Ontario's electricity market gamed: OEB ...and others

The Ontario Energy Board today posted a letter to the head of the IESO (Ontario's electricity system operator) regarding the gaming of one aspect of the IESO's operation.

Dear Mr. Campbell: 

RE: Market Surveillance Panel Investigation Report

The Market Surveillance Panel’s (MSP) Report on an Investigation into Possible Gaming Behaviour Related to Congestion Management Settlement Credit Payments by Abitibi-Consolidated Company of Canada and Bowater Canadian Forest Products Inc. was posted today on the OEB’s website. In its Report, the MSP concludes that the two market participants, through deliberate market conduct, engaged in gaming in relation to Congestion Management Settlement Credit (CMSC) payments at a time when they were operating as dispatchable loads.

...
I would appreciate if you would advise me in writing within 30 days of: a) the steps that the IESO plans to take in response to the recommendation in the MSP’s Report and the timelines for completion of those steps; and b) whether, in the IESO’s view, any actions or market rule amendments, in addition to those reflected in the MSP’s recommendation, should be taken or initiated.

The particulars of the gaming scheme couldn't be as interesting as the head of the regulator requesting the head of the IESO inform of any possible action on gaming 6 months after the February report was produced - but I glanced through for dollar values anyway.

Bowater’s high bid prices were used to obtain CMSC payments that more than compensated Bowater for operating profit reductions by at least $10.3 million. 

... All customers in the wholesale energy market were disadvantaged by paying additional Uplift charges of $0.12/MWh as a result of Bowater’s behaviours.

...Bowater exploited market defects. In so doing, Bowater received $11.0 million in CMSC payments during the Relevant Period, and there was a corresponding disadvantage or expense to the market. Bowater’s conduct constitutes gaming.

and for Abitibi

Abitibi’s high bid prices were used to obtain CMSC payments that more than compensated Abitibi for operating profit reductions by at least $5.9 million.

... All customers in the wholesale energy market were disadvantaged by paying additional Uplift charges of $0.09/MWh as a result of Abitibi’s behaviours.

...Abitibi exploited market defects. In so doing, Abitibi received $9.4 million in CMSC payments during the Relevant Period, and there was a corresponding disadvantage or expense to the market. Abitibi’s conduct constitutes gaming.

This is not the only area CMSC payments were discussed in the OEB's Market Surveillance Panel's April report. The IESO has addressed some of the matters in its technical meetings with "stakeholders." The letter today, including the link to a "public" version of the report (dated February) indicates frustration not all areas are being addressed.
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In related news, OPG gets a partner for its solar bids, and Tom Adams informs us as to why that may be unseemly.

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The Council for Clean & Reliable Electricity released a new paper, written by Greg Baden, Apples to Apples:Fixing Ontario’s Electricity Price Mismatch.

INTRODUCTION  

Ontario’s electricity pricing mechanisms result in Ontarians paying as much as $60 per megawatt-hour (MWh) more for their own electricity than those who import it. In a previous paper (Baden and Tomson 2012), we recommended addressing these anomalies and removing the effective subsidy that Ontario pays on electricity exports. We advocated calculating the Global Adjustment on an hourly instead of monthly basis and adding it to the Hourly Ontario Energy Price to give a “true” price that is valid for both the Ontario and export markets.  

A counter-argument to this proposal is that various electricity markets, including Ontario’s, have agreed to price exports based on the real-time market hourly price and, consequently, the Global Adjustment should not be included in the Ontario export price. Here, I respond to this counter-argument with the benefit of more data and reflection. I affirm both the initial recommendation and add a complementary recommendation that Ontario replace its existing partial day-ahead mechanism with a full day-ahead market.

I think it's an interesting paper with a sound idea for providing Ontario's ratepayers with benefits from an IESO market; I suspect a functioning market that provided value to all participants would feature a day-ahead market requiring firm day-ahead commitments from all suppliers, and a curtailment market until Ontario ceases to contract far too much power (see Plugging into Savings: A New Incentive-Based Market Can Address Ontario’s Power-Surplus Problem).

I don't think the IESO, and its political masters, want a market that functions to do anything but shift costs away from the largest, most politically influential, consumers (see "Stakeholders" destroying the viability of Ontario's electricity market).  This wasn't a good week for that.

It appears the IESO's system won't be as effective at shifting costs away from Class A consumers over the next 12 months. The final July global adjustment figures (the first month of a 12-month period) indicates the share of the global adjustment to be paid by class A consumers go up to 12.2% from 9.6%. I haven't seen confirmation on the percentage of supply paying that share, and Class A was opened up to more entities as of July, but I don't expect the class's consumption is up more than 15% (guess is 13%).

I was exchanging e-mails with a wiser (older anyway) person who had noted before the Class A scheme was introduced that very large consumers generally have much lower peaks than smaller consumers and would therefore benefit even if they did nothing. That nature of the mechanism is what causes their costs to rise now.

Here's how it works:

• The average consumption of the 5 high coincident peaks for the billing period just beginning is 21,580 megawatts
• The average consumption of the 5 high coincident peaks for the previous period was 24,114 megawatts. Of that 9.6% Class A global adjustment indicated average Class A demand for those hours of 2,315 MW.
• 2,315 MW is 10.7% of the lower 21,580 high five average for this billing period - so if class A consumption didn't change their global adjustment charge would have gone up 11.5%
• To get to 12.2% of the the allocation, Class A consumption would have grown 13% - so that's my initial guess at the increase in the class A contingent for this adjustment period.