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.