Parker Gallant eats crow on gas power generation (really!)

An eye-opening tour of the Lennox plant in Eastern Ontario leads to starting calculations, too

Lennox power station in Bath–fast, efficient, low cost …what the heck did we need wind power for? [Photo: OPG]
Back in late May and just before the Ontario provincial election, I wrote a “what if” post titled; “If I were Ontario’s new Minister of Energy ” which was suggested how I would undertake to reduce the costs of electricity.

So far, a few of my recommendations have actually happened.

I won’t linger over the enacted or missed ones but I will focus instead on my suggestion that we close the “Lennox oil/gas plant in Napanee/Bath with a capacity of 2,200 MW that is never used.”

I received an invitation to tour the Lennox plant and I accepted! The tour was led by John Hefford, VP Regional Operations-Eastern Region, who has responsibility for not only Lennox but for all the hydro generating facilities located in the eastern part of Ontario, which (including Lennox), totals about 4,800 MW — that’s about 30% of OPG’s total capacity.

Driving toward the Lennox plant one can’t help but notice, in the distance, the industrial wind turbines (IWTs) recently built on Amherst Island (“owl capital” of North America).  That project is considered one of the most divisive wind power projects ever awarded a contract by IESO under the McGuinty/Wynne  governments.

The tour combined with a takeaway “Overview” of Lennox was truly enlightening.  The most noteworthy bits of information picked up were related to the ability of each of the four 525-MW turbines to ramp up quickly from their minimum load point of only 28 MW or 5%.  To put that into perspective, the other gas plants operating in Ontario are mainly CCGTs (Combined Cycle Gas Turbines) and they have to idle at minimum loads that are six to 14 times higher.

The ramping load point at Lennox logically translates to much lower emissions than the units added to Ontario’s grid(s) backing up industrial wind turbines (IWT) and solar under the FIT (feed-in-tariff) program.

The other significant difference between the CCGTs and single-cycle Combustion Turbines (CTs) is in respect to idling costs: for Lennox the cost is about $4,200 MW per month versus CCGT generators with costs of $10,000 MW per month to $20,000 MW per month, and CTs which average about $10,000 MW.

Another impressive piece of information picked up on the tour is the ability of the units to operate on either natural gas or residual oil (or both). That means, if a fuel cost spikes due to high demand (e.g., gas in the “Polar Vortex” winter of 2014) Lennox can switch to the other fuel. Lennox was also recently called on when a Pickering nuclear unit was shut down due to the 2018 Lake Ontario algae situation.

IESO forecasted shortfall                                                                                                         It appears likely Lennox will be called on to provide the capacity during the shortfall that  the IESO projects during the upcoming nuclear refurbishment years. From a ratepayer perspective, it makes sense.

Carbon tax calculations

Completing the tour and driving home led me to the questions of how much Ontario’s ratepayers might have saved if Lennox had been deemed the back-up for wind and solar power generation or had been used to generate electricity instead of handing out high priced 20-year contracts under the FIT program.  The first question would take an inordinate amount of research, so I opted for the latter!

A report (IESO prepared?) titled the Ontario Energy Report has a chart showing emissions generated by the electricity sector and the report for year-end 2017 indicated emissions in Ontario were 14 mt* in 2009 and 3 mt in 2017, for a decline of 11 mt in 9 years. The decline was touted by the Wynne government as attributable to renewable energy in the form of wind and solar.

Looking only at the wind power generation and its associated cost in those nine years provides an indication of just how much Ontario’s ratepayers have paid on a per ton basis to achieve that 11 mt drop! According to the IESO, from 2009 to 2017, wind turbines generated 53.1 TWh (terawatt hours) and since we commenced paying for curtailed power (paid for but not used), ratepayers picked up those costs for about 6.9 TWh.

So, the approximate costs of the grid-accepted wind power generation was about $7.2 billion, and for the curtailed generation was another $800 million. That brings the overall costs of the 11 mt reduction to about $8 billion!

The cost of that reduction of 11 mt looking at IWT (generation and curtailed) only and without solar, works out to $655/ton!

Ontario’s ratepayers have obviously done their bit to reduce emissions and will continue to pay more until the wind turbines and those 20-year FIT contracts finally expire.

We don’t need a carbon tax.

PARKER GALLANT

P.S. The second in this two-part series about Lennox will follow shortly, covering off how much we might have saved without wind power

*mt denotes “megaton” equal to one million tons.

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The good old days of electricity prices in Ontario

… when supply and demand meant something, and electricity costs weren’t skewed by overpriced FIT contracts and “first-to-the-grid” rights

October 21, 2018

The good old days… just 11 years ago

My friend and energy analyst Scott Luft posted some interesting charts on his twitter account about generation on October 16, 2018, noting the wind was blowing and also that we used very little fossil fuel for power generation — the gas plants were basically all idling!

As is often the case in our fall and spring months, Ontario’s demand for power was low and IWTs (industrial wind turbines) were spinning. In fact the TX (transmission-connected) IWT delivered about 44,850 MWh and had another 26,760 MWh curtailed.  The corporate wind power operators were paid for potentially operating at 66% of their capacity — well above their annual average of 29 or 30%.  The cost of the generation they delivered, along with the curtailed (wasted) generation, put $9,265,000 into the pockets of the developers and all but approximately $84,000 found its way into the GA (Global Adjustment) account, as did the cost of hydro spills and those idling gas plants.

On a fall day when Ontario demand was only 343,680 MWh, as noted by IESO in their “Daily Market Summary”, we had net exports (exports less imports) of just under 50,000 MWh for which we received the market price (HOEP) of $1.88/MWH.  Those exports returned about $94,000 for generation that cost Ontario ratepayers north of $5.6 million.  As IESO reported, the total value of our consumption and exported electricity had a market value (HOEP) of only $749,000, but a cost of about $45 million.

Nostalgia about the good old days took me back to 2007 when the Global Adjustment Mechanism* was first introduced, so I looked at the IESO’s “Daily Market Summary” of October 16, 2007 to see what that day’s HOEP was.  On that day there were few wind and solar “renewables” in place and Ontario demand was higher at 393,000 MWh.  The HOEP for the day was $54.47/MWh or 5.5 cents per kWh. That is slightly higher than what IESO said the cost of electricity was in 2007 in the year-end report when they noted “The average weighted electricity price in 2007 was 5.05 cents per kilowatt hour (kWh)”.

The good old days of supply and demand

Compare that to the IESO Monthly Market Report for August 2018 which came in at $113.32 (HOEP + GA) or 11.32 cents/kWh — that’s 124% higher than 2007 just 11 years later! Put another way, before we added intermittent and unreliable wind and solar in large amounts to our generation sources, the market operated in a way that properly reflected supply and demand economics!

All this serves to demonstrate how intermittent renewable energy sources in the form of wind turbines and solar panels which have been granted guaranteed prices under FIT (Feed-in-Tariff) prices and “first to the grid”** rights, can distort Ontario’s electricity market.

A cost/benefit study, recommended by two Auditors General in the past, might have proved useful.

It is time for the incumbent government to cancel the acquisition of any more wind or solar power generation that have not commenced construction or are fighting actions before the ERT or the courts.

PARKER GALLANT

*The GA was originally called the “Provincial Benefit” but the name changed when the ruling Ontario Liberal Party introduced the “Ontario Clean Energy Benefit” reducing hydro bills by 10%.

**Wind and solar generation ranks at the same level as non-dispatchable nuclear power so when generated must be accepted or if not needed due to low demand will still be paid.

 

Calculating the costs of Ontario’s electricity: which sources add the most to our bills?

More transparency in the Ontario Energy Ministry  would reveal important facts, sooner 

The Ontario Energy Board (OEB) took more than nine months to compile and release what they label Ontario’s System-Wide Electricity Supply Mix: 2017 Data, a one-page document identifying the Electricity sources and the “Electricity Mix.”  The data includes both TX (transmission-delivered electricity) and DX (distributor-delivered electricity), but only in percentage terms. In order to determine the amount of electricity actually generated by the “Supply Mix” one must go through a mathematical exercise.

Lagging transparency

If one wonders why it takes nine months and why the OEB won’t supply the amount of electricity delivered by each of the “Electricity sources” you wouldn’t be alone.  Why have we spent billions on “smart meters” and the “smart grid” (developed by IESO) and the data can’t be provided within, say, the first Quarter of the following year?  That question should be raised by our elected politicians as the ratepayers of the province would like to know that all those billions weren’t wasted.

Digging deeper

Going though the math exercise isn’t unduly onerous; if one uses nuclear as the base (generating 60.1%) and the IESO “2017 Electricity Data” the information shows nuclear generated and delivered 90.6 TWh (terawatt hours), so the other percentages can be used to calculate the actual electricity delivered.  As all of nuclear generation is grid-connected, the total electricity generated (DX + TX) for 2017 was 150.7 TWh.  From that it is easy to determine solar with 2.2% generated 3.3 TWh, wind 10.85 TWh, hydro 38.6 TWh, biomass .6 TWh, natural gas 6.0 TWh and other .45 TWh. Add those figures to nuclear generation of 90.6 TWh and it comes to 150.7 TWh

The next step is determining the costs of those generation sources so we ratepayers can judge if they are giving us value for money. That is easier said than done; however, there are enough clues and information available to give us some reason to believe we will come close to disclosing costs.

Let’s start with the HOEP average for 2017 which was $15.81/MWh (megawatt hour) or $15.81 million per TWh meaning the 150.7 TWh of generation represents a cost of $2,282.6 million. The GA (Global Adjustment) inclusive of Class A and B for 2017 total was $11,851 million making total generation costs $14.233 billion for the 150.7 TWh.   Other costs such as transmission and wholesale market service charges add another $1.8 billion to total costs.  Adding the latter brings total cost to $16.033 billion.

If one than examines total Ontario demand for 2017, it would be the 132.1 TWh that IESO claim in their year-end report plus generation within the DX sector of 4.45 TWh making Ontario demand 136.55 TWh.

Finally, If one estimates the revenue generated from “net exports,”* reported as 12.471 TWh at the HOEP value of $15.81 million per TWh, the net revenue generated was $197 million reducing total electricity costs to $15.826 billion.

Putting total Ontario demand (136.55 TWh) in context, nuclear generation of 90.6 TWH and hydro’s 38.6 TWh together provided 94.6% (129.2 TWh). In 2017 OPG was forced to spill 6 TWh and Bruce Nuclear steamed off 1 TWh meaning those two generation sources could have supplied almost 100% (99.7%) of Ontario’s total demand.  Gas generation (10,548 MW capacity) could have easily supplied the balance including peak periods as they operated at only 6.5% of capacity.

So, what did wind and solar cost? 

Wind generated 10.85 TWh so at $135/MWh cost $1.465.000,000 + curtailment of 3.3 TWh at $120/MWh, added $396 million, making the total cost from wind generation $1,861,000,000. Solar generated 3.3 TWh so at an average of $448/MWh would add costs of $1,478,400,000

The two together — without including spilled hydro or steamed-off nuclear or gas back-up — totalled $3.339 billion.

The math calculation to get the actual cost of 2017 Ontario consumption therefore is simply dividing total electricity costs of $15.826 billion by 136.55 TWh, giving a per kWh cost of 11.6 cents kWh!

Without the total costs of wind and solar of $3.339 billion the costs of electricity consumed by Ontario electricity customers would have been $12.487 billion or 9.14 cents a kWh. That would have been 2.5 cents a kWh less than we experienced with wind and solar as generation sources.

The additional costs of wind and solar in 2017 added approximately $220.00 per average household to their electricity bills. Should wind and solar contribute similarly over the next 20 years the costs to Ontario ratepayers will be in excess of $66 billion.

The time has come to demand more transparency and to re-evaluate the details in long-term wind and solar contracts.

PARKER GALLANT

PS: Scott Luft has created pie charts that highlight much of what is contained in the foregoing article and they can be found here: https://twitter.com/ScottLuft/status/1050045294287745024/photo/1?ref_src=twsrc%5Etfw%7Ctwcamp%5Eembeddedtimeline%7Ctwterm%5Eprofile%3AScottLuft&ref_url=http%3A%2F%2Fcoldair.luftonline.net%2F

*exports less imports

 

Big Wind’s hyperbolic spin should not impress

Grand claims about wind power’s role in Ontario not borne out by the facts

September 18, 2018

The Canadian Wind Energy Association (CanWEA) has a new web posting titled “Ontario Wind Energy Market Profile” that is pure hyperbolic spin.

The four-page report says: “Ontario is our nation’s leader in clean wind energy with an installed capacity of 5,076 MW, about 40 per cent of Canada’s total installed wind energy capacity. There are 2,577 wind turbines currently operating in Ontario at 96 separate facilities.” It goes on to say “Supplying 7.7 per cent of Ontario’s electricity demand today, wind energy helps to diversify Ontario’s electricity generation mix.”

What CanWEA’s report doesn’t say is that wind represents over 12% of grid-connected generation and that the 7.7% supply it adds to the grid is intermittent, unreliable and frequently (65% of the time it is actually generating power) out of sync with demand.   As an example, on Friday September 14, 2018 at hour 18 (6 PM), when demand in Ontario was near or at its peak, the 4,400 MW of grid-connected wind generated a miserly 10 MWh.

That’s 0.23% of capacity.

To put the 10 MWh in context, that is enough to supply one average household with electricity for a year.  At the same time as wind was probably consuming more electricity than the turbines were generating, gas plants (installed to back up wind capacity) were generating 3,862 MWh.

Total generation for hour 18 was 19,274 MWh, not including net imports (imports less exports) of 1,249 MWh, representing Ontario grid demand of 20,523 MWh.* That means the 12% of grid-connected wind generation contributed 0.05% of grid demand. For the full 24 hours of the 14th of September, wind generated just over 3,500 MWh which equates to 3.3% of their capacity. If that isn’t bad enough, 2,500 MWh of that generation occurred from 12 AM to 7 AM when demand is lowest.  Needless to say, nuclear, hydro and gas supplied the bulk of Ontario demand for the day.

What this all means is that industrial wind capacity does nothing more than add to the costs of the generation of electricity in Ontario, and, actually, pretty well everywhere else in the world.

Ontario can’t and shouldn’t fall for the hyperbolic self-interested wind spin, so hopefully our politicians recognize it for what it does—drive up the cost of electricity while killing birds and bats and inflicting harm to humans in rural communities due to the audible and inaudible noise emitted.

PARKER GALLANT

*IESO’s Daily Market Summary indicates Ontario’s peak demand was 20,845 MWh on September 14, 2018.

Is it time for Ontario to use more power?

A warm summer meant  electricity use went up and costs went down. Is there a lesson here?

Photo © Norris Wilson

With Ontario experiencing a relatively warm summer, I thought it might be interesting to look at three recent months, starting with May 2018, to see if power consumption had increased compared to the same period in 2017.

As it turned out, May, June and July in 2018 versus the same three months in 2017 resulted in an increase in total demand (Ontario consumption plus net exports [exports less imports]) of 1,447,000 MWh or 3.9%.   With “net exports” dropping by 1,120,000 MWh, Ontario consumption actually increased by 2,567,000 or 7%.  This increase occurred despite the continued spending of approximately $400 million annually on conservation initiatives.

You might expect that an increase in power consumption by that much in Ontario would have resulted in a substantial increase in the cost of electricity, but as it happens, the amount was a meager $73 million for that extra 2,567,000 MWh. Based on the average cost (GA + HOEP) of electricity over those three months, the additional cost should have been around $313 million. The additional consumption cost only 2.8 cents per kWh (kilowatt hour).

The question is: why did that additional consumption (enough to power 1.1 million average households for the three months) cost so little?

There are several reasons why! First, curtailed wind (paid for but not added to the grid) in 2018 was 416,400 MWh* less than 2017. That means the savings from lower curtailment was approximately $50 million.

As well, Ontario’s net exports were thus lower by 1,120,000 MWh — that saved Ontario ratepayers the full cost of the GA (the GA averaged about $101/MWh in 2018) or approximately $113 million.

And, the 3.4 million MWh of net exports in 2017 generated only about $8/MWh versus $20/MWh in 2017 (the approximate GA for the three months in 2017 versus 2018) for the 2,280,000 MWh of net exports in 2018 for a net benefit in 2018 of about $18 million.

If one totes up the additional costs of $73 million plus the wind curtailed savings of $50 million, the $113 million saved due to reduced net exports, and the $18 million extra earned on export sales due to a higher GA in 2018, it comes to $254 million or $59 million short of the $313 million noted above.

I suspect the unexplained $59 million is related to: spilled hydro, steamed-off nuclear, and a reduction in the Class B to Class A subsidy resulting from the higher average GA. Most of those latter details are not yet publicly available.

Interestingly, wind power — generated and curtailed — was equal to 80% of net exports in 2017 and 112% of net exports in 2018. That suggests wind power was surplus to demand in both years.

It time to acknowledge again that wind, as an intermittent and unreliable source of power, tends to present itself when not needed. That, along with the multiple millions spent by the previous government encouraging electricity consumers to conserve has a simple effect!

Together, they simply drive up the cost of electricity.  Perhaps we should increase consumption to drive costs down.

© PARKER GALLANT

*Thanks to Scott Luft for his data related to wind generation and wind curtailment.

Hydro One’s profit engineering and the Fair Hydro Plan

Who gained the most under the Fair Hydro Plan? Not you. Hydro One comes out the winner

That baby is still not happy… who comes out on top with the Fair Hydro Plan?

In the section titled ”Other Regulatory Developments” in the “Management’s Discussion and Analysis” chapter of Hydro One’s financials for the year ended December 31, 2017, is this interesting note. (The emphasis is mine.)

“In March 2017, Ontario’s Minister of Energy announced the Fair Hydro Plan, which included changes to the Global Adjustment, the Rural or Remote Electricity Rate Protection (RRRP) Program, the introduction of the First Nations rate assistance program, and improving the allocation of delivery charges across the rural and urban geographies of the province. Hydro One worked collaboratively with the OEB on the First Nations rate assistance program, and was a key stakeholder in providing solutions that address both the Global Adjustment and RRRP elements. The Fair Hydro Plan came into effect on July 1, 2017 and resulted in a reduction of approximately 25% on electricity bills for typical Ontario residential customers. The Province also launched a new Affordability Fund aimed at assisting electricity customers who cannot qualify for low-income conservation programs. Additional enhancements were also made to the existing Ontario Electricity Support Program (OESP).

Hydro One customers saw the full benefits of the Fair Hydro Plan for all electricity consumed after July 1, 2017. A typical rural residential customer using 750 kWh per month will see savings on their monthly bills of 31% on average, or approximately $600 annually. These changes did not have an impact on the net income of the Company.

Now, fast-forward to the release of Hydro One’s 2018 2nd Quarter results and there is no mention of the Fair Hydro Plan, the Global Adjustment, the RRRP or the First Nations rate assistance program!

In the recent report, Hydro One simply brags about the big jump in its net income. That jump was supposedly due to approval of a substantial transmission rate increase and favourable weather noted as “higher energy consumption resulting from colder weather in April 2018”!*

The actual growth in revenue for the six months was only $24 million; however, after-tax net income** year over year increased from $284 million to $422 million, showing an increase of $138 million or 48.6% for the comparable six months.

Dreams come true … for Hydro One

If one looks at gross revenue less the cost of “purchased power,” Hydro One’s RoR (Return on Revenue) for the six months was 25.6% (after-tax). Any other service provider or retailer could only dream about growth like that!

So, was the $138 million improvement in net profit a reflection on the now retired, six-million-dollar man’s achievements or other factors?

Let’s look at a few aspects of the results.

As it turns out, the “substantial transmission rate increase” generated additional revenue of $123 million. The transmission revenue is paid for by all local distribution companies (LDC) and included in the “delivery” line on electricity bills. The result of the $123-million increase collected by Hydro One (and all LDC) in delivery costs should have increased that line on the bills, but for Hydro One customers, it didn’t!   The “delivery” costs for Hydro One customers is estimated to have decreased from about 8.2 cents/kWh to 5.4 cents/kWh and “distribution” revenue fell by $96 million despite increased demand of 5.4% (697,000 MWh) in the comparable six months.

Another significant item affecting the positive results is related to what Hydro One paid for the cost of power which fell (despite increased demand) by $113 million from $1.538 billion to $1.425 billion and also fell for “delivery” line items previously included on hydro bills.

The kickbacks, under the Fair Hydro Plan, resulted from moving the “purchased power” costs to future ratepayers and by moving costs of issues such as the OESP*** and “conservation” spending to current taxpayers.

Those cost shifts naturally had a positive effect on Hydro One’s earnings.

In addition, and as noted in an article in the Ottawa Citizen Hydro One is responsible for monitoring “the energy production and pay thousands of FIT and MicroFit producers across the province, it is no longer able to share any information about those contracts publicly.”

Worthy of our trust?

Hydro is simply required to submit a bill to the IESO for the generation produced for all the MicroFIT contracted parties on their distribution network. Those bills are submitted monthly without scrutiny by the OEB or IESO, and IESO simply writes them a cheque the cost of which is billed to all of Ontario’s ratepayers.

Should we trust Hydro One’s billing process for those thousands of FIT and MicroFIT producers, knowing that back in 2015 Ontario’s Ombudsman reported they issued more than 100,000 faulty bills to their customers? Privatization by the former Ontario Liberal government has resulted in a monopoly, now operating without oversight.

The Ottawa Citizen article about this issue had a fitting comment from Steve Aplin, an energy environment data specialist (website Emmissiontrak): “That’s what happens when you break up this system. Now, nobody is minding the store. It’s outrageous that the IESO, they send the cheques. You don’t just blindly send a cheque off to somebody. There must be some fiduciary responsibility.”

The results of Hydro One working “collaboratively” with the OEB reduced revenue in a positive way for them, as they shifted costs to future ratepayers and current taxpayers, generating higher profits.

Additionally, despite ratepayers picking up the billions in costs for “smart meters” and the “smart grid” neither the OEB or the IESO seem able to execute their fiduciary responsibility!

From all appearances, improving results for shareholders is more important now than containing costs for ratepayers and taxpayers for Hydro One, IESO and the OEB.

© Parker Gallant

*A quick estimate of additional April demand for Hydro One suggests increased distribution revenues of $10 million at say $50/MWh for the additional (estimated) 200,000 MWh their ratepayers consumed.

**Net Income before costs attributed to the planned acquisition of Avista Corporation.

***Hydro One has consistently had the highest percentage of dollar amounts in customer arrears. In 2016 they had almost 52% of all dollar amounts of arrears of $69.7 million.

 

What did we get for billions spent on electricity in Ontario?

It’s not over: Ontario taxpayers and ratepayers will be paying for the past government’s mismanagement for years to come. Here’s how… and how much.

Ontario wind turbines at Belle River project

The last in a series on the IESO

August 2, 2018

The two earlier articles about Ontario Independent Electricity System Operator or IESO revealed the fact that it could be “gamed” — and in fact, it was! To the tune of $100 million, by just one generator.

Needless to say, any gaming by a local distribution company (LDC) also may be happening. Why would I suggest that?  When I asked the IESO why the Fair Hydro Plan “Variance” amount was so high for May 2018, they said this:

“Please note that settlement data submitted to the IESO by the LDCs is not audited by the IESO (audit responsibilities reside with the OEB) and is processed as submitted.”

The May “Variance” amount was $309.9 million. More disturbing is that the first six months of the current year has rung up $1.180 billion in the “Variance” which could represent $2.360 billion for 2018 if the last six months are similar.

The results to date of the FHP “Variance” amount is well in excess of the calculations presented by the Ontario Financial Accountability Office (FAO) in their review, which had the following note:

“Figure 3-3 summarizes the FAO’s estimate of the annual cost of the FHP through to 2045-46. The FAO estimates the cost of the FHP to the Province will peak at $1.8 billion in 2020-21, after which the FAO assumes that the electricity relief programs will no longer be funded by the Province. The HST rebate is forecast to cost $0.9 billion in 2021-22, rising rapidly to $1.6 billion by 2028-29”.

The average suggested by the FAO per year was $1.750 billion, so, at the current rate of accrual, future Ontario ratepayers may be looking at total of almost $9.5 billion (without including interest costs) added to our electricity bills.

Taxpayers will be affected too: They’ll have to bear the costs of lost revenue of about $4.1 billion (plus interest costs) associated with the HST rebate and another $3 billion associated with “Adjusting Electricity Relief Programs”. The latter includes the RRRP (Regulated and Remote Rate Program) the OESP (Ontario Electricity Support Program) and a new First Nations On-Reserve Delivery Credit and Affordability Fund.

So, the 17-percent reduction on our electricity bills, coupled with the HST foregone tax revenue plus the cost of those “Relief Programs” represents $16.6 billion of spending, without interest costs.

What are we getting for $16B?

What are we getting for that $16.6 billion? No new power generation. No new transmission lines or upgrades to LDC infrastructure. Simply more wasted money, lots of it, as a result of the Green Energy Act.

Questions put to the IESO about the May Variance amount got the following response from them:

“Hi Parker– the increase in GA deferral in May is mainly due to most LDCs submitting settlement data to the IESO based on the second GA estimate which was unusually high (i.e., 13.2 cent/KWh) in May. LDCs submit May settlement data to IESO during the first four business days of June at which time the actual GA rate would not have been calculated yet as per IESO’s settlement schedule. Each month there is a true up when LDCs submit their data to the IESO for the previous month plus an estimate of the current month they are submitting for.”

Read that and you have to ask, Why? Why not settle the Variance account once IESO has determined “the actual GA rate” rather than go through a series of wasted financial maneuvers? Logic doesn’t seem to be a formula used or followed within the electricity sector.

Are the ratepayers and taxpayers being “gamed” or can we trust IESO with our hard-earned money and believe that each and every action by them is truly being “audited” by the OEB?

I will leave the foregoing question to be answered by an “Electricity Audit” that will hopefully be conducted by Ontario’s new government.

PARKER GALLANT