Monday, August 8, 2011

A 400% Rise in the Global Adjustment, and Other Disturbing Trends

The Global Adjustment provides both adequate energy supply and green energy for Ontario. It accounts for differences between the market price and the rates paid to regulated and contracted generators and for conservation and demand management programs.

The IESO provided a second, lowered, estimate for July's Global Adjustment (GA), of $30.75/MWh or $390.3 million. In July 2010, the figures were $7.50/MWh and $98.8 million.

The GA is important because it indicates the discrepancy about what the government values electricity at (which is the rates paid to suppliers), and what the market values it at, which is the Hourly Ontario Energy Price (HOEP). The combination of the HOEP and the GA is the wholesale rate in Ontario (which will equate with the residential regulated price plans if OEB forecasting is accurate) – it can also be considered the 'cost of power' in Ontario1. On exports, Ontario cannot charge the GA. We can endlessly debate the extent to which exporting benefits Ontario, but at the simplest level if the cost of electricity is the HOEP plus the GA, there is a subsidy on exports because they don't have the GA. The increased GA means, increasingly, external customers pay less than Ontarians do for Ontario's electricity production. Tracking 12 month running totals, the difference is now about $550 million dollars, and will likely end August 2011 about $200 million above the level of August 20102.

Many people that wish to alleviate anthropogenic global warming (AGW) argue that markets undervalue electricity because the externalities (most notably emissions) aren't accounted for in the market. That may be true (in my opinion it is), but electricity consumption over the first half of 2011 was up very slightly over the first half of 2010, and July 2011 use was nearly identical to that in July 2010(down 0.07%). The comparison of the two months, of July, is apples to apples.

The market price, or HOEP, declined from $54.29/MWh in July 2010 to $37.08/MWh in July 2011. That is a slightly different subject, except to note peak production seems to be becoming increasingly cheaper.I briefly examined export statistics for various province the other day, and the Ontario experience looked to be typical – and that experience is cheaper pricing at higher demand levels, and fewer hours at elevated demand levels.

The implications for sanity in variable pricing policies is being impacted by these market trends. I am opposed to time-of-use rates (TOU), and not to real-time pricing (RTP)rates, but the difference is looking increasingly inconsequential. When Ontario first introduced TOU rates the ratio was 1:2:3 for low/mid/high demand, and a recent OEB exercise indicated the government felt that remained desirable.  Reality has seen the ratio, which existed in these usage groupings as recently as 2009, eliminated.

The HOEP doesn't really matter to the wholesale rate within Ontario. If the market rate was $0 then the GA would just be the entire wholesale rate!  For July the wholesale rate will end up around $67.83/MWh, and that will be almost 10% higher than the previous year. We know the GA adjusts the charges to match the contracted costs – so the wholesale price, paid by many businesses, is up 10%, with consumption at the same level, not because of any market reason, but primarily because the government drove up the rates 10% arbitrarily (which is, coincidentally, the arbitrary election year reduction they have taken off consumer bills).

But ... the wholesale rate was lower in July than it has been in the previous months of 2011 – and the same was true in 2010. It's worthwhile to examine why it is that the highest demand month has the lowest cost (in 2010 July had the most demand, but in 2011 July ended up with just .03% less consumption than January).

One reason is the growth of industrial wind turbine generation in Ontario, and their feeble output in July, which is a benefit in lowering contracted prices for the months of July and August. In 6 years of IWT's at operational locations exceeding 10MW capacity, the July output has ranged between 13% (2007 and 2011), and 16% (2008).3

This low in production during Ontario's peak demand season isn't the only negative aspect of wind supply on pricing/supply. As demand ramps up in the morning, wind is, on average, dropping down to it's daily low-point in production. Similarly, as demand is stepping down in the last hours of they day, wind is headed upwards in production. Ontario's public hydro assets handle some of the ramping adjustments necessary for system stability – carbon plants handle the rest. They are more necessary because of wind supply.

The natural gas plants, and the coal plants, are the big driver of lower cost electricity during higher demand periods for electricity. I've previously noted the nature of our most recent CCGT contracting impacts – a guaranteed base payment . A net revenue requirement for the natural gas plants means the first MW of production, for the 4000MW of capacity at the big 5 plants contracted since 2007, is very expensive ($7900/MWmonth, which ends up at about $1,050,000 a day), but after that the price drops with each MW produced (to the cost of the fuel).4 I punched a figure of $32.50/MWh for the fuel into a spreadsheet, and added up the generation for the 5 plants over a couple of months. April's 400GWh of production cost worked out to about $111/MWh, and July's 3X greater production reduces the price per MWh to only $58. The more we burn, the cheaper it gets. Coal has no regulated price at all, and the plants are essentially treated as having no value. So, as with gas, if the HOEP is above only the cost of fuel, coal is a money maker. In July Ontario had more production from coal than it had during the first 6 months of the year. Consequently, the wholesale rate of electricity in Ontario (the HOEP + GA) has been dropping during Ontario's highest demand months.

As an election approaches in Ontario, with choices in electricity policy ranging from a return to public power, to a renewed attempt at competitive markets, Ontarians need to understand where the past years, of what is flatteringly referred to as a 'hybrid' market, has brought us. Higher demand increasingly means lower prices, due to the increase in supply from fossil fuels – and thus the pricing curve moves in the opposite direction of the emissions trend. 

In fairness, there is a trade component that makes scoring emissions far more difficult.  Ontario overwhelmingly exported to Michigan and New York in July, and if that generation did not come from Ontario's gas and coal plants, it would have come from other coal plants anyway - and those emissions would have drifted into Ontario.  There is also a trend that makes the costs, or benefits, of exporting difficult to measure - in July those exports occur primarily during higher use daytime hours (as they did in January).  These things don't change the overall messages.

Higher demand equating to lower prices, and lower prices equating to higher emissions, is not what we wanted - and it is not sustainable. 
 If we want a market system, we should move on to questions of regulation, market design, and, above all, value.  

If not, we should re-examine the public option.
The free market cannot continue to be synonymous with the free lunch.

1 The second last paragraph of the IESO's summary of 2010 figures defines it as such.
2 Data, queried from IESO hourly data and GA monthly figures, is in this spreadsheet.
3 The generation data is from the IESO, filtered to data after commercial operation dates as shown at the OPA site – and the formulated data I've put here.
4 See page 16 of this OEB document, and this IESO page for the capacities of each location.


  1. Of payments made to the OPA through the GA, do you know what the split between conservation programs and procured generation(CESOP, RESOP, FIT, etc) is?

  2. In terms of the breakdown between CESOP, RESOP, and FIT generation, the answer is no. I'm unconvinced the answer is knowable, so I have not pursued it (aside from contract privacy, I think some projects were allowed to move to programs introduced after they came into operation).

    The split is, I believe, in table 1B on page 23 of the OPA's 2010 Annual report (, which roughly coincides with GA figures on the IESO site.
    Year, Operating Expense, Conservation, Generation
    2010, 65.2 (Million), $317, 1619.6
    2009, 64.1, , $223.5, 1402.2

  3. An e-mail I received noted:
    "... the "delivery" line of the LDCs bills also includes revenue deterioration increases caused by conservation. Conservation winds up costing us both in the electricity side and the delivery side."
    Personally, my delivery charges, per/kWh, have doubled in the past 4 years, and tripled in the past 6 years. I can't say that would be typical though, as my household's annual consumption is about 40% of what it was 6 years ago.

  4. Thanks for the response.

    It seems that over the last couple of years, all news about LDC filings are significant rate increases. I think in the coming years it'll be very interesting to see to what degree the delivery increase is driven by an increase to the revenue requirement vs conservation's impact on the load forecast.

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