Monday, August 26, 2019

Henvey Inlet provides opportunity for RIckford to address declining performance in Ontario's electricity sector

It's shaping up to be the worst year in some time for Ontario's electricity sector.

The useful structures planned during the previous government are falling apart during the implementation stage, and the current Minister of Energy, et cetera, has appeared - well, infrequently. It's still early in the sophomore year for the Honourable Greg Rickford, but he's shaping up to be the worst energy minister since Brad Duguid.

Duguid could have saved Ontarians billions if he'd stuck to his druthers and implemented the solar rate cut the Ontario Power Authority decided on in 2010, but he didn't. He succumbed to lobbying from an industry not to reduce rates, and eventually, as those high-priced contracts entered service, Ontario became a global laughingstock for contracting solar capacity at an average price well above $400/megawatt-hour (MWh).

A feed-in tariff (FIT) contract for the 300 MW Henvey Inlet wind project was announced eight-and-a-half years ago on February 24, 2011. From the standard FIT contract during February 2011 (version 1.4):

2.5 Milestone Date for Commercial Operation
The Supplier acknowledges that time is of the essence to the OPA with respect to attaining Commercial Operation of the Contract Facility by the Milestone Date for Commercial Operation set out in Exhibit A. The Parties agree that Commercial Operation shall be achieved in a timely manner and by the Milestone Date for Commercial Operation.
The date for commercial operation was generally 3 years from the contract date. Later it was extended to 4 years for many contracts.
Henvey Inlet, at some point, received extra special consideration and it's date for commercial operation was extended to February 25, 2018 (according to IESO contract list). Today being August 26, 2019, is more than 1 and half years from the date for commercial operation.

Section (9.1), "Events of Default by the Supplier", includes:
(j) The Commercial Operation Date has not occurred on or before the date which is 18 months after the Milestone Date for Commercial Operation, or otherwise as may be set out in Exhibit A.

Thursday, August 15, 2019

In defense of Ohio's bailout of nuclear, and other, generating stations

July ended with Ohio passing an energy bill :
to facilitate and continue the development, production, and use of electricity from nuclear, coal, and renewable energy resources in this state, to modify the existing mandates for renewable energy and energy efficiency savings...
I noticed American pundits hating it.
The bill prevents Ohio's only nuclear generating stations from closing, as previously announced, so I thought it worth my time to investigate it. Unfortunately it's one more subject that demonstrated the shallowness of most energy commentary.

Ohio just passed the worst energy bill of the 21st century announced David Roberts at Vox. Self-described "energy Ronin," Jesse Jenkins responded to the claim the legislation, saving 2 nuclear plants in Ohio, was better than "passing nothing and letting them close," with a flat: "No. Not really." It's a claim that should be revisited in the not too distant future - when Ohio can be compared to Pennsylvania, where no bill was passed to save two nuclear facilities soon to exit operations. I'll plant the seed for that future comparison with some background on what did happen in Ohio - and very briefly at the approach that failed to sway lawmakers in Pennsylvania.

Roberts' article has these bullet points on the Ohio legislative action:
  • Bail out two nuclear plants
  • Bail out two coal plants
  • Gut renewable energy standards
  • Gut energy efficiency standards

Nuclear

If I skimmed the legislation correctly nuclear (and some other generators) will receive up to $9/MWh in credits for their output - with the amount being reduced if the market price is above $46/MWh and disappearing at $55USD/MWh (currently equates to about $73 CAD/MWh).
A fact-based commentary on that price might note most pricing is now set by natural gas so the $9USD/MWh stipend equates to a $22/tCO2e implied cost of emissions (tonne of CO2 equivalent emissions) - which is a little under $30 Canadian dollars per tCO2e.

It's a sad commentary on the state of American commentary that those who claim to support positions on reducing emissions fail to mention implied emissions' costs in their comments.

Regardless, that's the nuclear bailout: it can be perceived as compensating trivial-emission generation for the unpriced negative externality of currently cheap and abundant natural gas-fueled generation. Previous actions by New York and Illinois legislators have tied their funding of threatened nuclear plants directly to a social cost of carbon.

So why the coal bail-out?

Wednesday, July 31, 2019

OPG's nuclear facilities are now the major cause of increasing electricity costs

Ontario rates are on the rise again, after going largely unchanged for the final two years of the previous, Liberal, government. Many consumers won't realize the 7% increase during the first half of 2019 as the impact is hidden by subsidies, which have grown to about $4 billion a year in the recent provincial budget. In stark contrast to past years, this year it is publicly owned Ontario Power Generation (OPG) nuclear units driving the increase. I estimate all supply costs up a little over $400 million (nominal) during the first half of 2019, while the cost of OPG's nuclear output is up a little under $500 million.

This article is going to be about electricity rates - promised and realized. It will touch on too many complex areas I've spent too little time on to understand fully, but enough to understand Ontario’s rate-setting process cannot deliver reliable pricing on regulated nuclear supply.

Ontario's government announced it was "moving forward with nuclear refurbishment at Darlington Generating Station," in January 2016. That station has 4 reactors - the last 4 new-builds in the province, with the last of those entering commercial operation 25 years ago.
The average cost of power from Darlington nuclear units post-refurbishment is estimated to range between $72/MWh and $81 MWh, or 7 and 8 cents per kilowatt hour.
The low end of the estimate, $72/MWh, is what Ontario's consumers were paying for supply from OPG's nuclear power plants at the time of the announcement in 2016. Today we are paying $89.70, which could generously be considered as just above the high end of the estimate (adjusted to real 2015 dollars). This is somewhat explained by the inability of the regulator, the Ontario Energy Board to set a rate in 2017, but another 6% rate hike is already baked in for 2020, so we will be back at the high end of the estimated range in 2020 regardless.

It is not, however, accurate to blame the recent rate escalation on the refurbishment project.

Sunday, July 7, 2019

Baseload's threatened ability to contribute to lower emissions

“Baseload” is a contentious term in energy discourse. In analysing electricity data in Ontario it occurred to me there’s a simple way to demonstrate the potential value of supply that delivers a consistent output all of the time - one that ignores all generation technology, using only hourly demand data. In this post I’ll demonstrate this methodology before discussing implications for supply mixes.

“Base” and “Load” are two fairly well-defined terms - neither of which are strictly adhered to in my methodology.

“Load” I treat as whatever data I have. I’ve collected available hourly, or half-hourly, data for 3 Canadian provinces, 5 Australian states, and 5 US systems. The data is unlikely to be equal: one example is the figure used for Alberta is “Alberta Internal Load” which includes “behind-the-fence” self-generation unlike the Ontario system operator’s “Ontario Demand”, which only reflects supply from their grid. I am not aware of what supply is included, or excluded, in data I’ve collected from the U.S. Energy Information Administration (EIA) or the Australian National Energy Market. Until the case study section of this analysis the differences can be ignored.

“Base” could be called minimum, but I think it’s helpful to eliminate outliers. The most extreme example is the great blackout in August 2003 that impacted most of Ontario, but more generally there will be some ideal nights on holiday weekends where demand is below its normal lows. In this analysis I define “Baseload” in relation to the statistical mean, which is better known as the Average (A) by those of us who determine it using the available spreadsheet, or other database, function.

While I am well-acquainted with data, I’ve only met statistics. Wikipedia explains the standard deviation, represented by the symbol “σ” (sigma), “is a measure that is used to quantify the amount of variation or dispersion of a set of data values,” and provides a very helpful graphic displaying 1st, 2nd and 3rd standard deviations on a plot of a normal distribution.

(By M. W. Toews - Own work, based (in concept) on figure by Jeremy Kemp, on 2005-02-09, CC BY 2.5, https://commons.wikimedia.org/w/index.php?curid=1903871)

People who are well-acquainted with statistics might be able to anticipate the results of much of my analysis, and probably could use it to determine how the distribution of electricity demands differs from a standard distribution. For instance, the average percentage of hours where I find demand is below A - σ (the statistical mean less one standard deviation), in 13 electricity system hourly data sets, is 15.45%: in the diagram above of a standard distribution it’s 15.8%. That result should not surprise a statistician, but perhaps some other metrics I’ve collected will be - and if not I will attempt to present the analysis for those that those unfamiliar with statistics.

Sunday, June 16, 2019

Market re-animation: the Herculean task of reforming Ontario’s electricity sector

My writing output seems to be inversely related to the number of calls for comments about different aspects of Ontario’s electricity sector. That’s probably not entirely accidental as I"m not motivated to work on demand for free, and the work seems much more complex than it did - hopefully as I see more connections between issues. Regardless, some thoughts have been percolating for many months and it’s time I release them into the wild. In this post I want to connect the Ontario government’s consultation on industrial electricity prices and the system operator's market renewal initiative, but if I only provide a backgrounder on the current market debacle, and how it came about, I think the reader will be rewarded for their attention.

I did write a post a year ago with 6 suggestions for the then-new Premier’s government. Reviewing the list now I see some action on 4 of the points. One exception remains “Restrict eligibility to the Industrial Conservation Initiative (ICI).” In terms of what can be done within today’s system my comments from last year remain my short-term position on industrial electricity prices:

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.

This would have an immediate benefit for smaller industrial consumers that are not eligible to participate in the ICI. The reality for existing industrial consumers within the ICI is that they have been largely protected from rate increases with a program promoting inefficient spending that only benefits ICI participants by adding to the burden of remaining Ontario consumers. Lowering rates further should be an outcome from lowering the electricity sector’s costs - not transferring costs to lesser consumer classes, most of which subsequently transferred costs onto future ratepayers and taxpayers.

The Market Renewal Initiative was the last government’s hope for future cost reductions, and there’s no indication today’s Ford government has changed tack. There’s a lot of fine analysis being done on different aspects of a new market design, and very informative reporting being produced. It’s just not clear, to put it very kindly, that there is a real commitment to a market system.

In the beginning (of the current structure) there was the Independent Electricity Market Operator (IMO), and its market, and maybe it was good for an hour or two but things went sideways pretty quickly.

Monday, April 29, 2019

Analysis of an analysis of Canada's Federal Carbon Pricing System

Fiscal and Distributional Analysis of the Federal Carbon Pricing System” is a product of the The Parliamentary Budget Officer (PBO). The PBO’s analyses are, in general, performed, “for the purposes of raising the quality of parliamentary debate.” This analysis of the PBO document is intended to raise the quality of debate everywhere.

The Canadian government’s policy on pricing greenhouse gas emissions is to enforce provincial government’s have a policy on pricing greenhouse gas emissions - and where they don’t to impose a “federal backstop” policy. The PBO’s analysis is looking at the impact of the provinces where the federal backstop will be imposed - here I’ll analyse the analysis for only one of them (Ontario) to avoid bombarding the reader with too many figures.

Ignoring the other provinces will only be a portion of what’s ignored. The PBO’s analysis notes there are “two components” of the backstop policy empowered by the Greenhouse Gas Pollution Pricing Act.
  • A charge on fossil fuels, or “fuel charge”... and
  • A regulatory system for large industry, known as the “output-based pricing system” (OBPS)
The OBPS is glossed over for a few reasons: it’s expected to be a small portion of total revenue (less than 4% for Ontario), it’s not finalized (despite being expected to apply back to the start of the year), and therefore it’s not known which provinces will have satisfactory pricing already in place for large emitters and which the federal backstop will be imposed on.

So... in the PBO analysis, and here, the hundreds of large emitters that emit over one-third of the country’s greenhouse gas emissions aren’t considered.
Image captured from my presentation of data from Canada’s GHG Emissions Reporting Program
We’ll all focus on the millions of residential households instead.

Friday, March 29, 2019

f in efficiency: Free-riders of the soft path

There are lots of opinions on energy, but only one most acceptable conclusion to a discussion of what actions should be pursued - it is some variation on, "and of course efficiency, we have to do all the the conservation we can first." This signals everybody to nod approvingly and terminates the discussion.

I don't agree - which is a difficult position given the culture that views any energy analysis with the assumption "efficiency" (often used interchangeably with "conservation") is the most effective way to reduce costs. In this post I'll challenge the usefulness of a perspective that values negawatts above megawatts.

Before moving to some foreign data from the American Energy Information Administration (EIA), I'll introduce a graphic showing both official estimates of a levelized cost of energy (LCOE) for efficiency in Ontario, and the LCOE I estimated of available but not utilized cheap supply. I've added trend-lines to emphasize that while I find the cost of efficiency was higher than foregone supply until 2015, the claimed LCOE has dropped quicker and appears cheaper than the foregone supply in recent years. I'll need to cover a lot of ground before arriving at a place to explain why that is.


Saturday, March 23, 2019

Ontario government takes action to reduce electricity costs

Ontario's Minister of Energy, Northern Development and Mines (a.k.a. Energy) announced actions addressing electricity sector costs on Thursday. I summarized points from viewing the Minister announce the changes on Twitter:
  1. moving conservation cost from ratepayers to taxpayers is moving costs - not reducing costs;
  2. reforming the [Ontario Energy Board] is nice, but regulatory costs are neither a big portion of bills nor what drove rate increases;
  3. showing cost of [un]Fair Hydro Plan is also a positive - but also doesn't address costs.
While I was initially underwhelmed by the changes described by the Minister, having now reviewed the extensive material posted due to yesterday's announced changes I need to correct the misinformation I posted, and be more appreciative of some of the other changes.  

The main news release is titled, Ford Government Taking Bold Action to Fix Hydro Mess, and it shows I misinterpreted action on conservation as simply moving costs from ratepayers to taxpayers:
Find savings of up to $442 million by refocusing and uploading electricity conservation programs to the Independent Electricity System Operator (IESO)
The savings referred to are either efficiencies, in uploading programs from local distribution companies (LDC's) to the system operator (IESO), or program revisions. This is much clearer in reading a Ministerial Directives delivered to the IESO

Thursday, March 7, 2019

Available low-cost electricity not utilized in Ontario

All figures are estimated (view in workbook)

In preparing my previous post I created a graphic posted separately on Facebook and Twitter. The graphic got more views than the post I edited it out of.

Comments on the original graphic included thoughts from the "electrify everything" perspective. I responded with too much caution, noting shrinking supply. Having given topic some more thought, I've added dumped exports as supply that has been available to Ontarians over the past years, on top of curtailed potential supply and under-utilized gas generators. In this post I hope to provide some context to the graphic, and show why coming changes in supply don't present a challenge for meeting Ontario's annual electricity needs, if not its capacity requirements.

Friday, March 1, 2019

Value lessons from Ontario electricity statistics

Data - and lots of it.

While I'll try to prevent this post from sliding into an abyss of Ontario electricity statistics, I'll be citing provincial data as the basis for discussion about public understanding being restricted by the presentation of data from official sources, and present new views of generally unreported data that would benefit literacy in valuations of electricity sources - an area where reckless ignorance blooms again and again.
but enough about academics, let's dive in!

The old standard of valuing generation sources is the Levelized Cost of Electricity (LCOE ). I was particularly pleased in late 2015 when a report from Ontario's Auditor General included a figure (5) indicating the cost and quantity of energy sources for 2014. I was more pleased a few years later when I received figures from a freedom of information (FOI) request with the same information for years 2007-2015. While I think the data is terrific, when I wrote about it I cautioned on presenting LCOE, "stressing these calculations deserve a big asterisk and lengthy footnote on the impacts of things such as curtailment and capacity payments." 

I have now done the data work required to add that lengthy footnote on curtailment and capacity payments.

I am certainly not unique in hoping for superior valuation tools to LCOE: the U.S. Energy Information Administration (EIA) has developed a  Levelized Avoided Cost of Electricity (LACE) metric, and the International Energy Agency (IEA) a Value-Adjusted Levelized Cost of Electricity (VALCOE - see pg 41). LACE is intended to value the cost (of alternatives) avoided by the generation, with the intent LACE > LCOE would signal a good project. VALCOE attempts to recognize the different capabilities of sources in providing firm capacity and flexibility. The specifics are less important than the principles: not all generation is of equal worth to systems that are intended to minimize loss-of-load situations. Concrete examples of LUEC's limitations will help conceptualize the issues that have people looking for better valuations.

Before I discuss my data I will note one other frequently cited source of Unit Cost in my province (I regard LUEC and LCOE as interchangeable terms): the Ontario regulator. Their most recent explanation of regulated rates includes a table (3) indicating hydro at 6.2 cents per kilowatt-hour, nuclear at 7.7, wind at 15.9, gas at 18.8 and solar at 51.3 c/kWh. I'll show replacing the OEB list's lower cost supply with gas is likely to lower total costs.

I have collected hourly data for the transmission-connected (Tx) generators reported by Ontario's system operator, including imports, and I've estimated (hourly) distribution-connected generation (Dx), curtailed supply, and contracted cost, either by unit generated (or curtailed), or by capacity required to be available. My base union query in working the data has over 16.4 million records. I will not repeat the word "estimate" in this post but simply note this one time it may be applied to everything (my work and the numbers from the IESO and OEB I cite).  

Here is my summary of annual generation and costs from 2008-2018:

Monday, February 18, 2019

A message from 2018 Ontario electricity statistics

Two notable aspects of 2018's electricity numbers in Ontario: average rates did not substantially increase, and demand did. Both of these buck the trend of the past decade. I'll explain how the trends broke.

The IESO's December reporting shows year-to-date Class B Wholesale Market rates of:

  • $114.94/MWh in 2018
  • $115.55/MWh in 2017
  • $113.18/MWh in 2016

That should be the most accurate source for this one consumer category, although the IESO did bungle November's rates due to an error in consumption figures (they compensated for it in December by pretending 688.6/8.695= 74.04). In 2017 they bungled June's consumption figures (which was accounted for in July, pretending 913.4/8.858 =112.8). These details demonstrate all IESO figures should probably be treated as estimates too - so I'll stick with my own data work here, and a graphic demonstrating the trends in different consumer segment pricing I developed, and explained in Trends in Ontario Electricity rates by Consumer Segments