Rebuttal to Ontario Clean Air Alliance (OCAA) Latest Paper on Closing Public Power Plants

Rebuttal to Ontario Clean Air Alliance (OCAA) “Ontario’s electricity surplus: an opportunity to reduce costs”

The introduction to the OCAA report notes that demand is likely to continue to decline, both in annual consumption and peak consumption.  Parker Gallant and I wrote on where previous declines were - and they were largely in the loss of Ontario’s largest power users, also known as industry.  The OCAA cites page 335 of the North American Electric Reliability Corporation’s 2011 Long-Term Reliability Assessment (November 2011)  in claiming that Ontario’s electricity consumption and peak demand will continue to fall until at least 2021.     
Page 338 states that growth rates to 2021 are expected to average -0.1%, but reality notes the peak demand exceeded the IESO's expectations in 2011 and 2012.  

“I don’t know” is as valid a forecast as any, and page 343 shows the ability to meet NERC’s on-peak reserve margin requirements will be strictly conceptual in the near future.

The OCAA report states “According to the Independent Electricity System Operator (IESO), our electricity generating capacity will exceed our forecast normal weather peak demand this summer by 48%.”  The IESO’s current 18-month outlook contains a number more important to system requirements than capacity, which is the “Forecast Capability at Summer Peak” (which might be referred to as capacity value).  Of the 28406 MW the IESO forecast as being available to be available at peak, 2100MW  is from the Lennox GS, which is really an emergency reserve (it’s why the IESO category is oil/gas, and it has a very large heat rate).  And with our dry summer, the 5662 MW of hydroelectric capacity expected was not realized, with hydro peaking almost 1000MW below that.   Our demand, excluding the Lennox units, peaked at 24630 which was, in fact, close to our practical capability without getting into reserve margins.

It’s important to note that wind has little capacity value.  Spain’s government is cutting back subsidies because their generating capacity is approaching 300% of their peak demand.  If you have capacity which lacks capacity value, that happens.   

On page 3, the OCAA notes a “Nuclear Debt Retirement Charge”  There is no such thing.  The Debt Retirement Charge still exists entirely because Ernie Eves siphoned mony out of OPG to fund a rate freeze for consumers, and the McGuinty government’s over-procurement of supply coincident with the recession has seen the residual stranded debt rising over recent years, despite nuclear doing nothing but producing 50-60% of Ontario’s power and receiving rates for it far below what Ontarians were paying to consume it (with the difference - or grift - going to many of the companies funding the OCAA).

The Global Adjustment (GA) is not a subsidy.  That aside, the OCAA claims that 45% of GA revenues went to nuclear and 34% went to natural gas-fired generation (between 2006 and 2011).  2007-2011, inclusive, nuclear production was ~417TWh and gas ~88TWh.  The OCAA’s fiddling with GA figures shows nuclear received 32% more of the GA pot than the natural gas industry did; and the nuclear industry received that 32% more for producing 370% more output.

From the earlier errors, it’s easy to see why the OCAA would misinterpret what  “superfluous electricity generating stations” are, as it does when discussing how to reduce rising electricity costs.  They are the generating stations that are unnecessary - meaning the ones that have no capacity value.

The OCAA claims options to the higher cost existing generation are sources “such as hydro imports from Quebec or comgbined heat and power plants.”  Here are statements from a Mr. Jennings of Ontario’s Ministry of Energy at the Darlington New Nuclear Power Plant Porject Joint Review Panel hearing on April 7th, 2011.

it is often suggested that combined heat and power is very cost effective, very easy to do and there iis a lot of potential for it. This competitive RFP was for 1,000 megawatts. They ended up only getting 414 megawatts of responses, so those were all taken. In terms of the cost in that plan, they ranged. The cost of the products procured ranged from about 11.5 cents up to about 24 cents a kilowatt hour, so these are quite expensive projects.

…

an industrial customer in Quebec might pay 4.5 cents a kilowatt hour for electricity. They wouldn’t sell us the power at 4.5 vrntd, they would be looking at natural gas what they could sell it in New England for.

The “lower-cost and more flexible” option of CHP is not lower-cost.  
The price of importing from Quebec should be the price of production in New England.

The OCAA says that closing the coal plants could save $367 million a year, but the payments OPG receives for Lambton and Nanticoke are about the same, per kWh of output, as private natural gas plant operators receive for keeping the new gas plants available (I wrote this on capacity payments only 9 days ago).  I don’t like capacity payments, but they are not fine for the goose and not for the gander.

Pickering A has only two operational units and the ScottMadden Inc. benchmark study did put it high above other nuclear facilities for cost/kWh.  But it was still at 9 cents/kWh - cheaper than what the OCAA argues it should be replace with.  Pickering B has 4 units and the benchmarking put it around 6 cents/kWh (I referenced these figures in an entry I wrote the last time this nonsense was being written about in the Toronto Star).

When the OCAA write costs are multiples more than the “market price of electricity” they means the 2 cents/kWh HOEP, and when he says “approximately equal to the fuel and operating costs of our new gas-fired generating plants”, he forgets the massive Net Revenue Requirements that push those costs even beyond Pickering A’s benchmarked 9 cents/kWh

The OCAA’s conclusions now are the same as they always are: shut down public power to buy really expensive private power.

It is nonsense... so you can read about it in the Toronto Star.

Ontario's Electricity Market Pricing Problems: Past and Present

There are a number of entities exploring fixes for Ontario's dysfunctional electricity market - few of which can admit it is dysfunctional.   Yesterday the Hamilton Spectator had an article on the topic, based on the "Putting the Pieces Back Together: "True Pricing" for Ontario Electricity" paper I noted in an earlier post.  Ontario's electric system operator (IESO) has multiple "stakeholder Engagement" groups working towards alleviating, or expanding, problems with coordinating supply and demand - depending on the stakeholder.  Last summer the regulator (Ontario Energy Board - OEB) tepidly explored alternative schemes for setting time-of-use rates.  Discussions are dominated by the few entities, or stakeholders, benefiting from lucrative private contracts financed through higher consumer rates and lower payments for public companies.

The discussions are not only be burdened by the lobbying of the participants on the stakeholder side; public employees are burdened by an inability to note the faults in the government's directions.      The stakeholder sessions seem interested in where we are, but in not being able to honestly address how we got here seem oblivious to the direction we are moving in lest we break the inertia of the current, poorly labeled, stakeholders.
This post will add to a number of previous posts is assessing Ontario's current situation, particularly my most recent writings on the global adjustment mechanism, capacity payments through the net revenue requirement mechanism, and the transfer of value from public assets to private ones.

There's the progress we have found

A way to talk around the problem

Building towered foresight

Isn't anything at all

                 - Fall on Me, R.E.M.

In 2000, Ontario's PC Harris government was moving towards privatizing the electricity system in Ontario concurrent to the Alberta's PC government working towards the same goal.  In Ontario,  price spikes and tight supply conditions led Harris' successor, Ernie Eves, to freeze pricing shortly after the market opened in 2002, which essentially abandoned the movement towards a functional Ontario market.  

Using AB definition of On-Peak: "hour ending 08:00 through to hour ending 23:00"

Reviewing the years since 2002 in the two provinces is useful.  The AESO 2011Annual Market Statistics provides figures for Alberta, with Ontario Data from the IESO's Hourly Ontario Energy Price (HOEP).  In 2003 the prices were similar.  By 2011 the "off-peak" (11pm-7am) prices remained similar, while Alberta's "on-peak pricing had climbed to $102.22  as Ontario's had dropped to $34.85.

Ontario, of course, has an additional cost on top of the HOEP market charges, which is the global adjustment.  Add the Global Adjustment on, equally across all hours, and Ontario has much higher off-peak pricing.   The average pricing for the provinces was quite close in 2011 (ON $71.94/MWh, AB $76.22).

The average pricing since 2002 saw Alberta shoot up above Ontario in the years immediately following deregulation, but it also allowed price drops, in Alberta, with the recession of 2009.  That is precisely the time when Ontario's demand, and HOEP, drop sent the global adjustment costs soaring, and the habit of subsidizing exports formed.

A functional market is one where lowering pricing lowers the amount of supply offered, and raising prices does the opposite.  Jurisdictions throughout the world are grappling with the perceived requirement to provide a reliable electricity supply with the desire to let a market function to handle the efficient allocation of resources, both in terms of supply (generation) and demand (allowing greater ability for consumers to control their behavior based on timely pricing information).

One champion of the market allocating resources is Texas.  Faced with tight reserve margins (and threats of controlled blackouts in February and August of 2011), Texas acted by raising the price ceiling on the market from $3000/MWh to $4500, and may raise it again.  Charging very high rates at peak times is the market solution to having sufficient generation to meet peak demands.  Alberta is similar to Texas, but their rates are capped at only $1000/MWh.
Many jurisdiction have a secondary market solution in that they have added markets where capacity is purchased.  In my opinion the PJM market is the most successful (it is expanding, now far beyond the Pennsylvania, New Jersey and Maryland states it took it's name from), and have a capacity market (Power magazine has an overview of capacity markets throughout the US here).

The issue of sustaining capacity sufficient to meet peak demand is being critically examined in many jurisdictions - particularly those with large components of intermittent generation; primarily wind and solar (see "Power Plant" section here - and an argument for letting the market dictate capacity, without the distortion introduced by capacity markets, here).   In many areas wind/solar capacity does not reduce the capacity requirement needed for other sources to meet peak demand.  For instance, Ontario's data shows wind is least productive in July, which is the month it is expected to see peak demand.  This means a generator that can meet peak demand periods will see less use throughout the year, and will therefore require more income to come during the reduced hours it is generating.

A consequence of retaining capacity available to meet peak demand, in addition to sources (wind) that are given priority access to the grid when they are producing, is that when there is an abundance of intermittent production, all generators see lower rates.  The data from Alberta's AESO demonstrates this:

Wind generation, which is a price taker (meaning that wind generation is priced at $0/MWh), tends to receive lower prices per megawatt hour because it displaces higher cost gas generation and reduces the pool price.  In 2011, wind generators on average received $50.28/MWh, a 34 per cent discount to the annual average price.

We've already seen that the variance in HOEP is much narrower in Ontario than Alberta, but calculating average HOEP by source/fuel since September 2010, the same pattern is apparent, with coal and gas providing the most valuable generation (according to the judgement of the market).  The solar figures, which are similar to those for gas and coal, are based entirely on modeling, and therefore have a much greater margin of error.  The least valuable supply could be expected to be baseload, which is all nuclear, much of the hydro and some of the natural gas; it is, as in Alberta, actually wind.

As Ontario's supply of wind generation grows, it will become increasing less valuable.  Ontario is not heeding the market's messaging on the valuations of suppliers, and it has destroyed the market signals that might indicate a need for additional supply.  Subsidizing the least valuable power sources (through the FIT program) generated the subsidizing of the most valuable power sources (through the net revenue requirements).

The government, along with the regulator (OEB) and the system operator, appear nonplussed, and push on with schemes to mimic a functional market's pricing instead of scheming to have market pricing.  Time-of-use rates have been implemented along with the installation of smart meters.  For customers that are charged the HOEP rate (plus the global adjustment), we've already seen that rate does not vary much depending of the overall demand level, and the Time-Of-Use (TOU) rates, implemented in 2006 at an off:mid:on peak ratio of  approximately 1:2:3, has seen that ratio dwindle to 1: 1.5: 1.8

Last year the OEB undertook a consultation on TOU pricing in which it invited comments based on  a consultant's report from the Brattle Group designed to facilitate discussion.  The report suggested on-peak times be reduced to fewer hours only over the summer, with the costs of renewable energy feed-in tariff (FIT) procurement program being assigned to those hours.  I noted (here) that was grossly unfair, as the FIT program overwhelmingly procured energy that the system operator did not anticipate being productive during those hours (Table 4.1 on page 5 here).  No decisions resulted from that OEB consultation.


This summary of where the system is reviewed material visited frequently on this blog.  Market pricing is increasingly incapable of providing signals adequate for a functioning market, and the incumbent entities, both public and a small cabal of collaborators known as 'stakeholders' are in a pattern of increased studies, consultations, papers, etc., ad nauseum.


The OEB's consultation on TOU pricing, and the more recent Council for Clean & Reliable Electricity commentary, "Putting the Pieces Back Together: "True Pricing" for Ontario Electricity", do provide some concepts that can be adapted to break the cycles of increasing supply, increasing subsidies, reducing consumption and increasing costs.  The goal should be to eliminate the Global Adjustment mechanism, not to adjust it, because the goal should be to have a market allocating resources, not to mimic a market mimicking the allocation of resources.

Sir Adam Beck is dead: The Gifts of Nature have been taken from the public

The Adam Beck Memorial.

dona naturae pro populo sunt

-the gifts of nature are for the public-

Early in the 20th century, Adam Beck lobbied the Premier, from his position as a Conservative Member of Provincial Parliament, for a commission to investigate the electricity sector.  An advocate of public ownership in the sector, a century later Sir Adam Beck has Ontario's largest hydroelectric facility bearing his name, and his statue sits prominently in Toronto surrounded by iconic structures housing iconic organizations - including Osgood Hell, the Four Seasons Centre for the Performing Arts, and the Bank of Canada.

I hope the iconic institutions surrounding his statue endure better than Beck's legacy has.

My previous two posts have demonstrated the global adjustment mechanism measures the dysfunction of the market, and that large, and increasing, capacity payments are serving to drive down the market price (HOEP).  This post will show how the reduction of the HOEP, and the global adjustment mechanism, have combined to take the benefits of public hydroelectric facilities away from the public, and distribute them to the private entities awarded contracts by the McGuinty government.

Ontario Power Generation (OPG) is the public generator - it is one successor of Ontario Hydro, in turn Ontario Hydro succeeded Sir Adam Beck's Hydro-Electric Power Commission, which had a "Power at Cost" slogan.  

OPG's largest hydro-electric generating stations are the Beck generating stations (~2000MW capacity) in the Niagara Plant Group, and the R.H. Saunders (1045MW capacity) generating station on the St. Lawrence river; these are 'regulated' hydro assets, meaning the Ontario Energy Board sets the rates they receive for their production.  The last rate change for regulated hdyroelectric facilities (~60% of OPG's hydro production) was a reduction in rates to approximately 3.5 cents/kWh.  

The other 40% of OPG's hydro assets are unregulated; now almost exclusively the generation  exposed to the HOEP/market pricing.  As Ontario approaches an annual bill of almost $2 billion to pay for the availability of natural gas and coal generation, the 2012 2nd quarter reporting from OPG is likely to show that non-regulated public hydroelectric received approximately the same amount per MWh of production ($20) as private natural gas generators receive each hour for each MW of capacity simply to exist.

The government's twin actions of continuing to bring generating capacity online as demand declines, and paying capacity charges to distort the market, has destroyed the financial results for OPG's hydroelectric assets.  Before the latest dry spell, there was already evidence in periods of surplus generation it was hydro seeing curtailed purchases, and the HOEP has been declining since Ontario demand peaked in 2005 - but increasingly so with the acceleration in procurement since the Green Energy and Green Economy Act passed (GEA/GEGEA).

In 2008, OPG's unregulated hydroelectric production received, on average,  ~$47/MWh.  Over the course of the most recent 12 month period ~$27/MWh, and over the course of 2012's second quarter ~$20/MWh .

In 2011 OPG's revenues were 1 billion below 2008's levels, with the first half of 2012 well below 2011 levels.  The nuclear story is not dissimilar to the hydro story.  The total OPG 'net income' tale can increasingly be seen as the story of the performance of the investments set aside to cover the long-term costs associated with it's nuclear operations.

In 2008 OPG reported Net Income of only $88 million, somewhat reduced by a loss in the investments of nuclear funds of $93 million.  

In 2009 OPG's net income was less than the income from the investments of the nuclear funds.

In 2010 OPG's net income was less than the income from the investments of the nuclear funds.

In 2011 OPG's net income was less than the income from the investments of the nuclear funds.

Yet actuaries indicate the nuclear funds do not yet cover the long-term liabilities they exist to cover.

Despite the consistent losses, the 2011 annual report for OPG showed owner's equity  increasing by over $1.5 billion since 2008 (the government is the sole shareholder), with long-term debt growing ~$400 million.  This seems nonsensical for an organization that is years away from the last time it showed a real profit.

Public power receives little sympathy in Ontario due to the presence of a debt retirement charge (DRC), of $7/MWh, on consumers' monthly statements.  Ontarian's are told that this charge, which collects about $1 billion annually, is to retire the residual stranded debt (RSD) portion of the debt amassed by the public forerunner to OPG and Hydro One, Ontario Hydro.  The problem with this is that if the stranded debt were being used to pay off the debt that was stranded at the time Ontario Hydro was broken up, it is already paid off.   In May of 2012 the government provided it's first accounting of the residual stranded debt (which the DRC was intended to pay down); the RSD stood at $5.6 billion at the end of March 2009, and rose to $5.8 billion two years later.  The tally at the end of March 2012 is yet to be released, but there is virtually no chance the government's projection of $4.5 billion will be realized as OPG continues to lose money (factoring out the performance of the nuclear funds).  This means there is a billion dollars collected every year that does not fund the stranded debt, or perhaps more accurately, the strand debt charge cannot keep pace with the rate at which debt is becoming stranded.
Meanwhile, private power producers receive 60% more for generating a Watt than OPG does.

Coincidentally - or not - there is about a $1 billion dollar a year difference between what OPG receives for it's hydroelectric output, and the value of that output at the average price paid to suppliers of electricity in Ontario (30.7TWh sold at $31.16/MWh while the average rate for all supply was ~$66/MWh).

The value that is not realized by the public, on the resale of the production from "the gifts of nature," is not servicing the public debt.  Instead it is servicing the costs of private natural gas, wind and solar initiatives - as is approximately $800 million a year of value from the output of OPG's nuclear facilities.

Treating electricity as a commodity, I calculate which generators' production is undervalued, and which are overvalued: all output is sold at approximately $66/MWh - generators paid less than that are net contributors to the global adjustment (undervalued), and those receiving more are beneficiaries (overvalued).

Estimated Net Contribution/Withdrawal (-'ve) From the Global Adjustment ($Millions)

- this table is taken from my data site (where it is updated each month)

The roadmap for this transfer of wealth from the public generator to private generators was laid out years ago by the Ontario Clean Air Alliance.  In Tax Shift: Eliminating Subsidies and Moving to Full Cost Electricity Pricing they argued that the greatest subsidy in Ontario was "Below-Market Water Royalty Rates" - a rather bankrupt social view compared to that which built Ontario's electricity sector a century earlier on the premise that "the gifts of nature are for the public."

There is little chance things will improve for OPG.  The Ontario Energy Board (OEB) is the regulator that prescribes the rates for OPG, and on April 20th, 2012, they received a report prepared by Power Advisory LLC.

Power Advisory LLC represents many of the largest private producers currently benefiting from the bleeding of OPG - and they do so quite aggressively.   An article appeared in the Toronto Star in May, demeaning OPG's nuclear assets; another in June where former OPA/government contract negotiator Jason Chee-Aloy raised an alarm over the government's lack of enthusiasm for moving forward with contracts for Power Advisory LLC's 'green' energy clients (the system operator is aware that 40% of all contracted output will be generated at hours where output will be driven beyond Ontario's demands).  Mr. Chee-Aloy's lobbying seems to have worked rapidly once he utilized the Toronto Star to broadcast his message, as soon after Ontario's system operator released base pricing levels that will see nuclear generators maneuvered prior to wind turbines, as Power Advisory desired.

With powerful clients and a broad platform to communicate it's propaganda, it is unlikely the OEB could have found a worse consultant to represent the interests of Ontario's consumers than Power Adisory LLC.

In future posts, I'll explore examples of markets that negate the need for much of a regulator's role in meddling with pricing, and revisit pricing models that might be appropriate for Ontario to reverse the downward spiral it is experiencing as affordability deteriorates concurrent with public assets being devalued to the benefit of only a few private entities.

Capacity Payments: The High Cost of Ontario's Collapsed Electricity Market Price

Price inflation of the electricity commodity in Ontario has been relatively muted, but the limited growth hides some deep structural problems.  This post will compare annual figures for 2008 to figures for the period from July 1, 2011 - June 30, 2012 (as did my previous post), by examining the purchase price of different categories of supply.  I'll be drawing from work I've done collecting production data (ie. here) and establishing estimated contract values for generators in showing which type of generation grew during this period of overall decline, which generation decreased, and the costs associated with the changes.

The changes in generator capacity are almost entirely related to Ontario's policies of eliminating coal, and growing renewables.  Nuclear and hydro capacity has changed little.  The renewables chatter disguised the rapid build-out of natural gas capacity, which has been expanding quicker than coal generation capacity is being removed.  Coupled with the increase in wind and solar capacity, the increase is significant.

Estimated Generation Capacity Changes Since 2008:

Generation has predictably grown most in the 3 source categories where the capacity has grown. While the total growth in the dollar value of the market is only $503 million, gas generation has grown by $1.25 billion, wind by $453 million, solar by $264 million [1], and spending on the Ontario Power Authority's conservation programs (funded through the global adjustment) has grown by $161 million. Altogether the increase is ~$2.1 billion dollars in the areas policy is designed to increase, with an increased 14.9 TWh of production while the market was contracting 17.3 TWh. Ignoring the conservation spending, the average cost of the increased gas/wind/solar generation is ~$130/MWh.

The total market shrinkage and new generation mean 32.2TWh (19% of 2008's total) must have been displaced. The declines came in imports, coal, and hydro generation; the 3 cheapest sources in 2008 (averaging $49.23/MWh).

Imports are a complex issue in Ontario. In the period from July 2011 - June 2012, there were no days when Ontario was a net importer, and only 286 hours where imports exceeded exports (3% of the time). It's possible to argue the bulk of imports are 'wheeled through' Ontario, particularly as the majority of imports come from Quebec, while the majority of exports go to New York and Michigan.  It's doubtful Quebec finds Ontario an attractive export market, as the market pricing is lower in Ontario than the other markets to which it connects.  Net imports is a far more useful metric, and those have shrunk by only 2.1 TWh (exports have shrunk along with imports).

The decline in coal production is accompanied, in my analysis, by a rise in the price per MWh from $55.42 in 2008 to $100.65 in the past 12 months.  This is an entry point to the murky subject of various methods that Ontario, primarily through the Ontario Power Authority (OPA) has developed to pay suppliers to be available when needed.  In 2008 coal production essentially received the market price, and there was a 'revenue limit' placed on the pricing that saw OPG's profits turned to a loss that year. During the most recent 12 months, OPG received "contingency support" payments for it's Lambton, Nanticoke, and Lennox generating stations.  I have estimated the hourly value of the payments at $12.30/MW of capacity for the coal units, and $8/MW of capacity for Lennox GS.   The argreements exist due to the need to maintain the availability of the generation capacity concurrent with a policy of minimizing the use of it (due to emissions).  For the coal units, this means that the costs of procurement in the past 12 months are about 1/3rd market price, and 2/3rd's capacity payments.[2]

5-year Henry Hub Natural Gas Spot Price (Closing)

The natural gas-fired generation also is heavily impacted by the OPA's contract structure emphasizing capacity payments.  My estimate of $100.54/MWh is up from ~$90 in 2008, while the price of the fuel has dropped significantly during that time.  To Ontario's south, the American Energy Information Administration (EIA) reported that in April Natural Gas was the source of as much generation as coal for the first time.  Average pricing for electricity is little changed in the USA since 2008; total generation is little changed, with growth there, as in Ontario, primarily in the natural gas and renewables sector.

I consider there to be two distinct classes of gas generators in Ontario.
Non-utility generators (NUGs) are older contracts, signed by Ontario Hydro and now managed by the Ontario Electricity Finance Corporation (OEFC).  These contracts generally result in generators running at high capacity factors (~66% on average).  Planners 6 years ago were looking to the end of the NUG contracts to provide some competition in pricing within the market, but the government squashed this through a Directive from the Minister.  Rates are currently estimated between $100 and $120/MWh, with payments based on output.

The second class of contracts have been negotiated by the OPA and contain guaranteed Net Revenue Requirements (NRR).  These generators are running at much lower capacity factors (%28) - particularly low considering the low cost of gas and the additional capital expenses of the largely CCGT plants contracted of late.  However, carbon reducing strategies, as those that are cited as the rational for OPG's 'contingency support' payments, appear to have led to the NRR capacity payment mechanism for recent natural gas payments.  Navigant Consulting has long held a contract to produce a document for the Ontario Energy Board to set regulated price plan rates (RPP).  Those documents have implied the NRR is ~ $7900 per MW month, of capacity, for the most recent plants.

Using $7900 per MW month, I had consistently estimated low on the supply side with these figures.  My method is, perhaps, overly simplistic in that I assumed the generators would only generate when the marginal cost of production was exceeded by the market HOEP rate, and that the full $7900 would be a capacity charge (not reduced by a profit on generation due to high market  rates).
That assumption may be incorrect.  OPG's financial reporting, on the coal side, shows market revenues for their thermal segment well below fuel costs.

Last week a "Dear Gallery" e-mail was sent out with the subject line, "Gas Plant Background Information" (copy here): it contained some important information on Net Revenue Requirements, including:

• The average benchmark NRR for Ontario’s gas fleet is $13,187 MW/Month. 
• Older plants that resulted from a competitive process typically are under $10,000 MW/Month. Newer plants that were negotiated and procured in a time of shortage tend to be over $15,000 MW/Month.

The newer plants are the same plants Navigant has noted for some time with an NRR as $7900/month, and while they may have been procured during a time when the Ministry had a perception of shortage, they were not procured in a time of actual shortage.

Regardless, using a capacity payment of $20.50/MW hour (~$15000/MW month), for the new plants does result in supply cost estimates matching the much more reliable market estimates (value of total market demand at HOEP rate, plus the total global adjustment pot).

This means that over the past 12 months the non-NUG natural gas fleet received over $70/MWh when the capacity payments are allocated to actual output, in addition to a revenue from sales at the market rate.

The capacity payments to coal, and natural gas, suppliers have enormous implications to the market price.  The fossil fuel based production is frequently the supply on the margin: Ontario is committed to take all nuclear, wind, solar, non-utility generator contracted output, and must-run hydro; after that supply, the marginal supply should be other hydro, and after that gas or coal (the marginal supply should set the price).  The structure of the NRR contracts, in guaranteeing profitably simply in existing, guarantees depressed market prices - particularly if coal and gas suppliers can bid into the market below even only the fuel costs.

The rapid growth in capacity payments, and the rapid adjustment of capacity payments to ensure private supplier profitability, raises some important considerations for future exploration:

• whether the concept of a competitive market is one Ontario should attempt, oppose, or continue to fake.  In 2008 ~77% of production in Ontario came from hydro and nuclear sources (largely public), while 71% of all payments went to those suppliers.  In the most recent 12 months my estimates show ~78% of production is still from nuclear and hydro, but only 58% of payments now go to those suppliers.
• the only supplier exposed to HOEP rates is the public generator OPG, who has seen their profitability drastically curtailed due to the lucrative contracts gifted to, apparently, anybody who is not the public generator
• whether contracts should be respected.

The last point will be considered very contentious, but the precedent of altering a contract that is not satisfactory to one party appears, through the limited data available on net revenue requirements, to have been set repeatedly.

[1] all figures are estimates, but none more so than solar, where capacity figures are from OPA quarterly reports of actual and forecast projects
[2] Lennox is included as "Other" in the second table of figures - and that is what drives the average cost of other to $194.38, although the dollar volume is not large.

Ontario's Troubled Global Adjustment Creation

Rising electricity prices in the electricity sector is the topic of a number of Ontario news stories this year;  The Guelph Mercury reported on a couple of manufacturers in the Waterloo with much the same narrative as reports out of the North Bay region earlier in the year.  Increasingly, the Global Adjustment (GA) mechanism, which ensures the money paid to suppliers is fully recovered from ratepayers regardless of market pricing, is portrayed as the reason electricity costs are moving higher in Ontario.  


Most of Ontario's supply is subject to contractual payments (or regulated rates), so the lower the market price, the higher the Global Adjustment rates (there are more than one).  As the market HOEP rate drops, customers see the GA rise.  The rising line of a bill is a convenient target for inciting anger.  Groups as disparate as the Ontario PC party, NDP, Green Party, Greenpeace, Environmental Defence have all referenced the charge as a subsidy.  And they aren't the only ones.  Google "the global adjustment subsidy" and you'll find hits to this blog!
Which is somewhat unfortunate.

The GA is a measurement of the dysfunction of Ontario's market - meaning the inability of market price signals to coordinate supply and demand.  Complaining about the Global Adjustment, in itself, is along the same lines as moaning about the use of Celsius degrees or a passionate hatred of those holding onto the yard measurement.
Too hot outside for your liking.  Try using Kelvins.
Better?

The economic basics could not be simpler.  Supply is high because the contractual prices offered by the government, via the Ontario Power Authority, are high, and firm (made on a must take basis of all generation regardless of value/time).

One cost of having high supply includes the need to dump the generation not consumed locally in external markets (as Parker Gallant and I noted in the Financial Post one year ago).

Graphed on Cold Air Data site

The total market is defined by Ontario's system operator as the sum of the output of all generators plus imports.  Market demand is set to match this. Similarly, we can estimate the total market value by total market demand at the market rate (HOEP), plus the total global adjustment pot.

In the most recent 12 months (July 2011- June 2012) the Global Adjustment Pot is $6.1 billion; the market recovery at the HOEP rate is only $4 billion (so the GA is 60% of the commodity charge).  However, while the GA is up over $5.2 billion since 2008, the total value of the market (GA + HOEP) is up only $453 million.

Total market demand is down 10% over that time.  After the math, the average cost of a MWh of power inflated 16.5% in the past 4 years - a price that is kept artificially low due to the abuse of the public asset that is Ontario Power Generation (I'll support that statement in an upcoming column)

Year	Total Market (TWh)	Global Adjustment ($M's)	Total Market Value at HOEP ($M's)	Total ($Millions)	Average Cost/MWh	Class B' Commodity Rate
2008	170.9	$901	8,778	9,679	$56.64	$57.79
2009	154.3	$4,220	4,861	9,081	$58.85	$62.17
2010	157.4	$3,848	5,932	9,780	$62.15	$65.03
2011	154.3	$5,310	4,840	10,149	$65.77	$71.95
Last 12 Mnths	153.6	$6,144	3,989	10,133	$65.97	$72.86

The global adjustment could be viewed as contributing to the Class B customer paying 26% more for electricity while the costs for the entire market climbed only 16.5%.   That difference is partially due to the need to recover the difference between what is paid, on average, for supply (about $66) and what is received when sold to export customers (~$26/MWh over the past 12 months).    It's also explained by demoting most Ontarians to class B status, in order to provide Class A status to Ontario's largest users (some of whom it is simply stupid to confer the special status too - unfortunately for our future, the stupid choices for membership in that elite group include universities).


Most Class A customers probably belong to genuine energy-intensive industries that were seeing major job losses as companies relocated (or closed).  The pricing for Class A customers is therefore a response to the same issues as the price for export customers - the price is what can be collected for the product, which must be sold.  The Class B global adjustment, which is included in the regulated price plans for residential and small business customers, reflects the weakness of substantially captive customers.  As such, the tool allows the cost of contracted supply that cannot be collected from non-captive customers to be shifted to captive customers.

While the GA provides a crutch for managing supply poorly, the dialogue around the issue should not centre on the length and shape, or the colour, of the crutch.

The broken leg is the problem.

Plunk Ontario Demand into a graph with HOEP on a second axis and ECO 101 textbooks spring to life!

Demand goes down, price goes down.
Supply is not allowed to fall, so price stays down.

Duh.

Graphing demand, production and market pricing contradicts the common thinking about Ontario's electricity sector.

Graph from my review of the Feed-In Tariff Mechanism

Between 2002 and 2005, Bruce Nuclear Units 3 and 4 came online, as did Pickering Units 1 and 4, and the 550MW Brighton Beach Natural Gas facility in Windsor.  All projects were initiated prior to the Liberal government's election in 2003 and there has been no additional generation needed since 2005.  The popular perception that the system was a disaster and was suddenly righted by Liberal actions on the supply side is false.

The demand side is another question, but much of the demand reduction was through the decline of industry.

Ontarians pay the Global Adjustment largely because of procurement policies - those same policies cause the dumping of excess generation in adjacent jurisdictions.    The policies are the issue.


Pretending the structure of the global adjustment is a fundamental problem strikes me as a poor diagnosis made to facilitate the purchase of another 8000MW of capacity, in a period of stagnant demand that seems as likely to lead to another period of decline as it does to increased demand.


The Global Adjustment is perceived as the troubled child of Ontario's electricity sector. 
Before forcing the child to change, we should listen to what it is telling us.

---

Notes

This column was instigated by the Council for Clean & Reliable Electricity release of a commentary titled "Putting the Pieces Back Together: "True Pricing" for Ontario Electricity"  The first sentence is:

Most people have surely never heard of the Global Adjustment (GA) mechanism yet it is why Ontario consumers are paying more for electricity than exporters of Ontario power.

From IESO June 2012 Monthly Report

If there were no GA, Ontarians would still be dumping excess generation on adjacent markets.  The GA is a measure useful for estimating a price on the dumping.  The terminology is admittedly tricky.  I reference a "cost of exports" in breaking down pricing for Ontario's customers, but it would be more accurate to call it "cost of dumping" or "cost of excess supply".

Ontario has a number of issues causing it to have a lower market price (HOEP) than adjacent markets - but the prices across markets are not entirely dissimilar, and Ontario's pricing power is limited.

The introduction to the CCRE includes, "the GA has been instrumental in meeting the government's objectives..."
True.
That is the problem.

The price signal works on the concept of scarcity - we should not be treating the GA symptom instead of the disease.
In the case of low pricing, the problem is abundance (the government policy).

---

The CCRE paper's premise I find poor, but there may be use in tinkering to improve the price signal, and I will make that the topic of a future post.

---

From Post #1 on this blog, in November 2010:

This graph clearly shows that since 2007 the only driver of per watt price increases in Ontario is the contracting of supply at greater expense (note the HOEP does match the demand curve quite closely).

---

Year-to-date Highs And Lows In Ontario's Electricity Sector

Posts have been sparse lately.  I've been working on the data side, including on putting reports up on my data site.  Yesterday I wrapped up what I wished to accomplish in terms of monthly reporting - which followed the creation of a cost breakdown report.  All of that work is to serve as a reference for myself, as well as readers of this blog.

I have just updated the weekly reporting, the first report I created on the data site.

Week 27, from July 4-10, is the highest Ontario demand week of the year, at 3,076,701 MWh.
Not surprisingly, it also has the highest average Hourly Ontario Energy Price of the Year - although that price is still only $37.25.

Nuclear, gas, and coal generators all had near high weekly generation levels for the year.

Hydro had it's worst production level of the year, which is a statement that has been true for the past 3 weeks.

Wind had it's worst production level of the year.
By far it's lowest production of the year.
Weekly total output of 34,101 MWh was 36% lower that the previous week (which wins 2nd lowest generation of the year).   To find a lower week of output, we need to go back to the heat of the summer of 2011.

Changing statistical periods only a little, performance for the first 6 months of the year shows wind, coal and gas, and therefore emissions, up.
But not demand, which remains slightly down due to a warm winter.

The big down is in the HOEP rate, which is 35% down, making the gap between price for export customers, and Ontario customers, widen.

The Globe and Mail's Flawed Reporting on Alberta's Brownout

... troubles occurred at four coal plants and two natural-gas plants, Mr. Simpson [director of market operations for AESO-Alberta Electric System Operator] said. They all suffered unrelated problems, have different owners, and are located in different parts of the province. Wind power helped fill the void, and by late afternoon, three of the six troubled power units were ramping up their operations, Mr. Simpson said.

The Globe and Mail - July 9, 2012

The problem with the statement from Mr. Simpson is that it is nonsense.
The problem with the Globe and Mail is it's disinterest in that.

The facts are simple. Alberta has over 939MW of wind capacity, which didn't step in to anything but for a mild bump in a wispy moment around 6pm.

Other, suddenly more reputable outlets, got the story right.

The Vancouver Sun and The Edmonton Journal

Energy Minister Ken Hughes said rolling backouts were instituted with no warning across much of the province Monday because of an unusually bad set of circumstances, including extreme power demand, unexpected shutdowns of several generating stations and calm weather that kept wind turbines still. 

The daily report can be found at www.aeso.ca - but it takes some digging so I've embedded it here:

Checking into reporting available at the Alberto electricity system operator (AESO), I quickly located a weekly reporting and checked a week for the heart of January.  It demonstrates how wind is not reliable for meeting demand needs in either peak season.

Week 26 Reporting: Nuclear productivity highs and continued pricing woes

I've had a lull in posting as I am developing some more reporting on my data site to support future blog posts.
Here's a post to indicate how my Weekly reporting demonstrates the supply mix, pricing, and export issues frequently noted on this blog - and increasingly elsewhere.

Weeks 25 and 26 are amongst the highest demand weeks of the year.  Peaks are far higher than in January, but total weekly consumption is yet to surpass week 3.

Summer is now our peak (hourly) demand period, which should raise some supply requirement issues.  During the highest demand week in January, peak demand was ~7000MW above the minimum demand for the week.  During the heat of week 25, demand rose to ~12000MW above the minimum demand for the week (essentially doubling the week's minimum demand).
Ontario has been meeting this demand through exceptional, timely, availability of it's nuclear fleet.  The following graph, for week 26, illustrates increased demand Thursday-Saturday (a negative "demand_reduction"), with the constant increase in production coming from nuclear generation.

The very significant generation from nuclear is tremendously important in meeting peak demand, but is requiring frequent curtailment activity even during these higher demand weeks.  Bruce B underwent a number of maneuvers last week to curtail generation during the wee small hours as supply outstripped demand by more than we could find other markets to pay to take the excess output:

My weekly reporting page contains a graph showing estimated curtailment hours - along with hourly wind production.

It is not surprising that the surplus generation baseload periods in week 26 experienced some sharply negative pricing.

The recent heat has increased demand significantly over 2011, with growth over the two weeks (25 and 26) averaging over 1400MW per hour, but the Hourly Ontario Energy Price continues to trail last year's low levels, with an average price of ~$26/MWh.

For Ontarian's now being charged over $80/MWh for that supply on their regulated price plans, the discomfort of soaring temperatures is exacerbated by subsidizing exports at about a third of their price.
Exports have climbed, on average, 430MW each hour during weeks 25 and 26.