Should OPG sue the IESO and/or the OPA... and other questions from the market of 2014

Energy markets in Ontario have behaved far differently during the early months of 2014 than they have for many years. Most Ontario ratepayers will experience a rare instance of the total commodity cost dropping in January.  Unfortunately, that's not going to be a trend; the first 7 weeks of 2014 are more notable for questions the behaviour of Ontario's energy markets bring up regarding Ontario's markets, the reliability of it's energy supply chain, and the competency of it's bureaucracy to manage the system in a manner that provides value to both ratepayers and the overall public.

January's final numbers for the Ontario electricity market are a monthly average (weighted) Hourly Ontario Energy Price (HOEP) of $65.43/MWh (the highest since December 2005) plus a global adjustment rate (class B) of $12.61/MWh: the total, $78.04/MWh, is down from $81.58 in January 2013.

While the total commodity rate hasn't changed much, the changed composition of the price, a lower global adjustment charge and a higher market rate (HOEP), makes a big difference to Ontario Power Generation (OPG).  Here's how Parker Gallant and I put it last May:

The big lag on OPG’s earnings has been the unregulated hydroelectric segment. It contributed more than $500-million or 46% of OPG’s pre-tax generation in 2008. Now it loses money. The reason for the loss is simple: OPG’s non-regulated hydro-electric assets are the only significant generation in Ontario exposed to the market price of electricity, which has collapsed under the McGuinty Liberal green energy manipulations. OPG’s non-regulated generation has fallen by 31% since 2008, revenue by 58%.

In 2014, coal-fired generation is removed from the market place, and suddenly the value of production from OPG's non-regulated hydroelectric assets is receiving ~$71/MWh, instead of the $33 it received for the corresponding period in 2013.  I estimate the difference is nearly $90 million in revenue to OPG, and we are only 7 weeks into the first year without coal.



Critics of continuing coal past the 2007 date originally promised by Dalton McGuinty, in 2003, blamed the IESO for forcing it to continue operating; as demand dropped after 2005, and in light of the 4500MW of natural gas-fired capacity entering operation from 2008-2010, it's worth asking if the generation from Lambton and Nanticoke were needed in 2011 and 2012.
One reason it's worth asking is because of the damage done to OPG's profitability by the supply glut depressing the HOEP; another is because it's also worth wondering if Lambton and/or Nanticoke wouldn't be useful right about now.

The "energy" in the HOEP has always been a misnomer- it's an electricity price.  There are other "energy" prices in Ontario.  There are many times the HOEP is set by the price of  natural gas - and the price of natural gas is a story all on it's own; pushing electricity generation into the tasks demanded of natural gas adds a new pricing risks to residential gas consumers.

In terms of the final electricity rate being lower for most of Ontario's ratepayers exposed to the market, it's not because the cost of procuring supply dropped; I estimate the average rate for supply rose $2.39/MWh, but last year's losses on exports added ~$5/MWh to last January's bills.   The costs to Ontario ratepayers is a little lower because the rate recovered from export customers was more than twice last year's.

Known mechanisms at work in causing the higher market rate (HOEP) include rising natural gas prices being the marginal supply at times, and exports setting even higher prices at other times.

"Net Revenue Requirement" (NRR) contracts for natural gas generators seem to have benefitted Ontario's ratepayers in January.  A news release accompanying the first NRR contracts in 2005 stated:

Screen capture from NGI Data - price at Dawn hub soars!

The contract winners are assured that they will have sufficient ongoing revenue to meet their fixed project costs, such as capital and financing, if they operate efficiently according to the pre-agreed standards. When market revenues exceed these fixed-cost requirements, the contracts stipulate that 95 per cent of the surplus will flow back to ratepayers.

All good, except that in February the NRR contracts generators have not been generating at the same level they did in January - even as the HOEP has continued to be higher than we've seen since 2005. They don't even seem to be operating at the same level they've operated at in past Februaries.  This raises questions about the security of energy supply, particularly as the change in pricing performance occur in the first high demand months since Ontario shuttered it's coal-fired plants (Thunder Bay GS excepted).

Economically there's a number of questions:

• are the NRR suppliers attempting to lock-in supply in advance (hedge), as suppliers in a competitive market might, or do they not, because most profits aren't to benefit them at all?
• should the NRR contracts allow them to lock-in supply?
• do we have enough supply for an extended period of cold temperatures, both in terms of storage capability and pipeline capacity?

I don't know the answer to these questions.

I do know that 8 of the past 9 days Ontario has been a net importer of electricity - and that was only true 9 days from 2010-2012.   Over the first 16 days of 2014's February, the NRR gas generators contracted to have supply available have generated less electricity than they did during the same period in each of the past 3 years.

A dozen years into what was supposed to be a competitive market the questions that need to be answered for Ontario to have functioning energy markets, for electricity and beyond, are not likely to be asked.

Ontario copied Germany's feed-in tariff (FIT) program but not it's coal policies.  It's not apparent that ordering a la carte off of the German menu was feasible; the lack of peaking depth in Ontario seems to be a key determinant of a newer, peakier, daily pricing profile.

The demand reported by the system operator is not as high as what it reported in 2008, and well below the level of 2004, but those numbers are less and less reliable; only a midday drop in pricing indicates inexcusably unreported solar production.

The shrinking of the global adjustment, which I've called "a measurement of the dysfunction of Ontario's market," is a healthy sign.  The pricing curve is now brutally honest in identifying the morning demand ramp and the evening peak demand - with much of the peak demand occuring during, comically, "off-peak" pricing hours.

The market's behaviour this winter indicates troubling questions for a province intent on shrinking it's diversity of firm, reliable supply.

January's exceptional electricity market

It's been cold.
The temperature impacts energy pricing.  Ontario's electricity system operator shows an average Hourly Ontario Energy Price (HOEP) of $65.43 per megawatt-hour (MWh) - which is the highest it has been since 2005, although well below the ~$89/MWh (8.9 cents/kWh) that regulated price plan consumers will average.
A couple of entries on the "Ontario Network for Sustainable Energy Policy" blog (parts 1 and 2), dealing with temperature and price caught my attention this week; the first of which concluded observations "stimulate further discussion about the drivers of Ontario’s electricity system, "which can then feed into conservation and demand management discussions...and about sustainable energy service provision in this province more broadly."   

I'll analyse based on two months with comparable demand data; comparing two similar demand periods migh communicate more about the impacts of supply and pricing changes.

This being Canada, it doesn't seem that surprising that January provides the majority of the highest demand months over the past decades[1]. 

This blog has covered a number of pricing/demand matters before - so let me skip through the main points that might stimulate discussions outside of schools:

• most suppliers in Ontario act as "price-takers" in competitive market do; meaning they aren't involved in setting the market rate (marginal control price, or mcp, in Ontario); this supply has guaranteed rates so the HOEP is largely irrelevant; there are issues when this supply (wind, solar, nuclear, regulated hydro and non-utiltity generator production) is all that is required
• some unregulated hydro exists, which can set prices at times
• there are a set of generators paid for capacity with net revenue requirement contracts, and because of that the price is generally set by the cost of fuel for these generators
• Exports are also purchased, and join some hydro and some gas as the likely candidates for setting the marginal market price 

Total monthly Ontario Demand [2] was higher in January 2014 than it had been since January 2009.   Comparing the average hourly metrics for the two Januaries demonstrates where demand, and pricing, changes occurred

The big changes in pricing come during the early morning hours, and the evening peak.  This is one month of data, and the month was exceptional in adjacent markets setting pricing on a number of occasions, but this peakiness in pricing for the morning and evening demand ramps is something to watch.  

Coal generation, eliminated in most of the province as of 2014, did provide superior peaking depth, and the absence of coal-fired generators may result in more price spikes.

In 2009 not many Ontario ratepayers were on time-of-use (TOU) rates, so an evaluation of the impacts of TOU rates isn't possible in comparing a month in only 2009 and 2014.  However, it is clear the first price spike is exiting off-peak hours while demand, and the other higher prices of the day, are in the early evening hours, which, as of hour 19 (7 pm) are now off-peak. [3]

When including an estimated production from solar panels [4], the conclusions about market changes must change significantly.  The following graph shows only the changes from 2009 to 2013.

Adjusted with estimated embedded solar panel generation, the changes in daily consumption patterns looks very different.  TOU pricing policy has actually shifted use to the highest demand period of the day, with a corresponding jump in wholesale market rates during hours 19-22.

It's expected that winter demand see a dual peak, at least for pricing - with the morning ramp up in demand presenting a challenge, and the increased demand of lighting and cooking, as well as heating, coming after nightfall.  But looking at the extent of the change in hourly pricing between 2009 and 2013, it would not be implausible to suggest the system operator is surprised each day by excessive supply, or lax demand, during the sunlight hours.  With a brief exception mid-morning, the price pressures at sunrise and sunset surround a price change curve inversely matched to changes in solar output.

Looking at pricing the solar data may surprise many; solar output, in winter, has only average value to the market.  While that's far better than it's cousin, wind energy, I'm not sure many informed people would choose to spend 6.5 times more contracting intermittent supply providing a product of average value.

The clear leader, measured by the market valuation of production, was natural gas in January -as it usually will be.  With coal pushed aside for political reasons, gas generators had record production and probably record revenues - although much of that production came from producers with net revenue requirement contracts that should see the vast majority of the profits flow back to the Ontario ratepayers who fund the availability of the production every time they pay a bill.  Consequently much of the HOEP price increase will simply result in a lower global adjustment charge.  While the market revenues will be up for January, the charges to most Ontarians will not be. [5]

Known ways for the HOEP to rise are an escalation in fuel (natural gas) pricing, and export markets setting the price.  In January 2014 both were, at times true.

The beginning of this blog entry noted an evaluation of weather and electricity demand opining it might be valuable in "conservation and demand management discussions...and about sustainable energy service provision in this province more broadly."

Highly unlikely.  A useful discussion about sustainable energy would note Ontario is only procuring product (wind and solar) which the market values least.

Demand does not set price except as part of the supply and demand relationship; supply that has no capacity value can only reduce prices when it produces.

Demand management pricing strategies were, for winter, essentially, abandoned in 2011.  TOU is a plaything now - and that is likely a good thing.  Ontarians pay for the system and it's not surprising they don't particularly feel like apologizing for eating warm suppers.

Conservation?
It's the highest demand month in 5 years and not only did Ontario meet it's demand needs, it exported heavily during higher price hours; January 2014 was aan exceptional month in that the average weighted HOEP for exports was higher than the average weighted price for Ontario's demand.

I doubt any particular lessons could be drawn from our cold January in 2014, but looking back to the last month of even greater demand might be instructive.  January 2009 likely had cold temperatures lead to deeper freezing, more snow and a later freshet during more temperate spring hours when surplus generation can be exceptionally problematic.

Despite January's high demand, 2009 ended with the lowest total electricity consumption since 1997.

Not sure what lessons could be drawn from a comparable month to start 2014.

It's cold; stay warm
Watch HBO.

Spring is Coming




Endnotes

1 The IESO has a .csv file indicating "Demand prior to market opening was derived from operational meters."   So data up to May 2002 is actually demand data, but after the market opened what the system operator (now called the IESO) reports is not demand, but the supply on it's grid.
This should have been greater than the meter data figures in the early years of the market, as line loss likely exceeded the amount of generation "embedded" within local distribution companies (LDC's).  As most solar generation, and some other newer supply, is embedded, the IESO's "Ontario Demand" would have been coming back to "metered" demand levels up to about a year ago, when demand reported by the IESO likely transitioned to being less than actual metered demand.
To complicate that, the IESO has also changed how it calculates the supply included in it's "ontario demand" -so the data quality is declining, but overall the trend shown is still likely reflective of reality.

2. As defined by the IESO - see endnote 1!

3. Time-of'-use hours changed prior to the general election of 2011, in order to move dinner hour to off-peak from on-peak for purely political reasons.
I'd suggest TOU is not a sensible policy regardless - so it's pricing will always be set politically.

4.  Embedded in local distribution networks, current solar capacity does not show as "demand" in IESO reporting - instead it would impact figures by reducing demand.

5.  The exception being the Class A customers who have worked the system assuming (likely correctly) the HOEP will be so low most charges will be from the global adjustment mechanism.

Most residential, and some business customers, will be on regulated price plan rates, and those rates are higher than a year ago.  However, the regulated price plan rates are forecasts of the average class B rate for a 6-month period. (adjustted for existing variance pools).  Class B rates will not rise perceptively for January - but they did in November and December and will likely resume their upward trend once the cold weather leaves.

Debt and indecency in Wynne's Ontario

Toronto's Premier Wynne has sent out Energy Minister Chiarelli to sing to the masses on the debt retirement charge burdening Ontario's electricity bills.
In the past we've seen Minister of Energy Chiarelli mangle the accounting related to electricity exports and the profitability at the public Generator, OPG; my rebuttal to the claims of profit levels at OPG included:

Profits that exceed those considered a fair return to the shareholder (the Province) for it's equity in OPG (all of it), were also to pay down the stranded debt.
And yet you still have a stranded debt charge applied to your hydro bill.

Now, regardless of how ridiculous the claim is following the last ridiculous claim, the Wynne government is looking at a line item charge (charges are BAD) on electricity bills, introduced by a Progressive Conservative government,(see what charges are) and telling us it should probably stay on the bill.

Compassionately, they are looking at a line item credit on the bill (credits are GOOD), the Ontario Clean Energy Benefit (OCEB) introduced by a Liberal government (see what credits are), and thinking maybe it should stay on there.

The Toronto Sun reported:

Hydro customers pay an amount toward that stranded debt with every bill.
Chiarelli said retiring that debt is taking a little longer than originally anticipated.
“The financial projections turned out not to be as precise as they were anticipated,” he said.
The ministry is now looking at options to ensure that when the OCEB comes off the bill, residential customers don’t face additional costs, he said.

At least until after another election, I'm sure it's useful to partisan Liberals to have a Conservative charge on the bill, amounting to 0.7 cents/kWh, and a Liberal credit, amounting to twice that amount (or more), but the existence of the debt retirement charge (DRC) has nothing to do with the existence of the OCEB.

Heck, the existence of the DRC has nothing to do with the debt levels either.

The Ontario Electricity Financial Corporation (OEFC) is the entity that was tasked with handling the debt of the former Ontario Hydro.
In the final full fiscal year before the McGuinty Liberals replaced the Eves Conservatives in power, the OEFC reported debt of $26.8 billion.
The most recent accounting shows the OEFC's debt at $26.9 billion  (Table 5.5 of 2013 Ontario Budget) .

It does not look like Liberal governments have attempted to pay down any debt.  The big picture is more muddled than this, with different types of debt with different revenue sources meant to address one debt pocket or another.[1]   The original care in structuring the debt seems rather nonsensical in hindsight: since 2003 Liberal governments have not reduced debt, the market share of the public generator (OPG) has shrunk as it's assets aged, and the market has contracted (demand is down).  Whatever debt there now is must be more vulnerable that that which existed a decade ago.

What the government has done is spend recklessly.

OPG's Niagara Tunnel project was financed through the OEFC.  It began construction not long after Dwight Duncan's "hybrid" system was introduced, which set low regulated rates for OPG's large hydroelectric assets to offset the much higher rates the government intended to contract from private-sector suppliers, with the expectation this, "would keep the overall blended price for electricity relatively stable.” Over the next seven years OPG's hydroelectric output would be remain at essentially a frozen, very low, regulated rate as the rates charged to consumers soared, while OPG was forced to finance $1.5 billion in spending on the Niagara tunnel project.  Only 1 cent/kWh more on OPG's regulated hydro, during construction of the tunnel, would have avoided any loan, Parker Gallant advises that the cost of the financing will instead be, "about $96 million annually ...for the next 50 years (amortization period), which equates to $4.6 billion."[2]

The debt incurred during the Niagara Tunnel project benefited OPG's private producer competitors as OPG's regulated rates hit the cost impacts of the new supply; now the debt will benefit financiers for some years to come. There is no indication it helped ratepayers.

Tom Adams recently uncovered some sobering statistics related to OPG's other major hydroelectric project on the Lower Mattagami: $2.4 billion for 885 GWh/yr.  Were the interest rate 4%, that would require a rate of $110/MWh just to service the date.  But the price needs to do more than service the debt; the project is set up as a partnership which requires a return on investment.  Because the project has a Hydroelectric Energy Supply Agreement (HESA), Ontarians are unlikely to ever get an accounting of the financing, or to learn the price of the power purchase agreement.  The project looks like a social, or regional development, matter at this point - certainly not a "power" project the OEFC should have offered financing to. [3]

Perhaps the most clear signal that this government has no intention of paying down electricity sector debt, or provide electricity sector value for consumers, is not coming from the difficult generation side of the business, but from the profitable distribution side's Hydro One.  The legal Lexology site provided an exceptional article from Ian A. Mondrow last week dealing with what appears to be an unfolding spending spree; The future of Ontario's electricity distribution sector: renewal or disappearance?

...Hydro One has agreed to pay a sizeable premium over net book value to win the bidding process instituted by Norfolk’s owners. There were other bidders, but it is hard for others to compete with the Hydro One borrowing clout that comes from the backing of the provincial balance sheet.
...Also troubling is the chill that this acquisition path by Hydro One seems to be having on other would-be acquirers. There are not many utilities that can afford to pay the premiums Hydro One has agreed to pay for Norfolk Power
... Hydro One borrows to finance all of its significant investments.

...What is not clear is why the Ontario government, tacitly or otherwise, is endorsing Hydro One’s aggressive approach to local distributor acquisition. It can only increase Hydro One’ already large debt load, and is squeezing out potential acquirers that may be lower cost operators.

It's clear to me.

Debt is great - it allows a Progressive Conservative charge of 7/10ths of a cent per kilowatt-hour to remain on every ratepayer's every electricity bill.

Minister Chiarelli, having blessed another round of excessive spending by Hydro One, now spins that each ratepayer will see that Conservative charge continue because the debt just isn't going down as hoped.

There's just no way to stop collecting it.

To compensate the compassionate Wynne government will continue to show, on ratepayers' bills, their OCEB credit of 10%, or roughly 1.7 cent per kilowatt-hour.

This is idiotic.
Hopefully it is not also politically effective.

Endnotes

[1] I've wrote on this initially here and here; the Auditor General looks to have borrowed from those pieces in their 2011 Annual Report, and my most definitive work is Stranded Debt - Abandoned Responsibility)

[2] The inability to finance a project during construction isn't uncommon.  In Ontario, it strikes me as an artifact from the days of public electricity supply "at cost"; Ontario Hydro was not allowed to make a profit, so it could hardly reinvest profits in new projects.  Neither can its successors - which is, given what was to be a competitive market, a policy probably long past it's "best before" date.

[3] Most of the financing thus far the Lower Mattagami project is not from the OEFC, although there is an agreement to draw on funds from the OEFC - to be unfair, loans are at higher rates than the OEFC would have provided.
The OEFC's "effective rate of interest on the debt portfolio was 5.70 per cent after considering the effect of derivative instruments used to manage interest rate risk" (here)