At the end of the Week, Surplus Once Again

Today Ontario's Independent Electricity System Operator (IESO) released it's latest 18-month outlook.  When their previous version was released, I wrote "At The End of the IESO 18-Month Outlook," which included quotes from the end of their past 4 versions' final paragraphs.
Here's the latest:

Another large variation was in the frequency and energy volume of manual actions, such as nuclear unit maneuvers or import transaction curtailments, for surplus baseload generation conditions. In Q1 2012, there were 73 GWh of curtailments versus 32 GWh in Q1 of 2011. The rise in manual action is a result of lower minimum demands as well as a growing portfolio of baseload generation. The ability to dispatch renewable resources may help mitigate the need for these actions moving forward.

The IESO 18 month outlook now graphs some curtailment actions

It may, but it's less likely in light of the IESO's presentation prepared for a June 27th meeting of the Renewables Integration (SE-91) 'stakeholder' group, which prioritizes renewables over nuclear output (by suggesting a minimum offer price of -$10 for wind and solar, -$5 for 'flexible' nuclear).  This will mean, as oversupply drops pricing into the negative, nuclear bids will be rejected first, requiring 'flexible' nuclear to curtail first.
As it does now - with those curtailments having risen 128% in the first quarter of 2012 over Q1 of 2011.


Those are the curtailments they acknowledge, but there is reason to be skeptical they are all the reduction in nuclear production.

I updated my weekly reporting today, to reflect the June 12-19 period; the last two days having high demand growth due to a heat wave that would peak on the 20th.  One element of my weekly report graphs the changes in supply since the same week in 2011.  As demand grows (graph ends on Tuesday the 19th), it shows as a negative demand reduction, which is compensated somewhat by increased generation from coal, and natural gas, but most notably by an increase in nuclear output.

Our nuclear, in Ontario, doesn't have 2000MW of flexibility at this time (although it reportedly will have, at the 8 Bruce units).  Bruce unit 8 and Pickering Unit 8 both were brought back online as the warm weather approached/arrived, and Bruce 3 also returned to approximately full power for the first time since 2011.

It is likely a couple of those reactors were offline primarily as the system struggles to accommodate the type of output nuclear produces (constant baseload).

To end the post, and the week where Ontario's supply mix met high demand in part by returning nuclear units to service, I'll post the IESO's Surpus Baseload Generation Forecast for the days after the heat wave.

Curtailments didn't end with the spring.

Differentiating Baseload and Pantload Power Generation

Today's hot, humid weather drove Ontario's electricity demand to it's highest levels since July 22nd of last year, with demand forecast to peak at 5 pm.

The day's generation profile isn't exactly typical for a summer day, but it is a good example for clarifying some of the confusing terms in electricity generation.  The term baseload is being deliberately obfuscated recently, but it's pretty easy to spot the traditional meaning in the day's actual production figures for 3 am, and 3 pm

At 3 am demand was around 14000 MW, and we were exporting about 1800 MW in addition to that, at a little over 1 cent/kWh.  That gives a decent idea that whatever was generating is more expensive to stop generating than to sell at rock bottom rates.  For different reasons, this applies to nuclear, the big hydro installations (ie. the Niagara and St. Lawrence generating stations), contracted non-utility generators (gas), and wind.



The bulk of the production is nuclear and hydro, both of which have characteristics that are historically considered part of what makes a plant baseload, which is a big capital cost, and much lower operating cost.


Ontario's coal units, and much of it's gas, can be considered intermediate generation, which simply means it can have a generation profile that matches the predictable daily demand profile that rises in the morning, peaks at 5 pm on this particular day, and then declines until a sharp drop-off late at night.

Peaking generation is that which is available to handle sudden needs, which could arise from generators unexpectedly going offline or unexpected demand levels, and does now also arise from the presence of variable generation, the wind and solar 'renewables', on the grid.  Much of the hydro, gas, and coal generation is peaking, and intermediate supply.  In the first graph, the orange line (CF @ 3 am) is a good estimate of baseload components of hydro and gas/oil, with the gap between the orange and green lines indicating the demonstrated ability to ramp up output to meet demand (as intermediate and peaking supply).  Using hydro for peaking likely lessens the production, while increasing the operating costs, for hydro turbines.  Figures from Germany and Ontario both point to the likelihood that increased peaking duty is leading to decreased hydro output.


Which leaves wind; on this day producing 1163MW at 3 am (the HOEP market valued this at $10.60/MWh), and only 431MW at the peak demand hour of 5 pm (HOEP $38.36).  This may seem like a cherry-picked example, but the output at peak here is actually far higher than what the system operator expects for the wind turbines, which is only 230 MW (page 96 of the NERC 2012 Summer Reliability Assessment)

Some are now referring to wind generation as baseload because the fuel doesn't have a cost, and general operating costs are low, while the initial capital costs are high.  I'd suggests that it's frequent behaviour of output moving in the opposite direction of demand makes it inappropriate to use any of the traditional terms we slot generators into.


Considering wind generation's detrimental impact on the other generators in the supply chain, demands on the transmission and distributions systems, and the significant issues posed to markets, in it's fickle, demand agnostic, fashion of generating energy, I think it's clear it should be put in a new category within Ontario's generating system:

pantload

Wind 'em Up Day: Spin Baby Spin

Friday was dubbed "Global Wind Day"

In Ontario, that meant some rather predictable things - like installations that had been producing output for half a year had ceremonies to officially baptize them as open.  These included the largish Greenwich wind farm Enbridge has been operating near Thunder Bay; and David Suzuki slunk onto Manitoulin Island, with Ontario's current Minister of Energy, to open the 4MW Mother Earth Renewable Energy wind project.   What is also now expected, and disturbing, is the politicization of the bureaucracy compelled to join in with the suspect industry's agenda; all reported, as if news, in the mainstream, media.

The Environmental Registry posted 5 notices on Global Wind Day including 2 renewable energy certificates approving Samsung/Korean Consortium wind projects, with a third awarding the REC for their 'Grand Renewable' solar project.  The sudden flood of activity on the Samsung file followed John Spears' article in the Star pretending a need for urgent action on moving the Samsung projects forward.

Tyler Hamilton's article in the Global Wind Day edition of the Star began:

Climate-change skeptics like to call environmentalists “alarmists” because of their call for urgent action to reduce greenhouse-gas emissions. The skeptics say the science is too uncertain, that there’s no rush to act, and those who argue otherwise are sanctimonious lefties out of touch with reality.
For them it’s drill baby, drill.

I can't speak for 'climate-change' skeptics, but there are people, like me, who have demonstrated the wind turbines pictured with Mr. Hamilton's article do little, if anything, to reduce emissions.  Ontario's emission intensity is a small fraction of the same measurement in Denmark's, and Germany's, electricity systems.  The sanctimonious implication that those who refuse to overlook the severe defects of today's intermittent renewable energy must be climate-change skeptic is a little silly in some cases, and simply one part of an age-old Charlatan's con in most.

The true aim of many who advocate renewables  is ending nuclear energy.  Here is a picture of a scene I observed on International Wind Day, - it is sure to warm the cockles of a wind schemers' heart to a far greater extent than reducing the CO2 content in the atmosphere ever could.  The long-standing head office of Atomic Energy of Canada Ltd. with a big for sale sign stuck out by the curb.

In Ontario, wind production is up, demand is not, price is annihilated, dumping excess at far below cost as exports can't be constrained, and we are shutting down nuclear units on a regular basis as the use of coal is increasing - utilized for it's 'peaking depth' which intermittent renewables make necessary to be available.

Both coal and natural gas use in generation were up over the first 5 months of the year.

Demand is down, generation from wind is up, generation from solar is up, and emissions are up.

This is not indicative of urgent action on reducing greenhouse gas emissions.

---

Notes: Environment Registry Postings on Global Wind Day


011-5914 Grand Renewable Wind LP/Grand Renewable Wind GP Inc.

A Renewable Energy Approval (REA) has been issued to Grand Renewable Energy Wind LP to engage in a renewable energy project in respect of a Class 4 wind facility consisting of the construction, installation, operation, use and retiring of a wind facility, with a total name plate capacity of 148.6 megawatts (MW). The wind facility will be connected to Hydro One’s distribution system.
This Class 4 wind facility, known as the Grand Renewable Energy Park, is located in Haldimand County.

011-5719 South Kent Wind LP

A Renewable Energy Approval (REA) has been issued to South Kent Wind LP to engage in a renewable energy project in respect of a Class 4 wind facility consisting of the construction, installation, operation, use and retiring of a wind facility, with a total name plate capacity of 270 megawatts (MW). The wind facility will be connected to Hydro One’s distribution system.
This Class 4 wind facility, known as the South Kent Wind Project, is located generally between Highway 401 to the north and Lake Erie to the south, and from the Town of Tilbury east to the Town of Ridgetown, in the Municipality of Chatham-Kent.

011-5781 Permit for activities with conditions to achieve overall benefit to the species

The proposal to construct and operate a wind facility and solar facility has the potential to adversely affect Bobolink and Eastern Meadowlark and their habitat. The proposed permit conditions would provide benefits that exceed the adverse effects on Bobolink and Eastern Meadowlark.
Bobolink and Eastern Meadowlark are listed on the Species at Risk in Ontario (SARO) List, in Ontario Regulation 230/08 of the ESA, as Threatened.

011-6555 Notification of Northland Permit for an Overall Benefit
This introduces an application by Northland to do what Samsung was approved to do in the approval re: 011-5781 (above)

011-6005 Renewable Energy on Crown Land Policy

A draft Renewable Energy on Crown Land policy has been developed to provide updated direction on how the government will manage Crown land to support Ontario’s renewable energy needs while balancing the social, economic, and ecological interests of the Province...
The first three objectives of the draft policy focus on where (location) and how (process) the Ministry will make Crown land available for renewable energy development. The Ministry will look to government energy plans and programs when deciding where to make Crown land available for renewable energy. New application processes will be established using up front criteria. The draft policy represents a fundamental shift from previous approaches, where the Ministry accepted applications across the province, to a more coordinated and focused approach better aligned with government energy objectives....

Electricity Exports Continue to Cost Ontario Families

Ontario electricity exports in May cost Ontario families, adding about 6/10th's of a cent to the charge on each kWh they consumed.

It's that time of the month where the govenment release it's silly spin on Ontario exports, and I am silly enough to rebut it once again.  This month is a little different as the release comes just days after the government announced it would sell the power it has been exporting, at very cheap rates, to industry willing to commit to adding employment in Ontario.



June 2012 Ontario Electricity Exports Bulletin:

"Ontario's electricity market generated over $17 million in May by exporting electricity to other states and provinces, bringing total net export revenues to over $93 million this year.
This revenue helps Ontario:

• Keep costs down for families

• Build and maintain a clean, reliable and modern electricity system

Ontario's families, and it's smaller businesses, end up paying a rate comprised of the Hourly Ontario Energy Price, plus the "Global Adjustment Class B rate"
Ontario's largest industrial consumers pay a rate comprised of the HOEP and a "Class A" rate (which is likely about $20/MWh less than the Class B rate lately).
Export customers actually pay somewhere between the HOEP and the price in their home markets (usually the government reports revenue about 10% higher than the HOEP would indicate).
so
In May most Ontarians will pay ~$77/MWh ($20.09 HOEP)
Big industry will pay, on average, ~$54/MWh
Export customers will pay about ~$22 ($20.09 HOEP + 10% observed variance)

I recently crunched some data to quantify the benefit of this to families in Ontario (data exercise)

The average rate paid for electricity in the total market (internal and external demand and production) was ~$67/MWh.
Because export customers paid only ~$22/MWh, the remainder of that $67 was added into the global adjustment pot, adding ~$5.80/MWh to each small business and residential bill in Ontario.

Assuming an average residential use between 800 and 900kWh per month, exports benefited Ontario families in May by removing $5 from their disposable income.

Presumably $5 that would have been harmfully dispensed with purchasing cigarettes ... or alcohol ... or food.

Billions at Stake In Feed-In Tariff Contract Fine Print

March 22nd the Ontario government announced results of a review of it's feed-in tariff (FIT) program to contract supply of renewable energy.  The announcement did little to provide visibility on costing, for either project proponents or the ratepayers taking on the liability of the long-term contracts.  Concerns, from the suppliers' perspective, are apparent at the Independent Electricity System Operator (IESO) as discussions, and proposals, related to the integration of renewable energy supplies into Ontario's system are studied (SE-91).   The cost of excess supply in Ontario is likely to be over $1 billion a year, and possibly double that amount, by 2014; the fine print in the revised FIT contracts will determine how much of that cost is from curtailing payments to FIT generators, along with generation, and how much will be borne by Ontario's ratepayers.

An attendee noted that there has been some slippage in terms of the timelines for finalizing a floor price mechanism and addressing compensation/contract issues. He noted that without specifics regarding dispatch and floor price mechanisms, that developers cannot make go/no go decisions on projects.
The IESO responded ... From a contract perspective, the OPA has stated that they recognize that some language exists in contracts which do not have clear definitions. The IESO recognizes this problem for developers, but the additional clarity that developers are seeking is not yet available.           -Minutes of May 3rd SE-91 Meeting (emphasis added)

The IESO SE-91 process has noted a couple of issues indicating 'stakeholders' efforts to maximize their revenues.  The suppliers' concerns revolve primarily around proposed rules for dispatching supply off.  The IESO is passing the buck, perhaps rightly, to the Ontario Power Authority (OPA), on the issue of costs related to the dispatch rules.  The OPA and IESO are targeted for merger by the government, and it is likely that final decision on rules must come from the Minister of Energy, Chris Bentley.
The cost of those rules is hugely important because of the large amounts of renewable energy that cannot be utilized by the power system.  The FIT's have defined that an amount (ie $135/MWh in FIT 1.0 for wind, $110 in FIT 2.0) is to be paid, and suppliers can show due diligence in forecasting potential production levels; the trickier figure to forecast  is how much of that possible production the grid can/should accept.

The discussions about curtailment involves issues of Surplus Baseload Generation (SBG), CO2 emissions, and exports.  The proper issue, from a ratepayer perspective, revolves around when our contracted supply, and actual baseload sources (which are sources that ouput a constant energy, meaning power, at a low marginal cost - often with huge capital costs invested up front), exceed the demand in the province.  Demand currently is remaining around the level of 2009, which is also the level of 1989, so we can anticipate little change in demand.  This allows forecasting to estimate how frequently, and by how much, our supply commitments will exceed demand.

It is now broadly acknowledged to be quite often, so the market price in Ontario should remain quite low.  In Ontario, as in many adjacent markets, the market price moves with the price of natural gas - but the price is consistently lower in Ontario than other markets.  The SE-91 hearings frequently refer to assumed export levels (~1500-2000MW).   They should not. The full cost of production cannot be recovered from exports, so the discussion on export levels is a discussion of how much power we can sell at $20/MWh before we stop paying $110 - $800/MWh to purchase the supply.
If consumers were stakeholders, the answer would be, "none".

Last year I analysed the costs of adding wind energy to Ontario's electricity system, within the supply context of the Liberal government's Long Term Energy Plan, in part by forecasting supply and demand on an hourly basis through 2022.  My assumption at the time, I hope wrongly, was all FIT contracts would pay out on all production, even if it was curtailed.  That analysis estimated 3 costs attributable to intermittent wind:

• the cost of surplus baseload generation
• the cost of avoided hydro production
• the cost of capacity payments to natural gas/coal generators

SBG cost, and the avoided hydro, should be valued at the price of wind ouput, as this is the cost to the consumer of purchasing wind output while letting water flow over the falls, instead of through the turbines in the Niagara system - or other foregone hydro.  It is also the cost when paying nuclear units to curtail production while paying full price for wind output, and it is very close to the price when purchasing expensive electricity strictly for export at 1/6th the price (which is the case so far in 2012).  My 2011 analysis showed the cost of wind, when paying for every MWh produced, would be ~$263/MWh, for the utilized production, by 2014.

Thing have gotten worse since then, with the scheduled addtions of capacity accelerated, and the FIT 2.0 announcement adding wind (to ~8000MW) and all renewables to 10700 (so ~2700MW of solar capacity).   I have rerun my data exercise, adding in a solar estimation and the scheduled changes to wind capacity.  The numbers provide the magnitude of the importance in settling compensation rules, if there is to be any compensation, for curtailed/dispatched down supply.  Most years ~40% of industrial wind production will either bump other contracted generation, be curtailed, or be dumped on export markets.

	Wind	Surplus	Foregone Hydro	Utilized Wind	% of Wind Utilized	Cost of Wind Not Utilized ($Ms @ $122/MWh)	Nuclear	Hydro	Gas/Coal	Wind	Solar	Total
2011	3.9	0.6	0.3	3	77%	$110	84.9	33.5	19.1	3.9	0.3	141.7
2012	5.5	1.1	0.6	3.9	70%	$195	85.1	33.2	16.5	5.5	0.5	140.8
2013	9	2.2	1.6	5.2	58%	$464	88.7	33.0	12.5	9.0	0.8	144.0
2014	16.5	5.6	4.6	6.3	38%	$1,244	90.2	31.1	10.4	16.5	1.6	149.8
2015	19.6	4	3.4	12.3	62%	$891	76.0	34.1	13.5	19.6	2.4	145.7
2016	20.7	4.9	4.3	11.4	55%	$1,135	76.0	33.3	13.6	20.7	2.9	146.5
2017	20.7	4.5	4.2	11.9	58%	$1,074	76.0	33.4	13.0	20.7	3.1	146.2
2018	20.6	4.7	4.5	11.4	55%	$1,122	76.0	34.0	12.6	20.6	3.1	146.4
2019	20.6	4.3	4.3	12	58%	$1,049	76.0	34.2	12.2	20.6	3.1	146.1
2020	21.2	4.9	4.4	11.9	56%	$1,135	77.6	34.8	12.4	21.2	3.1	149.1
2021	20.7	4.7	4.1	11.9	57%	$1,074	76.0	34.2	12.5	20.7	3.1	146.5
2022	20.4	4	3.7	12.7	62%	$939	71.8	34.5	14.7	20.4	3.1	144.5

I've included annual totals to demonstrate what this forecast measures.  Hourly forecast for demand are made for demand, nuclear, contracted must take supply (NUG's), baseload hydro, wind, and solar.  If that supply is not enough to meet demand (ie. NOT SBG), then the weekly forecast of available hydro is distributed (if it can't all be used, it is considered 'foregone hydro' as shown in the chart.  If there is still unmet demand, it is considered to be met by 'Gas/Coal' generation.  

In reality, gas and coal generation units have more operating constraints than the model allows.  The actual figure in 2011 for those units was closer to 27.3 TWh (not the 19.1 shown as necessary in my modelling).   Practically, this means the model likely exaggerates the proportion of wind output that is utilized to meet domestic demand.

I have not discussed the capacity charges one might attribute to wind, nor the cost to Ontario's treasury of depressed pricing and dispatched off hydro.  Neither of these issues deals specifically with the issue at hand in clarifying rules regarding dispatching off of renewable supply; rules that are uncertain in not only FIT 2.0, but also apparently remain vague in FIT 1.0 contracts.

Will Mr. Bentley commit Ontario ratepayers to spending ~$1 billion a year for dispatched off, or dumped, FIT contracted energy?

Hopefully Mr. Bentley does not use history to guide his decision.  We know Ernie Eves rate freeze added billions, over 3 or 4 years, to the debt repayment schedule, and we know Dalton McGuinty's OCEB is also taking about $1 billion a year from Ontario's line of credit.  

We have a word for politicians who show reckless disregard for the public purse with billion dollar decisions in the electricity sector.

We call them, "Premier"

Estimating Costs in Ontario's Electricity Sector

I haven't posted lately as I've revisited data to provide improved estimates of a number of entities in Ontario's electricity system.  I've tried to do so in a manner that can be easily updated, and written some descriptions of the process, in a lengthy entry at my data site (users with slow connections are warned).   Since I've put the time in building the data structure to support posts, I'll grab some of the data to illustrate the types of figures that can be produced, albeit as estimations with imperfect data, depended on a number of assumptions.

The cost of supply is broken down based on known information on contracts with suppliers.  Some of these contracts pay for capacity (Cpcty) in different formats. The average pricing for 2011 is shown below.  Also shown is graphing of each 'fuel' generation type as a percentage of supply, and of cost (if it's cost share is greater than the share of generation, it's more expensive than average)

Fuel	Rate_Output	Rate_Cpcty
Nuclear	$57.05	$0.00
Hydro	$36.47	$0.00
Gas	$63.58	$24.44
Coal	$37.66	$75.27
Imports	$36.23	$0.00
Wind	$135.00	$0.00
Other	$115.77	$112.82
Solar	$500.00	$0.00
Unknown	$28.40	$0.00
TOTAL	$55.85	$6.41

I worked the data to estimate the net contribution of each generator to the global adjustment.  By "net" I mean the difference between what the end consumer pays for the generator's output, and what the generator receives.  In a world of perfect data, this method would balance to $0.

$Millions	Wind	Solar	Conservation	Other	Gas	Coal	Nuclear	Imports	Hydro
2012 05	-$19	-$24	-$27	-$17	-$45	-$17	$79	$19	$103
2012 04	-$29	-$22	-$26	-$17	-$27	-$19	$63	$23	$107
2012 03	-$35	-$22	-$27	-$18	-$45	-$14	$81	$14	$108
2012 02	-$32	-$17	-$25	-$17	-$23	-$7	$61	$9	$96
2012 01	-$42	-$14	-$27	-$19	-$29	-$14	$47	$8	$84
2011 12	-$32	-$9	-$27	-$18	-$39	-$15	$86	$8	$94
2011 11	-$38	-$9	-$26	-$17	-$35	-$14	$62	$9	$80
2011 10	-$23	-$14	-$27	-$17	-$38	-$22	$71	$9	$72
2011 09	-$17	-$16	-$26	-$15	-$36	-$19	$55	$11	$59
2011 08	-$12	-$17	-$27	-$18	-$41	-$14	$69	$13	$66
2011 07	-$10	-$15	-$27	-$19	-$40	$2	$50	$14	$70
2011 06	-$14	-$14	-$26	-$17	-$42	-$22	$75	$7	$97
2011 05	-$20	-$14	-$27	-$18	-$47	-$24	$58	$8	$108
2011 04	-$28	-$12	-$26	-$18	-$51	-$22	$63	$10	$90
2011 03	-$23	-$11	-$27	-$19	-$47	-$18	$47	$9	$82
2011 02	-$31	-$8	-$25	-$17	-$33	-$15	$48	$9	$75
2011 01	-$19	-$6	-$27	-$19	-$40	-$12	$62	$10	$84
2010 12	-$27	-$4	-$27	-$19	-$56	-$12	$46	$11	$76
2010 11	-$24	-$4	-$26	-$18	-$48	-$13	$43	$13	$68
2010 10	-$19	-$5	-$27	-$18	-$49	-$22	$62	$16	$79
2010 09	-$20	-$5	-$26	-$18	-$50	-$17	$13	$18	$50

Aside from working on figures to show the relative costs of each supply, I also indicate a breakdown of costs comprising the Class B commodity charges that most bills in Ontario are based on - the exception being the large Class A customers.
The breakdown includes the cost of the OPA's consevation programs, the addtional burden on Class B customers creating by the creation of the Class A category, and the cost added by selling exports cheaply.