The High Cost Impact of Wind and Solar on Ontario Residential Electricity Bills

A Review of the

Environmental Defence Canada Report

Your Home Electricity Bill

Kent Hawkins

July 1, 2014

Abstract

Abstract

The Environmental Defence Canada report (EDC) can safely be ignored as making a contribution to the understanding of the impact of wind and solar photovoltaic electricity generation plants on Ontario’s residential electricity bills. The report fails to account for the full costs of wind and solar photovoltaic implementation and integration, which include many costs not required without their presence. Further the EDC report examines only the period from 2014-2024, ignoring the substantial impact of prior wind plant implementations.

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Executive Summary Wind and solar have added substantially to the costs of generating electricity in Ontario, well beyond the narrowly defined costs of the generation plants alone. The additional costs are unique to wind and solar and should be attributed to them as opposed to being absorbed elsewhere, for example in the costs of the generation plants that have to support their highly variable generation in the short term of minutes or less and their unreliable nature in the longer terms of hours and days. The substantial extra costs unique to wind and solar are due to:

Duplicate generation requirements because of the non-dispatchable nature of wind and solar.

Longer than realistic lifetime projections for wind turbines in particular.

Higher than realistic load factors, (also referred to as capacity factors), especially in later years.

Extensive grid additions, not otherwise required, to serve the highly dispersed energy source of wind and solar, often remote from load centres.

The result is a total cost of about 3-4 times that of the wind and solar plants alone. This illustrates how the total costs of these plants can have a much more significant impact on electricity prices than a superficial analysis shows and can explain the very high increases in electricity prices already experienced and projected. During the period 2014-2024 the total costs for wind and solar are about $31 billion in real 2012 dollar terms over and above that required to meet demand from reliable, dispatchable generation technologies. Any environmental benefits from wind and solar are highly questionable, removing the main rationale for their inclusion in Ontario’s electricity supply mix. To assist in the funding of this, prices charged for the electricity used portion of residential bills have increased 44% per cent by 2014, and will increase to 85 per cent by 2024, compared to the period in 2010 before the implementation of smart meters and time of use charges. The residential user burden of this is calculated to be $17 billion in real 2012 dollar terms. Further, it is suggested that the Ontario’s 2013 Long Term Energy Plan (LTEP) understates the electricity generation costs for the period 2014-2024. As a result, the average monthly residential 2024 electricity bill will be at least $218, in nominal dollar terms, versus the projected $191 by the Ontario Government and a report by Environmental Defence Canada. There is a notable cost reduction in total projected generation costs between the 2010 and 2013 versions of the LTEP. For the period 2014-2024 inclusive this is approximately $44 billion in real 2012 dollars out of a total of $263 billion for the total electricity service in the 2010 LTEP. This alone should raise questions. The factors driving this reduction are:

Wind plant costs shown in the LTEP are unrealistically low by about $8 billion.

The assumption of an average 8 per cent decrease in residential demand over the period 2014-2024 in determining costs, representing about $12 billion, which is not a prudent planning assumption.

Other questionable decreases in total electricity system costs between the 2010 and 2013, the details of which will not be further dealt with here.

It is important to note that the Ontario Ministry of the Environment and the Ontario Medical Association report that most of Ontario’s smog comes from massive sources in the United States Midwest, and the Fraser Institute reports that Ontario’s coal plants contributed less than one-tenth of one percent of Ontario’s smog conditions. Further it should be noted that considerable pollution is produced by cars and trucks on our highways and other energy uses outside of electricity generation. Placing the blame for this, and burden of offsetting it, on Ontario’s relatively low emissions electricity system is not warranted, nor wise.

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Introduction

Environmental Defence Canada (EDC) commissioned Power Advisory LLC1 to evaluate the impact of renewable energy on electricity bills, as well as that of improved energy efficiency. The results are in the report “Your Home Electricity Bill – A study on the costs in Ontario released in March 2014.”2 Having analyzed other reports supporting the implementation of “new” renewable energy generation3 (that is new to the electricity system versus the traditional hydro-electricity), I find they consistently fall into the questionable category for a number of reasons. This one certainly does. You will see as the following analysis proceeds it becomes somewhat critical of the Ontario Ministry of Energy/Ontario Power Authority’s (MOE/OPA) Long Term Energy Plan (LTEP) as well. The issues surrounding any analysis of these matters are complex, so this review is necessarily not exhaustive or precise in its approach, but it is sufficiently indicative to allow a better appreciation of their nature. This follows the concept that it is better to be approximately right than wrong with precision. As a minimum it should allow many to better understand the issues that need to be properly addressed. An example of a more rigorous approach would be the OPA Supply Mix Recommendation (2005) and Integrated Power System Plan, IPSP, (2006). These provided a very comprehensive analysis of Ontario’s electricity needs and plans. This transparent planning process was suspended in 2008 and new targets for renewable energy sources and conservation were mandated by the Minister of Energy. What followed were a series of directives from the Minister of Energy4 and the Ontario Green Energy Act in 2009, the 2010 LTEP and in 2013 its current version, apparently without the comprehensive planning process provided by the IPSP.5 This review will primarily address wind and solar photovoltaic, and the latter will simply be referred to as solar. Bioenergy falls into a different category of renewable, which will be touched on. However, none of these is really environmentally friendly, contrary to claims by many in government, environmental organizations, academia and the media. The main difference in the non-hydro renewable group is that bio-energy is dispatchable and wind and solar are not. In simple terms dispatchable means that it can reliably be called on by the electricity system operator as needed, in Ontario’s case the Independent Electricity System Operator (IESO). Wind and solar are available only when nature supplies the fuel, that is sunshine and wind, and are therefore non-dispatchable. As well, when they are producing their output is usually highly variable, in the short term period of minutes, and unreliable in terms of hours or days. Electricity systems and users depend on a steady supply of electricity from reliable generation resources. Without this our society could not be sustained in its present form as we would lose much of our vital services, including health, medical, emergency services, transportation, food and water supply, education and business operations. So, there are considerable consequences to introducing non-dispatchable generation resources into an electricity system and these have typically not been properly acknowledged or addressed in almost all published reports. One of the consequences is unnecessarily higher electricity rates for residential, commercial and industrial users. This matter is

Residential consumers should not take comfort from claims that wind and solar will not have a significant impact on electricity bills, because the issue is not the costs of the renewable energy plants by themselves, but of all the otherwise unnecessary associated costs directly attributed to renewables. When these are properly identified the impact on electricity bills is considerable.

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complicated somewhat by taxation and economic policy considerations that may remove some of the costs from electricity rates, but typically not all costs. Other consequences will be described, or at least touched on. The EDC summarizes its report as follows:

“The study shows that renewable energy accounts for a relatively small part of residential electricity bills. It also shows that the anticipated reduction in home [electrical] energy use can offset a large part of the projected increase in electricity prices...”

Residential consumers should not take comfort from this because the issue is not the costs of the renewable energy plant by themselves, but of all the otherwise unnecessary associated costs directly attributed to renewables. When these are properly identified then the impact on electricity bills is seen as considerable. Also it will be argued that an assumed reduction in total home electrical energy use through conservation should not be a factor in prudent planning. Advanced societies need copious quantities of energy in order to sustain themselves and continue to develop. One of the reasons is the creation of increasing complexity as development progresses. Translate that into the growing energy needs of developing and undeveloped societies and the result is a global requirement for substantial, reliable energy availability, especially electricity. A good source for more information is in the writings of Thomas Homer-Dixon the CIGI Chair of Global Systems at the Balsillie School of International Affairs in Waterloo, Canada. At the University of Waterloo, he is Director of the Waterloo Institute for Complexity and Innovation and Professor in the School of Environment, Enterprise, and Development.6 Electricity will play an increasingly important role in final energy delivery to users, for example in the electrification of transportation, and in providing increased fresh water supplies by desalination and transport (pumping) of water to needed areas. All these will require substantial increases in electricity supply world-wide. The concept of reducing energy use is not consistent with the continued security of our species, and relying on this in planning is not realistic. That said there is merit in eliminating waste and frivolous use. The important issue here is cause and effect, and unfortunately simple explanations will not suffice. One thing is clear: electricity bills in Ontario are showing considerable increases since the introduction of wind and solar, and will likely continue to do so with the aggressive implementation plans for these resources for the next 10-15 years. Because of the complexity in establishing cause and effect here, a number of points of view on the subject will be provided all indicating that it is reasonable to conclude that wind and solar are the cause. So, this review is structured as follows:

1. Comments on the questionable introductory comments of the EDC report, which appear designed to position the reader to accept the report’s messages.

2. The first step in evaluating the impact of wind and solar is a review of overall electricity prices to show how Ontario compares to other North American areas and provinces versus that shown in the EDC report. Electricity prices in Europe will also be reviewed.

3. The realities of generation costs are explained as background to understanding and evaluating the EDC report and the LTEP.

4. Real wind costs are shown and a suggestion as to how these are provided for in the LTEP as opposed to being fully accounted for in the non-hydro renewables category.

5. The impact of the introduction of time of use charges for residential electricity as implemented by the Ontario Government in 2010. This looks specifically at the actual electricity charges within the bill to illustrate how this affects the total.

6. A review of the projected increases in residential electricity bills by the LTEP and the EDC report. 7. An analysis of the total costs of providing electricity to 2024, with and without wind and solar. 8. Commentaries on conservation and its place in planning, and a realistic assessment of bioenergy as

renewable are provided. Other consequences of wind and solar are described in Appendix A.

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9. The final section is a general discussion about residential electricity pricing trends in Ontario since 1972 and projects a new residential electricity bill forecast for 2024 showing notably higher prices than that provided by the LTEP and the EDC.

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Questionable Introductory Comments in EDC Report Have these been used to set up the reader to accept that the ill-advised, major changes that are claimed necessary to address societal matters, and that residential electricity users should accept carrying some of the burden? The EDC report does go on to represent that the cost impact has been exaggerated in any event, which is not the case. As an example, the impact on human health will be addressed because of its significant stage-setting nature. The EDC report over-emphasizes the role of the Ontario electricity system in air pollution, specifically highlighting it this with the comment:

“The good news is Ontario’s grid is now coal-free, and the number of smog days has dropped from a record 53 to just two in 2013, which is better for our lungs and the environment.”

This was prefaced by:

"Coal-fired electricity used to cost Ontario an estimated $4.4 billion in health care, environmental and financial impacts" (emphasis added as almost all of these coal plants are outside of Ontario and are still a problem – consequently there are very little savings and “used to” is not a valid statement.)

This appears to be making a direct causal link between Ontario’s coal plant closures and smog levels, but this is not a supportable position. What is not mentioned for example is that 2012 had 30 smog advisory days. Although there

does appear to be a slight downward trend amid considerable variations from year to year, since 2003 which had 20 smog advisory days. The question as to what has caused this has not been answered in the EDC report, and is likely due to other major highly variable factors year over year, perhaps caused by changes in atmospherics and weather conditions

for example. In summary, the EDC report does not come close to accurately describing the historical record of this important issue or explaining it properly. According to Air Quality Ontario, the same source used in the EDC report, most of Ontario’s smog, and most episodes of elevated smog in Ontario come from massive sources in the U. S. Midwest.7 Another large portion comes from activities outside of electricity, such as automobiles and trucks on our roads and the commercial/industrial sector. The reality is the almost all the coal-fired electricity impact comes from US coal generation plants and these are still producing. The only “good news” in this respect is that the US is shifting away from coal to gas for electricity generation, but this process will take some time. The Ontario Medical Association also has commented on this as follows8:

“It is on hot summer days when air masses stagnate that smog episodes occur, with smog blanketing large areas of Ontario, both urban and rural, for several days at a time. Levels are usually highest in the afternoon and early evening. Although pollutants are produced by local emission sources, trans-boundary transport from Ohio and other midwestern U.S. states contributes significantly (more than 50 per cent) to ozone, particulate and acid aerosol levels in southwestern Ontario. Levels are highest in the Windsor-Quebec corridor, and along the Lake Huron shoreline.”

There are introductory comments on historical events that attempt to summarize fairly complex considerations, and should not be taken at face value.

Most episodes of elevated smog in Ontario come from massive sources in the U. S. Midwest.

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and,

“In the regions under study (Ontario, Eastern Canada, Ohio Valley/Great Lakes, and U.S. Northeast), more than 96 per cent of the coal-fired electric stations are located in the United States.”

The closure of Ontario’s coal plants, may have contributed somewhat to the mitigation of Ontario’s smog conditions, (less than one-tenth of one percent, according to the Fraser Institute9), but not to the extent that justifies major increases to our electricity bills. Later the minimal, if any, contribution that wind and solar plants make to reducing emissions will be discussed. Other introductory comments under the guise of “a little history” include:

The 2003 “massive” blackout as demonstrating the fragility of Ontario’s electricity system. This is a very narrow account of this event and should be discounted.

The heavy use of tax subsidies lead to “chronic” underinvestment in Ontario’s electricity infrastructure - another very narrow account of a complex issue.

Representing wind and solar as “the new kids on the block”, implying that they are being unfairly treated. This ignores the point that they have an abundance of ill-advised influential and powerful protectors, who are supporting and welcoming them. In any event, wind is a very old technology and has been used for hundreds of years when and where more useful, extensive and reliable energy sources were not available.

Proper treatment of these deserves considerable more representation than that provided. It is possible to conclude that these introductory comments serve to condition the reader to be more accepting of the messages in the report.

Ontario’s coal plants contributed less than one-tenth of one percent to Ontario’s smog conditions.

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Residential Electricity Bills and Overall Prices As a first step in analyzing residential electricity bills, overall electricity prices will be examined. These are obtained by dividing the total electricity bill, typically excluding sales taxes, by the kilowatt-hours (kWh) used, and this is often used as a benchmark for comparisons between jurisdictions. Importantly it includes the delivery costs. In the examples provided, reported bills and prices are based on an average user at either 750 or 800 kWh per month. Later, there will be a discussion of the increase in actual rates charged for the electricity portion of the Ontario residential electricity bill, and its part in affecting the total. To avoid confusion these two terms will be used to differentiate these two measures of electricity costs. The EDC report’s Figure 2 suggests that Ontarians should be reassured by the fact that in 2013 they were in the middle of the range of residential electricity prices for a selection of North American cities. This is based on some

questionable data and ignores trends. In 2009 Ontario ranked 13th highest out of 22, and by 2013, Ontario had climbed to the 6th highest place, and not the middle of the group as shown by the EDC report’s Figure 2. The reason for the difference is that the Hydro Quebec source contains some questionable data, especially for Ontario in 2013.

The Hydro Quebec calculations have produced some very odd anomalies. For example it shows that Alberta prices increased by over 60% between 2010 and 2011, a very unlikely event, and not consistent with other sources. For Ontario the prices are reduced by 6-8 percent between 2012 and 2013, also not consistent with other sources as shown in Table 1. Otherwise the Hydro Quebec data is fairly reasonable. Table 1 – Comparison between Various Sources of 2013 Residential Electricity Prices for Ontario

Source 2013 Residential Electricity Rates

(cents/kWh) Comments

Hydro Quebec10 (used in the EDC report)

Toronto 12.5 Ottawa 12.4

OPA11 15.3

Ontario Hydro12 14.8

Manitoba Hydro13 Toronto 13.7 15.7 cents excluding OCEB?

Alberta Government14 (based on Manitoba Hydro data)

14.9

My Electricity Bill (as an example) 15.0 Average monthly usage over four years was 687 kWh

The Manitoba Hydro calculation can be explained if Manitoba Hydro perhaps included the Ontario Clean Energy Benefit (OCEB) of $15. Adding this back produces ($103+$15)/750 = 11,800 (cents)/750 = 15.7 cents. It is reasonable to ignore the Quebec Hydro electricity prices for Ontario in 2013 and their use in the EDC report. So Ontarians are not as well-off as represented. This positions us to look at an analysis by the Alberta provincial government comparing the electricity prices by province from 2002 to 2012 in Figure 1, which shows similar results

In 2009 Ontario ranked 13th highest out of 22 North American cities in residential electricity prices, and by 2013 had climbed to 6th place.

There are strong indications of a cause and effect relationship between high electricity prices and wind and solar implementations in Canadian provinces and in Europe.

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to Hydro Quebec data, except for the two anomalies discussed above. We can now see a persistent upward trend in Ontario.

Figure 1 – Trends in electricity prices by province showing average monthly bill.

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The overall electricity price can be determined for the monthly bill amount shown by dividing the monthly bill in cents by 750 as shown in Table 2. Ontario is about two-thirds of the difference between $100 and $120 yielding prices of 15.1 cents/kWh for 2012.16 P.E.I. is noteworthy and later the much higher implementation of wind and P.E.I.’s relationship with the Nova Scotia electricity system will be expanded on. Table 2 – Translates the Figure 1 Average Monthly Electricity Bills to Prices

Average Monthly Bill Price (cents/kWh)

$40 5.3

$60 8.0

$80 10.7

$100 13.3

$120 16.0

$140 18.7

The annual changes in prices should show a smoother transition in general and not be as variable year-over-year as some appear in Figure 1, for example Alberta in 2008 and Ontario in 2011. The apparent oscillations from year to year may be explained by the assumptions that had to be made, for example an assumed adaption to time of use rates in Ontario, in the determination of these averages. Also it should be remembered that electricity prices may be “capped” by governments and increased costs not recovered by rates made up by government subsidies from general tax revenues.

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Figure 2 shows much the same information as Figure 1 using the Quebec hydro data with the two major anomalies adjusted.

Figure 2 – Electricity Rates for selected Canadian cities provided by Hydro Quebec. As explained some apparent anomalies have been removed, especially for Ontario in 2013.

This further illustrates the persistent rise in Ontario’s rates since 2009 for the period data was available from Hydro Quebec. Note that time of use rates were implemented in Ontario in 2010. Many might not have been aware of the magnitude of the change as the billing periods changed from every three months to two months when time of use rates were introduced It is interesting to look at the ranking of provinces by wind and solar energy generation is shown in Table 3 and compare this to the history of rate increases. Table 3 – Percentage of Wind Penetration by Province

Province Wind and Solar Percentage of Total Generation

Other 201117 201218

PEI 100% 93.1%

New Brunswick 3% 6.7%

Saskatchewan 2% 3.5%

Alberta 1% 4.6%

Nova Scotia 1%? (4% including PEI19) 4.4% 3.2% in 201020

Ontario 0.9% 1.8% 4% in 201321

Quebec 0.2% 0.3%

BC 0% 0%

Newfoundland 0% 0.24%

Manitoba 0% 1.2%

Solar is not a major factor in this table.

6.00

8.00

10.00

12.00

14.00

16.00

18.00

2009 2010 2011 2012 2013

Ce

nts

/kW

h

Charlottetown

Halifax

Calgary

Edmonton

Toronto

Ottawa

Moncton

St John's

Regina

Vancouver

Winnipeg

Montreal

By 2013 Ontario’s average residential electricity bills have increased over 50 per cent since 2002, including 30-35 per cent after the introduction of time of use rates in 2010.

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The following trends emerge from Fig 2 and Table 3.

Alberta, Ontario, Nova Scotia and Saskatchewan are leaders in wind and solar implementations and show notable upward trends in residential electricity prices since 2009. PEI is reported as being very tightly coupled with Nova Scotia and exports most of its wind production to Nova Scotia. Note the trend in PEI prices in Figure 1.

Quebec, BC and Manitoba have very small wind implementations, large hydro resources and enjoy significantly lower prices.

Notably New Brunswick has combined wind presence with level electricity prices. Is the explanation in tax policy?

Can it be convincingly argued that wind and solar do not have a significant impact on electricity prices? Admittedly the converse is not established by this information either. Contrary to misinformed opinion, 3-4% wind penetration, in terms electricity produced, is approaching a limit in what can be easily handled within a jurisdiction. It is reported that the Ontario system operator, the IESO, says that it can handle up to 10,000 MW of renewable supply22. If this represents a wind and solar only, it is a penetration of about 11 per cent, which should be considered aggressive unless the IESO is assuming exporting much of this at very low prices23. It is interesting to note that the LTEP shows 4 per cent wind and solar penetration in 2013 and 14 per cent in 2025. This is not to say that lesser amounts are worthwhile. In Europe, Germany's neighbours are taking steps to block unwanted German wind and solar from swamping their electricity systems.24 Some commentators mistakenly point to wind in Denmark as fulfilling close to 30% of its energy demand.25 This is not true and is also misleading. It is not

true because wind production in Denmark represents this percentage of electrical energy produced, not total energy demand. Wind fulfills less than 1% of total energy demand. It is misleading because tiny Denmark exports most of its wind electricity production at very low rates to hydro-rich Norway and Sweden, and their combined hydro generation alone is 30 times

the size of Denmark’s total wind production. Even with this large hydro resource, Norway and Sweden reduce their imports of Danish wind in wet years when reservoirs are full.26 Denmark cannot alone absorb any more than a small fraction of its wind production. It is instructive to look at residential rates in Europe and others compared to Canada. Table 4 provides a sample. To assess the changes in rates, outside of overall trends, the relationship to the EU average is used. The euro to US dollar exchange rate was taken to be 1€ = 1.32 US$ in 2007 and 1.33 US$ in 2011.

Wind does not fulfill anything close to 30% of Denmark’s electricity demand.

Provinces with higher wind and solar implementations show a strong upward trend in residential electricity prices.

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Table 4 – Electricity Prices in Selected EU Countries in € cents/kWh (except as noted)

Country 2000 2005 2007 2011 2005 2007 2011

€ cents/kWh (including all taxes)

€ cents /kWh

Relative to the EU Average

EU Average

12.5 14.7 16.227 12.5 14.7 16.2

Countries with aggressive wind and solar implementations

Denmark 18.4 21.6 24.3 30.8 +69% +65% +89%

Germany 15.7 18.1 26.5 +23% +23% +63%

Spain 10.1 11.3 22.2 -21% -23% +37%

UK 10.1 8.8 13.2 15.4 -31% -10% -5%

Countries without Aggressive wind and solar implementations

France 11.6 11.7 14.1 -9% -20% -13%

Czech Rep.

4.9 7.2 8.7 15.9 -44% -41% -2%

Poland 10.4 11.9 15.0 -19% -19% -8%

Comparison with Canada in US cents per kWh and € cents/kWh in brackets

EU Average

25.928

Canada (no HST?)

9.2

(6.9)

Canada (with HST?)

10.4 (7.8)

Sources: EU prices for 2000-2007, European Commission29

, EU prices for 201130

, Canada31

The European Commission prices reported are not complete and the respective columns are left blank. It is not clear from the British Petroleum report if the 2011 prices include sales taxes, but it appears that they do not. The Canadian electricity price is shown with the two HST assumptions, and either way is approximately the expected difference in electricity prices compared to the overall European average. The following can be noted, first among those aggressively implementing wind and/or solar:

Denmark started aggressive wind implementation in the mid 1990s, and virtually stopped in 2003. It has persistently shown very high residential electricity prices since the turn of the century. Denmark has recently started again with a focus on off-shore, arguably because of competition from Chinese on-shore wind turbines.32 A contributor to Denmark’s high electricity prices are that the wind costs have to be absorbed internally, exports are at a large discount, and imports are at higher rates, a reality in jurisdictions that have embraced wind and solar and must export unwanted excess electricity.

Germany also started aggressive wind implementations in the mid 1990s and planned 5,000 MW of off-shore wind plants by 2010. The off-shore implementations did not materialize and only about 400 MW have been installed to date, but there are now about 2,000 MW under construction33. The need to step up off-shore is likely because of the Chinese threat to their wind turbine manufacturers, as in the case of Denmark. Germany also aggressively started implementing solar plants in 2009, contributing to the notable increase in electricity rates by 2011.

Spain's aggressive wind implementations started a few years later. It enjoyed electricity prices below the EU average through 2007, which may have been in part a reflection of tax/subsidization policies. By 2011 the prices had increased substantially to well above the EU average.

In Europe countries with aggressive wind and solar implementations have significantly higher electricity prices than the EU average.

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The UK is a relative late-comer, running about 10 years behind Denmark and Germany and has shown steady climbing from very favourable prices to approaching the EU average by 2011. The UK is a world leader in off-shore wind installations.

In the countries not aggressively implementing wind and/or solar:

France obtains about 80 per cent of its electricity from nuclear and shows a very enviable history of low electricity prices.

The Czech Republic is heavily dependent upon coal, but nuclear is a close second at 35 per cent of total production. Investment was made in refurbishment and uprating nuclear plants in 2005-2008. Plans are for additional nuclear capacity to 50 percent of total production by 2025. Electricity prices were extraordinarily low up to about 2007, and increased notably, but still below the EU average, by 2011.34

Poland is also heavily dependent upon coal and in 2013 obtained about 2 per cent of its electricity from wind and geothermal35. This represents less than half of Ontario’s production from wind and solar in 2013, but Poland had about three times Ontario’s wind capacity installed, which may explain the increase in electricity prices by 2011. Poland is more a late-comer to wind implementations than the UK for example, and may have been influenced by its joining the EU in 2004.

The above comments are not intended as arguments for coal or nuclear plants but to illustrate the costs of wind and solar. Also, it is important to remember among all considerations that advanced societies depend upon copious quantities of affordable, reliable electricity. Canada’s electricity price is shown for comparison purposes and, compared to the EU average, roughly represents the expected traditional relative energy costs between North America and Europe. The prices shown here are not precise due to the number of jurisdictions with differing policies and assumptions made in arriving at average prices. This information strongly indicates there is a cause and effect relationship between high electricity prices and wind and solar implementations in Canadian provinces and in Europe. The next section on generation costs will reinforce this.

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Generation Costs The EDC report appears to base its projections of residential electricity bills on the generation costs data provided in the LTEP. The LTEP appears to base its cost projections on payments made to generators of electricity by various means, including significant payments to suppliers of electricity for the difference between the market price and contracted prices. This appears in the LTEP as “Global Adjustment”. At the same time the LTEP provides unit cost rates by resource (for example dollars per MWh) and these values appear to cover the actual costs taking into account the implementation and operations costs of generation plants. The unit costs tend to reflect this. If the rates paid to generators of electricity do not allow the recovery of these costs, plus profit where applicable, investment in future generation plants could be discouraged, which is a serious matter for long term electricity supply. Alternatively this can be made up in other ways through various subsidies, including tax considerations. In any event when it comes to costs, the piper must eventually be paid. A recent example of this may be the Debt Retirement Charge that appears as a single line item on our electricity bills. Assuming the payments to generators are the unit costs shown and meet the condition of recovering implementation and operations costs, plus profit where applicable, this basis will be used in the following analysis. To repeat, generation costs are usually expressed in dollars per unit of electricity produced, referred to variously as generation unit costs (LTEP), levelized unit costs (IPSP), and levelized costs (DOE/EIA). As discussed, the LTEP shows generation unit costs by resource, that is, in dollars per MWh36. The important consideration in analyses is that such costs for non-dispatchable resources cannot be directly compared to those that are dispatchable, as previously explained. Dispatchable generation resources are those that can be called upon to reliably deliver power and energy, and most of Ontario’s generation plants, for example nuclear, gas, and hydro, can do this. Wind and solar plants are not dispatchable because their fuel supply is dependent upon wind and sunshine being available when needed 24 hours per day. Figures 3 and 4, taken from a Carnegie Mellon University paper by Jay Apt et al37 illustrate the non-dispatchable nature of wind and solar graphically.

The U.S. Department of Energy/Energy Information Administration has determined that the unit costs in dollars/MWh for non-dispatchable generation plants (wind and solar) cannot be directly compared to those that are dispatchable.

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Fig 3 – Example of wind plant production as described in the Apt et al paper’s Figure 8. Although the vertical axis does not indicate the full scale, it does show zero which is the important reference point. This illustrates the reason wind is not dispatchable.

Figure 4 – Example of solar plant production, illustrating the reason it is not dispatchable, from the above Apt et al paper, Figure 13.

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Admittedly, these two charts for wind and solar represent small samples. However, they do illustrate the typical production characteristics of wind and solar. There will also be periods of little or no production, lasting hours and

days. On the subject of reliability, note that solar in the first four hours solar exhibits greater reliability than later in the day and wind at any time. However solar is not available at night. The change to highly variable production was due to passing clouds. Directly comparing wind and solar with other reliable generation technologies is one area where analyses go very wrong, and the LTEP appears to make this fundamental mistake in the way this is represented at least. This alone can render important areas of its analysis invalid, or

other analyses dependent on the LTEP information. Later it will be shown how the LTEP may have accounted for this. In the US, the Department of the Energy’s Energy Information Agency, (DOE/EIA) has recently corrected this in their reporting as follows:

“The duty cycle for intermittent renewable resources, wind and solar, is not operator controlled, [not dispatchable] ... and so will not necessarily correspond to operator dispatched duty cycles. As a result, their levelized costs are not directly comparable to those for other technologies (even where the average annual capacity factor may be similar) and therefore are shown in separate sections within each of the tables.”38 (emphasis added)

In order to make comparisons a number of considerations are involved for non-dispatchable generators, including:

Non-dispatchable resources must have dedicated duplicate generation plants available to meet their persistent shortcomings in the short term of minutes or less, and longer term of hours or days. This is a cost unique to them. The experience in Germany is that the duplicate capacity for wind is virtually the same the installed wind plant capacity.39 This alone considerably increases the cost of wind presence, and much the same considerations apply to solar PV.40 These costs must appear somewhere in total electricity system costs, but should be attributed to wind and not to the generation source that bears the wind balancing burden, for example natural gas generation. This will be covered in more detail later.

Another factor in determining unit costs by plant is the assumed life of the asset. Wind plants in particular are usually taken to be at least 20 years, but 30 years is sometimes assumed for the purposes of determining unit costs. The US DOE/EIA incorrectly still uses 30 years as the financing period for all technologies. For wind turbines, especially the larger ones, that is those in the order of 1-2 MW plus that have been almost uniquely and completely installed since 2000, experience is starting to show that lifetimes of 10-15 years are more the reality.41 This alone should account for approximately a doubling of the base unit costs. There are other reports on frequent, major component failures requiring substantial costs in the order of those for the initial implementation.42

These considerations do not take into account the extensive grid additions that are unique to wind and solar to collect a widely dispersed and relatively weak energy flow source, transmit it to load centres and changes to distribution network, such as smart meters to change demand profiles, all of which are another factor in the order of the original wind plant investment. On the subject of smart meters, these should be viewed as making consumers change their, largely speaking, normal routines to avoid punitive rates required largely to finance the investment in wind and solar. This is discussed further below.

Directly comparing unit costs of wind and solar with other reliable generation technologies is one area where analyses go very wrong, and the LTEP appears to make this fundamental mistake in its representations at least.

Non-dispatchable resources must have dedicated and duplicate generation plants available at all times to meet their persistent shortcomings.

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Figure 5 illustrates the redundant capacity needs required with wind and solar present, first showing a representation of the situation in Germany projected for 2015, derived from the reference cited above dated 2006 and comparing it to Ontario as projected by the LTEP for 2018.

Figure 5 – Comparison of the duplicate capacity consequences of adding non-dispatchable wind and solar in Germany and Ontario. The Capacity Credit for wind in Germany is 6 per cent or about 2 GW out of 35 GW of installed wind. In Ontario using the same Capacity Credit it is about 0.6 GW out of 9.4 GW for wind and solar.

Figure 5 graphically illustrates that with wind and solar extensive duplicate capacity, and hence cost, is required to offset the non-dispatchable nature of these energy sources. In Germany this is 35 GW (35,000 MW), about 34 per cent of the total needed capacity and in Ontario about 9 GW (9,000 MW), or 30 per cent of total needed capacity. Note that in Germany wind has a Capacity Credit of 6%. This is the statistically determined expected value of wind at any point in time that provides for an overall 99 per cent reliability for the electricity system43. So only 6 per cent of the installed wind (and solar) should be planned on as a contribution to peak capacity needs. This information can be used for capacity planning, but is not appropriate for real time experience. Even 99 per cent is still too low as an overall reliability target for electricity systems, so the Capacity Credit used here is aggressive for prudent planning. The LTEP uses roughly the Capacity Factor for wind and solar, that is 23 per cent, which is an average production over time and definitely not appropriate for planning to meet peak loads. Its use will produce an overall system reliability of about 90 percent, which means on average one day in ten could see a system failure. The nature of Capacity Credit for non-dispatchable sources is that it approaches zero as wind penetration increases. It does approach the Capacity Factor as wind penetration approaches zero. This is also discussed in the above reference for Germany. The argument that this cost is necessary to utilize non-emissions producing wind and solar does not hold as they have little or no effect on overall electricity systems emissions. It is possible that the presence of wind and solar in a large-scale, grid-feeding arrangement will actually increase overall emissions as will be further explained below. As a result of all these costs unique to wind and solar, their total generation costs far exceed those of the wind and solar plants alone by a factor of three to four times, and comparisons should be made on this basis.44 This will be expanded upon further for wind in the next section, Real Wind Costs.

The argument that this cost is necessary to utilize non-emissions producing wind and solar does not hold as they have little or no effect on overall electricity systems emissions.

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Real Wind Costs

The previous section introduced the real costs of wind and solar. This section will develop this further and show where these costs appear to be accounted for in the LTEP. This analysis is necessarily imprecise because of the lack of complete, detailed information available in the reports and presentations describing the LTEP. However, it is sufficiently indicative of the effect of the factors affecting total wind costs. As discussed, an important measure is unit costs, that is dollars per MWh, because it incorporates a number of factors, including implementation, operation and maintenance costs, electricity produced (MWh) over a generation plant’s lifetime. It is also how electricity is provided, used and paid for. To repeat, for emphasis because of its importance, in the case of non-dispatchable wind and solar, the costs of implementing and operating generation plants are significant and unlike other generation technologies in the Ontario electricity system. So how do these costs show up in the LTEP because they are not explicitly addressed? The LTEP information to determine this is contained in the following: load factors, unit costs, duplicate capacity requirements and grid additions unique to wind and solar.

1. Load Factor (or Capacity Factor) Assumptions This is the electricity produced over time (typically at least a year) expressed as a percentage of the total electricity that would be supplied if the plant produced at 100% of capacity for that period. Over the period studied in the EDC report wind load factors start at 26% and increase to 30% by 2024. This is not consistent with experience in Europe as wind load factor decreases with time mainly due to wear and tear on the wind turbines as previously discussed and less so as the better sites are used first. Accordingly the load factors in the following analysis are reduced over this period to a more realistic 15% in 2024.

2. Unit Costs The basic unit cost (dollars/MWh) for wind used in the LTEP are shown to rise and then fall back to 2014 levels by 2024, and then fall by about 20% by 2032, presumably assuming technology improvements. This is highly unlikely because wind turbine technology has been used for hundreds of years and employs basically a mechanical means of converting wind energy to electricity, and such technology improvements are very unlikely. Some improvement can come through increase turbine blade size and the height of turbine. Already the turbine and nacelle assemblies at the top of 200 foot or more high towers weigh 100 tons.45 As well these costs are largely implementation costs involving more than the generation technology itself. Technology improvements would have to be unrealistically substantial to overcome this. Regardless of the possibility of a surprise it is not prudent to plan for such improvements. The following analysis adjusts these rates to be level once the highest point of $120/MWh is reached in 2015, which is roughly the FIT (Feed In Tarrif) rates paid to wind plant owners in long term contracts, which probably include inflation escalators. These two factors alone result in less electricity production over 2014-2024 than the LTEP provides and combine to increase the unit costs to $240 /MWh versus the LTEP level of $107 by 2024. This is over twice the LTEP rate.

Costs for wind and solar must include costs in addition to those for the generation plants alone, which can increase their total costs by a factor of three to four times. This furthers their being the plausible explanation of electricity bills increasing as much as they are.

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3. Duplicate Capacity Requirements This is harder to pin down. It appears to be in the unit rate that the LTEP uses for the combination of gas plant and “Planned Flexibility”. This combination starts at $156/MWh, climbs to $174 and falls to $121 by 2024. “Planned Flexibility”, uses the simple gas turbine unit cost (a good complement to wind and solar) and likely would have the same role, but is a small factor in the mix. Although simple cycle gas turbine unit costs are typically in excess of $100/MWh, it is unrealistic to burden the whole gas fleet with this rate. A reasonable unit cost of the natural gas resource, with a mix of CCGT and SCGT, should be about $79/MWh, which is assumed to be protected with inflation escalation conditions in contracts. Why the major difference, even at the lowest level in 2024, because the LTEP states elsewhere that:

“Natural gas generation is cost effective to operate and can provide some of our lowest-cost capacity. Its output can be dispatched quickly to match changes in demand, and supports variable resources such as wind and solar.” (emphasis added)

This much higher unit cost could be explained by the gas plant category being burdened with the costs of balancing the persistent variable nature of wind and solar, especially in the short term critical period of minutes or less, but also in longer terms of hours and days. The higher unit costs provide for some combination of redundant capacity, as discussed in the previous section, and/or because of very low Load Factors (Capacity Factors) for the gas category at 13 per cent as an indication of this. There are a number of factors that come into play, so only a few important ones will be described. As a result:

The gas plants operate at part load to provide less electricity when wind is blowing. This means that over time they produce less electricity, which raises the unit cost rates to recover otherwise expected higher loading.

Because the gas plants have to complement wind’s erratic behaviour they consume more fuel to produce less electricity and incur greater maintenance costs over time. To help appreciate this consider driving a car on the highway at an average speed of say 70 km/hour and repeatedly speeding up and then quickly applying the brakes to slow down every few minutes. What would you expect the fuel consumption to be relative to driving at a constant 90 km/hour over the same distance? As well, think of the increased wear and tear on the car as well as the havoc created for other drivers.

To further complicate matters elsewhere the LTEP also bundles natural gas with imports. In summary, these extra costs contained in the very high unit rates for gas plants by the LTEP, are most likely because

wind and solar are in the system. Without wind and solar other generation means would require less capacity and could operate more efficiently, offsetting any gains that might be claimed for wind and solar in fuel consumption or emissions. The extra costs and emissions should be directly attributed to wind. Adding this duplicate capacity/low efficiency set of natural gas plants to the wind cost account will put wind unit costs at $293/MWh by 2024.

4. Grid Additions Unique to Wind and Solar

Generally speaking, the existing electricity grid is a distribution network to users from centralized generation plants, which are sited depending upon need. It is established to serve users. Changes to this grid will be necessary over the period studied due to replacement requirements, increases in demand, including regional shifts in demand, and upgrades or improvements in grid technology. The provision of economic, reliable electricity, as and when required,

By 2024 wind unit costs are estimated to be $293/MWh, not $107 as shown in the LTEP. The higher rate can now be used as a basis of comparison to reliable generation plants with unit costs in the range of $70-100/MWh.

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is a social need and these costs should be shared amongst all generation sources, and is typically shown in a separate cost category from generation. On the other hand, again generally speaking, grid changes needed to accommodate wind and solar are for energy collection, otherwise not necessary long distance transmission to demand locations and user demand management systems, all of which are needed to serve the shortcomings of wind and solar. In other words, grid changes unique to wind plants, are primarily due to:

The dispersion of the energy source (fuel), wind (and solar radiation)

The need to site these plants where the energy flux is strongest, not necessarily near to demand centers. Transmission considerations include the provision of capacities in the order of three to four times the average production levels to have the capacity to carry up to full wind and solar production when they sometimes occur, not the annualized average at 15-30% of capacity. The alternative is curtailment of wind and solar, already a common practice, often resulting in payment to wind and solar plant operators to not produce.

Additional distribution technologies required (such as smart meters) that purport to facilitate the integration of unreliable, random wind production through possible demand limitation and conveniently provide the electricity cost rate capability needed to finance them.

These grid changes unique to wind and solar are substantial, and they primarily serve the wind and solar plants not users. The required investment is about the same order of magnitude as the wind and plants themselves. I have not yet seen a conclusive and comprehensive study and so these costs are hard to quantify, but I have made an attempts to do so.46 There appears to be no provision for these additional grid costs in the LTEP, but some may already be imbedded in the base running rate for grid costs. Another possibility is that some provision may be made for it in the high rate assessed to natural gas resources discussed above. Claims are often made about the smoothing benefits of geographic dispersion of wind plants. Although this might seem intuitively so, real experience shows this does very little improve wind’s overall persistent erratic behavior.47 In summary, wind is positively correlated over large distances (thousands of kilometers), but show a tendency to reduced positive correlation with distance. For notable smoothing to occur this trend would have to go through zero into the higher negative correlation range. Also, mathematically summing all wind or solar generation in a province, state or country is not representative of reality as grids are typically regionalized and balancing is performed on a regional basis. For information on smart grid issues, and the reasons for not moving too quickly into this area, see my articles at MasterResource.48 This appreciation of real wind and solar costs can be seen as furthering the plausible explanation that they are the cause of electricity bills increasing as much as they ar. Analyses of the impact of wind and solar cannot be based on the LTEP reported contribution to costs, which is based on the wind and solar generation plant costs alone.

Wind and solar generation costs are 3-4 times the basic costs of the plants themselves.

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Evolution of Residential Electricity Rates in Ontario This portion of the analysis now looks at the rates charged for the electricity portion of the electricity bill. The other major elements are delivery (grid), regulatory, until 2019 the debt retirement cost (DRC), until 2016 the OCEB, and finally the HST, all of which are variable, roughly in proportion to the charges for electricity. Not surprisingly we will see a remarkable similarity with the increase in electricity bills and the overall rates calculated from these as shown in the Residential Electricity Bills and Overall Prices section. It is instructive to look specifically at how residential electricity rates have evolved since before the introduction of time of use rates (TOU) in 2010. Figure 6 shows the rate schedule.

Figure 6 – Ontario time of use rates for weekday residential electricity rates as introduced in 2010. On May 1, 2012 the lowest rates were changed to start at 7:00 pm on weekdays. Compare these with the previous rate structure of less than 7 cents/kWh for the average residential customer.

On weekends and holidays the lowest rates apply for the full 24 hour period. Note I have shown the lowest rates as white and increasing red as the rates increase. Compare this colour treatment to the representation provided by your electricity supplier, which are less obvious in this respect. The previous rates were flat across the day depending on the amount of electricity used over the billing period as shown in Table 5. There is a substantial difference compared to the TOU rates. This is not an argument against TOU rates in principle but against the Ontario Government’s implementation of them.

In general, the time of use rates have disguised a considerable increase in rates for those who for various reasons have to perform their usual electricity use activities between 7:00 am and 9:00 pm, or even now at 7:00 pm, which appears to include almost all Ontarians.

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Table 5 – Rates for Residential Electricity Prior to the Introduction of TOU Rates.

Tiered Price Applied To

6.5 cents per kWh Up to 600 kWh per month

7.5 cents per kWh Above 600 kWh per month

The story since TOU rate implementation is dramatic annual increases as shown in Figure 7.

Figure 7 – Cumulative per cent increase in TOU rates since implementation in 2010

As of 2014 there have been significant increases in residential electricity rates since 2010 in the range of 30-35%. Note that the effect of these increases is based on nominal dollars. To approximate the effect of inflation apply an annual discount rate of 2 per cent, which means reducing the above by 2 percentage points per year. This means that annual increases approaching an average of 10% will now be reduced approaching 8%. This does not change what the residential users will be paying in each year; it just takes inflation out of the calculation so that non-inflation increases can be seen. With the introduction in 2010 of TOU rates electricity rates increased by 29% from the old tiered rate structure, using a blended rate of 6.75 cents per kWh. Over the next four years until 2014, the TOU rates were increased by about 35% giving a combined increase of 74% in the rates over the four years. The impact on any individual bill for the same number of kWh will vary depending on how much each residence is able to make use of low overnight rights, or avoid the highest peak rates. We saw previously that the average electricity bill in Ontario are represented as having increased by 30-35% by 2013 versus 2010, or about half the rate increase in the rates themselves. My bill increased by 33.5% over this period. It appears that it was recognized that this was overly punitive, as about two years later the night time rates were changed to start at 7:00 pm instead of 9:00 pm. I suggest this was not really a major concession given the relatively high rates for the hours of 7:00 am to 7:00 pm.

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

2011 2012 2013 2014

Summer Off-Peak

Summer Mid-Peak

Summer On-Peak

Winter Off-Peak

Winter Mid-Peak

Winter On-Peak

Since the introduction in 2010 of time of use rates, Ontario’s residential electricity rates have increased by 30-35% by 2014. This is in addition to the initial rate increase of 29% from the old rate structure.

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In general, the TOU rates have disguised a considerable increase in rates for those who for various reasons have to perform their usual electricity use activities between 7:00 am and 9:00 pm, or even now at 7:00 pm, which appears to include almost all Ontarians. The most plausible reason for such a significant rate increase is the high costs of wind and solar. The next section develops the total of the residential electricity bills for comparison purposes. The section after that will translate the information covered up to this point into overall Ontario electricity costs.

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Electricity Rate Increase Impact on Total Bills as Projected by the LTEP and EDC

One of the main messages of the EDC report is that the average residential electricity bill should increase by only about 15% by 2024, which assumes:

No reduction in use from conservation, which would have made the bill look less than that for 2014.

The costs in the LTEP are reasonable. For example the LTEP projects that the unit costs for solar and wind energy will decrease by 42 per cent and 28 percent respectively by 2032. The projected reductions by 2024 are solar 20 percent (2014, $504, and 2024, $331 per MWh) wind one percent (2014, $108, and 2024, $107 per MWh).49 These improvements by 2032 are very questionable, especially for wind, and are not appropriate assumptions for prudent planning.50 This will be expanded on in the Total Cost Analysis section.

The LTEP costs for solar and wind properly include all costs associated with integrating them into the electricity system. As has been explained this is not the case.

The EDC report projects the average residential electricity bill to be $157 in 2024 versus $137 in 201451, whereas the LTEP shows $191 in 2014, with the same starting point in 2014. The difference is that the LTEP uses nominal dollars, a departure from real 2012 dollars in its generation cost projections. It appears that the EDC report uses real 2012 dollars for residential bill projection, which excludes inflation. Using the LTEP inflation assumption of 2% produces the same total 2024 electricity bill in 2024. There is merit in using nominal dollars, as the LTEP does, as this is the bill that consumers can expect in 2024 in the then current buying power of 2024 dollars. This is the currency in which incomes will be received and the electricity bill will be paid. This could be important to many of us. Those whose income rises faster than the 2 per cent annually assumed for inflation and whose expenditure profile does not change a great deal should not be concerned either way. To others, who might for example have additional expenditures like providing children with post secondary school education, projected electricity bills in real $2012 dollars is a less meaningful representation. On the side of using real dollars in the analysis, cost increases outside of that caused by inflation can be examined. Both approaches will be used for completeness, but care should be used in drawing conclusions as each serves different purposes. Table 6 summarizes the two representations.

The LTEP and EDC show a 53 per cent increase in the electricity portion of residential consumer bills since before TOU rates to 2014, and project a total of 85 per cent increase by 2024.

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Table 6 – Projected Residential Electricity Bill to 2024 by the LTEP ad EDC

LTEP (Nominal Dollars) EDC (Real 2012 Dollars)

2013 2014 2024 2014 2024

Electricity 69 78 100 78 83

Per cent change relative to 2014

+28% +6%

Delivery 43 46 62 46 51

Regulated Charges 5 5 6 5 5

Debt Retirement Charge (DRC)

6 6 - 6

Subtotal 122 134 169 135 139

OCEB (to offset HST) (14) (15) - (15) -

HST 16 17 22 17 18

Total 125 137 191 137 157

Per cent change relative to 2013

+10%

Per cent change relative to 2014

+53% +15%

Numbers are as reported and are not precise due to rounding in the source documents. The EDC 2014 bill should be slightly less if it is expressed in real 2012 dollars as assumed here, but this consideration will be ignored. As will be explained, and it is important to understand that the period from 2014 to 2024 is not a representative way of illustrating the impact of wind and solar. As a check on even the 2014 bill at $137, the average of my 2013 electricity bills (adjusted from an average of 697 kWh per month to 800 kWh) was $120 per month, which is reasonably close to $125 provided in the LTEP for 2013. Note particularly the increase of 10% ($137/$125) in the average residential bill between 2013 and 2014 according to the LTEP. This is a reflection of the rate increases for that period as shown in the previous section 6. Some questions might be raised about the projections in Table 6. For example the OECB, which is due to expire in 2015 and the Debt Recovery Charge (DRC) in 2019 are both included. These are distorting factors, and by its name (Ontario Clean Energy Benefit) inappropriately associates the impact of new renewables with mitigation of the HST application to electricity bills. A more informative comparison would be to leave out the OECB, DRC and HST. Alternatively an analysis based on the electricity services alone, which is the largest component in the bill and the other charges are roughly in proportion to this, is instructive. Table 7 shows electricity portion of the bill since before the introduction of TOU pricing in 2010, as the period from 2014-2024 does not provide a complete story. It is also important to understand that the impact of wind and solar on electricity costs in Ontario started even before 2010, but this is when the electricity rates changed substantially, made possible by the installation of smart meters.

The period from 2014-2024 does not provide a complete story of wind and solar impact on electricity bills.

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Table 7 – LTEP and EDC Projected Increases in Electricity Portion of Average Monthly Residential Bill

Electricity Portion of Average Monthly Residential Bill

Old Tiered Rates

2014 2024 Increase Since Old

Tiered Rates Increase

Over 2014 2014 2024

Real 2012 Dollars (EDC) $57 $78 $83 $21 (37%) $26 (47%) $5 (6%)

Nominal Dollars (LTEP) $54 $78 $100 $24 (44%) $46 (85%) $22 (28%)

The nominal dollar cost for the old tiered rates is calculated based on 600 kWh at 6.5 cents per kWh plus 200 kWh at 7.5 cents per kWh. The real 2012 dollar costs have been discounted and would be $57 in 2012 dollar terms assuming a 2 per cent discount rate. Note that the effect to 2014 was to increase rates by 37% in real 2012 dollar terms. For the period 2010 to 2024 the increase rose by another 10 percentage points only for a total of 47%. In summary, the year of TOU implementation is a better basis to measure the wind and solar cost impacts and not 2014 as shown in the last column. Using real 2012 dollars eliminates the effect of inflation and therefore represents the impact of other factors, such as the costs of wind and solar, assuming other costs are as represented in the LTEP. If not then the costs shown here are low. This will be looked at more closely in the final section, Updated Residential Electricity Bill Projections. Nominal dollars is a more useful representation of the bill that Ontarians will see. Although wind and solar do not represent a large portion of our total electricity generation, if all their costs are accounted for and attributed to them, the substantial real cost of wind and solar can have an impact out of proportion to their percentage share of the total bill, as represented by the EDC report. So far this analysis has shown that arguably the increases shown in Table 7 are attributable to wind and solar. The running rate since the pre TOU rates were introduced in 2010 going forward from 2014 is $21 dollars per month (real $2012) increase for the average residential electricity user by 2024. For 5.5 million households on average over the 11 year period of 2014-2024 inclusive (full years) this represents a total of 21 (increase in dollars of average monthly residential electricity bill) x 12 months x 5.5 million (households) x 11 (years) = $15 billion. Add to this the increase from 2014 to 2024 of another $5, or roughly an average of $2.50, adds another $2 billion (2.5 x 12 x 5.5 million x 11 = 1.8 billion) for a total of $17 billion. As will be seen this represents about one-half of the wind and solar costs over the period 2014-2024. In the next section the total cost of wind and solar in real 2012 dollars will be developed and compared to this.

If all the costs of wind and solar are attributed to them, their substantial total costs have an impact out of proportion to their percentage share of the total bill as represented by the EDC.

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Total Cost Analysis This section looks at the total costs of implementing wind and solar in accordance with the LTEP versus eliminating these from the supply mix entirely. Although this covers the period from 2014 to 2024, for wind and solar some costs include prior installations, so there is an element of sunk costs for them. As a result the savings are overstated, but they are worth noting because they are dramatic. In effect it shows what the costs would have been if the ill-advised wind and solar implementations had not occurred. Table 8 summarizes this for three cases as follows:

1. As projected by the LTEP, which includes a reduction in demand due to conservation. 2. Modifying the LTEP for adjustments to wind. This suggests that the LTEP total cost of electricity projection is

understated. See Table 9 for details. 3. The LTEP removing wind and solar, which means removing the wind and solar costs, ignoring sunk cost of

prior installations and increasing natural gas production to include previous wind and solar. This results in gas plant load factors in the 30-39% range, which is still a bit low and suggests that some capacity is not needed. This would lower the costs more.

Table 8 – Total Costs of Ontario Electricity System Generation for 2104-2024 in real 2012 Dollars

For Period 2014 to 2024

Total Costs

Difference Relative to

LTEP

Percentage vs LTEP

Comment

1. LTEP $146

billion

Contains a unit cost for natural gas of $120-156/MWh which is about twice the reasonable rate. This is 27% higher than case 3.

2. LTEP adjusting wind parameters

$154 billion

$8 billion increase

+5% Unit Cost Load Factor

3. LTEP without wind and solar

$115 billion

$31 billion decrease

-21%

The unit cost for gas set at a reasonable rate of $79/MWh and includes up wind and solar production. Includes sunk cost of pre 2014 wind and solar.

The LTEP costs in real 2012 dollars assume 16% decrease in demand in 2032 through conservation. This is aggressive and will be discussed further in the Conservation and Updated Residential Electricity Bill Projection sections. The impact of adjusting wind costs as shown in case 2 will also be discussed in the latter section. The high wind and costs in case 3 are largely due to the very high wholesale rates paid to wind and solar plant owners (including the “Global Adjustment” in the LTEP to meet contracted prices versus that received in the electricity market), and that of the duplicate natural gas generation resources. One of the main factors in the dramatic impact of removing wind and solar is the extremely high unit rate for the natural gas resource is automatically reduced to normal levels. With wind and solar present, this is how the LTEP avoids explicitly identifying the real costs of wind, by lumping them into an unrealistically high unit rate for natural gas. Table 9 provides a summary of the wind and gas parameters that were adjusted.

From 2014 to 2024 wind and solar represent an increased cost of $31 billion in real 2012 dollars above electricity system requirements without them.

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Table 9 – Adjustments to Wind Gas Parameters in Real 2012 Dollars

Adjustment to LTEP Adjustment Comment

Wind Unit Cost Starts at $106/MWh, climbing to $120 and then decreasing to $107 by 2024

On reaching $120/MWh is left at this level to 2024

Discussed in the Real Wind Costs section

Wind Load Factor Starts at 26% rising to 30% by 2024

Starts at 26% and falls to 15% by 2024

Discussed under Load Factor in “Real Wind Costs” section above

Gas (portion is attributed to wind and solar)

The unit cost starts at $156, rising to $174 by 2017 and then decreasing to $121 by 2024.

Set at $160/MWh for 2014-2024. Gas portion is set at $79/MWh

The LTEP unit rate shows very questionable reductions in later years.

It is extremely unlikely that wind costs will come down and projections in real dollars should be at least flat. Real 2012 dollars is used to eliminate the effect of inflation. Note that solar has not been adjusted and this will be commented further on this below. Representing these extra wind and solar costs as the LTEP has done has advantages to its authors. It allows for the provision of the required increased capacity and increased natural gas consumption in support of wind and solar. Thus it in effect “hides” this consideration within a high unit rate number for gas and "Planned Flexibility" as opposed to explicitly stating it as a line item or incorporating it in wind and solar costs. It is instructive to look at the total costs for natural gas generation with and without wind and solar implementations. Table 10 shows this. Table 10

2014-2024 Natural Gas

Generation Costs Percentage Increase

With wind and solar $22.4 billion

Without wind and solar

$24.3 billion +8%

In case 2 questions remain especially about unit cost projections for solar, gas (which show questionable reductions in unit cost in later years), and nuclear costs. In all cases analysis could show higher unit rates and overall cost, and arguably should be planned for52. As can be seen in case 3, if wind and solar had never been implemented the cost savings would be very substantial. As it now stands possible higher costs for nuclear, gas and solar than the LTEP projects would lead to even higher total electricity costs and electricity bills than the LTEP and EDC report show. The 2013 LTEP is $70 billion lower between 2013 and 2030 than the 2010 version for the total cost of the electricity service. This is roughly $4 billion a year for the period 2014 to 2024 inclusive representing about $44 billion out of a 2010 LTEP total of $263 billion. This will be further dealt with in the section Updated Residential Electricity Bill Projections. I’m sure there is some error in logic, or mathematics in my analysis and kudos to whoever can find it and show that it fundamentally changes the conclusions.

The additional costs of wind and solar appear to be buried in very high rates for gas plants and “Planned Flexibility”.

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Conservation In this section comments often deal with energy in general, but it must be remembered that electrical energy will likely play an increasing role in meeting demand. The electrification of transportation is an example. Much is made of conservation in Ontario’s Long Term Energy Plan (LTEP) and EDC report. The LTEP follows the Ministry of Energy’s directive to put conservation (apparently combining conservation and energy efficiency) first in their planning, approval and procurement processes. It would seem more important to put first the provision of economic, reliable electricity as required to meet demand today and in the future. I also suggest that energy efficiency and conservation should be thought of separately and not bundled into a single concept that might be hard to properly understand, and tends to just promote a “feel good” acceptance of policies under the conservation “umbrella”. Often when conservation is talked about in energy matters, it is really about energy efficiency, which is the reduction in energy per unit of production or service provided. However, improved energy efficiency does not necessarily lead to a reduction in total energy demand as well, which should be thought of as conservation. The impact of energy efficiency is already largely included in the baseline projection of total demand, because such projections are usually based on historic patterns, which inherently include the effect of past efficiency measures, and these have been notable.53 It is important to remember that total demand can also be affected by the performance of the economy. For example there was a significant global economic slowdown as the result of a crisis in the financial industry and markets around 2008, which appreciably reduced energy demand. Unfortunately, a number of people and organizations took inappropriate credit for some of the outcomes, for example in terms of reduced emissions, in support of their policies and positions. This was incorrectly attributed to carbon taxes (British Columbia), wind and solar installations and mandated closure of coal plants (Ontario). The producer/supplier chain includes products and services that provide energy efficiency capabilities/tools for subsequent stages of the supply chain and for the ultimate consumer, at which point individual human behavior introduces a complex new set of considerations. This makes the outcome much more difficult to forecast and unlikely to be significant in practice, except for laws that dictate behaviour, which is rationing. If this seems unthinkable, it is reported that the UK government is setting our Second World War like rationing measures necessitated by their unwise energy policies.54 To illustrate, an example might be the introduction of a more efficient air conditioner. The consumer has to make a decision about whether or not to acquire this. This person might decide to replace the existing unit in the interests of “helping to make a difference” or on the simple economic basis that this will pay for itself within a reasonable period. Another might choose to not install a new unit for some reason. Assuming the first situation, the complexity due to human behaviour enters the picture. Will the family be inclined to take advantage the improved efficiency to lower the air conditioning temperature as long as it does not show up in an increased electricity bill? Often, more efficiency can lead to no change in or even greater use. Conservation should be viewed as using less electricity whether or not a new energy efficient unit is installed. Remember, electricity reduction gains by the more efficient unit alone are already in the baseline demand projections. In essence, conservation should be viewed more as some degree of deprivation. This includes avoiding wasteful and unnecessary activities, a milder form of deprivation. As indicated, conservation might also be effected through rationing. Is our smart meter capable of enforcing this?

Improved energy efficiency does not necessarily lead to a reduction in total energy demand.

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The LTEP also views reducing peak demand, especially during hot summer days, as part of its broad definition of conservation. This might not save on electricity if load is shifted to another time of the day, but it does reduce the overall system capacity requirements providing users are prepared to make this change. Schemes are offered to incent users to do this. Electricity rationing during peak periods could achieve greater results. In general, absent rationing, peak shaving should not be a major factor in capacity planning. Nothing stated here is intended as a guide to individuals as to how to conduct their personal affairs but to illustrate how to view how planners and organizations represent issues. Acting independently is admirable, but societal action is what matters overall. It is also intended as a suggestion as to how organizations who plan, analyze or comment on energy matters should represent their findings. In the larger picture, advanced societies need copious quantities of economic and reliable energy. Such societies are increasingly complex as they further develop, and the energy requirements of maintaining and supporting this inevitable increased complexity grow exponentially. So, we should not assume lower demand patterns but higher ones. We simply have to find the means to deliver substantial energy flow needs in an optimally sustainable way, in the fullest sense of the term, that is, taking account of the social, environmental and economic spheres of human activity.55 As an aside, new renewables do not have the capabilities required to effectively participate in this.56 The exception might be solar but not before substantial increases in conversion efficiencies and storage technologies, within true distributed generation grid architectures. The commercialization of this is likely decades in the future. In summary, energy efficiency in excess of historical trends and over and above that, conservation (reduction in energy use) should be encouraged, but not counted on. Projections of energy needs that include a separate “conservation” or energy efficiency element (i.e. an assumption) reducing projected demand can safely be ignored. The baseline projection should be taken as a minimum for a realistic energy demand projection. One of the surest ways to achieve high levels of forced conservation is to aggressively implement industrial-scale wind and solar. The result will be electricity shortages and energy poverty, because it is no longer affordable and/or available.

Energy efficiency in excess of historical trends, and conservation in particular, should be encouraged, but not counted on in prudent planning.

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Biomass Biomass represents a very broad subject, and there are some interesting and worthwhile developments in this area, for example biogas as might be produced on farms with anaerobic digestion systems for local use.57 Largely speaking biomass in electricity production involves the burning of trees. It is undeniably renewable but not scalable because of sustainability issues and land use, and strictly speaking is not carbon neutral or, even low carbon, as is often presumed with renewables. The logic for including it is that the burning of biomass, which in electricity production is largely wood, the carbon released is offset by the carbon that was previously stored during the period of growth or the subsequent period of growth from replacement trees planted. The important fact that the rates of carbon release and capture are different is ignored.58 This assumption with respect to biomass is heavily relied on in Europe for electricity generation as it is thus allowed as contributing to 2020 targets for renewable energy use and carbon reduction. As a result its use has grown by a factor of 300-500% in Europe since 2001 as shown in Figure 8.59 Note the substantial growth in Western and Central Europe compared to other regions. It is reported that the practice of coal plants using 10% wood in support of coal generation is used in Europe so each MWh of coal generation is considered renewable and contributing to emissions reduction.60 Europe accounts for about 60% of the world total biomass use for electricity generation.

Source: Observ'ER, EDF and CA.sa

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Figure 8 – Biomass electricity production in TWh

In summary, biofuels should not be given much consideration in this analysis of our electricity supply mix.

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Updated Residential Electricity Bill Projections This section will summarize the previous information and provide another set of residential electricity prices by 2024. All the pricing provided, whether the total bill or the price in cents/kWh, is in nominal dollars, so will show what residential users can expect to pay in terms of their actual earnings in any year. Only the LTEP 2024 residential electricity bill is shown as the EDC version is in real 2012 dollars but is the same total bill when expressed in nominal dollars. The history of residential electricity prices in Ontario does show notable increases as shown in Figure 9.

Figure 9 – History of residential electricity prices with projections from about 2007 in nominal cents per kWh.

In 1972 a large portion of Ontario’s electricity was supplied by low-cost hydro. As demand grew beyond the available large-scale hydro resources, thermal generation plants were implemented including those burning coal, oil and gas and deriving heat from nuclear fission. The costs of these were higher than hydro and a distinct upward trend in electricity prices resulted62. In 1993 the Ontario government capped prices in response to public protest, which were removed after the turn of the century63. The closing of coal plants and growth has been accommodated largely by gas, and appears to start a new, slightly steeper upward trend represented by the line for “Projected from 2001”, likely attributable to the introduction of wind (and perhaps some solar), the slightly higher cost of gas generation versus coal and possibly some recovery from the capped price period. The role played by wind and solar between 2014 and 2024 is shown by the effective of removing the running rate for implementations before 2014, which in 2014 is 2.6 cents/kWh in real 2012 dollar terms as calculated in the last page of the Electricity Rate Increase Impact on Total Bills as Projected by the LTEP and EDC section. This has been converted to nominal cents/kWh throughout the 2014-2024 period and is shown in Figure 10.

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From 2014-2024 the total cost of wind and solar to residential electricity users will be $24 billion, and residential electricity bills will likely be higher than projected by the LTEP and EDC.

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Figure 10 – Shows the effect of eliminating the cost running rate of wind and solar for the period 2014-2024.

The result comes quite close to the “Historical Projection” line, but at a higher rate of growth, which itself could reflect higher prices due to greater use of gas plants with to the elimination of coal plants, as previously discussed, and reduction in proportion of nuclear in the generation mix. This would indicate that electricity prices in 2024 could have been about 18 cents/kWh and total bills about $144, rather than the LTEP projection of $191. The “2001 Projection less Wind and Solar” line is shown only for the period 2014-2024, as this is the period under review. There is some imprecision in this chart in 2014, which might be eliminated with more extensive raw data, but there is a fairly clear message. Figure 11 shows the effect of adding the projected wind and solar implementations after 2014.

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Figure 11 – Shows the effect of continuing with the LTEP generation mix with additional wind and solar implementations to 2024. This corresponds to the total LTEP projection for residential electricity prices.

The result is a yet steeper projection resulting in an electricity price of about 24 cents/kWh in 2024, which is the LTEP projection for the residential electricity bill. It is now possible to calculate the cost impact of the wind and solar implementations as they affect residential electricity bills between 2014 and 2024. Table 11 shows that the total cost is Table 11 – The Projected Costs Borne by Residential Users of Wind and Solar for 2014-2024

Nominal Dollars Amount of

Increase Comments

Portion with wind and solar installations to 2013

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$24 billion

The previous calculation in the Electricity Rate Increase Impact on Total Bills as Projected by the LTEP and EDC section was $17 billion in real 2012 dollars, which makes the two comparable. This total cost of wind and solar represents about $4,400 per average household, after taxes, and likely higher for those with more than 1-2 people per household. None of this discussion should be taken as an argument for or against the retention of coal plants, but to illustrate the effect on electricity prices of doing so. Having said all this it is very likely that residential electricity bills in 2024 will be higher still. The factors driving this are:

Effect of increasing wind costs by $8 billion in real 2012 dollars above that projected by the LTEP as described in the Total Cost Analysis section.

Interpolation of the projected conservation levels expected in the LTEP shows an average of about 8 per cent decrease in residential demand for the period 2014- 2024. This represents a cost in the LTEP of about $12 billion in real 2012 dollars.

Other questionable decreases in total electricity system costs between the 2010 and 2013 not accounted for here.

Based on the first two points above, the increased costs are $20 billion in real 2012 dollars, which is a 14 per cent increase over the LTEP projected generation costs as shown in the Total Cost Analysis section. The other line items on the electricity bill are fairly proportional to the electricity component. A rough measure of applying this percentage to the expected average monthly residential electricity bill of $191 in nominal dollars produces a new level of at least $218 per month. The represents an overall price of about 27 cents/kWh. Do we see another capping of electricity prices coming? Remember the piper must be paid though.

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Conclusions In the period 2014-2024, for the average residential electricity bill in nominal dollars:

The electricity portion will be 44 per cent higher than the pre-TOU rates in 2014, and 85 per cent higher by 2024 based on projections by the LTEP and EDC. Other bill line items are roughly in proportion to this.

For the total bill, the LTEP and EDC project an increase of 53 per cent between 2014 and 2024 which is consistent with this.

Residential users will pay about $24 billion in higher bills due to wind and solar already installed and planned in the 2013 LTEP than they would be without these non-dispatchable generation technologies. It is very likely that there will be little or no environmental gain with their presence, and they threaten the reliability of the Ontario electricity system.

The bills will likely be higher than this projection in 2024 due to questionable cost reductions of about $44 billion in generation costs between the 2010 and 2013 LTEP, representing about 17 per cent of the 2010 LTEP cost for the total electricity service.

Ontario plans that wind and solar will produce about 11 per cent of total electricity supplied by 2025, and because of their unreliability, no other country or jurisdiction has been able to accommodate this penetration without exporting or dumping large quantities of their electricity produced. The exported electricity is almost always at a very low price, and in the case of curtailment, the wind and solar suppliers are usually compensated for the lost production. The EDC report, which is based on real 2012 dollars, can safely be ignored as adding to the body of knowledge of the consequences of the implementation of wind and solar as planned in the LTEP.

Although it is valid to use real 2012 dollars for projections, in this case it gives a misleading impression of what electricity bills will be in future years, as these will be paid in nominal dollars, not real 2012 dollars.

Also the EDC depends too much in its analysis on the narrowly defined costs of wind and solar, which are likely only about 25-35 per cent of the actual costs of having them in the electricity system, in part due to full duplicate capacity requirements.

It is a flawed analysis which compares the unit rates of the cost of electricity generation of non-dispatchable technologies to reliable, dispatchable technologies, as it is not a fungible product. When combined with the other costs to make it fungible, the result is a much higher impact on electricity rates and the price of electricity based on the total bill than represented by the EDC, which is based on information in the 2013 LTEP.

In terms of ranking among a number of North American cities, Toronto and Ottawa rose from thirteenth place in 2009 to the sixth highest place in 2013, and Ontario’s average residential bill has increased by 50 percent since 2002, including 30-35 per cent after the introduction of TOU rates. In general in Europe and Canada those countries and provinces with the higher implementations of wind and solar have shown notably higher prices and price increases than others. Burdening Ontario’s relatively low emissions electricity system with these unnecessary high costs and the increased risks to reliability of supply as mandated by the Ontario government is not warranted or wise.

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Endnotes A number of references are to my previously published work, which may be of interest for those looking for more details on the considerations covered here. Their use saves much explanation which would only make this report even longer than it is. These references also provide links to a considerable body of information. 1 Website http://www.poweradvisoryllc.com/

2 Copy of the report can be downloaded from http://environmentaldefence.ca/reports/your-home-electricity-bill-study-costs-in-

ontario 3 Other reviews can be seen at:

http://www.masterresource.org/2010/02/is-doelawrence-berkeley-labs-wind-power-impacts-study-junk-science/ http://www.masterresource.org/2010/04/case-study-on-methods-of-industrial-scale-wind-power-analysis-part-i/ and http://www.masterresource.org/2010/04/case-study-on-methods-of-industrial-scale-wind-power-analysis-part-i/ http://www.masterresource.org/2011/01/kleekamp-part-i/ http://www.masterresource.org/2014/02/where-wind-studies-go-wrong-part-i-2/ 4 A list can be seen at http://www.powerauthority.on.ca/about-us/directives-opa-minister-energy-and-infrastructure . An

interesting example is http://www.powerauthority.on.ca/sites/default/files/new_files/IPSP%20directive%2020110217.pdf 5 The Society of Energy Professionals (2013). “Toward Evidence-based Planning: Long Term Energy Plan Submission”

https://www.thesociety.ca/the-society-advocates-evidence-based-long-term-planning-for-the-energy-sector/ If this link does not work Google the document title. 6 Homer-Dixon, Thomas (2010). “Complexity Science and Public Policy”. http://www.homerdixon.com/2010/05/05/complexity-

science-and-public-policy/ 7 Ontario Ministry of the Environment. “Where does smog come from?”

http://www.airqualityontario.com/science/transboundary.php 8 Ontario Medical Association (OMA). “OMA Ground Level Ozone Position Paper” Section 3.

http://www.godel.net/environment/smog/OMAgroundlevelozone.htm Look under the heading “The Ontario Problem”. 9 Fraser Institute. “Environmental and Economic Consequences of Ontario’s Green Energy Act”.

http://www.fraserinstitute.org/uploadedFiles/fraser-ca/Content/research-news/research/publications/environmental-and-economic-consequences-ontarios-green-energy-act.pdf This review of the Green Energy Act by the Fraser Institute gives some insight into why the EDC may have misinterpreted the DSS report. 10

Hydro Quebec (2013). “Comparison of Electricity Prices in Major North American Cities”. http://www.hydroquebec.com/publications/en/comparison_prices/ 11

OPA (2013). http://powerauthority.on.ca/sites/default/files/planning/LTEP-2013-Module-4-Cost.ppt Slide 56.The calculation is

12,200(cents)/800 = 15.3 cents/kWh 12

Ontario Hydro (2013). “Utility Rates by Province”. http://www.ontariohydro.com/index.php?page=electricity_rates_by_province 13

Manitoba Hydro (2013). “Utility Rate Comparisons”. https://www.hydro.mb.ca/regulatory_affairs/energy_rates/electricity/utility_rate_comp.shtml#residential_750 14

Alberta Government Fact Sheet (2013). http://www.energy.alberta.ca/Electricity/pdfs/FS_ABPricesGraph.pdf 15

Alberta Government Fact Sheet (2013). http://www.energy.alberta.ca/Electricity/pdfs/FS_ABPricesGraph.pdf 16

The calculation of the Ontario electricity rate is 2/3 x20 =13.3 for a total bill of $113. Dividing 11300 (cents) by 750 yields a rate of 15.1 cents per kWh. 17

Wikipedia (2011 data). http://en.wikipedia.org/wiki/Electricity_sector_in_Canada. Percentages calculated from “Utilities generation by fuel” table. 18

Canadian Electricity Association (2013). "Key Canadian Electricity Statistics" http://www.electricity.ca/media/IndustryData/KeyCanadianElectricityStatistics21May2013.pdf 19

Maritime Electric http://www.maritimeelectric.com/about_us/ab_our_island_electricity.aspx . Exporting 52 MW of wind to Maritime Electric probably means almost all wind production, but not exceeding the rate of 52 MW on a short term energy flow basis, which would equate to about a 25% capacity factor. It is further possible that wind curtailment is practiced when high winds occur. 20

Nova Scotia Department of Energy. http://nsrenewables.ca/wind-energy-nova-scotia 21

OPA (2013). http://www.energy.gov.on.ca/docs/en/LTEP_2013_Consolidated_Figures_and_Data_Tables.pdf. Figure 1. 22

The Society of Energy Professionals (2013). “Toward Evidence-based Planning: Long Term Energy Plan Submission” https://www.thesociety.ca/the-society-advocates-evidence-based-long-term-planning-for-the-energy-sector/ If this link does not work Google the document title.

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23

The calculation is {10,000 x 20% (average capacity factor for wind and solar) x 8760 (hours per year} / {157x106 (total system

MWh per year in 2024)} = 11%. 24

European Energy Review (2012). "Germans and Central Europeans lock horns over energy" http://www.europeanenergyreview.eu/site/pagina.php?id=3963#artikel_3963 Unfortunately access to this site is by subscription. 25

Globe and Mail Report on Business magazine (2014). “The Future is Clean” under “Siemens Canada” in the April 2014 edition p47. 26

Hawkins, Kent (2010). “Peeling Away the Onion of Denmark Wind (Part I)”. http://www.masterresource.org/2010/10/denmark-part-i-intro/. This four part series provides an extensive analysis of wind in Denmark for those wishing more details. 27

European Commission http://ec.europa.eu/economy_finance/publications/european_economy/2014/pdf/ee1_2_en.pdf Estimated based on Graph II.I.I on page 55 with VAT of 25% added. 28

Calculated using the 2011 exchange rate of 1 € = 1.33 $US. 29

European Commission (2008). "EU ENERGY IN FIGURES 2007/2008". Table 2.5.6. http://ec.europa.eu/dgs/energy_transport/figures/pocketbook/doc/2007/2007_energy_en.pdf 30 International Energy Agency. "2012 Key World Energy Statistics". http://www.iea.org/publications/freepublications/publication/kwes.pdf p71. VAT data http://ec.europa.eu/taxation_customs/resources/documents/taxation/vat/how_vat_works/rates/vat_rates_en.pdf 31

Canadian Electricity Association (2012). "Canada's Electricity Industry" http://www.electricity.ca/media/Electricity101/Electricity%20101.pdf and by province http://www.ontario-hydro.com/index.php?page=electricity_rates_by_province 32

Hawkins, Kent (2011). “China and Wind: What a Waste”. http://www.masterresource.org/2011/01/china-wind-waste/ 33

Wikipedia. “List of Offshore Wind Farms” http://en.wikipedia.org/wiki/List_of_offshore_wind_farms 34

World Nuclear Association (2014). “Nuclear Power in the Czech Republic” http://www.world-nuclear.org/info/country-profiles/countries-a-f/czech-republic/ 35

Polish Information and Foreign Investment Agency. “Energy Sector in Poland” http://www.paiz.gov.pl/files/?id_plik=19610 36

OPA (2013). http://powerauthority.on.ca/sites/default/files/planning/LTEP-2013-Module-4-Cost.ppt Slide 49. 37

Apt, J et al (2008). “Generating Electricity from Renewables: Crafting Policies that Achieve Society’s Goals” http://wpweb2.tepper.cmu.edu/ceic/pdfs_other/Generating_Electricity_from_Renewables.pdf 38

US DOE/EIA (2013). “Annual Energy Outlook 2013”. See discussion on “Levelized Cost of New Generation Resources in the Energy Outlook 2013”. http://www.eia.gov/forecasts/aeo/electricity_generation.cfm See the paragraph just before Table 1. 39 Hoppe-Kilpper, Dr. Martin. “Systems studies and best practices – Germany”.

http://www.ewea.org/fileadmin/ewea_documents/documents/events/2006_grid/Martin_Hoppe.pdf See slide 13. Hoppe-

Kilpper is the Managing director deENet, a consortium of 100 companies and research institutes in Germany. 40

Dispatchable plants do require reserves that must be available for example to meet unscheduled plant failure and to provide minute by minute grid balancing. Such reserves are properly socialized as they apply to the operations of all plants in the system, and are typically in the order of 20 per cent of peak capacity requirements. 41

Hughes, Gordon (2012). “The Performance of Wind Farms in the United Kingdom and Denmark” http://www.ref.org.uk/attachments/article/280/ref.hughes.19.12.12.pdf 42 This is not widely reported, and some links to sites previously dealing with this topic appear to have removed the documents

in question. Here are some currently available reports relating to this matter. http://www.renewableenergyworld.com/rea/news/article/2010/06/wind-turbine-gearbox-reliability?cmpid=WindNL-Thursday-June17-2010

http://billothewisp.blogspot.co.uk/2013/12/wind-turbines-ghost-in-gearbox.html http://www.queensu.ca/pps/reports/windstudy.pdf 43

European Wind Energy Association (2005). “Large Scale Integration of Wind Energy in the European Power Supply”. http://www.ewea.org/fileadmin/ewea_documents/documents/publications/grid/051215_Grid_report.pdf pp123-124. This document provides some good information within the promotional material. 44

Hawkins, Kent (2012). “Wind Consequences (Part III: Total Costs)”. http://www.masterresource.org/2012/09/wind-consequences-iii3/ See Table III-7. 45

AWEA. “Wind Power Facts”. http://www.aweo.org/faq.html 46

Hawkins, Kent (2011). “Wind Costs: Connecting Some Dots”. http://www.masterresource.org/2011/07/connecting-dots-wind-costs/ , and “Windpower Emissions: Kleekamp Critique (Part III – The Cost of Wind and Nuclear Plants”. http://www.masterresource.org/2011/01/kleekamp-part-iii/ 47

The following is a list of references on this subject:

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http://www.altenergystocks.com/archives/2011/04/gone_with_the_wind_debunking_geographic_diversity_1.html http://www.ref.org.uk/attachments/article/227/info%20note%20ref%20%20poyry%2031%2003%2011.pdf http://www.slideshare.net/JohnDroz/energy-presentationkey-presentation slides 70-73

Wind Power in Ontario: Quantifying the Benefits of Geographic Diversity

http://www.wind-watch.org/documents/wp-content/uploads/oswald-energy-policy-2008.pdf http://aefweb.info/data/Wind%20farming%20in%20SE%20Australia.pdf 48 Hawkins, Kent (2011). “The Smart Grid and Distributed Generation: A Glimpse of a Distant Future” http://www.masterresource.org/2011/04/the-smart-grid-and-dg/ and (2010) “Smart Grid Problems Revealed: The NERC Study” http://www.masterresource.org/2010/08/smart-grid-nerc/ 49 OPA (2013). http://powerauthority.on.ca/sites/default/files/planning/LTEP-2013-Module-4-Cost.ppt Slide 49. 50

First, there is the matter of the additional costs described in the “Generation Costs” section and then there is the associated uncertainty with respect to future timing and nature of technology developments, which should not be the basis for planning. At most, they could form the basis of alternative scenarios, including how the planning for the base scenario provides for such events. Solar does have considerable potential technology improvement scope, but the timing is far from known. Wind from an energy conversion technology point of view is largely mechanical in nature offering small opportunity for improvement. Gains can be made by using larger turbine blades and taller towers. Modern utility-scale wind turbines are already bear 100 tons of turbine blades and equipment nacelles on top of a 200 foot plus tower. http://www.aweo.org/faq.html 51

OPA (2013). http://powerauthority.on.ca/sites/default/files/planning/LTEP-2013-Module-4-Cost.ppt Slide 56. 52

OPA (2013). http://powerauthority.on.ca/sites/default/files/planning/LTEP-2013-Module-4-Cost.ppt Slide 49. 53

I would not normally reference the David Suzuki Foundation as a authoritative source of information on energy matters, but it did commission a report that includes a good review on energy efficiency experience in Canada summarized under the heading “Energy Productivity – the Sleeping Supergiant” starting on page 20. http://www.davidsuzuki.org/publications/downloads/2002/Kyoto_Beyond_eng.pdf 54

The Register (2014). UK govt preps World War 2 energy rationing to keep the lights on”. http://www.theregister.co.uk/2014/06/10/uk_preps_ww2style_energy_rationing/ 55

For an introduction to this see http://en.wikipedia.org/wiki/Sustainability 56

Hawkins, Kent (2010). “Wind is not Power at All” http://www.masterresource.org/2010/09/wind-not-power-i/ 57

Biomass includes the four categories of solid biomass (wood, wood waste and animal manure), biogas (from landfills, wastewater treatment plants or agricultural anaerobic digesters), solid renewable municipal waste, and liquid biomass (bioethanol, biodiesel, vegetable oil etc.). The most important to electricity generation is wood and wood waste. 58 Helm, Dieter (2012). “The Carbon Crunch” Yale University Press. pp91-94. 59

Observ'ER, EDF and CA.sa (2012). "Electricity Production from biomass" http://www.energies-renouvelables.org/observ-er/html/inventaire/pdf/14e-inventaire-Chap02.pdf 60

The Economist (2013). "Wood, the fuel of the future - Environmental lunacy in Europe" http://www.economist.com/news/business/21575771-environmental-lunacy-europe-fuel-future?fsrc=scn%2Ftw_ec%2Fthe_fuel_of_the_future 61

Observ'ER, EDF and CA.sa (2012). "Electricity Production from biomass" http://www.energies-renouvelables.org/observ-er/html/inventaire/pdf/14e-inventaire-Chap02.pdf 62

Dewees, Donald N. (2012). “What is Happening to Ontario Electricity Prices?” Departement of Economics, University of Toronto. http://www.sustainableprosperity.ca/dl764&display 63

The “Historical Projection” from 2006 was derived using the Excel LINEST function, which employs the least squares approach for linear trends.