Smart - or not: Ontario's Regulator calls for more new meters

I looked into an Ontario Energy Board (OEB) Notice of Proposal after seeing a tweet:

The Board is of the view that, given the current metering infrastructure and pricing environment, it is appropriate to ... require a distributor to install a MIST [Metering Inside the Settlement Timeframe] meter on any installation that is forecast by the distributor to have a monthly average peak demand during a calendar year of over 50 kW.

The comments the OEB has received on the proposal are informative - as is the omission of comments from a couple of well-paid government organizations that should have an opinion.

This is, I assume, a complex subject - particularly for people under the impression all of Ontario's electricity consumers already have "smart" meters.

They don't.
The OEB proposal addresses, for better or worse, a gap in policy.

Essentially all residential consumers should now have "smart" meters reporting through designed protocols and networks.  According to the most recent OEB Annual Yearbook of Electricity Distributors, about 90% of all customers fall into the residential category, but they don't account for even 30% of overall demand.

The next consumption category is for customers with an average annual monthly peak less than 50kw. Adding this class with the residential customers means total consumption of ~40% of all generation, but the class has well over 98% of all customers.

I'll assume this 40% of all generation reports to the Smart Metering Entity which maintains the Meter Data Management and Repository (MDM/R) that is populated from smart meter data communicated through the Advanced Metering Infrastructure (AMI).

At the other end of the spectrum, where the MIST meters exist, are Ontario's largest consumers of electricity with average monthly peak demand exceeding 5000kW (5megawatts).  A MIST meter is apparently smarter than smart - but maybe not as smart as we'd map the requirement if properly planning a grid for the future.  Regardless, between wholesale customers in the IESO market and customers embedded in distribution networks, these few (~0.003% of customers) account for ~16.5% of all consumption. In Global Adjustment mechanism parlance, these qualify as class A customers and their interval meters are required to establish a share of total demand during the 5 highest daily peaks (which in 2012 was, collectively, 10.04%).

It's important to note the hardware, communication standards and data requirements of the measuring device categories (smart/interval/MIST) are different.
Concerns of many of the local distribution companies is that the OEB directive will require spending money on new assets that strand old assets, and require significant technology spending to provide and manage worse data.

The OEB notice of proposal cited above is for customers with average monthly peaks over 50kW and under 5000kW.  This ignored group is a little over 1% of all consumers, but they appear to account for over 40% of demand.

Starting with this absurdity -that the nearly 99% of customers comprising around 40% of consumption were the target of a metering policy allegedly allowing for poorly targeted demand reduction programming - the much larger customers were not necessarily transferred to new metering devices (some have no interval metering and yet they may be charged time-of-use rates based on mocked up demand curves).

The local distribution company objections to the policy proposal stem from the direction in the quote above -"to install a MIST meter" - coupled with:

The Board expects that distributors will install interval metering systems that communicate through the distributor’s Advanced Metering Infrastructure installed as part of Ontario’s smart meter initiative.

It appears the regulator is cherry-picking: big-story meters and little-data smart meters.  From one submission noting that's problematic:

• There will also be additional costs for the Advanced Metering Interface (“AMI”) or MV90 systems to handle the new data stream. In some cases, the existing MV90 system would not be capable of handling the large increase in interval meters within the LDC. 

• If the Board were to require these meter reads to go through the Meter Data Management/Repository (“MDM/R”) there would be required changes to processes and file structures. It is not clear if this is the Board’s intent and the Utilities could not support this suggestion.

The big question might be: "if all these problems can be resolved, what should the interval of data collection be, who would it be of value to, and what access is required to add value."

I think the big answer is provided in the submission from Rodan Energy Solutions:

• Metering installations to have a customer-accessible communication port...
• Interval resolution of 5 minutes...

The Independent Electricity System Operator has been identified, for reasons I fail to understand, as capable of managing smart meter data, and now (more perplexing again) as capable of entering into procurement of supply including designing market policies for things such as net metering. The IESO's failure to champion the policies co-ordinating data collection with the market's 5-minute interval is an indication of ignorance about where markets must head to "facilitate CDM/DSM participation."

The failure of the Ontario Power Authority to comment is, provided their enormous conservation program budget, insulting to ratepayers.

There's no harm in the Ontario Energy Board distributing a notice of proposal, particularly if they honestly evaluate the comments.
The Board should evaluate proposals conscious that it did not "protect the interests of consumers" in the residential smart meter roll-out, as per its legal mandate.  They should feel a need to do better this time - and they'll need to do much better again if "net metering" plans are not accompanied by revised plans allowing a fairer recovery of the costs of transmission and distribution from all users of the grid.




NOTES:
Hourly billing has been ridiculous - in that the Ontario Power Authority/IESO tandem hasn't been able to identify a single hourly charge for the global adjustment (see the Global Adjustment/Ontario Roulette story)

Stats for this post, including references to base documents, are in this spreadsheet.

Natural Gas hikes impact on electricity pricing in Ontario

"After re-checking its numbers, the IESO agreed that Luft was substantially correct"

The price of natural gas impacts Ontario's electricity price; probably in ways many people don't anticipate.

On March 18th, an article by John Spears presented generation figures from Ontario's natural gas-fired fleet that I perceived to be incorrect.  Ouput from the province's natural gas generators is down this winter.  I communicated my concerns to Mr. Spears and the source of the incorrect data, Ontario's Independent Electricity System Operator (IESO), and, on Friday a second article corrected the first.
I appreciate the efforts of both in rectifying the data error.

Data is much less powerful than narrative and, unfortunately, some incorrect narratives survive the correction of poor data.  I was aware of the mistake in the first Star article (claiming a rise in electricity generated from natural gas this winter) because I'd written of record natural gas generation during January's coldest period (much of it for export), and started a summary of February's electricity sector activity with, "February was a disaster for Ontario's electricity consumers - but not nearly as bad as it will be for Ontario's natural gas consumers."

Natural gas pricing is expected to remain higher than 1 year ago throughout the summer season as storage inventories are replenished for, primarily, next winter.  The implications for the future can be gleamed from the impacts of the past.

Refresher on Ontario's Market

Higher natural gas pricing impacts the commodity wholesale market pricing.
The 5-minute market clearing price (MCP) is the relevant market price, but for reporting the average of that pricing is generally used - the Hourly Ontario Energy Price (HOEP).  That price is set by the most expensive supply bid accepted by the system operator (IESO).
The HOEP is not directly relevant to the vast majority of electricity purchased by Ontario's ratepayers.

The vast majority of electricity generated in Ontario comes from fixed-price supply, including: OPG's nuclear assets, OPG's Niagara system hydroelectric assets, OPG's Saunders generating station, Bruce A and B nuclear units (although B this needn't be true for), non-utility generators contracted by the old Ontario hydro (could have a floating price component dependent of natural gas pricing), and wind and solar generators.  These generators constitute over 80% of Ontario generation the a past few years.  When supply from these sources can meet Ontario's demand, the HOEP will usually be very low.

Coal, oil and gas generators often have capacity contracts guaranteeing them some payment to cover operating and/or capital cost recovery (contingency, reliable-must-run, and net revenue requirement formats). The wholesale rate (MCP/HOEP) will frequently reflect the spot market price of natural gas - because all the generators guaranteed a price can basically bid in a $0 (or much less) to ensure their generation is scheduled and the flexible gas generators have limited incentive to bid in above the cost of fuel. When gas generators must run, the price of gas is likely to determine the MCP/HOEP. [1]

A higher HOEP mainly lowers the global adjustment mechanism charge (GAM) - which is the mechanism ensuring the full cost of generation is recovered from ratepayers.  While the cost of supply doesn't change much regardless of whether it's paid through HOEP recoveries or the GAM, the distribution of those cost is heaviest on most Ontario consumers when the HOEP is low; high HOEP values are worse for Ontario's largest, Class A, customers.  Exported power receives only the HOEP.

Graphic from April 2013's Determinants of electricity
 pricing in Ontario: Beyond the Global Adjustment

In Determinants of electricity pricing in Ontario: Beyond the Global Adjustment I claimed "a 400% rise in the HOEP would result in only a 44% rise in the total cost of supply."   I estimate HOEP is increased 160% on a year-to-date basis as of March 23rd, and the cost across all consumer segments (Class A, Class B, and export) is likely up 18-20% - in line with my expectations.

Price is up the least for the Class B segment, which includes, indirectly, residential regulated price plan consumers.

Impacts of HOEP increase thus far in 2014

The single largest increase in total cost over the first 82 days of the year is almost certainly payments for  hydroelectric generation, as the only generation fully exposed, and now fully benefitting from, the market rate (HOEP/MCP). This comes with a major asterisk, as the revenue benefits a public generator starved for profits (OPG) precisely because the HOEP has been so low for so long that applications are already made for regulated rates to be set on the output (a very poor policy change).  It is likely the increased cost of hydro in the winter will result in less of an increase later.
Whatever profits are realized would be used to reduced the debt that is allegedly the reason for a debt retirement charge that stubbornly remains on consumers' bills.

Similarly, the impact of purchasing nuclear supply may cost an additional $200 million over the earliest period of the year, but have little difference over the entire year.  This is because the contract for supply from Bruce B has a floor price (~$52/MWh), which as best I can tell is an annual floor, calculated monthly.  I believe Bruce Power will have received ~$72/MWh for the supply so far in 2014, and the difference (which equates to ~$116 million) will be clawed back as the HOEP drops back below $52/MWh.
It's only slightly less possible they have not received the payments above the base rate.

The cost of purchasing generation from natural gas probably is up ~$135 million, but bundle it with other fossil fuels (coal and oil) and the increase is likely closer to $100 million.  That equates to paying ~10% more to receive ~30% less generation. 

The increased cost of imports is roughly equivalent to the increase from natural gas-fired generation; imports also edge out nuclear for the greatest increase in supply, with a 1.2 million megawatt-hour (TWh) increase.

Growth in nuclear and imports more than offset the decrease in coal and gas-fired generation, but demand is also increased. 

Wind and solar's estimated $124 million increase won't be mitigated later. These increases are likely to continue, and accelerate into the longer days of summer.   

On a positive note, revenues from the export of supplies look to be up ~$130 million despite sharply lower sales.  I estimate the average price of exported power is up 135% (from $30/MWh to $71/MWh)

Another factor which mitigates the cost increase for most Ontario consumers in a big shift in cost to the province's largest, Class A, consumers.   Because the global adjustment is dependent on cost recoveries through sale at the HOEP/MCP, the savings opportunities Class A customers can recognize by lowering their share of the global adjustment drop as HOEP rises.

I estimate Class A rates for the first 3 months will be up approximately 40% over 2013.

The overall 16-20% increase in electricity costs will be moderated for most Ontario's ratepayers by the steep hikes for export and Class A markets; class B consumers wil be seeing rates rise in the area of 10-12% for the first 3 months of the year - in line with the regulated price plan which was increased 12% prior to the season.

Implications

Residential and small business consumers are not likely to see rates rising substantially quicker than they have been due to natural gas pricing. Remembering that rates rose ~17% for class B consumers in 2013, that's small comfort.  Increases, likely double digit ones, will occur due to a great deal of expensive supply (wind and solar) getting added to the market.  

A greater issue for the immediate future is cost increases for industrial users.  Union Gas recently had a rate hike approved based on a forecast price of gas of 17.9207 cents/m3 - which my math indicates a fuel cost for electricity generation of ~$40/MWh.  That is 50% higher than the HOEP during the summer of 2013, so it looks like Class A customers will continue to see stiff year-over-year increases.  As the entire rationale for the Class A mechanism was to give the largest uses a break on pricing, presumably as an attempt to maintain some industry in the province, this is not welcome news.

That the IESO did not know the seasonal consumption of natural gas in electricity generation was down this winter is primarily a concern in that a shortage of supply (the primarily storage hub in Ontario hit "historic" lows) was exacerbated by the export of gas-fired generation during January's cold snaps.   Ontario subsidizes the operation of generators and those generators often sell into the US market at, or near, only the cost of fuel to generate.[1]

A concern is that there is no authority watching the supply situation.

A bigger concern is that selling subsidized gas-fired generation in export markets has escalated the costs of manufacturing in Ontario.




Endnotes:

1.  See: Ontario's Billion dollar subsidies of Gas-fired Electricity Generation

Power at what cost: appraising Ontario Hydro's successors

It's been a decade and a half since Ontario Hydro was broken up into 5 successor companies.
Recently the generating company that is one of those successors, Ontario Power Generation (OPG), reported it's 2013 results - which weren't very good.  Earlier in the year Hydro One - the transmission and distribution successor - released 2013 financial results that indicated a record net income.

A day after OPG's 2013 results were released the government announced new Chairs to the Boards of both OPG and Hydro One.  It's not surprising that both new Chairs have backgrounds as politicians as both entities have image problems. A recent report by the Auditor General of Ontario hammering costs at OPG has many clamoring for changes in the governance there, and Ontario's Ombudsman has an active investigation into Hydro One's "billing practices and the timeliness and effectiveness of its process for responding to customer concerns."

OPG's 2013 performance is impacted by other entities.
This post is a broad overview of today's status of successor companies to Ontario Hydro [1], particularly in terms of their impact on the public generator.

Ontario Electricity Financial Corporation 

The Ontario Electricity Financial Corporation is, as noted in its first annual report, "the legal continuation of Ontario Hydro ... responsible for ensuring the prudent and efficient management of $38.1 billion (as of April 1, 1999) in debt, derivatives and other liabilities of the former Ontario Hydro."  Ontarians might think the OEFC is paying down debt, because since Ontario's wholesale market opened May 1st, 2002, they've been charged 7/10th of a cent on each kWh of consumption as a debt retirement charge (DRC).
That works out to around $1 billion a year.

Ontarians thinking debt at "the legal continuation of Ontario Hydro" is going down are wrong.

Looking at the history of annual financial reports, the total debt level of the OEFC is higher in the most recent report (see pg1-105) than it was in the report preceding the election of Liberal Dalton McGuinty as Premier of the province in 2003 (pg 16 here).


The data shows the the revenue tools given to the OEFC have not resulted in debt being lowered in the past 14 years as much as it was in the 5 years before the OEFC "legally continued" Ontario Hydro.  It's also notable that the OEFC hasn't posted annual figures, on their site, for their fiscal year ending March 31, 2013 - whereas Hydro One and OPG have posted their reports for fiscal years ending December 31st, 2013.[2]

Profits at OPG and Hydro One are one tool that could fund the OEFC's alleged task of paying down debt; others are the debt retirement charge(DRC) and payments-in-lieu of taxes (PIL).  However, there's no evidence the OEFC is meeting the expectations of it as it come into existence 15 years ago.

Ontario Power Generation

OPG reports 2013 net income for the year of $135 million - down $232 million from 2012.  All of the decline, and more, can be attributed to the nuclear business segment.

Although nuclear generation was lower than in 2012, it was within the  44.2-49 terawatt-hour (TWh) range it's been in since 2005.

Gross margin was down only $142 million while the loss of $19 million was a drop of $383 million from 2012 - meaning the majority of the loss was due to non-generation factors including some 2012 accounting changes that befitted only 2012, combined with whatever financial voodoo is involved with "depreciation and amortization" changing $146 million.

The loss on the nuclear business segment - the first since 2007 despite rates essentially being frozen since 2008 - is more notable because OPG's unregulated hydro business segment continued to produce little in 2013- receiving an average 2.8 cents/kWh, far below 2008's 4.8.  Parker Gallant and I covered the loss of profitability in this business segment in Ontario Power Generation Turning Water Into Debt last May.  That article noted:

... massive increase in supply has been instrumental in the market price collapse and OPG’s decline. The public generator is being devalued at great cost to taxpayers by the collapse of the market price brought on by massive new and redundant non-coal sources of power.

One of the treasures in OPG's rate hike request documentation, currently before the Ontario Energy Board, is that this supply is to be given a regulated rate - and 'the ask' appears to be around 4.8 cents/kWh (the average in 2008).  This is the largest hike OPG is requesting for its business segments.

view as a Google spreadsheet

The hikes will not necessarily be approved by the Ontario Energy Board (OEB), which has turned down rate requests from OPG in the past (I criticized a 2011 decision here).

As the OEFC review hinted, reducing debt is not an actual priority; the priority the government has for OPG is to"keep the overall blended price for electricity relatively stable.” [source]

OPG's poor financial results for 2013 come after half a decade where their stable rates have hidden the impact of rapidly rising average costs from private generators - particularly non-nuclear ones.

If OPG is being evaluated on it's ability to generate revenue, it had a bad year.

If OPG is evaluated on the basis of hiding the inflationary impacts of other generators, it had a good year. Had OPG received the average rate of all the province's supply, it would have ~$1.3 billion more revenue for 2013.

Hydro One

Hydro One, the distribution and transmission company originating in the breakup of Ontario Hydro, has been the money-maker; OPG last out-earned Hydro One in 2010; in the 3 years since then, Hydro One has averaged income of $730 million to OPG's $280 million.
Hydro One has set a record for annual net income each of the past 4 years.

More than 3 years ago I communicated how "smart" grid, metering in particular, and proposed transmission expansions to enable wind and solar generation, have been beneficial to Hydro One; all the capital spending allows it to ask for higher rates from the Ontario Energy Board (OEB).

Hydro One's good returns are due to a growth in equity - rates being regulated on a return-on-equity basis. Only late in 2010 did the regulator seem to resist reckless spending as an outcome of any whim from the government (OEB ruling noted here). By that time, most Hydro One customers had smart meters installed and capital spending had peaked.

Hydro One now claims it's customers are "currently paying $3.92 per month to recover smart meter-related costs."  There's an additional charge paid to another entity of  $0.806/month, so in fact the smart meter adventure is costing the average Hydro One customer $4.73/month - 28 cents more than OPG's rate request  application which notes an estimated consumer impact of $4.45/month.

Hydro One's current plans don't call for severe price hikes, but they do a call for 3 years of record capital spending.  One possible future has them continuing to be the big revenue generator for the province, but there are some threats on the horizon.  One is a general backlash against basic billing competency eroding under all the capital-intensive "improvements" to metering and billing systems - which should prevent the regulator from falling back to rubber-stamping rate requests.

The greater threat is one not unique to Ontario - it is self-generation. Another of the successors to Ontario Hydro, the Independent Electricity System Operator, is exploring net metering policies that are likely to negatively impact Hydro One's revenues.

Independent Electricity Market Operator (IMO)/Independent Electricity System Operator (IESO)

Upon the break-up of Ontario Hydro the Independent Market Operator (IMO) was created - it was renamed the Independent Electricity System Operator (IESO) for 2005.

If the IESO is evaluated on the basis of its current name, it could do well - the system operates.
If it was evaluated on the implication of the original name - in terms of the functioning of the electricity market - it would not score well.

In 2013 the market recovered the lowest percentage of the cost of supply in it's history (the Global Adjustment Mechanism existing to recover the full cost of supply).

Ontario added supply as prices dropped (along with demand) as the government refused to depend on a market's price movements to signal generators to enter, or exit the market.
The contracting of new supply was decreed by the government, and carried out by the Ontario Power Authority (OPA), but the IESO has long been active in preventing existing supply from closing.  They contracted OPG to keep the Lennox Generating Station operational as far back as 2006. OPG had written off the plant citing, in its 2005 financial results, lost expectations of a capacity market concurrent with the government's initiative to procure 2,500MW of new supply.

The IESO's June 2006 Reliability Outlook included a "Coal Replacement Policy" section, which argued that planned retirements could not take place for a number of reasons, including replacement generation developing slowly, transmission issues, and no satisfactory replacement existing for the "voltage support" provided at Nanticoke.  This outlook included the outline of what would become a contingency support agreement for OPG's coal units, before concluding:

The IESO will continue to monitor the progress of the coal replacement program and will provide timely advice and notice on when circumstances are such that the units can be put on reserve status and then removed from service.

The government then changed tactics, from closing coal in 2007 to limiting emissions along with issuing a contingency support agreement through 2014 (with some flexibility - as the IESO's 2006 report had advised). Although the IESO felt coal pivotal to system stability beyond 2007, it probably could have made some suggestions as to how to avoid the production from coal in 2008 that contributed to record exports that year. [3]

In January 2013 it was not the IESO, but lame duck Premier Dalton McGuinty, announcing the closure of the final 6 coal-fired units in southern Ontario.  Ontario's ratepayers will continue to fund contingency payments throughout 2014.

It's never been apparent that the IESO considers the abundance of supply to be relevant to the functioning of a market.  9 years and $2.6 billion after they agreed to pay for Lennox to be available [4], the IESO is now to investigate the capacity markets that OPG had felt imminent a decade ago.

Despite the billions received to keep the generating units available, the unregulated thermal business unit of OPG lost over half a billion dollars since 2006.

Government/Conclusion

OPG's 2013 financial results weren't good, but there's reasons for that beyond OPG.

Low revenues from wholesale market sales at continued very low rates are, in part, due to excessive government procurement policies and a very cautious system operator (in terms of capacity).

The bigger issue may be environmental/cultural.  

No government has been enthusiastic about public power for over 2 decades - and that includes governments formed by 3 diverse parties.  This can't be good for morale.

The Liberal government's push for wind and solar power shoved hydroelectric power aside.  The Green Energy Act, passed in 2009, raised the rates for solar and wind contracts as revenues for OPG's unregulated hydro revenues were dropping rapidly.  Perhaps worse, those contracts gave priority to the new generators.

OPG's annual report states, "dispatching hydroelectric units down to reduce production" is the first choice of curtailment options at the IESO.

There's a limit on OPG's ability to contribute to its future through superior operations.  The Auditor General's 2013 report appalled people with it's depiction of reckless spending at the generator, but it's important to review what happens to revenues from Hydro One and OPG.  All revenues go to the sole shareholder (the Province), and the law is that the first $520 million pays interest on a supposed $8.885 billion debt, and the remainder pays down another defined debt (the residual stranded debt).  Neither OPG nor Hydro One can retain earning to invest in new opportunities.

Worse, the reality is that the earnings legislated to retire debt aren't actually being paid to the OEFC, but only recorded as an asset "Due from Province..."  

That asset was $3.266 billion as of March 31, 2013; the last time the Province actually used electricity sector revenue to actually pay down electricity sector debt, Ernie Eves was the Premier of Ontario.

ENDNOTES

[1] The 5th original successor entity to 1998, as per the Electricity Act, 1998, is the Electrical Safety Association (ESA).

[2]  For an overview of debt issues, see Stranded Debt - Abandoned Responsibility

[3] An overview of contingency payments to Ontario Power Generation, is here.

[4] The $2.6 billion figure assumes that the revenue line "Other" is  revenue from the agreement (now for only Lennox as "Contingency support agreement" is a separate line item - for the coal stations).

The blog, the question, the answer, and the wind moratorium?

I have a number of blogs - this being the main blog for my entirely my original content, and coldaircurrents the blog I usually post non-original content to, usually with some input as to why I find it relevant to the subjects I follow.
Yesterday I posted to a secondary blog I've been maintaining, partly to say more partisan, and meaner, things that I think may not fit with the brand I've built here.   The particular post is partisan, but its content is substantial, as indicated by both parties in an exchange in the Ontario Legislature's question period today.
I raised an eyebrow when commercial operation dates were mentioned in the question, but really couldn't avoid thinking there was a connection to my post when Minister Chiarelli says in answering:

the reality is since the first of award of contracts under the FIT program... there has been an actual moratorium on wind because we have not issued any new wind projects.

Where did that come from?
With the distinction between my blogs blurring ... here's a video of Lisa Thompson questioning Bob Chiarelli today, followed by my post of yesterday - which may have been known to both sides in the exchange.


Ontario Liberals Often Fail to Honour contracts (first posted at morecoldair.wordpress.com)

The Toronto Star ran an article recently indicating a political leader in Ontario would not honour contracts.   That leader was PC leader Tim Hudak, and since I've said in the past Ontario's ratepayers would have saved billions by electing Hudak's party when they had the change in fall 2011, I thought I'd take some time to show why that is, and how the current government has not honoured the contracts signed prior to that election. The PC's party "Changebook" 2011 campaign platform included;

We will end the feed-in tariff program that, in some cases, pays up to 15 times the usual cost of the hydro. Hardworking farmers and other Ontarians who signed contracts to host energy production on their property will have their contracts honoured. But there will be no more of these deals. We will end the king of all secret, sweetheart deals – the $7 billion Samsung deal...

As Mr. Hudak's stance of trying to end contracts is portrayed as being impractical, in the Toronto Star article and elsewhere, it's important to note that in the two years following that election there has been little new contracting of supply.    Comparing the OPA's 2013 Q3 – A Progress Report on Contracted Electricity Supply to the same report for the quarter prior to 2011's election, only 33.6MW more "wind" shows as being contracted ( 5,755MW total), and 62.7MW more solar (of 2,050MW total).    The majority of renewable supply contracted since July 2011 is the conversion of Atikokan from coal to biomass (Hudak is currently being criticized for supporting another biomass project).
Despite the lack of new contracts, the contracts not "in service", but "under development", went down by less than 25% over the two years. The earliest contracts under Ontario's now mercifully defunct (for industrial wind) feed-in tariff program were offered almost 4 years ago, in April 2010.  Despite the contracts including, "The Supplier acknowledges that time is of the essence to the OPA with respect to attaining Commercial Operation of the Contract Facility by the Milestone Date for Commercial Operation...the date that is three years following the Contract Date,"  most of the projects initially contracted did not meet the timelines.  Many still aren't in service, nor are any of the sites contracted in February 2011, although those sites were contracted after the first sites were given a option to extend the timelines. The government continues to find reasons to offer extensions to projects.

Not long after I wrote Killing Time, in April 2013, the government did finally take one small step to rectify a too-generous, and not necessary, contract, and revised the agreement with the Korean Consortium - but instead of honouring the contract (by cancelling it after the dates were missed), the government newly guaranteed a minimum rate of $295/MWh for large solar in a revision; a competitive bid would currently come in far, far below this price, and the most recent, still too high, FIT price is already under the Korean Consortium's foolishly guaranteed minimum.

More slow was the government to respond to another article I wrote in in 2012, Billions at Stake In Feed-In Tariff Contract Fine Print.   The article may have had some impact on Minister of Energy Bentley, as the rumoured gifting of payments for curtailed production from industrial wind turbines didn't occur - but once Kathleen Wynne became Premier and installed Bob Chiarelli in the Energy ministry, the gift was given.  This too is a violation/alteration, of some original, pre-FIT, contracts.

Early indications are that policy changes to pay for curtailed supply will benefit a few large companies (see Big Thunder is a Big Mistake).

Successive Liberal governments have failed to honour the public's side of contracts by attempting to enforce the original agreements.  The Niagara Tunnel contract was re-written (to enrich it for the contractor), and the Oakville Generating Station moved instead of letting the courts sort it out (Oakville may have prevented the project from moving forward without the still ratepayer penalty).

Tim Hudak is not the one who should be under examination for how his approach to managing contracts will cost Ontarians.

Note: spreadsheet comparison of OPA Q3 figures of contracted renewable supply, for 2013 and 2011, is here

 Related: Wind Feed-in Tariffs in Ontario: An Info-Obit

Declining security and soaring industrial rates: February numbers show Ontario's Energy Policy is non-existant

February was a disaster for Ontario's electricity consumers - but not nearly as bad as it will be for Ontario's natural gas consumers.

Here's some storylines from my first look at February electricity data from the Independent Electricity System Operator (IESO):

• $81.39 weighted average Hourly Ontario Energy Price (HOEP), which is up $16.40 from January, and 178% over February 2013 ($29.31)
• Ontario Demand is shown [1] as 11.4% lower than January 2014, and 2.8% higher than February 2013
• Total market value of ~$1.05 billion, by HOEP, is up 5% from January, and 177% from Feb. 2013
• The 2nd estimate of the global adjustment is $178 million, up 10.8% from January's final, and down 66% from February 2012
• The total costs (market value at HOEP plus global adjustment) will be $1.23 billion if the global adjustment is not changed when finalized, which would be the highest monthly value since the market opened in May 2002
• Exports were ~966GWh, down 44.5% from January and 22.2% from Feb. 2013
• Imports were ~877GWh, up 88.5% from January and 248.6% from Feb. 2013
• Ontario's natural gas generators produced ~ 1.47TWh in February, down 39% from January and 36.5% from Feb. 2014

The increased HOEP is entirely a natural gas supply story: the victims in the story are the largest consumers in Ontario.  

The chart refers to "Class A" global adjustment consumers as "industrial" - which should be true, but isn't entirely correct

The Toronto Star carried an article last week, Ontario's big industries plead for lower hydro rates, expressing the concerns of the Association of Major Power Consumers of Ontario (AMPCO); those consumers are likely to see rates for February 2014 about 50% higher than a year earlier.  AMPCO had lobbied in 2010, successfully, for a scheme in allocating the costs of supply, not captured through the market HOEP charges, that would benefit their membership - but this winter's sudden shift in cost recovery back to the HOEP has greatly wiped out the cost savings they had been experiencing due to that change.  Ontario's official opposition party recognizes the threat of higher electricity pricing to the provincial economy, but the Minister of Energy continues to dismiss concerns even as his lack of an energy policy drives prices, particularly those for industry, rapidly higher.

In December the province released what they incorrectly titled a "Long-Term Energy Plan."   All  the terms in that reference are questionable, but the relevant misuse today is of the word "energy"; to the extent the document presented a plan at all, it was an electricity plan.

The province's long-term desire to get rid of coal-fired generation was largely accomplished at the end of 2013, as the units remaining in operation at Lambton and Nanticoke were retired a year early.  
Luck was not with Ontario as a cold winter accompanied the loss of coal, putting an enormous load on the natural gas fuel that heats most homes in the province.

Image from NGIdata; DAWN hub pricing

Intelligence and responsibility were not with Ontario either.  As demand spiked in adjacent jurisdictions in January, Ontario produced electricity with natural gas, much of it for export, at record levels - for a change, exports were at a rate that made a profit for Ontario's ratepayers. [2]

It appears nobody was managing Ontario's natural gas inventories, setting up an extraordinary February where electricity prices were both often below $20/MWh, and frequently about $200/MWh - based almost entirely on whether the province's non-gas generators would meet demand, or if the supply setting the market control price was natural gas-fired (increasingly, throughout the month, imports pushed out scarce natural gas).

People with natural gas bills to pay should note that, in Ontario, the prices are regulated and the cost of gas is a pass-through (your utility doesn't make money on the commodity).  This usually works well for consumers, but in this case the utilities will be recovering the full costs of purchasing expensive gas this winter in upcoming rate applications.

It is also likely that most of the gas-fired electricity generators in the province treat gas pricing as a pass-through cost.  Again, that usually would benefit consumers.  The problem is when it doesn't, there is likely little hedging against possible cost increases.  Ontarians may be far more exposed to a surge in natural gas pricing than the residents, and businesses, of adjacent jurisdictions.  For electricity, most supply is at a fixed price so the gas exposure will have limited impact.
Not so for gas utility bills.

As February ended, 2014's annual imports from New York were the highest since 2010, and imports from Michigan (coal) also appeared to be accelerating.

Premier Wynne has introduced a poor bill that is sure to be very popular in energy-illiterate circles; it would ban any new coal-fired generators.  Such laws are always a bad idea (legal restrictions on building new nuclear, unless absolutely necessary, being a bonanza only for lawyers working towards the death of common sense), but this is a particularly stupid time to introduce this one.

There's no plans for any new, firm, generation in the province, so the bill is obviously grandstanding - and that's a sorry substitute for substance.



Notes:

I have updated, to display February data, my supply costs and preliminary monthly reporting - both are estimates only, with known issues, but ...

The IESO's estimate of $178 million for February's global adjustment seems, to me, to be ridiculous.  My data page is showing an estimate of $30 million, and I'd expect another $40-$50 million on top of that in the OEFC pool largely because coal units, now retired, are likely to receive contingency payments for a contract running through 2014 (thus industrial users will pay for coal, and, especially, pay for the absence of coal).
The IESO's estimate of $11.18/MWh, combined with the $178 million total, implies total demand of 15.9TWh; the actual is 12TWh.  For the final either the total dollars will be lowered (as they should), the rate raised (it's already recovering more than I estimate it should), or both.
The one thing the IESO's 2nd estimate of the global adjustment charges can't be is correct... again (see November's Record electricity Rates: the Global Adjustment/Ontario Roulette story ).

I was somewhat surprised, in loading my preliminary monthly reporting, to note that my estimate of off-peak weighted average pricing is higher than the mid-peak estimate.
Similarly, while the average HOEP was ~$81/MWh, the average weighted HOEP for Ontario's rapidly expanding solar output was only $77/MWh.
Winter's peaks drive pricing to spike morning and evening, but it's still surprising midday power is priced below the daily average.
Wind was again the least valued production, by the market, at $67/MWh (nuclear $77, hydro $83, Gas $100 and imports $79).


Endnotes

[1]  This refers to what the IESO reports as "Ontario Demand", which is a figure corrupted by their changing definition and the increase in "embedded" generators that, to the IESO measurements, act as negative demand.  Accounting for growth in solar generation, actual consumption in Ontario is more likely 3.1% higher in February 2014 than it was Feb. 2013.
[2]  For more on selling at a profit in January, see Polar Vortex almost generates a profit for electricity exports from Ontario and Exports setting Ontario electricity market price