1500MW of wind capacity produced only 70MWh.  It's important to note that to emphasize there will be no apparent supply changes capable of replacing coal's peak matching ability between now and the end of 2013.

It's notable that the majority of coal generation in 2012 came from the units at Lambton; units equipped with both scrubbers for SOx reduction and Selective Catalytic Reduction (SCR) systems for nitrogen oxides (NOx) reduction.  The Lambton generating station in located on the St. Clair river - within kilometers across the river lie 2 of Michigan's generators, including the St. Clair Power Plant located almost directly across the river.  Considering much of the production from Lambton could be considered as being exported to Michigan, the results of closing Lambton have a couple of possible outcomes for air quality:

• the power is replaced by Michigan using it's plants on the St. Clair: emissions changes are dependent on the cleanliness of those plants, and air quiality in the area of the Lambton plant is likely to be worse.
• the power is replaced in Ontario: meaning Ontarian's will continue to pay ~8 cents/kWh for electricity, with ~.5 cents of that subsidizing the export of cleaner output to states such as Michigan

Ontario's coal use is a pittance on a global scale.  The majority of coal generation in Ontario in 2012 was either serving purposes to maintain the integrity of our electricity system, or replacing generation, probably coal-fired generation, in Michigan, New York, and other states.

The environmental value of phasing out coal would come primarily in setting an example that it could be done economically.

---

Postscript ... or Update 1:

I pulled some data on annual additions/subtraction to Ontario's generating capacity, and updated 2013 for the coal phase-out.  Since 2002 Ontario Added ~5600MW of natural gas-fired capacity and ~4080MW of nuclear (refurbished - this treats Pickering A as 0MWe in 2002, with units 1 and 4 only in this accounting as refurbishments completed).
Demand is approximately 11TWh less than it was in 2002, or an average of ~1250MW each hour of the year.

There have been ~2000MW of wind and ~600MW of solar capacity added as of the end of 2012.  While I believe the solar has some capacity value (the expectation of performance when required to meet peak demands), I thought it worthwhile to demonstate that Ontario has added ~2000 MW more traditional capacity than we will have removed when all coal units are removed from service.

The attributes of Ontario's generation mix are changes, and those changes demand more changes to recover the flexibility that will be lost as coal units are pulled.


and ... some old references:

Ontario's Energy Action Plan is one of those very political but officially government pieces that lays out the promise to eliminate coal by 2015  It is from the Eves PC government in 2003
The document notes phasing out coals "was a key recommendation from the all-party Select Committee on Alternative Fuel Sources."

From that committee's report (bold emphasis added):

A.8 Operation of Traditional Carbon-Based Fuel Generating Stations
Commentary
The operation of Ontario Power Generation’s (OPG) traditional carbon-based fuel generating stations was a major issue raised before the Committee, primarily due to the adverse air emission impacts of these facilities.
The Nanticoke, Lambton and Lakeview generating stations are among the largest sources of air emissions of the top 15 thermal electric generating facilities in Canada, according to national figures compiled by the North American Commission for Environmental Cooperation (2001 report; 1998 data).  The Committee believes that Ontario should work to eliminate its reliance upon coalbased power generation, unless future technological advances result in dramatically reduced air emissions that are equivalent to or lower than emissions from natural gas generation.  At the same time, Ontario should continue to adopt aggressive air pollution requirements to promote clean energy options.  Traditional carbon-based fuel generation constitutes only 19% of Ontario’s electricity generation by fuel type.  In some Canadian provinces, such as Alberta, coal-fired generation provides 81% of electricity generation (1999 figures).
Proposals were put forward to convert Ontario’s existing coal fired generating stations to natural gas.  The Ministry of Environment and Energy has mandated the Lakeview Generating Station in Mississauga to stop burning coal by April 2005. Concerns were raised regarding the re-powering of these stations in the event of their sale or lease, as part of the requirement for OPG to reduce its share of generation. It was suggested that one option might be to replace these stations with new combined-cycle natural gas plants.  The Committee was also concerned that a future re-powering of these stations with natural gas could cause a major increase in demand for this fuel, and a resulting increase in price.  This could affect the long-term supply and price of natural gas within Ontario.
In addition, the Committee reviewed an Ontario-designed battery/capacitor (passive electronic component that stores energy) technology that could store offpeak and intermittent power.  If proven, this technology has the potential to obviate the need for traditional carbon-based fuel generation.
The Committee heard that the coal industry believes that it can perfect ‘clean coal’ technology by 2007.  The Alberta Energy Research Institute is currently conducting research into clean power generation from coal.  However, based on current technology, Ontario should work to first eliminate coal-fired generation.  Oil and natural gas-fired generation should also be phased out. 

Recommendations 

30.  The Ontario government shall complete, within 12 months, an assessment of the feasibility and cost of converting all Ontario Power Generation coal and oilfired generating stations to natural gas.
31.  The Ontario government shall set stringent emissions limits that are no greater than the emissions limits for natural gas-fired generating stations for the operation of all current coal and oil-fired generating stations.
32.  The Ontario government shall mandate the closure of the Ontario Power Generation Atikokan and Thunder Bay coal-fired generating stations no later than July 1, 2005.  This capacity shall be replaced with a windfarm(s), possibly on the plateau adjacent to Thunder Bay.  Consistent with recommendation 16, the Ontario government shall mandate the closure of all remaining coal or oil-fired generating stations by 2015. 33.  Any requirement(s) to convert/replace current carbon-based fuel generation shall responsibly manage debt obligations associated with the original construction of these stations.
34.  The preferred long-term goal is to eliminate traditional carbon-based fuel generation and, wherever possible, all new renewable power sources in Ontario shall be used to displace traditional carbon-based fuel generation.
35.  The Independent Electricity Market Operator shall give preference to the sourcing of economic renewable power in the bulk dispatch of power.  Coal-fired generation shall be given the lowest dispatch priority.
36.  The Independent Electricity Market Operator shall take into account power dispatch policies in neighbouring states and provinces to ensure that Ontario does not import/export unwarranted amounts of non-renewable power.
37.  The Ministry of Environment and Energy should work with Environment Canada to ensure that air quality impacts of traditional carbon-based fuel generated power in other provinces and states are equitably mitigated. 

Rebuttal to conservation and demand management claims

Ontario's Environmental Commissioner produced yet another report and newspapers reported on it.
I won't waste any more of my life reading clerical bureaucratic irrelevance produced by the innumerate Mr. Miller (I've suffered through 2 in the past), but seeing reference to costs, and savings, from demand reduction programs, I did quickly flip through the 2011 Conservation report from the Ontario Power Authority (OPA released in December 2012) - enough to get the impression that the claims are that from 2006-2011 $2billion in spending on conservation and demand management (CDM), with a cost in 2011 of about $30/MWh, has resulted in $4 billion in savings for customers.

I don't want to repeat an eroneous implication I made two years ago that the OPA just makes these things up (I'm OK providing the link), but I do want to state most of the claims are probably nonsense.

The frequency where the HOEP exceeds $30 is decreasing

If you pay $30 to reduce a MWh of consumption, and the consumer generally pays over $60/MWh, the savings is not $30.
Most supply in Ontario is either publicly owned with the capital costs already incurred and the operation costs set regardless of production, contracted on a 'must take' basis, or subject to "net revenue requirement" guarantees that essentially guarantee recovery of capital costs regardless of production.  The separaton of capital and non-fuel operating costs from the market price means that reducing the total MWh consumed primarily increases the price of the remaining consumption, with very little overall savings to the consumer.


The Hourly Ontario Energy Price (HOEP) could be used to estimate the incremental cost of the next MW of generation - or of the value of not needing the next MW of generation.  Because we essentially pay the capital and non-fuel operating costs outside of the market pricing mechanism, the market price is the incremental price of the next MW of production (often this will be the cost of the generator's fuel consumption).

The HOEP averaged ~$24/MWh in 2012.

Which is less than $30/MWh

The awkward reality is that we are almost always net exporters, and those net exports usually yield a little over $20/MWh.  Ontarians should be viewed as spending ~$450 million, in 2012 alone, to subsidize exports (see note 1 from my initial review of 2012 stats) - which has an impact on most of our bills of approximately $5.25/MWh.  Funding the OPA's programming, primarily CDM activities, adds another ~$2/MWh.  Combining the costs of dumping exports with the cost of curtailing domestic consumption, the impact on the bill is now probably greater than the debt retirement charge.

And that is before accounting for the production we curtail.

Curtailment is difficult to quantify, or judge.  The programming I've done to estimate when non-utility generators are taken offline for a low-demand weekend; when Bruce's nuclear units reduce output via condenser steam discharge procedures for a couple of hours; and when hydro turbine output is diverted overnight to feed directly into Quebec's grid, totals ~843GWh, which is again greater than the OPA's claimed 717 GWh reduction (for 2011).  The hydro redirection may not be as damaging as it appears, as there may be returned benefits from Quebec; however, neither the amount of production redirected nor the agreements under which it is done are known.

The Independent Electricity System Operator (IESO) often writes about the issue of Surplus Baseload Generation, but does not provide firm numbers on curtailment.  A Recent submission by the IESO to the North American Electric Reliability Corporation (NERC):

With the forecast increase in SBG, an increase in out‐of‐market control actions is foreseen such as minimum hydro dispatch and nuclear maneuvers, to be required in order to manage the surplus, extending beyond the typical market actions which include exports. With wind and solar becoming more prominent resources on the electricity system, the need for maximum flexibility from all resources has become integral for the reliable and efficient operation of the grid.

Translated, that says with the additional generation we are contracting we will more frequently curtail other no/low carbon sources.
We are still contracting more supply while curtailing existing contracted generators and spending heavily on demand management.

Searching for evidence on the impacts of "minimum hydro dispatch" lead me to Statistics Canada CANSIM database treasure.  While there I also picked up enough information to estimate Ontario's domestic consumption back to 1977.

Chart data comes from CANSIM table 127-0001 for 1979-2005, then demand is calculated from ieso hourlydemand.csv file: hydro form 127-0001 until 2007, CANSIM 127-0002 for 2008-11, and IESO hourly production data for 2012 adjusted up to estimate CANSIM equivalence based on 2011 comparison of two data sets (IESO data does not include all generators)

One year ago, in reviewing the electricity statistics for 2011, I was somewhat surprised to find evidence that total generation from all renewable sources had been low by the historical standards of the past two decades.  This year my initial review again showed hydro production dropping - by approximately the increase in wind and solar production (~900GWh).  The data indicates 2012's hydro production is the second lowest annual output in 35 years - the past 3 years ignobly occupying 3 of the 4 lowest positions.

Production from renewable resources is essentially unchanged in 2012, while apparently more demand is eliminated by demand reduction programs as more electricity is exported at lesser rates.

Ignoring the current reality, Ontario not only continues to commit to more generation, we evict rare eagles and sacrifice important bird areas to attain more and more.

If only there were an Environmental Commissioner to stick up for the natural environment against actions that threaten it.

Link ot the Google spreadsheet containing the data for the graphs in this post

New Years Bring Record Wind Generation in Ontario

According to initial IESO data there were some records set by wind generation in Ontario on January 4th 2013 - as there was on New Year's Day 2012, and January 1st 2011.

On January 4th, industrial wind turbines in Ontario produced a daily record of ~36,873MWh.
An hourly record of 1640 MW was set in hour 18.

At hour 18 Ontario was a net exporter of 2086MW, and the Hourly Ontario Energy Price (HOEP) was $24.32/MWh - if all the wind output was purchased at the initial feed-in tariff (FIT) price, the loss on exporting the wind power in that one hour would be ~$181,500.

The average HOEP for the day was $22.07/MWh, which, under the same assumptions the day's revenue for wind generators on the IESO-controlled grid at ~$4.8 million, with the resale value at ~$800 thousand.

A $4 million loss.

Dispatchable coal and natural gas units were also generating on the 4th, and all but 5 hours net exports also exceeded the amount of dispatchable generation - so the export story is certainly not exclusively about wind turbines.

The exports (net) during wind's record day were lower than they had been the previous 2 days.

The reason the dispatchable coal and natural gas-fired generators need to be available may be explained by wind production 47 hours prior to the record set on the 4th; when Ontario demand was higher than it had been for 118 days, the grid-connected wind resources were producing only 234 MW.  As it was dark at the time, and assuming the non-grid wind turbines were producing at the same efficiency as the turbines on the grid, Ontario's 2500+MW of renewable energy was outputting only about 10% of capacity at peak.

That explains why the dispatchable generators need to be available.

This generation frequently operates for export customers because Ontarians pay the full operating and capital costs through the global adjustment mechanism.  This explains why the net exports are frequently higher during the higher demand periods of the day than the low demand of early hours.

That does not explain why net exports could be lowered by high winds.

Perhaps the markets we export to also have more supply than anticipated when the wind resource is plentiful - and perhaps that will increasingly be the case.

2012 Ontario Electricity Statistics Show increased use of Fossil Fuels

Postscript, added January 12th, follows original post of January 3rd.

A first look at 2012's electricity statistics yields the surprise conslusion that prices charged to Ontario ratepayers were far more stable in 2012 than anticipated, and that the Green Energy Act darlings of wind and solar generation contiued their growth while demand did not grow.  Closer looks show these may be rather meaningless stats - hiding increasing emissions, and increasing shifting of the costs of our electricity from the ratepayer to the taxpayer.

Growth in wind and solar generation in Ontario's electricity system was accompanied by growth in coal and natural gas-fired generation.
Greenhouse gas emissions likely rose along with coal and natural gas-fired generation, despite wind output growing a little under 20%, and solar growth I estimate above 60% (~540 GWh).
Solar figures are necessarily estimates because none exists in IESO's reporting, as it is all embedded (as is, in all likelihood, a significant amount of wind production).
The cost of the additional solar generation in 2012 I estimate in the $100 million range.

The IESO will likely report a very small decrease in Ontario demand for electricity in 2012.  That will be true only because the IESO reports Ontario demand as the sum of generation that is on the IESO controlled grid plus imports - meaning the growth in embedded generators is not reflected in IESO figures for demand.

In summarizing 2011 the IESO claimed, "Ontario's wind generators are playing an increasingly important role in meeting demand for electricity."  The passage of time makes that statement increasingly nonsensical.  Again in 2012, net exports rose - and again, the rise was similar to the rise in wind generation.  Net exports spiked during the dramatic drop in Ontario's demand in 2008/09, but the trend since 2006 is evident.

The increase in wind output in 2012 was primarily from 3 generating stations with only partial reporting in 2011: Enbridge's Comber facility, Brookfield's Greenwich, and IPC's Pointe-Aux-Roches.  Assmuming Brookfield's Greenwich project received the same $135/MWh rate as the feed-in tariff (FIT) contracts of the other 2 projects, the ~700 GWh of increased 2012 production at these facilities, constructed during a period of surplus, cost Ontarian's $80 million more than the market valued it at (~$20.19).

All additional generation capacity added during a period of surplus has additional costs to the bulk of Ontario's ratepayers, as it serves to lower the Hourly Ontario Energy Price (HOEP) while driving up the global adjustment charges that recover the other costs of generation (note [3] comments on December's global adjustment estimates).

The average Hourly Ontario Energy Price in 2012 was ~$24.11/MWh, down $7.35, or 23%, from $31.46 in 2011.  For Ontario's ratepayers, the decrease in the HOEP was more than offset by the rise in the global adjustment mechanism - which I estimate added ~49.82/MWh to the commodity charge on the bills of class B customers (up ~$9.64 from 2011), and an average of $30.64/MWh to the bills of Class A customers (Ontario's largest users - up from ~$23.96).  Export customers don't pay a global adjustment charge, so they did realize cheaper prices in 2012.

Aside from the industrial wind facilities I noted experiencing their first full year of hourly reporting in the IESO system, the only new generators in the IESO's 2012 data are the 393MW York Energy Centre and 1500MW of nuclear in the return of newly refurbished Bruce A nuclear units 1 and 2.  The impact of the Bruce units remains to be experienced, as they returned late in the year.  It is notable the 2 units should produce over 10TWh annually, but due to the attributes of the technology, it is unlikely that generation will replace 2012's 4.3TWh of coal-fired generation.

In 2012 the total cost of all generation to all customers I estimate as little changed from 2011, at approximately $66/MWh [2].  Segments of the consumer market saw bigger swings because of the distribution of costs to different categories of customer - as export customers paid less, domestic customers must pay more.  The global adjustment mechanism recovers that full cost of generation from Ontario's ratepayers - the cost of paying suppliers $66/MWh to export power at ~$24/MWh rose to approximately $452 million in 2012 (from $341 in 2011 - see Note [1]).



Adding the increased losses in exporting to the increased costs of renewables I've estimated ~$280 million in costs.  These costs were largely cancelled out by reducing payments to Ontario's forgotten renewable generation - hydroelectric.  Ontario Power Generation (OPG) is the only generator in Ontario exposed to the HOEP rates through it's unregulared hydro division, with the estimates for all hydroelectric generation being pulled down by the reduced payments for OPG's hydro output.

The average price for the bulk of Ontarians will be closer to $74/MWh.  In addition to the average cost of $66, the cost of subsidizing exports will add ~$5.30/MWh, and the cost to most ratepayers of the savings realized by Ontario's largest, Class A, consumers of electricity will add about ~$2.60/MWh.  Combined, the cost of dumping supply, and of offering lower rates to large users (introduced in 2011), now exceeds the amount of the debt retirement charge added to Ontarian's bills.

While the reduced payments to OPG helped hold the line on pricing for many individual Ontario ratepayers in 2012, accounting for the health of Ontario's public generator, OPG, and the management of Ontario's electricity sector debt, the outcome is not as appealing for Ontario's current and future taxpayers.
The Ontario Clean Energy Benefit continues to pull approximately $1 billion a year from taxpayers to subsidize electricity ratepayers - meanwhile the electricity ratepayers continue to pay approximately $1 billion a year to retire an otherwise neglected debt.

The debt is supposedly managed by the Ontario Electricity Finance Corporation (OEFC).

2012 did provide a first; it was the first year the OEFC didn't even bother with issuing an annual report.

POSTSCRIPT

Table from IESO release on 2012 data

The IESO issued their year-end summary on January 11th.

The figures they report for generation differ from my figures in this post (they have nuclear producing 0.4 TWh more, hydro 1.4TWh, gas 0.2 less and other is 0.1 less).  While some difference is not unexpected, the IESO figures, by the rules they have historically used, contain at least one error.

The proof of the error is complicated, but the recognition of the error is not.  The total generation the IESO is reporting, plus the imports they are reporting, exceeds the sum of the Ontario demand and exports (as they report them).  Put simply, the IESO summary indicates more supply than demand.

The IESO's monthly reporting has long defined demand by supply:

The IESO calculates Total Market Demand by summing all output from generators registered in the Market plus all scheduled imports to the province...

The IESO calculates Ontario Demand by subtracting exports from the Total Market Demand quantity 

Under these definitions it's clear demand cannot exceed supply.

The IESO is an exemplary governmental organization in sharing non-critical data, and provides weekly updates of text files reporting hours for demand, and import export schedules, back to market inception in 2002.  Summarizing the figuers in these files yields the same figures for demand, imports and exports as reported in the IESO's 2012 data summary news release.

It's important to note that calculating the supply from only the two text files (for demand and import/export) won't yield the same figure as totalling the supply from the Hourly Generator Output and Capability Report.  Ignoring relatively minor data issues, such as rounding, the IESO notes "The Hourly Generator Energy Output and Capability Report presents the Energy output and Capability of each generating facility in the IESO-administered energy market with a maximum output capability of 20 MW or greater."  This means that summarizing the data from the Hourly Output and Capability report (figures I report are from my capture and manipulation of data in these files) should yield a total supply that is lower than that calculated by subtracting imports from the total market demand (from the two text files noted earlier).  Reviewing the data for the past 5 years, and summing the generation totals from the IESO's 2012's data release, reveals that up until 2012 the calculated production does exceed the generation totals showed by the IESO.

2011's growth in what I've called "unreported generation" made sense to me as many new generators are increasing smaller than the 20MW capacity, and therefore the amount of "unreported generation" should be increasing.

The IESO's reported figures for 2012 are clearly wrong under the rules they have always used before, but that does not mean they are wrong - they may be communicating something different under new rules.

The additional 0.4 TWh of nuclear could be showing the 'deemed' generation that Ontario's ratepayers will pay for despite the production being curtailed; the 1.4 TWh added for hydro could be showing spillage, and output sent directly onto Quebec's grid.

However, under the IESO's definition if supply curtailment is to be considered suppy then it must also be considered demand.

Ontario's Long-Term Energy Plan calls for 7100MW of supply capacity to be provided by conservation.  Put bluntly, much of our supply is to come from curtailing demand.

It logically follows that much of our demand could come from curtailing supply.

NOTES:

[1] In estimating the costs of exporting, I've calculated the average price of all electricity in the total market (including imports and exports) and valued imports and exports hourly, at the HOEP rate - this model shows a profit on imports, and a loss on exports.  I have updated figures using a format I used in following up on an article Parker Gallant and I had in the Financial Post in July 2010.  The approach is very conservative in that it assumes without the export losses, the profits on imports would not be possible; looking only at losses on exports the 2012 caculation is $628 million.




 [2] I regularly update supply costs estimates on my data site

[3] The IESO's 2nd estimates of the global adjustment, for December, I have ignored - if they were taken seriously, January would have the cheapest commodity charge (Class B) since September of 2010.  I have used my estimate which is ~$85 million higher.  Over the course of the enitre year the difference is minimal - and if the global adjustment is adjusting for prior months, as it looks to have also done in November, it would not be surprising.
It is surprising the province attempts hourly pricing for it's smallest consumers without being able to properly calculate monthly charges for the global adjustment, which is 2/3rds of the commodity charge.