Sunday, June 17, 2018

Ontario Electricity: Backgrounder and suggestions for Premier Ford

Ontario has a new Premier. Congratulations to Doug Ford who, despite my recent quiet, is receiving a lot of free advice on addressing costs in Ontario's electricity. Some of it good, but much of it not only bad, but based on flawed views of how Ontario's residential and small business consumers came to experience rapid rate growth.[2] I also have noted some advice - from academics - is oblivious to the new political reality of Ontario. Before getting into thoughts on controlling electricity costs, I'll provide my perspective on the politics of the situations that will determine which suggestions are actionable.

I wrote very little in the run-up to the election because it struck me as a race to the bottom. I used to write on things that angered me (to some extent), and then I'd hope to edit out my annoyance based on, "Nobody cares that I'm angry. What is my point?" This election the point seemed to be people were beyond angry with Kathleen Wynne. I'd call it disgusted. There's a saying in politics that "anger is not sustainable." That's probably true but around the time her government was introducing the ridiculous [un]Fair Hydro Plan I'd wondered if the Wynne policy team had let the anger of the first half of her mandate develop into disgust. Disgust is not an emotion, it's a sense. I was curious to see if I was wrong, and a climb up in the polls was possible for Premier Wynne. I don't think I was wrong - I do think the election was about this sense of disgust, and I found it so unpleasant I voted in the first hour of advanced polling and then tried to ignore it altogether.

I realize many of the angriest were people who follow my blog and know about the Liberal party's enormously wasteful performance in the electricity sector. The waste cost most Ontarians money, but not food, or housing, or heating. With the election over, and the previous governing party embarrassed by failing to win enough seats for official party status, I am hoping many will start the new era of Ford's rule by editing out their anger and trying to find their point. This is not a kumbaya moment though. A real cost reduction of the scope promised by incoming Premier Ford will require tough choices harming real people and angering numerous constituencies, but particularly the one known in the electricity sector as "stakeholders."

Political Constraints

The political reality of the election is pricing carbon is dead: Doug Ford took the leadership in the race for leading the Progressive Conservatives by opposing the recently implemented current cap-and-trade system in Ontario and the federal government's demand province's implement some regime. I'll try to avoid the topic - and fail (but hopefully only once).

Functional Constraints

Ontario's electricity, if mine is any indication, is pretty reliable (the lights stay on) and it is exceptionally clean, with very low emissions of greenhouse gases. My views on what can be done to control costs is influenced by two concerns that I don't see noted very often:
  • capacity
  • industrial electricity costs
By capacity I refer to sufficient capacity credit to meet anticipated peak demands. There are North American Electricity Reliability Council (NERC) requirements for this firm capacity. Currently Ontario comfortably meets the figure, but there are concerns on the horizon. Whereas one nuclear reactor is currently out of operation for refurbishment, two will be offline in 2020 (if all goes as planned), and 3 or more for several years thereafter. Perhaps as importantly, Ontario has a very large duel-fuel site, Lennox, that essentially serves as a strategic reserve providing capacity not anticipated to be needed frequently. Lennox has been described, to me, as a sister plant of Lambton - a decommissioned coal-burning plant. While Lennox seldom operates, when it does it has a very high heat rate resulting in emissions well above those demanded for coal units refurbished to run on natural gas - and there's a modern gas generator entering commercial operation on the same site that is 45% of Lennox's capacity. For reasons that I do not know and cannot comprehend, Ontario's system operator contracted Lennox through 2022, but I do not expect it to be operating come 2023.

On an operational basis, there are constraints on generation capacity imposed by the grid's composition. The ability to generate, or import, enough electricity to meet the demands of the province does not mean each area of the province can be supplied to meet their demands. Fo instance, much of Toronto's electricity comes from 2 relatively close nuclear power plants to its east: Pickering and Darlington. When the NPD campaigned on closing Pickering immediately, they were effectively campaigning on reducing that relatively local generation from 6,600 megawatts (MW) in 2016 to 1,800 in 2022. I will not suggest such gambles.

Ontario's Industrial Conservation Initiative (ICI) scheme was introduced as rate escalation started to hit very hard. It became active January 1, 2011 and greatly protected Ontario's largest "Class A" consumers from the rate hikes experienced by smaller consumers. Unfortunately, the policy depends on a large "Global Adjustment" component of Ontario electricity costs, and a very small recovery of those costs through sales valued at the Hourly Ontario Energy Price (HOEP) in the system operator's (IESO) so-called hybrid market. This is a fantastically complicated problem as the IESO claims savings in the future on redesigning a market whose dysfunction was modelled into protecting large, trade-exposed, industries.

The Cost Reduction Challenge

When the New Democratic Party released an electricity platform in February 2017 I had some hopes for a meaningful campaign. Those hopes died when the Liberal government introduced the [un]Fair Hydro Plan, which set the election up as a race to the bottom - with the Liberals offering an immediate $2.5 billion a year discount for regulated price plan (RPP consumers), but result in building about $20 billion before future consumers would be required to pay it back. Both the Financial Accountability Office of Ontario and the Office of the Auditor General of Ontario reported on the plan, so I won't review it again. I mention to introduce $2.5 billion, and $20 billion, as the annual and total reductions necessary to be in a position to lower bills authentically by what the Wynne government did through sleight of hand.

Where did the increases of the past decade come from

I've written on the factors driving cost increases in Ontario many times.[2]  Here I'll offer only a brief summary of events predating the major cost driver of recent years:
  • in 2002 an all party committee of the legislature recommended eliminating coal, and an electricity market opened
  • consumer prices were frozen soon after price spikes occurred on the market
  • in 2003 all parties had the elimination of coal in the electricity sector in their platforms - the Ontario Liberal Party campaigned on a 2007 phase-out, and won
  • by 2006 the Energy Minister, Dwight Duncan, had introduced a hybrid market that allowed for some market activity but also the procurement of new supply (primarily to replace coal), largely due to a "global adjustment" mechanism that allowed for full cost recovery regardless of market revenues,
  • the recession that peaked in 2009 hammered electricity demand, and the pricing on Ontario's hybrid market plunged.
That was the end of coal in Ontario - it just played out over the next 5 years as contracted generation, including the refurbishment of 2 nuclear reactors came online.
Completely separate from the phasing out of coal is the lobbying, eventually successful, for the Green Energy Act and related feed-in tariff (FIT) contracting. According to the Minister that pushed the legislation, George Smitherman, “The government saw an opportunity for the promotion of renewable energy to be a source of new investment, and new jobs.”[3] Years later, in 2015, Smitherman claimed a success in that, We were trying to nurture the white-collar side of green energy as well. There is [now] a big cluster of renewable related jobs in the downtown core of Toronto.”[4] 

There are two points related to the Green Energy Act be emphasized. The first is the cost, which has been done. The Auditor General's 2015 annual report noted, "We calculate that electricity consumers have had to pay $9.2 billion (the IESO calculates this amount to be closer to $5.3 billion, in order to reflect the time value of money) more for renewables over the 20-year contract terms under the Ministry’s current guaranteed-price renewable program than they would have paid under the previous program." While that number is shockingly large, it doesn't account for the lack of any business plan demonstrating a need or value for any contracting, nor does it account for additional cost due to ignoring advice from the procurement authority.[5]  The amount is only the additional on procuring using feed-in tariffs instead of the renewable energy standards previously utilized.

Ontario electricity supply costs are recovered through 2 revenue streams: sales into the IESO hybrid market and the global adjustment. In 2017, $3.33 billion of the global adjustment was due to wind and solar. Growth was slowing,[6]  as much of procured in the orgy of contracting that followed the passage of the GEA has now entered service. The majority of today's wind and solar costs is due to post-GEA contracting (roughly 2/3 rd's of wind, and 80% of solar capacity). 

This is not to blame all increases in costs on wind and solar, but it does match the scope of the government's cost cutting challenge. Savings that aren't realized in rolling back contracts that were established without business plans and based solely on government directives, despite the advice of experts in the bureaucracy, will have to be realized elsewhere.

Six Recommendations for reducing costs

1. Repeal the Green Energy Act

The intent of the Green Energy Act has been used as a weapon in the past, and will surely be so again, restraining the ability of the new Ford government to act to reduce costs.
The Government of Ontario is committed to fostering the growth of renewable energy projects, which use cleaner sources of energy, and to removing barriers to and promoting opportunities for renewable energy projects and to promoting a green economy.
The Government of Ontario is committed to ensuring that the Government of Ontario and the broader public sector, including government-funded institutions, conserve energy and use energy efficiently in conducting their affairs.
The Government of Ontario is committed to promoting and expanding energy conservation by all Ontarians and to encouraging all Ontarians to use energy efficiently.
When the system operator first attained the ability to curtail industrial wind turbine output a group of pre-GEA generators used the GEA to argue for payment for curtailed generation - which they were awarded by a new Premier, Kathleen Wynne. That decision, which avoided testing the case, has probably cost around $250 million to date.
Worse is the continued spending on "conservation" at the system operator, and at local distribution companies. In 2017 Ontario demand was reported as 132.1 TWh by the IESO[7], while 10.2 TWh of contracted/regulated potential generation was curtailed and another 19 TWh was exported - most of it dumped far below cost. Additionally, modern combined-cycle natural gas generators operated at exceptionally low capacity factors. Despite all the excess, the IESO continued spending over $400 million annually - as it has done for years.

In order to address costs, the government needs to repeal the act that enabled, and gave priority to, low-value projects.
Escaping high cost is a difficult enough task that if need not be attempted with the GEA straight-jacket.

2. Empower the regulator to practice regulation that protects ratepayers - such as observing a "benefits follow costs" principle

While it's no doubt often difficult to determine whether or not a project is "uneconomic", in Ontario there's a really great indicator: the government issues a directive ordering something be done that would not pass a regulatory test.

Under section 96.1 of the Ontario Energy Board Act, 1998, the Lieutenant Governor in Council (Cabinet) can make an order declaring that a new, expanded or reinforced transmission line is needed as a priority project. Even if a transmission line is declared by Cabinet to be a priority project, OEB approval to build the line is still required. However, in these cases the OEB must accept that the project is needed.

The following transmission lines have been identified as priority projects pursuant to section 96.1 of the Act:
While Ontario's residential electricity rates spiked, natural gas rates did not. Part of the reason for this is the Ontario Energy Board was allowed to function more independently in regulating the natural gas industry. In ruling on a generic hearing about expanding service to areas currently not serviced by natural gas, the Ontario Energy Board included:
If the revenues do not recover the costs over time, an up-front payment in the form of a capital contribution will be required from new customers. This ensures that existing customers do not have to pay higher rates to subsidize the extension of natural gas service to new communities. This is known as the “benefits follow costs” principle, and has been used for many years in Ontario and other jurisdictions.
The $1.6 billion "New Line to Pickle Lake and Connection of Remote First Nation Communities" cannot pass this test - and therefore passing on the costs to existing consumers should not be allowed.

The East-West Tie line is interesting in the context of promised savings from "market renewal" at the system operator (IESO). Part of that renewal is to introduce Location Marginal Pricing (LMP). LMP accounts for transmission constraints. The IESO has a nodal price report that similarly "provides a representative indication of the relative cost of generation in each of Ontario’s electrical zones based on transmission limitations and system conditions relative to generation and load."[source]. Mapping generators to nodes, as best I could, displays the average nodal pricing for the Atikokan, Pine Portage and Andrews nodes have been negative most years since 2009.[8] I am not convinced running more transmission from a constrained zone in the east (around Wawa) to constrained zones in the west will alleviate the constraints - which, I suspect, is why the regulator is not left to decide the wisdom of the spending and a government order is required.

3. End conservation spending

I am disappointed this requires noting after years of curtailing the excess supply that could not be dumped on export markets well below cost, but that's why ending the GEA, and the special priority it gives to conservation, is the top priority.
I've written on the waste numerous times and will mostly let the numbers tell the tale here: for every 100 units of electricity Ontario consumed in 2017 it dumped, or curtailed, 22 more. That was the same as in 2016 (but more costly), and 2016 was worse than 2015 which was worse than 2014.

Ontario's conservation spending added $443.3 million to the global adjustment charges in 2017 - which is the annual average for the past 3 years.

In Ontario conservation is remarkably wasteful.

4. Restrict eligibility to the Industrial Conservation Initiative (ICI)

As demand was crashing and rates rising in 2009 a policy was developed allowing "the province's largest industrial companies and manufacturers" to reduce their costs. That policy set their share of all global adjustment charges at their share of consumption during the highest 5 daily peak consumption hours.[9] The scheme was sold as benefiting all through reducing the need for additional generators to meet infrequent peak demand. From the mandarin's perspective the program could be seen as having no cost, because it simply transfers costs from one group of ratepayers (Class A) to all the others in the province (Class B).
From a Class B perspective, the ICI provides spectacularly bad value. Three years ago I calculated the capacity cost of this "Negawatt" capacity at a ridiculous $500,000 per megawatt, and since then it's gotten worse. For 2016 I calculated the cost at $754,000 per megawatt.

While this a horrifically expensive program for most ratepayers, it does function to retain trade-exposed "industrial companies and manufacturers." While it is unclear exactly what entities participate in the ICI program, it's obvious more and more of those entities are not exposed to trade, or relocation risk - and it's clear participation of non-industrial entities in the Industrial Conservation Initiative is growing.

The government has repeatedly lowered both the threshold consumption qualifying consumers for the ICI, and lightened or removed restricting the program to certain industries. Since its first year (2011) Class A consumption grew 64%, while overall consumption fell 2%. The rate impact of the ICI program on Class B consumers moved for $2.55/MWh in 2011 to $11.43/MWh in 2017.

An IESO presentation in January (2018) noted "72 municipal facilities participating in ICI" (including 23 new participants). Those municipalities join universities and, I suspect, many other publicly funded entities. I was aghast when work out of the Ivey Energy Policy and Management Centre, at the University of Western Ontario - a Class A institution, if only by ICI standards -recommended the deferral of a portion of the Class B costs charged out through Regulated Price Plans. RPP rates that have been significantly inflated by the transfer of costs from institutions exactly like UWO.

This is taxation through electricity rates - facilitated by a blind emphasis on conservation that is demanded by the Green Energy Act.

Purging the ICI rolls of all entities with no actual exposure to trade will offer an immediate reduction in residential, and small business, electricity costs.

5. Review/Cancel Contracts where possible

I've purposely de-emphasized contracts as there's a lot of conflicting information about what could be done. Whatever action is taken on contracts, I believe the outcome will be uncertain.
Successful actions to reduce contracted costs would require the GEA first be revoked.

The most interesting work I've read on revising contracts is by Professor of Law at Queen's UniversityBruce Pardy, FIT to be Untied: How a new provincial government can unravel Feed-In Tariff electricity contracts. The work was published by the Council for Clean and Reliable Energy which include this in describing it:
Cancelling long-term electricity contracts or imposing a royalty or other tax is a legitimate legal step that a newly elected government could take.
Worth looking to - and I would recommend doing so with an eye to Spain's history in addressing its so-called tariff deficit, with particular attention to their tax on the value of electricity output (TVEO).

The topic is too complex for me to offer an opinion on possible savings, but I can offer some figures for contracted projects that have not yet entered commercial operation, which are therefore likely the highest priority to review (before more money is spent on their development).

The two single most expensive feed-in tariff contracts are yet to enter service. The second most expensive project is the Henvey Inlet Wind project, which was offered a contract 7 years ago, with the expectation it would be in service 4 years ago, and has now missed a revised Milestone Commercial operation date. Not only have costs fallen significantly since that contract was offered, the turbines ordered for the project will produce at a capacity factor beyond anything which was possible in their wind conditions when the contract was offered. If rates from the initial contract signing in 2011 have not been reduced in the interim I anticipate this project will cost ratepayers $126 million a year, totaling $2.5 billion over the 20-year term. The most expensive contract would be the offshore Wolfe Island Shoals project, which was granted a contract before a ban on industrial wind turbines in the great lakes was introduced. Revoking all incomplete FIT contracts might be useful in making sure this project stays dead.

Far lower price tags are attached to more recent contracts, but at least a couple of the more recent Large Renewable Procurement are in locations already seeing enormous curtailment - particularly during periods where the interconnection with Michigan has operated at reduced capacity. In other words, the contracts are for supply that will be overwhelmingly dumped or curtailed. The new government should review all projects not yet at the "notice to proceed" stage.

It would be nice if some savings could be found in the contracts that caused the need to look for savings.

6. Make a Versailles

A problem in solving the problems that created the inflation in pricing is that most "stakeholders" in the realm of Queen's Park are complicit in creating them. People there since the GEA alliance started lobbying are people with a decade of experience in bleeding consumers - and not much else. While there is only one functional industrial wind turbine within 65 km of the legislative buildings, Mr. Smitherman was correct in claiming, "There is [now] a big cluster of renewable related jobs in the downtown core of Toronto.” The people in the jobs are the ones who wrote the contracts, financed the projects, and the courtiers that lobbied to drive costs onto ratepayers to benefit other bureaucrats, such as those at municipalities, and schools. The culture of these so-called "stakeholders" will be the biggest impediment to addressing costs.

Moving as much of the decision making apparatus out of Toronto's core should aid in avoiding wasteful contracting and transfering of costs onto common residential, and small business, consumers.

Towards a lasting fix of Ontario's Electricity Cost issues

Whatever actions are taken on costs the new Ford government should maintain a proper perspective: the system now is clean, and it does get electricity delivered.

The situation is not dissimilar to 1994, when a couple of years of double-digit price increases occurred as Darlington units entered commercial operation after demand had been reduced by recession. What followed then was a freezing of rates, and spending, that eventually saw 8 nuclear units idled, coal generation surge, and supply adequacy problems to appear within a decade - unfortunately coinciding with the opening of what was planned to be a market.[10]

That market never did get to balance supply and demand. Rate freezing shortly after open discouraged any new entrants, and by 2005 government returned to central procurement. Market pricing, however, remains indicative of the relationship of supply and demand. The Hourly Ontario Energy Price remains very low because Ontario has an excess of supply.

The problem of excess supply is compounded by the industrial pricing policy requiring a very low market price - which requires excessive supply.
An easy fix from some tinkering is not available.

Some possibilities for a move to a meaningful, efficient, system exist. One was tried when Ontario Hydro was broken up in 1998 - identify stranded debt and attach a charge to consumers to pay it outside of market pricing mechanism. Early in 2017 I estimated the wind and solar contracting had produced a net liability of $38.1 billion - which is a shockingly high figure, but not a surprising one for those who follow Germany's experience (from whom we copied feed-in tariffs and the Green Energy Act).

Germany's EEG surcharge, and its exemption of trade-exposed industry from that surcharge, may provide a model to return the market to providing more meaningful pricing and exempt trade-exposed industries from the worst contracts.


2. Articles of relevance that I've produced:
3. Planting the seeds of green energy | John Spears | The Toronto Star

4. Quote originates in Going green: Does Ontario’s energy shift have the power to sustain itself? | Richard Blackwell | The Globe and Mail - but I've copied it from where I've previously cited it in Beyond expectedly high cost: 2015 Ontario Electricity Summary Part 3

5. Brian Hill and Carolyn Jarvis recently reported on the government ignoring pricing advice in Billion dollar ‘mistake’: Ontario Liberals ‘hijacked’ plans for sustainable green economy An Earlier Auditor General's annual report, for 2011, had also noted the cost of ignoring pricing advice from the Ontario Power Authority.

6. In 2016 solar and wind generators added $3.18 billion to the global adjustment ($2.48 in 2015). In each of 2016 and 2017 market sales likely recovered  approximately $200 million.

7. The number is deceptive as generation embedded in distribution networks, such as most solar, is not included in the calculation. The IESO's "Ontario Demand" is essentially demand from generators operating on the IESO's system - so much of the newer generation escapes reporting while lowering the IESO's reported demand.

8. There is some guess work in matching generators to nodes. My placement of generators within nodes can be viewed using the filtering tools in my Annual Facility Generation (2003-2017) reporting. Weighting the generation from generators to the hourly nodal pricing results in these annual hourly averages for each node.

9. I've written on the scheme many times, most relevantly in "Stakeholders" destroying the viability of Ontario's electricity market.

10. Capacity reductions will occur over the next decade: 900 MW essentially disappeared when Darlington's unit 2 entered refurbishment last year - when it returns 2 more units are planned to enter refurbishment, and the next year a third - and the closing of units at Pickering is to begin. Ontario's nuclear capacity likely peaked by 2016 - it was effectively reduced by 900 MW for 2017, will be reduced by another 850MW for 2020, 900 more in 2021, and another 1000 MW by 2022's end.


Monday, April 16, 2018

Carbon-Con: ECO communication

A couple of weeks I was asked about potential ways to collaborate with reputable sites. I put some thought into that before responding that simply an association with me could bring a site to disrepute, but my thoughts on communication persist. From the belligerent uttering of a federal Minister on a Sunday talk show, to a media blitz from an organization marketing itself as expert on economic tools to reduce carbon emissions, to the Ontario report I'll feature in this commentary, it's been as if a convention of climate change alarm is occurring.

A Climate convention.

Comic Con (short for convention) is a really big event now, which makes some sense in this era of communication. Text is a low impact medium - the sites adding audio and video, integrating with podcasts, have a huge advantage. As the comic and related genres (science fiction, fantasy and superhero) grew from print to screens of all sizes, the graphics and sound growth has simply piled success onto success. The term "simply" recognized almost all characters can be grouped into good or bad.

Perhaps due only to my musing about communication, collaboration and branding, I thought the polarized nature of climate, and energy discussions, make Comic Con a model for communication and promotion in the 'clean tech' industry.

I'd prefer to be a hero, but realize the model needs villains too.

What I hope will be found in my little section of this Carbon Con is data-driven iconoclasm delivered thorough research, competent data handling, pointed if not visually appealing graphics, and full contact criticism of those blissfully unaware they deserve to be blisteringly opposed.

What many will find is villainy - I've been accused as anti-wind, anti-renewable, anti-conservation, pro-nuclear, disrespect and misogyny. I don't agree with that entire list, but I'm okay with being the villain if it makes for better heroes.

My concern with the profession of professing concern about carbon emissions begins, as most things do, with religion.

Monday, April 9, 2018

Base load and baseload generation

The term baseload gets thrown around frequently but seldom is associated with a base, or minimum, load. It occurs to me the level of knowledge in discussions on electricity supply could benefit from reviewing the level of total electricity that would be met by a mythical generator running throughout at a the year at the minimum system demand. The results are not surprising,but the current level of discourse indicates the results are not intuitive.

I’ve revisited hourly load data I’ve collected over the past year for two provinces and British Columbia (bce … or BC). Each data set measures “load”, or demand, differently, but the particulars are not important for this simple review. For each province’s data set, I’ve queried the minimum annual load along with the average. Upon reflection it’s obvious that the minimum load divided by the average load produced the percentage of annual supply that could come from the steady production of the minimum load.

Differences between years are minimal, but the difference between Alberta and the other 2 provinces is significant. Alberta’s flat load profile means 80% of annual generation could usually be met by consistent supply at the base load level. “Alberta Internal Load”, or AIL, is the statistic used, and it includes behind-the-fence generation which is large due to extensive cogeneration, particularly from oil sands operations. Large industrial loads tend to be far more consistent than, particularly, residential demands. In Ontario and BC the reported loads, which omit behind-the-fence generation, indicate over 2/3rd of supply requirements would be met by output at the base load level.

For reasons I’ll return to in discussing implication of this base load supply level review, I ran some figures estimating how much usable supply would come from increasing the base supply level to 10% above the annual base load level, and with base supply 20% above base load.

Monday, March 5, 2018

Transmission constraining Ontario's Niagara Hydroelectric potential

I was recently asked why I claim there are transmission constraints on electricity generation from Ontario Power Generation (OPG) Niagara river system generators.

I’ve written a number of times on production levels and argued the constraints largely because I have consistently found the actual output from OPG’s 5 Niagara system generators less than it could be. There are current reasons to revisit the issue:
  • In 2017 the total was 11.32 TWh[1], which is probably the lowest level since I first appeared, in 1965,
  • OPG reported 4.5 TWh of "forgone hydroelectric generation" due to surplus baseload generation (SBG) in the first 9 months of 2017, up 15% from 2016 when OPG's annual foregone generation was 4.7 TWh, 
  • OPG intends on adding 106 megawatts of capacity through an overhaul of  two idled old units at the Sir Adam Beck I Generating Station
I’ll review the annual generation data but acknowledge the lowered generation doesn’t prove a transmission constraint - so I’ll also build a timeline demonstrating increased transmission was deemed necessary a decade ago, and the need must have grown significantly, along with generating capacity in the region, since then.

My curiousity on the topic of foregone generation was piqued in June 2011 by an article in the Buffalo News.[2] The article discussed Canada’s inability to utilize all the water it had rights to in generating electricity on the Niagara river, and OPG's Niagara Tunnel project that was to address that, increasing generation by 1.6 TWh. In March 2013 the tunnel was declared, by OPG, to be in-service.

By 2014 I was utilizing Hourly Generator Output and Capability reporting from Ontario’s system operator (IESO) to collect data on individual generators[3], and U.S. Energy Information Administration (form EIA-923) data for the generators on the U.S. side. The comparisons showed OPG output falling far behind the U.S. generation on the Niagara river[4] - a trend which has since, surprisingly, accelerated.

When the output at OPG’s generators did not increase after the Niagara tunnel project completion, I looked for other causes.

Thursday, March 1, 2018

Review of 2017 electricity supply in Ontario

You purchase a  full 9-unit container of energy .
The 3 men who deliver it pour out 2 units out while lecturing on consumption. 
They imply you should make more yourself as they leave.

A couple of months have passed since I last posted to the blog. This may be due to writer's block, or a lack of ambition - or maybe I was wisely waiting until I had something nice to say!

With growing knowledge, and curiosity, I seem to muddle all little issues into the broad themes I deem important - and not only for energy. In this post I'll touch on metrics from 2017 the reader may be looking to this blog to find, with hopes of connecting the data to bigger issues.

There are many possible headlines from an annual analysis:
  • electricity "demand", as reported by the system operator was down, to levels not seen in decades
  • supply generated from fossil fuels (natural gas) was sharply down too, and again to levels probably not seen in over over half a century
  • prices for consumers on regulated price plans were sharply down in 2017 due to legislation and consequent debt (the [un]Fair Power Plan), but,
  • total costs for supply declined in 2017, although average unit cost was up slightly (as demand declined more)
  • nuclear supply was down as one unit (Darlington 2) was out of service for the entire year due to refurbishment, but the units remaining online largely took up the slack as Bruce Power had record output, as did the set of 9 units at Ontario Power Generation which operated during 2017, and
  • for the first year since the system operator reported on their system's wind output, in 2006, it reported a decline (albeit a very slight one)
I didn't wish to dwell on numbers in this post. During 2017 I learned some new data reporting tools which I put on on a site where I invite data-gluttons to learn the filters and views to generate the typical year-end summary statistics, such as the total annual biomass generation for the past decade.
I do wish, in this post, to combine commentary to statistics to demonstrate very good figures from one perspective can have bad implications from a broader perspective. This is particularly important to note as the reasons rates didn't rise sharply in 2017 aren't sustainable.

Friday, November 17, 2017

A benefit of Electricity trade - and what's reducing it

I was wrong.

I've been broadcasting a couple of messages about Ontario's electricity exports: that only the IESO can accurately report on the revenues, and that exports at negative prices are not allowed under market rules. It now seems neither of those is correct. Not only can export revenues be calculated, the analysis of export volumes, and revenues over time reveals benefits of markets, and trade. It's not at all clear Ontario's electricity powers understand the benefits.

I was recently alerted to a claim that the export revenues could be calculated from Intertie Schedule and Realtime Market Price reports. If that sounds confusing it'll gets worse before I'll try to ease off the jargon. As the Intertie Flows reporting is hourly, and the Realtime Market Price reports in 5 minute intervals some data manipulation is required to match the data sets. The IESO has posted annual files (.csv) with values from each of these reports for 2010 through 2016. To dispatch with the technical talk in one confusing swoop, I'll simply note that averaging the "ENGY" rate by delivery hour for each control area in the Realtime Market Price reports, and multiplying that by the "OFFT" value in Intertie Flows report for the same control area does result in the annual figures the IESO has released either to the Office of the Auditor General or in response to Freedom of Information Requests.
I can now extend my work from a previous post to include 2016 data.

Having worked the data down to the hourly time-frame by control area I can additionally summarize revenues, and costs, by jurisdiction. The results have some important messages about trade - as each "control area" has a separate market control price.

I won't discuss imports much in this post because there's nothing new to discuss. Most imports into Ontario are now from Quebec (over 82% since 2012 began), and those are valued in the new analysis almost exactly as the typical Hourly Ontario Energy Price (HOEP) valued them.

Messages about trade from this analysis may be hidden by the realities of communicating summaries of very large data sets. I posted some graphics on hydro(electric) generation by river system, and I received an e-mail from somebody who likely wanted to pursue a story, asking if the data was public knowledge. It was every bit as much public knowledge as what I am writing on today - summarized from hourly data captured from IESO hourly reporting since 2010. However, as most can't process the hourly information, and an official source had not published a summary, it wasn't the basis of a story. I think publication of a summary by an official source is what is required to be considered "public available".

The IESO once summarized volumes and revenues for exports and imports on a web page at (long since a dead link). These monthly totals were meaningfully publicly available as they were both available and summarized by a trusted figure. Remnants of the IESO summaries remains in old government press releases, such as this from May 2012:
"Ontario's electricity market generated over $20 million in April by exporting electricity to other states and provinces, bringing total net export revenues to over $75 million this year.
That figure was, in hindsight, actually net exports ($28.6 million revenue from exporting less $8.1 million importing cost). In 2012 I noted:
[my] figures on export sales are estimates based only on the [Hourly Ontario Energy Price] ... in actuality export customers pay different rates. Because Ontario's market pricing is lower, sometimes much lower, than adjacent jurisdictions, it appears from both the ministry 'news' releases, and National Energy Board reporting, we generally export power about 10% above the HOEP  rates.
10% was the assumption I had when the IESO ceased summary reporting, but with the base data now summarized, I now know that assumption became wrong as they moved up and up, to nearly 70% above HOEP valuations by 2016.

Thursday, November 9, 2017

Alberta. Bound.

The government of Alberta has a plan to "reduce carbon emissions."
Their plan restricts the ability of the province to efficiently minimize greenhouse gas emissions.

The three aspects of the Alberta's "Climate Leadership Plan" most relevant to the electricity sector are:
  • implementing a new carbon price on greenhouse gas emissions
  • ending pollution from coal-generated electricity by 2030
  • developing more renewable energy
I've seen my province - Ontario - cited as an impediment to growing renewable energy in Alberta. This is understandable from a cost perspective, but if reducing emissions were the primary goal Ontario's example would be encouraging, as its emissions from generating electricity are a fraction of Alberta's.

I realize most Albertans are not awaiting opinions from Ontario, but I'll trust my analysis will be of interest to some in Alberta, and some elsewhere. Alberta is simply the sample case I'll use to argue specifically banning coal-fired electricity is unnecessary, and quotas for renewable sources to provide a fixed percentage of supply a little worse than that. This is not to argue for coal or little supply from renewables. Functionally, what I'll point to as better policy is likely to result in similar outcomes. I intend to demonstrate rules are being gamed to predetermine an unambitious outcome at the expensive of achieving greater things.

A brief review of Albert's electricity system will be helpful prior to discussing the growth of renewables and elimination of coal. 

Figures are collected from AESO annual market statistic files (year 2013-2016) 

Available figures for Alberta's electricity generation include the percentage of electricity produced by generation technology. Unfortunately some categories change in 2010, but whether 2016 is compared to 2010 (the earliest year of the current categories) or 2004, coal has lost the greatest market share, and it has lost it to wind (probably the greatest change since 2004, natural gas (Combined Cycle gas turbines had the biggest 2010-2016 growth) and "Cogen" (for co-generation). Coal does continue to have 60% market share by this measure, so adding renewables until they have a 30% share seems doable - but it's more difficult depending on the definition of the market.

Sunday, October 15, 2017

A gathering in Prince Edward County

Today in Picton people will assemble at a rally against what has become a 9 turbine industrial wind development in a ecologically sensitive area near Lake Ontario. I won't be attending as it's a 3-4 hour drive away, but I will contribute by arguing the existence of the contract for the location, at this time, is indicative of negligence at Ontario electricity system operator (IESO).

Details at the Prince Edward County Field Naturalists Facebook page
This rally coincides with a legal action launched by the Association to Protect Prince Edward County (APPEC). 
APPEC has commenced legal proceedings naming the Independent Electricity Operator (IESO) and WPD White Pines Wind Inc. (WPD) as respondents. APPEC alleges that the Feed-In-Tariff (FIT) contract between the IESO and WPD should have been terminated as soon as it became evident that WPD would be unable or incapable of fulfilling the FIT contract terms. These FIT contract terms have been made publicly available and are well known.
In 2010, a FIT contract for 60MW wind energy project to be operational within three (3) years was offered by the Ontario Power Authority (now the IESO) to WPD. The contract allowed for termination if the project was not able to deliver at least 75% of the contracted power.  -APPEC (on Facebook)
The inability to deliver 75% of contracted capacity is but one of the reasons WPD cannot now fulfill their end of the feed-in tariff contract.