Wind Dies Down as Solar Growth Accelerates

Being cheap, and a blogger, when I went searching for a data source of European statistics to analyse electricity sector characteristics, my preferred source quickly became ENTSO-E

The European Network of Transmission System Operators for Electricity (ENTSO-E) provides data related to the operation of it's memeber TSOs, and much of the data is available via the data portal on their website.  ENTSO-E acknowledges the limitations of the TSO data, and it's members are to provide information to establish the 'representativity' of the received data to allow for the establishment of more reliable figures (see ENTSO-E .pdf on data issues).

The current data can be downloaded summarized by month, which I have done - and I have summarized that data on a 12-month running total basis.  The graph shows monthly figures as lines, with the scale on the left axis, and 12-month running totals as bars with the scale on the left (doc is here).  The data shows 12-month total wind production is now 2000GWh (2TWh) below the level of 36 months earlier, while solar production is up 15400 GWh at nearly 4 times the level of 36 months earlier - monthly solar production exceeded wind production in March, and the gap has continually widened since that time.

The data is so striking it is suspect.

I had previously checked ENTSO-E data for 2011 to a second source, the German AGEB, which seems to translate to "The Working Group on Energy Balances".  The final .pdf on this page provides figures that are close, although not exactly equal, to ENTSO-E's.
I recently saw a mid-year report from the Fraunhofer Institute for Solar Energy Systems (Franhofer ISE) which provided different figures for both wind and solar - but the solar figures were about 10% higher (for the first 6 months of 2012), while the wind figures are 100% higher than in the ENTSO-E reporting.  The cited source for the Fraunhofer ISE report is the European Energy Exchange (EEX).
The EEX has something called a "transparency" platform that requires €600 to acquire historical data.  For me that means the data is worthless, but it certainly raises some interesting questions about the value of data, and the commitment of institutions to meet their reporting obligations with an existing platform when another platform offers payment for the data.

The Fraunhofer ISE report, Electricity production from solar and wind in Germany in 2012, may have far different figures than ENTSO-E for 2012, but the figures for 2011's first half are actually slightly lower than the ENTSO-E figures.  It seems to me that Germany needs to look into why it's reporting is, to be blunt, bad (they might even consider an energy department at some point - currently the responsibilities are split between environmental, and commercial, ministries).

Regardless, the Fraunhofer ISE/EEX data also shows monthly solar production exceeding monthly wind production, although not until May, then continuing in June and July.

I also pulled the data for the same period for Spain; another country often cited in discussions on renewables.  That data does not show the suspect decline in wind apparent in the Germany data, but it does show, over the past 3 years, growth of about 30% for wind production, and 300% for solar production.
The figures are similar to Germany's figures if we substitute the ENTSO-E data with the Fraunhofer ISE data for the first 6 months of 2012.  The trend look fairly obvious in the two countries..

The wind has died down.  If it's anything like the local weather this week, the wind isn't likely to come up again until some time after the sun's power has died down.

July's Ontario Electricity Price Lowest Since 2010

I told you so.
The IESO posted the final Global Adjustment figures (GA)for July late yesterday: $421.7 million.

That is $177.3 million less than their preliminary estimate of $599 million, but only $38.4 million less than mine.
With my estimates atop my podium, I'll try to reinforce some lessons using July's commodity pricing (class B) of  $67.10/MWh - which is based on an average market HOEP of $33.51, and the freshly released Class B GA of $33.59

• $67.10 is the lowest price commodity since September 2010.
• $33.51 is the highest HOEP figure since July 2011 

The paradox of the higher market (HOEP) rates accompanying the lowest overall commodity charges has been notable in Ontario for some time - and relates to high demand periods (July 2012 being the highest summer demand since at least 2007).
A quick overview of Ontario's production sources in a low-cost month:

• Nuclear produced 7,807,250 MWh, the highest summer output since August 2006.   
• Hydro production was low, but likely not as low as in July 2010.
• Wind production was normal for July - meaning it had it's least productive month of the year, by far
• Solar production continues to go entirely unreported, but the monthly costs of solar contracts likely far exceeded the costs of wind contracts
• Coal-fired generation was as high as it has been since the last July (and before that the summer of 2010)
• Natural gas-fired generation was higher than ever, ~17% higher than the summer of 2010
• Imports were the highest they have been since July of 2008

By calculating a rate as the total value of all sales (including exports) at the market rate, adding the $421.7 million global adjustment, and dividing by the total market demand, the average rate for electricity in the market was $61.97 in July - the lowest price since September 2010, but only about $4.13 less than April's $66.10.  On a monthly basis $1.80 - $2.20/MWh of this I estimate as being due to the OPA's consumer demand management programs (CDM).

The difference in the class B rate was much greater than that, at $10.83.  This means that ~40% of the lower price in July is explained by the cost of procuring supply.  Some of the other 60% is attributable to the shifting of costs from large users to smaller ones via the Class A global adjustment mechanism (in April the cost to class B was ~2.95/MWh, in July only ~$1.46); and much of the remainder is the cost to Ontarians of dumping exports (~8.25/MWh in April, and ~$3.35 in July).

All other things being equal, the higher the HOEP, market price, the lower the cost to Ontario's consumers of subsidizing export, and large class A, consumers.  

This is why the higher HOEP rate lowers the commodity rate.

The other 40% of the difference in July's lower commodity price is attributable to lower procurement costs.  These are explained by the capacity payments made to natural gas-fired, and coal-fired generators (explained here).  Ontario's electricity market (commodity only) is approximately $10 billion a year.  Of that, my estimates indicate that approximately $1.8 billion is charged regardless of production levels:

• $308 million for coal units
• $934 million for natural gas units (other gas units are paid over $100/MWh, but must produce)
• $147 million (Other - primarily Lennox GS)
• $320 million OPA (primarily conservation)

For coal, natural gas, and Other/Lennox, the contracts, despite being hidden, are clearly structured so the actual use is generally the cost of the fuel: this means that over the past 7 years the system has been structured so that the more fossil fuels are used in generation, the cheaper the price to consumers will be.

The cheaper July price is therefore not only due to higher market prices (bizarrely), it's also due to the highest production of the year for coal, and the highest ever from natural gas.

Higher July demand also spreads the monthly base fees of $145 million over a greater denominator.

The capacity payments/net revenue requirements, have the additional effect that the marginal cost of production is simply the fuel component for gas and coal producers, reducing the market price.

These contracts are not only responsible for the 40% of the reduction being explained in July by lower procurement costs, but much of the class A and export costs transferred onto consumers is due to low HOEP rates accentuated by capacity payments at all times.

The Class A structure, Time-of-Use (TOU) pricing, and many of the OPA's CDM programs are directed at reducing peak demand, with the explanation that it's cheaper to remove the demand than to build generation to support it.

The ~$1.4 billion in annual capacity payments appear to be recovered from consumers equally across all months, regardless of demand volumes, which I've demonstrated has the outcome of making power cheaper during peak demand periods.

These policies work against each other.

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Note:  In response to this title it was communicated to me that households where not getting lower pricing, and in fact the prices they pay were not only 10% higher, but is now noted by Statistics Canada that electricity prices were up 3.7% across the country; "Increases in electricity prices in Ontario were the biggest factor in this rise.

An explanation is probably in order.
Regulated Pricing Plans are set in advance of 6 month periods in Ontario, based on forecast of what the actual pricing will be.  The current period is now half way completed, with each month well below the forecast rate.
The difference should be entering a variance account, which would then benefit RPP consumers when the next RPP pricing occurs (November).

I am not confident the RPP pricing process is reliable, and I am not confident there will not be a further transfer of cost from business owners to residential customers.

I do estimate a variety of prices in my monthly reporting, on my data site, illustrate the difference between class B pricing (which I refer to as "commercial") and the RPP rates ("residential").  

Fact-Checking Ministry of Energy Statement Shows We aren't at 1994 yet

Today the Ontario government posted a news release; "Ontario's Electricity System Can Take the Heat."  There's a couple of 'facts' included in it that should be examined more closely - not only to verify what is said in the release, but to show why wind production looks to be intentionally de-emphasized.

In July, Ontario's electricity system experienced the highest monthly summer demand since August 2007.

The communication states "summer" because January 2007, 2008 and 2009 were all higher - the IESO figures also indicate July 2006 was the last summer month with greater demand, but that's probably a deficiency in their inability to report on solar generation coupled with their inability to report actual metered demand.

Looking at the monthly generation chart for July 2007 (page 17 here), generation from coal and natural gas ("other" in the chart) are approximately 3.45TWh, or roughly 200GWh less than the generation from coal and gas-fired generation in July 2012.
We seem to have burned more fossil fuels generating electricity in July 2012 than we did in 2007

Come a long way?

Since 2003, Ontario has brought more than 10,000 megawatts of new and refurbished clean energy online from sources like wind, solar and bio-energy. That's enough power to meet the needs of more than 2 million homes during the hot summer months.

Also sources exactly like natural gas and nuclear - primarily natural gas for capacity, and most significantly to reducing greenhouse gas emissions, nuclear.
Added (approximately) were 5600MW of natural gas-fired capacity, 1500MW of nuclear capacity,  500MW of solar and 2000MW of wind capacity.  Subtracted (not mentioned) has been ~4300MW of coal-fired generation.



More pertinent to the reign of the Liberal government are changes since 2005, as the 1500MW of nuclear was initiated before they took power, as was some of the natural gas build and the elimination of the Lakeview Generating station (coal).    Roughly 5000MW of gas, 500MW of solar, 2000MW of wind on the added side (7500MW) and 3200MW of coal-fired generation removed.  2005 was the peak year, and the peak July.  Compared to July 2005, Ontario demand was down 637GWh while production from coal and gas-fired generators was down ~454GWh.  There is some indication reducing demand reduces the use of the dispatchable generation coal and gas provide, but no indication anything else is doing so.

The 2 million homes statement is a bit of a mystery, but it's clear the 7100MW of nuclear and gas capacity are the ones actually powering homes.  While solar is certainly useful in reducing peak demand in July, it is also certainly useless in meeting peak demand in January.

Wind is frequently useless in July, and less frequently, but still at times useless, in January.

The only place the word "wind" appears in the release is in claiming 10,000MW of added overall capacity - of which wind capacity is 20%.

The Quick Facts section of the government's news release states:

Eliminating coal-fired electricity in Ontario is the single largest greenhouse gas reduction measure in North America.

The numbers show natural gas is replacing coal.  This is not going to reduce greenhouse gases anywhere near the extent of Southern Power's construction of Vogtle Units 3 and 4.  In the atmospheric short-term (100 years) the additional methane from the natural gas industry is unlikely to change the greenhouse gas impact, in switching from coal to gas, much at all.

In 2011, more than 80 per cent of the power generated in Ontario came from clean sources of energy such as water, nuclear and renewables.

Water AND renewables?

In 1994, water and nuclear comprised  86% of all Ontario's generation ... before that era's environmentalists started the switch to coal.

Vampire Turbines In July

I recently read an entry on Wayne Gulden's Wind Farm Realties website reviewing some figures for the Vestas V82 - 1.65MW capacity industrial wind turbine. The statement that stuck with me was:

... when the wind doesn’t get above 3.5 m/s – typically there’s a MINUS 50kw of production. This is power that must be supplied from the grid just to keep the turbine in business. And 50kw seems to be what the turbine uses to stay alive in good weather. In the winter it gets slightly higher – the highest negative numbers were in the 80 kw range.

I decided to investigate the performance of an industrial wind turbine project in Ontario comprised of 110 of the Vestas V82 turbines; Enbridge's Underwood turbines in Bruce County.

110 turbines potentially each drawing 50kW means that at times when all Enbridge's turbines are still, the draw would be ~5.5MW.  In the parlance of the Ministry of Energy, and the renewables lobby, a draw of 5.5 MW is enough to prevent power being provided to over 4000 homes.

In Ontario, we know that wind is least productive in July - so the topic of how much "parasitic" load is present when turbines are unproductive is particularly relevant here.

The turbines' manufacturer, Vestas, produced a Life cycle assessment of the V82-1.65 MW (the LCA) showing "energy balance" is achieved in 7.2 months of production.  The "energy balance" is how long the turbine will take to generate the amount of energy consumed in production and disposal.

The 3392 MWh they claim cannot include the consumption of electricity required for the operation of the turbine, as 50kW (the minimum cited in the Wind Farm Realities article) equates with 8766 MWh over 20 years.  Presumably most of that amount is generated by the turbine itself, but the turbine is frequently idle, so some of that amount should have been in the LCA.

The LCA based it's conclusions, in part, on a site offering an annual capacity factor of 39% (claiming 41% from tubine less 5% loss in cables and transformer).  This is not true for turbine performance in Ontario; Enbridge's Industrial wind project in Bruce County (Underwood in IESO reporting), has had an average annual capacity factor averaging ~29%.  If we added 5.5MW at all times (for the parasitic load), the turbines would be producing at 32% capacity factor (and consuming close to 10% of that).
It's not surprising the 39% figure is not reached in Ontario, as the Wind Farm Realities post showed it wasn't reached at any location checked.

Actual output being 25% below the levels Vestas used as typical, 'energy balance' is not achieved in 7.2 months of operation - and it seems unlikely Vestas accounted for the need to externally power the turbines intermittently throughout the 20-year life of a turbine.

The amount of electricity consumed by Enbridge's Underwood turbines can be estimated from how frequently the 110 turbines, collectively, report no output.[1]  Not surprisingly, the graph of the monthly occurrence of hours with no output is the inverse of graphing the output, with  July generally showing the highest percentage of hours with no output, at ~30% (the annual average is approximately 16.9%).  Assuming the average draw from the grid during those hours is half of the maximum draw, parasitic consumption adds ~700MWh of energy consumption over the life of the turbine.  Adding that to the LCA from the Vestas study, the total would be ~4100MWh, which is slightly under the average annual production from an Underwood turbine.  The "energy balance" figure should therefor be close to 12 months.

A far greater revision is required for Vestas' LCA claim that "wind power plant emits appr. 6.6 g CO2 per produced kWh."

The LCA numbers indicate Vestas underestimates the figures for emissions generated in manufacturing, as the electricity used in the manufacturing of the turbine is argued to be quite clean, comprised of 70% hydro, 5% wind, and 25% the average of the European grid.  The claims are suspect, as even if Vestas procured hydro, it almost surely displaced that hydro production from other usage.  In Ontario, the largest customers are now offered rates that could only be met with the public generator's historic hydroelectric facilities; according to Vestas those large users would have no emissions, while residential consumers, deprived of the hydro production (which they own), must have escalating emissions.

If Vestas could generate the additional hydro to power wind turbine production, they'd probably be focused on expanding their hydro business instead of contracting their wind turbine business.

Assuming all power used in constructing a turbine produced average emissions, for Denmark's generation, the emissions would be ~ 19 g CO2 per produced kWh.    While almost triple the figure provide by Vestas, that's still attractive, but it's also still incomplete.

Reviewing weekly data for some peak demand periods since the Underwood Wind Generation turbines became operational, it is clear the turbines cannot replace any capacity, and, in fact, may be drawing power during the system's peak demand periods.  For instance, the afternoons of July 4-6th all experienced periods where the output of Underwood reported as 0.

The poor performance of industrial wind turbines during Ontario's summer is well known, but there are also week periods of production in the winter.  Over the past couple of years, the least productive winter week for wind (treating weeks as Wednesday - Tuesday) is also one of the highest average demand weeks in Ontario.

The review of data for Enbridge's project therefore ends up emphasizing the same issues as many other reviews of many other data sources.

While wind produces very little in terms of emissions, it also produces very little in terms of value.  Unable to displace other capacity, it is inappropriate to measure the costs of wind generation without accounting for the negative impact it has on other generators.

[1]  The IESO reporting of hourly output for wind generators does not show any negatives.  It is assumed the meters don't measure the negative draw (ie. meters don't go backwards).  Because I am using a 'parasitic' consumption for the 110 V82 turbines as 5.5 MW, a report of 0MW from the IESO indicates between 0 and 6 MW are being generated by the turbines. The calculation of 8% of all parasitic supply coming from the grid assumes an even distribution from 0-5.5 MW (ie. half).

July Electricity Stats: Mild Demand Growth and double-digit inflation

Data from the Independent Electric System Operator (IESO) indicates July 2012 saw mild demand growth, over July 2011, of 1.2%, while prices look set to rise ~13% for Ontario's businesses.  Regulated price plans had already been set 10% higher. The Hourly Ontario Energy Price (HOEP), with a weighted average of ~$33.65/MWh is 8% lower than in July 2011, leading to the likelihood exports were sold at a lower rate.

These figures, and others, are shown in the preliminary monthly report now posted on the Cold Air Data Site (the weekly report, and the monthly supply cost estimates, are also updated)

The rise in price (from $64.97 to the preliminary estimate of $73.93/MWh) is far higher than my estimates indicate, and far outside the normal variance.  At $599 million, the global adjustment is shown as increasing $207 million over July 2011, while the amount recovered by sales at the HOEP rates dropped about $43 million.  This is extreme even in 2012's Ontario.

I have fought the growing trend to refer to the global adjustment as a tax, but it is becoming murkier each day; as lawsuits are suddenly settled and revelations indicate net revenue requirements for natural gas generators have been drastically increased, it is increasingly desirable to have better disclosure on how the GA pot is being calculated, and allocated.


July did see declining hydroelectric production each week, which was compensated for by increased nuclear production, and far higher production from natural gas sourced generators - generators we have been led to believe we pay for all months to be available, and only for, essentially, the costs of fuel when used.  That appears to be untrue as gas, particularly the net revenue requirements guarantee, is increasingly indicated to be the main driver of cost inflation in Ontario, both when used to generate electricity, and when it is idle.

Due to the lack of accounting in the global adjustment (most costs are simply classified as "OPA") it is difficult to prove where the cost inflation comes from.

My estimation of monthly costs has had solar production having a greater impact on bills than wind production (which is fairly well known) - and there are no production figures for solar anywhere.  However, the OPA's most recent progress report on supply gives a figure on capacity that makes it hard to envisage solar driving up the July price to the extent the GA does - and wind produces less in July than any month of the year, so that is also not the cause.

If you are a small business in Ontario, your rates are going up, but the explanation of why remains very elusive.