The Capacity Trap: Ontario's Electricity Costs Soar as Emissions Drop

Ontario's market has inflation of over 20% each of the past 3 months.  The price drivers are now well known: adding supply to an already oversupplied market; exporting more electricity at rates well below the prices paid to suppliers, and capacity payments to natural gas and coal-fired generators. Nonetheless, when driving down into the data, I am astonished by the punishing reality of Ontario's electricity design: the cleaner our supply, the higher the price.

If limiting greenhouse gas emissions is the goal, the system is increasingly designed to fail.

Ontario fell into paying capacity payments over time.  The key moments were a 2004/05 decision to offer "net revenue requirement contracts" to natural gas-fired generators - primarily to encourage market entrants to displace coal-fired generators.  The enormous Lennox Generating station became less utilized and uneconomical - but the system operator felt it was necessary to the system and it started to receive contingency support payments soon after.  In 2008/09 demand dropped with the recession, and the coal-fired generators (also felt necessary by system operators) also began receiving contingency support payments.

Graphic from Behind the Switch .... | The Pembina Institute

Other types of contracted supply exist: non-utility generators have managed to have secret contracts for 2 decades, but it's generally understood most have must-run contracts to take all supply at a fixed price, which is also true of contracts for variable renewable energy sources (vRES - wind and solar), private hydro supply, and private nuclear (Bruce Power).  The largest public hydro, and nuclear, generators have rates set by the regulator.

Traditionally, all numbers related to producing electricity are thrown into a calculation and out pops a levelized unit cost.  The graphic displays some estimated ranges for these costs (they aren't reflective of costs in Ontario for legacy hydro and existing wind contracts)

Looking at the data from May-July 2013, and the same months in 2012, reveals the magic impact of capacity payments as replacing high cost generation with low-cost generation drives up Ontario's electricity rates.

The average cost of a unit of electricity in Ontario is up 19% over the same period in 2012 [1]: export customers, and perhaps large "Class A" consumers are protected from much of the increase, so the average Ontario consumer will see rates up approximately 23.5% for the period [2]

My estimates for the period in 2012 [3] indicate that, using a levelized unit cost, natural gas and coal were far more costly than nuclear and hydro supply.
In 2013 overall production drops (not as much as demand), but hydro shows strong growth, with nuclear showing the second largest MWh growth.

While the two lowest cost domestic generator types showed the strongest growth, the largest declines came in the far more expensive - using levelized costs - natural gas (primarily) and coal-fired generators.  

There are other notable changes between the periods in 2013 and 2012, including lower exports (the cheapest supply), a suspected large, but unreported increase, in solar generation, and continuing government interference with the sector likely seeing costs of their bungled political gas plant cancellations passed onto ratepayers - but the 23.5% wholesale rate increase is partially due to a decrease in production from the higher carbon emissions, higher priced, fuels we wish to move off of.

This is due to capacity payments.
During the 3-month period in 2012, units with net revenue requirement contacts produced approximately 3.6 million MWh of electricity [4]; their payments would have been comprised of approximately $220 million guaranteed by the net revenue requirement and $32.33/MWh for the production (the average  HOEP weighted to the generators' production).  The average cost was ~$93/MWh.

In 2013 the production for May, June and July dropped 56%, to ~1.6 million MWh, but the net revenue requirement changes little, and the average cost received from production (HOEP) moved up only ~$5/MWh.  The average, levelized, cost nearly doubled in climbing to ~$174/MWh.

During the 3-month periods being compared, I estimate the output of solar, wind, nuclear and hydro generators increased by 2.6 TWh (2.6 million MWh) while the output of coal and gas generators dropped by 2.8TWh [5] - so I will assume a zero-sum game, where every unit of production with one source displaces a unit of production from the NRR gas generators, with a value of $37.41/MWh (my estimate of the actual weighted average HOEP for the NRR gas generators for the period in 2013):

• Hydro production increased 1.4 TWh - at a $39/MWh rate that adds $2.2 million to costs
• Nuclear production increased 0.85 TWh - at a $59/MWh rate that addes $18.4 million

The hydro figure, in particular, indicates the absurdity of the market design, where replacing supply at half the levelized cost, and 0% of the emissions, causes a rate increase. The same mechanism likely prevents customer demand management programs from achieving expected savings.

• Wind production increased at least 0.165 TWh - at a $135/MWh rate that adds $16 million
• Solar production increased an estimated 0.189 TWh - at a $500/MWh rate that adds $87 million.

No surprises with the variable renewable energy sources (vRES).  The higher the rate is above the fuel required to generate the same amount of electricity, the harsher the rate impact.

Ontario's system will probably lead to high emissions, eventually, as the value proposition to consumers, also known as voters, is structured to encourage the use of facilities guaranteed revenue and therefore only having fuel costs as an incremental expense.
Ontario's system clearly demonstrates some truths being stated more often, exemplified by Schalk Cloete in The Fundamental Limitations of Renewable Energy:

...renewables need to overcome the following two challenges in order to displace fossil fuels in a fair market:

• Solar panels and wind turbines need to become cheaper than raw fossil fuels. This is the challenge posed by the diffuse nature of renewables.

• Storage solutions need to become cheaper than fossil fuel refineries (e.g. power plants). This is the challenge posed by the intermittent nature of renewables.

Ontario's procurement contracts have made all generators need to be cheaper than "raw fossil fuels" - which is simply bizarre.

If one were to think of designing mechanisms to reduce carbon, due to the perceived cost of externalities from burning carbon, taxing carbon would be a better approach.  Carbon taxes are not going to do much to spur wind and solar generation - nor should that be the intent.  The intent should be on enforcing a discipline to cost the externalities of the concern driving policy, and to align an economic desire to reduce cost with the desire to reduce emissions. Without pricing, the desire to reduce emissions is not economical, but only political.

Fortunately for the bulk of the people struggling with energy questions, it is possible to learn from a bad example.  Annual 20+% inflation in Ontario is one more indication must-take power purchase agreements for the politically preferred, combined with capacity payments for the operationally required, are bad policy.





Endnotes

[1] The average cost is estimated, from IESO data, by multiplying the hourly "total market demand" by the "Hourly Ontario Energy Price", summing the value for all hours, adding in the total value of the global adjustment, and dividing the total by the sum of "total market demand" for the period.

[2] The increase is in the Class B customer "commodity charge" which is indicated in the IESO's monthly reporting (on the second to last page).  Most residential consumers will not immediately pay this rate, but the regulated price plans attempt to be set to match the Class B totals for a 6-month period; the big increases this summer were not indicated by the summer's RPP rates, so significant increases are likely to be felt as new rates are set for the winter.

[3] The estimates are explained on the supply cost page of my data site

[4] The sites I've included in estimating "unites with net revenue requirements" are: Brighton Beach, East Windsor, Goreway, Greenfield, GTAA, Halton Hills, Portlands, St. Clair CGS, Thoronld CGS and York.

[5] The majority of the reduction, 2 TWh, was at the generators listed in endnote 4

Putting lights on the blackout of August 2003

Some thoughts, and data, on the blackout of 2003, influenced by the perspective of my recent work on long-term energy planning issues.

August 14, 2003 had the 3rd highest daily peak of the summer of 2003 - peaks were higher in the winter back in 2003 and 2004 - unlike today.  Many of the articles written a decade after the blackout pretend it was primarily an Ontario event largely driven by a supply shortage, despite widespread acknowledgement it was a cascading failure starting in Ohio.

It's important, for future planning, to address some of the issues being raised, generally by lobbyists, about that blackout.

We were importing at the time of the blackout - importing about 2130MW.

Is that a bad thing?
Our neighbour, Quebec, has a winter peak of around 37,000MW and Ontario has a summer peak of about 25,000MW.  It's not clear to me it is bad to expect to be an importer during peak summer periods.  It is, in my opinion, irresponsible to claim importing was an issue when it was not, partly because it may be that peak summer demand should be met with imports.

Not that in 2003 the idea was to count on imports.

In my previous post I quoted the 1993 head of Ontario Hydro stating, "In light of our current surplus capacity, which we project will continue for the next 10 years ...."  Ontario Hydro had later stopped 7 of it's nuclear reactors, but the government was hopeful a number of them would be back in service for the summer of 2003.

Unit 4 of Pickering A returned to service in September 2003, Bruce A's unit 4 followed in November 2003 and unit 3 followed in March 2004; altogether these reactors provide approximately 2000MW of capacity - essentially equalling the imports at the time of the blackout.

the right axis indictates the average hourly net export MW

There are other articles that note a contribution from conservation in avoiding more cascading blackouts since 2003.  Conservation may be contributing, but the numbers show that while the annual demand is now lower, 2013 actually has experienced a higher peak demand than 2003.

Average demand is down about 7% since 2003 while peak demand is up 1% according to IESO figures for "Ontario Demand."  [1]

Other IESO data indicates that roughly 2/3rd's of the decline in annual consumption is due to the wholesale sector - presumably dominated by a dwindling industrial sector.

There are more households/people, so there is a real reduction in per capita consumption - but the reduction is primarily ouside of peak demand periods.  Just as the issue with tight supplies in 2003 was primarily high emissions from the fossil fuel plants, the issue with conservation may be it is most effective in the periods it is least necessary.

I take 2 messages from reviewing the blackout:

• tight supply margins are created years in advance - in 2003's case these margins didn't cause the blackout
• a reliable grid is probably more important than plentiful domestic supply.

Endnote

The IESO figures aren't actually for demand but supply,and the figures greatly underestimate demand this summer because they don't capture much of the newer wind generation, and absolutely no solar generation is included.  

Wynne should right Duguid's wrong NUG directive

Premier Kathleen Wynne's first 6 months in office was characterized by an acceleration in the activities she feigns concern over so well - more wind turbine projects than ever before are being approved and another suburban seat has been bought (this one with a subway - they'd already cancelled the possibility of the wind turbines off the bluffs to protect their Scarborough seats prior to the last election).
Meanwhile, the cancelled/relocated gas plant scandals continue.

The government response has been to force the energy bureaucracy into a summer of assigned 'conversation' with the small subset of Ontarians deigning to converse with it.

The Premier would find more conversational partners, if she cares to find them, by actually doing something to halt an expensive, backroom-born, opaque, emission generating, electricity ratepayer-punishing, decision from the McGuinty era.

Here's one:

To support the objective of clean and efficient electricity generation and to help ensure electricity system adequacy, the Ministry of Energy (the “Ministry”) has determined that it is advisable to pursue the initiative of seeking new contracts (the “New Contracts“) for the non-utility generators ...    -Nov. 23, 2010 Directive to OPA from Mister of Energy Brad Duguid

• Brad Duguid (pronounced "do good") was the minister that announced the Samsung deal.
• Brad Duguid was the minister in office for every industrial wind turbine contract ever offered under the feed-in tariff (FIT) program
• Brad Duguid was also the minister when a moratorium on offshore wind was announced
• Brad Duguid was the minister when the Oakville Generating Station was cancelled
• Brad Duguid was the Minister when the Liberal campaign promised to cancel the Mississauga gas plant 

Duguid was a central figure in many of the poor decisions that have the current government in constant crisis control mode, but the worst directive of his stint as Minister of Energy may be the direction to extend the NUG's.

The Origin of Ontario's Non-Utility Generators

The 1980's, and early 1990's, were a time in Ontario's Electricity sector history when massive projects, primarily nuclear builds (Pickering B, BruceB and Darlington - in that order) were underway as demand growth unexpectedly slowed (it's been slowing for 6 decades and it's still somehow unexpected).  Rate impacts for new projects then, as now, couldn't take effect until the project entered service, so as Darlington was repeatedly delayed, and cost escalated, concern started to build about the costs of electricity in Ontario, but concerns also grew about the power planning process in Ontario.

In December 1991 the new head of Ontario Hydro, Marc Eliesen  (installed in the position by a new NDP Premier, Bob Rae) spoke to The Empire Club of Canada and spelled out the rationale of contracting non-utility generators:

The changeability of the future suggests to us that megaprojects are becoming less of a credible answer. They are a huge capital drain and carry a great deal of financial risk.
When the future is uncertain, it's better to count on smaller increments that track growth in electricity demand more precisely, and don't pose such a rate shock when they come into service. Their environmental impacts should be smaller- or at least more localized.
That's an important reason why, by the year 2000, we expect non-utility generators will be able to meet 14 per cent of our system load requirements.
When Hydro filed our 25-year plan in 1989, we were counting on 1,000 megawatts of non-utility generation. Since then, we've announced new targets. We now expect 3,100 term. Response from the private sector has been overwhelming. We are malting deals with as many proponents as we can fit onto the transmission system.
Projects involving cogeneration are getting preference, for environmental and economic reasons. Clearly, cogeneration efficiencies of up to 80 per cent reduce overall energy use and environmental damage.
And it's clear to us at Hydro that industries that generate revenues along with energy will be able to compete better against their global competitors. And by avoiding major new investments for Hydro, they will help make our province more competitive.

By the time Mr. Eliesen delivered this speech 1989's 25-year plan was already outdated; a deep recession had gutted demand from levels already lower than anticipated when the "megaprojects" of Pickering B, Bruce B, and Darlington were initiated.  The inertia of bureaucratic plans was still masking the obvious from Eliesen.
During a recession the target was tripled because it was plausible to argue the projects were good for business and "green": cogeneration provided a more efficient use of gas, and some projects used exhaust gases from TransCanada's pipeline to generate power.

16 months later his successor at Ontario Hydro, Maurice Strong, spoke to the same club and announced something quite different:

In light of our current surplus capacity, which we project will continue for the next 10 years, Ontario Hydro cannot commit to developing new capacity, to extending existing capacity by retubing the Bruce A reactors, or purchasing new supplies from non-utility generators at a time when we don't need the power. To do so would result in unnecessary rate increases at a time when our customers can least afford them.

As Ontario ended the NUG strategy that would make industries "able to compete better against their global competitors," it started to recover and move to a much stronger economy.

The Long-Term Cost Implications of the 1990's NUGs 

When Ontario Hydro was broken up, it's liabilities were either deemed backed by assets, or deemed to form an unfunded liability to be managed by the Ontario Electricity Finance Corporation (OEFC).

The OEFC's first annual report showed at formation an unfunded liability of $19.433 billion, of which $4.286 billion was due to the expensive NUG contracts.

By 2005 the market had been launched, a government had cowered and frozen rates, and the newer Liberal government had, under Minister of Energy Dwight Duncan, introduced the global adjustment mechanism which created a method to recover from ratepayers, on a monthly basis, the full costs of electricity contracts, including the NUG contracts.

The 2005-06 OEFC annual report included:

Effective January 1, 2005, the OEFC started to receive actual contract prices for power sold under legacy Ontario Hydro Power Purchase Agreements (PPAs) with the non-utility generators (NUGs), as well as related administrative costs, and is no longer incurring losses on these contracts, effectively eliminating this liability to the OEFC.

But the"statement of financial position" did not eliminate the liability, only reducing it to $3.389 billion. [1]


The NUG's in the Integrated Power System Plans

The last version of the Ontario Power Authority's Integrated Power System Plan, in 2008, saw expiring non-utility generator contracts as an opportunity for flexible resources in Ontario's supply mix:

When gas-fired resources are used, they are generally planned to be SCGT, to meet peaking requirements, or CCGT, to meet intermediate requirements...There are also a number of gas-fired generators, known as non-utility generators or NUGs, which are assumed to operate as baseload resources because of the contractual terms of their current NUG contracts. The Plan assumes that for the NUG contracts that expire by 2015, the associated capacity will continue, but will meet intermediate and peaking load requirements, depending on whether the NUGs are CCGT or SCGT resources, respectively.

Environmental Concerns

The Environmental Commissioner of Ontario recently blogged "We could have carbon free electricity in Ontario in 2014!"  His conclusion indicates he is not aware of Minister Duguid's direction to extent the NUG contracts

...about 1000 MW of gas-fired generation is under contract to non-utility generators in this province who burn gas continuously 24/7 if they want to and they typically do. So, it is nice to think about the possibility of carbon free electrical generation but until we build that option into the structure of our long-term electricity plan it will not happen. - Environmental Commission or Ontario Gord Miller

Currently

This weekend the Independent Electricity System Operator (IESO) Hourly Generator Output & Capability report showed natural gas-fired generation reduced to ~500MW, which coincides with about 1/2 the NUG's being curtailed for the weekend (because the OEFC holds the contracts, curtailment is scheduled ahead of time and generally for a weekend).

It appears Ontario's ratepayers may be charged for the NUG production that was curtailed while Ontario's atmosphere received emissions from the NUG production that wasn't curtailed during off-peak hours, and during on-peak hours we didn't get the emissions from the inflexible NUG's but instead got a full component from coal-fired generation !

Conclusion

NUG's provide inflexible, expensive, greenhouse gas emitting generation.  They were originally contracted under a false premise that megaprojects were more expensive than multiple small projects nobody paid much attention to; they provided about 6% of the supply mix as Ontario Hydro was broken up but accounted for ~22% of the unfunded liability Ontario's ratepayers were left to deal with.

Some NUG's provide a benefit to the natural gas pipeline business - and it's somewhat obscene that electricity ratepayers are funding the natural gas industry this directly.  

Ontario claims to be consulting on a Long Term Energy Plan, yet it again deals primarily with electricity.  

Electricity CO2 equivalent emissions are less than the emissions from fossil fuels providing residential heating.  Most Ontarians that opine on energy don't seem to realize our peak use is in winter; electricity peaks in the summer but that peak isn't much different than other months, whereas natural gas use soars in cold weather.

There is no justification for spiking electricity rates higher to subsidize gas heating and the operation of gas pipelines, which leaving explanations of extending non-utility generators' contracts ranging from incompetence through consultation processes hopelessly skewed to favour lobbyists/"stakeholders" and at the most unseemly end, corruption.

Dealing with the ridiculous NUG directive would provide an indication that the Premier really does want to have a meaningful discussion about the electricity sector; without some meaningful action, her claims to want to have a conversation only indicate a desire to appear to care.

LTEP Tools: Calculating deception

Ontario's government is currently presenting an appearance of consulting on another iteration of a long-term energy plan (LTEP).

Ontario's Ministry of Energy now has a web page with a graphical tool for designing a portion of Ontario's 2025 Energy Mix: Power Play: Make Your Electricity Mix.

Ministry of Energy Power Play tool

It's understandable the Ministry would not wish to get stuck in debates over numbers, so a simple, entirely graphical, presentation is prudent in avoiding complicating contributions to a legitimate conversation.

The Power Play tool caught my interest as I have been designing an energy mix calculator to assist me - and anybody who cares to download it - on a separate site.

Neither 2003 nor 2005's supply mix met reserve requirements

In order to meet NERC requirements for comparison purposes,

natural gas generation was added in the "+" models

A dishonesty in the Ministry of Energy's tool is the choice of meeting demand requirements with supply that cannot meet demand requirements. Specifically wind and solar generation (or vRES, for variable renewable energy sources).

The reason vRES cannot independently fulfill needed generation is contained in Table 4.1 of each forecast from the Independent Electricity System Operator (IESO), where each type of energy supply has a "Forecast Capability at [seasonal] Peak."

The IESO forecasts peak demand and that peak demand forecast is reported to the North American Electric Reliability Corporation which has a "Reference Margin Level" of 20.2% for the IESO's region (page 21).

There is a number a supply mix needs to hit that is not for total generation (such as the 155TWh imagined in the Ministry's Power Play tool), or for total generating capacity, but is instead the figure for the "capability at peak" - a figure sometimes referred to as a sources capacity value.


All these figures are incorporated in the calculator that produced the figures in the first graphic in this post as I ran some historical supply mixes through my calculator to test it.

The emissions intensities in the model are very low compared to what they have actually been, which is a function of the model used by the calculator, and of the realities of interconnected markets. The model uses all available natural gas generation before turning to coal-fired generation; in reality the market does not.  The market is also not contained to Ontario, and Ontario's guarantee of capacity costs for the majority of it's gas and coal-fired production contribute to the province being a cheap place for external markets to purchase electricity.
In a recent 12-month period approximately 10TWh of fossil fuel-fired generation could be attributed to generation for export markets.

Finding the calculator useful with the historical mixes, I turned to 2025, and the Ministry of Energy's Power Play tool's supply assumptions, and options.

I did add enough generation to produce another 20 TWh of annual production, and I changed my demand forecast to 155TWh (my previous post on conservation in the LTEP shows I disagree with the Ministry's higher forecast).  Surprisingly, to me, my assumptions about the generation currently committed to for 2025 could produce 134TWh of the 135TWh the Power Play graphic shows as existing.

Surprising because my understanding is the only nuclear capacity firmly committed to for 2025 are the newly refurbished Bruce A units 1 and 2 (more here), so the 135TWh of committed supply the Power Play tool assumes may already include far more fossil fuel consumption than Ontario's electricity sector has seen in years.

My calculator indicates that gas (another 16,400MWp of it) is the cheapest option to meet peak generation requirements (the calculator is using an estimated natural gas cost of $5/MMBtu), the next cheapest is refurbished nuclear, and then wind (the cheapest vRES in the model).

The 7600MW of wind capacity required to generate 20TWh in Ontario can displace only 1,150MW of that additional natural gas capacity.

17,500MW of solar capacity does displace 4300MW of gas-fired capacity.  While solar capacity can displace other capacity (only to the extent summer daytime peak demand exceeds winter peak demand), the price clearly needs to be far lower than the contracts signed by the government's agents in recent years.



What is notable to this nuclear advocate is the nuclear option (including a new build at Darlington) is the only supply mix in this chart that drops emissions.
Either a rise in the natural gas price, or carbon pricing, or a combination of both, could also make the nuclear option comparatively cheaper.
To demonstrate the comparative costs of each low/no emissions technology in reducing emissions, I've used the "2025+ Natural Gas" as the reference scenario, and the cost of reducing a ton of CO2 equivalent emissions is therefore the increased cost of the mix divided by the reduction in emissions achieved by the mix.

Nuclear provides the only option of reduced emissions in a carbon pricing range that might be tolerated in the near future, with the refurbishments of Bruce and Darlington reactors feasible at a price under $30 and a new build at a price under $60.

Variable renewable technologies are not viable at the prices set by the government in Ontario at any carbon price likely to be introduced in the next decade, but they may provide a picture of being green while ramping up emissions with a switch to gas.

If optics are the primary concern, the decision to exclusively use graphical tools in the Power Play planning tools is understandable

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It's particularly notable that the most efficient low carbon supply mix is taken from the Ontario Power Authority's 2008 Integrated Power System Plan; the most comprehensive plan coming out of the most transparent planning process, that plan died with the Green Energy Act and related introduction of feed-in tariffs to spur the construction of wind and solar generation.

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The calculator version was 3 as this post was being prepared - 4 when it was completed!

The Google spreadsheet used for the tables in this post is here

15% Up: First look at July's electricity figures.

It's by-election day in Ontario.

It's also the first day of August - meaning I've been running July's numbers for Ontario's electricity sector (preliminary monthly report and supply cost estimates) .

Demand down ~5.5% from July 2012, and price up ~14.5%, based on the IESO's low second estimate of the global adjustment rate (low meaning the millions divided by the demand in Ontario is higher than the rate projected).
The 14.5% is essentially the year-to-date increase over the first 7 months of 2012.  Most Ontarians will not yet realize the increase, but they'll become suddenly aware when new regulated pricing plans are set for November.

Inexplicable price hikes peaking in June
followed by inexplicable drop in July

Here's a striking monthly change:  If you value the Ontario portion of the market as the hourly demand at the Hourly Ontario Energy Price plus the overall total for the global adjustment, you'll find, based on the IESO's estimate of a $593.7 million, that July's total Ontario market value rose $10.2 million from June, while the total electricity demand rose 1.7 million MWh.

That makes the incremental cost of the additional supply required in July less that 7/10ths of a single cent/kWh.



Which is nonsensical: the highest demand months are the lowest cost months only because of extraordinarily poor market design.

It is problematic the government claims conservation should be pursued because it avoids the cost of building generation while this nonsensical relationship exists to the point where a kWh of additional supply appears to cost 7/10th of a cent.

How is Ontario claiming conservation is queen while ignoring the structural perversions it has created to make the highest demand months the cheapest supply months?