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.

Thursday, October 12, 2017

Site C'ing: BC's electricity adventure

Site C is a hydroelectric project in British Columbia that may soon to be cancelled.

The commentary surrounding the Site C project has been driven by political posturing, and a recent change in government is therefore likely to end, at least temporarily suspend, the project. The situation is worth commenting on from afar because while it's B.C. today, in another time and other places some different - and many of the same - people will be discussing the merits of big, public, baseload power projects and small, private, sporadic power projects.
"BC Hydro’s Site C Clean Energy Project will be a third dam and hydroelectric generating station on the Peace River in northeast B.C. It will provide 1,100 megawatts (MW) of capacity, and produce about 5,100 gigawatt hours (GWh) of electricity each year..."   BC Hydro
I have 4 questions I wish to address in discussing the future of Site C:
  1. Will there be a need for capacity?
  2. Will there be a need for energy?
  3. What are the costs and benefits of a Power Purchase Agreements (PPAs) with Independent Power Producers (IPPs)?
  4. What are the costs and benefits of publicly owned generation assets
While Site C would have a reservoir (9,300 hectares), the main energy store for the system would remain the Williston Reservoir (177,300 hectares) upstream on the same system. It's not surprising the site would generate 5,100 GWh annually as the implied 53% capacity factor[1] is essentially what the B.C. hydroelectric fleet achieves annually. [2]

Many of those claiming Site C won't be necessary comically follow that argument up with a list of alternative generation technologies. To evaluate the alternatives it is first necessary to determine the value Site C may provide.

B.C. currently has adequate supply - it's peak "load" occurred early in 2017, and the province was a net exporter of power during that peak (as it is during most peaks). BC Hydro's resource planning anticipates the ability to meet the peaks to become less certain, and disappear around 2023. The need for additional annual energy is predicted to come later. The difference between the ability to meet peaks and the ability to provide enough energy throughout the year is important.
Graphics from BC Hydro. Links to view source graphics: Capacity and Energy

Friday, September 29, 2017

Ontario Electricity Operator brags of ICI subsidy, continues spending on wind experiment

7 days after news broke of a lawsuit claiming the global adjustment charge is “an unconstitutional tax, not a valid regulatory charge,” Ontario's electricity system operator (IESO) issued a news release congratulating their generators and certain consumers:
Ontario’s peak demand days typically don’t happen at this time of the year. Yet with hot weather persisting, and in spite of summer’s end last week, the province experienced new annual peaks this week of 21,786 MW on Monday and 21,542 MW on Tuesday.
Generators did their part to help meet the peaks, as well as Ontario’s consumers participating in the Industrial Conservation Initiative (ICI) and other demand response initiatives.
According to preliminary analysis, consumers participating in the ICI are estimated to have reduced peak demand by over 1,500 MW this week. By reducing demand during peak periods, ICI participants can both reduce their electricity costs while helping to defer the need for investments in new electricity infrastructure that may otherwise be needed.
They didn't mention if the 21,783 MW remains 2017's annual peak it will be a record annual low (the 3rd one recorded in the past 4 years).

Tuesday, September 26, 2017

Global Adjustment mechanism again headed to court.

Jeff Zochodne reports that a,
August lawsuit filed by National Steel Car (NSC) believes the revenue the IESO collects for the global adjustment, from the company “and others,” should be declared “an unconstitutional tax, not a valid regulatory charge.”
The company gives numerous reasons, including that the global adjustment allegedly “redistributes wealth from the consumers of electricity in Ontario to, among others, the generators of renewable electricity.”
I don't like their chances, partially because I doubt the quality of Ontario's courts, but I will discuss reasons the lawsuit has a chance at succeeding to demonstrate the need for changes in Ontario's too pliable electricity pricing structures.:
  • pricing includes the full cost of current supply despite the intent of the Green Energy Act to grow value outside of Ontario's electricity sector, 
  • the courts have already ruled the global adjustment structure to be a subsidy of one group of consumers, at the expense of all others,
  • only certain consumers were exempted, at the end of 2015, from the Debt Retirement charge, and,
  • another group of consumers has now been rewarded with a "Fair Hydro Plan"
The global adjustment mechanism being challenged was introduced in 2005 to ensure the full costs of electricity supply were paid by consumers of electricity (Section 25.33 (1) of the Electricity Act 1998) - it was intended to be the difference between what suppliers were paid through contracts (or regulated prices) and what the market valued supply at. In half of the first 26 months of the global adjustment the line item was a credit on consumer bills, but it's been a charge in all but one month since 2008.