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Need For Transparent Electricity System in Ontario
February 13, 2017

Trevor Shaw Trevor Shaw CPA, CA, CMC, CQA
Senior Consultant,
Legislative Auditor

Change not only the rates but also the way the system is made transparent to the public. 


In August 2015 I wrote an article about Ontario's hydro Debt Retirement Charges (DRC) as paid by hydro customers since the year 2000 and flow into the Ontario Electricity Financial Corporation (OEFC). It shed light on what this was and where $11.5 billion (now up to $13.4 billion as of March 2016) in such ratepayer charges went.

I did a follow up and found the DRC story has not changed significantly.  As of March 2016, the stranded debt of old Ontario Hydro was $24.4 billion (compared to $31.3 billion in 2000) and the net unfunded liability (liabilities less assets) of OEFC was $4.4 billion (compared to $20 billion in 2000).  See Attachment A for details of the change in OEFC financial position and results of operations for the past seventeen years.

The good news is the net unfunded liability of OEFC has been reduced considerably to $4.4 billion.  This was helped by recent events relating to the sale of Hydro One Inc. shares (see Attachment A for details).  

Debt proper is now reduced by $7 billion over 17 years (about 22%).  Interest paid on the debt has amounted to $31 billion over the same period; the bulk of which went into Provincial coffers since it now holds about 70% of the debt compared to about 33% in 2000.

I wrote about DRC as a case in point for transparent governance and accountability for whether or not the intended benefits of hydro reform have been achieved – the reason given for breaking up old Ontario Hydro in 1999 and creating the stranded debt (debt not passed on to successor entities along with assets transferred) as administered by the OEFC. 

This paper continues the transparent governance theme.   


This paper draws on publicly available information augmented by questions posed to the Ontario Electricity Financial Corporation (OEFC) and the Independent Electricity System Operator (IESO). Questions sought additional information and clarifications.  I thank them for their responses which assisted greatly in preparing this paper.

In particular, I made use of the IESO’s September 2015 Report to the Minister of Energy titled “NUG Framework Assessment”.  Financial and other information were drawn from IESO’s 2015 Annual Report and audited financial statements as well as the Annual Reports and audited financial statements of the OEFC from 2000 to 2016.  I also reference certain findings as reported by the Auditor General of Ontario in 2015.  Other sources of information are indicated in the body of the paper where appropriate.

A draft of this paper was reviewed by professional colleagues.  I sincerely thank them for their comments and assistance. 

The views expressed in this paper are strictly those of the author and not that of any organization of which he is a member or associated.


As we know, hydro costs in Ontario are very much a public concern; some call it a crisis. For example, according to media reports in July 2016, 60,000 residential customers in Ontario had their power turned off for non-payment.  Apparently the Minister of Energy was not aware of this.  An interesting question – should he have been? 

Over the past ten years hydro rates have doubled on average.  For rural customers (mainly served by Hydro One) delivery charges and distribution fees have made the increase even more significant.  This was not exactly what was bargained for when old Ontario Hydro was dismantled back in 1999 giving rise to five new entities and to the Debt Retirement Charge (DRC) levied on hydro customers to pay for the stranded debt.  

Does it occur how things got this way?  It did not happen overnight.

The restructuring of the electricity system at the turn of the 21st century was supposedly all about creating a competitive and efficient market place leading to prices that “were as low as possible for consumers”. 

Whether that goal has been achieved is up for debate given the current situation.  But then, did anybody back then say what “low as possible” actually meant?  Does anyone recall seeing that?  It’s just words without some kind of baseline, point of reference or target.  Are hydro customers just to assume that rates now charged are as “low as possible”?  The prevailing view of course is that they are too high with consumers pushing back.

The current situation has prompted the Provincial government to respond. This includes rebating the 8% provincial portion of the HST and introducing a rural and remote rate protection credit for Hydro One customers starting January 2017.  As previously planned in an earlier Provincial budget, the DRC was also discontinued for residential customers (saving about $5 a month for the average household) but continues for non-residential ratepayers.

In addition, the provincial government just announced a $100 million subsidy to help supply natural gas to rural communities as an alternative to electric power and to cut down high hydro bills (source: the Ottawa Citizen).  A cost for taxpayers.  It occurs that an incentive to use natural gas would likely contribute to increasing an already excess supply of electricity likely causing additional costs that will need to be offset or eaten.  Everything is connected and there are always domino or unintended effects.

At the same time, the Ontario Energy Board recently increased the price of electricity (4.4% for customers on time of use prices) and a further increase of 10% resulting from ending the Ontario Clean Energy Benefit.    

I would now like tell you about something that twigged my curiosity back in 2015 when researching and writing about the DRC.  This is about $16 billion going in and out of the OEFC over the years with regard to Non-Utility Generators or NUGs as they are called in the industry.


While many probably barely noticed the Debt Retirement Charge (DRC) on their hydro bill, I imagine most have not heard of Non-Utility Generators (NUGs).  Unlike the DRC, NUGs are not itemized on your hydro bill; but they are in it. 

Then, if I said you have been bearing the cost of hydro liabilities in ways other than the Debt Retirement Charge and in the process perhaps helping private enterprise – would that peek your interest? 

At some point in the past twenty years you may well not only have contributed to old hydro debt servicing costs via your hydro bill, but also to the production of ketchup and beer or helped defray operating costs of the University of Toronto or Ottawa Health Sciences (see list of NUGs in Attachment B). You may have also helped sustain employment in small communities.  All not necessarily bad things – but you have a right to know if such was or is the case.


Debt Retirement Charges (DRC) collected of $13 billion thus far is not the only cost to hydro customers for purpose of paying the liabilities remaining from the breakup of old Ontario Hydro.  Without change in legislation in 2005 to allow the OEFC to recover the full cost of NUG power supply contracts from ratepayers, it would not have been possible for the OEFC to have reduced its liabilities to the extent it has. One measure of the burden placed on ratepayers is $4.3 billion.

NUGs and their contracts with the Province are not readily transparent to ratepayers.  A comprehensive list could not be found.  We also have to look to bodies such as the Independent Electricity System Operator (IESO) to assert that the cost/price paid for NUG power is “competitive”, “fair” or “reasonable.

At the moment, the NUG picture is a mixed muddle.  And, if NUGs are contracted to produce electricity for the electricity system but for purposes other than meeting system needs, this should be made clear to the public by the Minister of Energy including the cost paid through hydro rates.

Finally, the DRC and NUG stories are just a part of a much bigger issue.  In the end analysis, it’s about transparent governance of the electricity system.   Costs have been greater than need be and by extension hydro rates.  There are important things that could be made clear to both hydro customers and taxpayers.  It is in the public interest. 


The term NUGs refers to independent power producers not owned by a public utility. They generate electrical power for local use and/or sale into the Provincial system/grid pursuant to contracts with the Province of Ontario. These are not nuclear, water or wind driven facilities.  Mainly they use natural gas, landfill gas, or waste or some combination thereof to generate electricity.  See Table 1 later in this paper and Attachment B for a list of NUGs.

Best as I could establish there are as many as 45 NUG facilities in Ontario that have been or are presently contracted to supply power into the electricity system.  The map below shows 29 NUG locations as per a map published by the IESO.  It appears to exclude 16 other facilities carried on from old Ontario Hydro and remain contracted with the OEFC.

Ontario NUGs

Source:  Independent Electricity System Operator (IESO) NUG FRAMEWORK REPORT -2015

As context, according to a brochure from my hydro company, about 81 % of the total electrical power in Ontario is produced by nuclear energy (58%) and water power (23%).  Natural gas accounts for about 10% and the remaining 9% is alternative power (wind, biomass, solar).  Just how much power NUGs actual provide today was not determined, but it would be a small portion of the provincial total.

That said, NUGs are not insignificant players.  According to OEFC audited financial statements, NUGs have cost hydro customers $16.7 billion to supply power over the past seventeen years - on average about $1 billion a year.  


This is made into a two part story and then brought together. The first deals with the financial liabilities and costs administered by the OEFC and their NUG contracts and the second with NUG contracting by the IESO.

At the outset, it is important to understand (as informed by the OEFC) that OEFC is not currently responsible to contract new power supply, including re-contracting of expired NUG contracts beyond the terms of their current agreement.  This is the responsibility of the Independent Electricity Supply Operator (IESO).  However, the OEFC recovers its NUG power supply contract costs through the IESO settlement process.  That is how the OEFC gets reimbursed from ratepayers for their power supply costs pursuant to contracts with NUGs.

NUG contracts with the Province of Ontario are divided between two Provincial entities; OEFC and IESO.  I was unable to find a comprehensive and complete list of all NUGs (owner, facility name and location) along with basic contract details - past and/or present. Contract details are not made public as far as I can tell.  Such details would include contract dates, parties, term and value.  Perhaps such details are considered proprietary information and not for public consumption.  Perhaps there is a provincial government contracting data base that could be google searched for NUG contracts, but was not able to locate.  Apologies in advance if my research skills fall short in this regard.

Appendix B provides a “piece-meal” list of NUG owners, locations and facilities and their contracts to the extent I have been able to compile using IESO information.  Table 1 following in the next section was supplied by the OEFC but it gives only facility name and contract expiry date for the contracts “remaining” with the OEFC. 


In 1998, Ontario Hydro was reorganized into five successor companies, one of which was the Ontario Hydro Financial Corporation, later renamed to the Ontario Electricity Financial Corporation (OEFC is owned by the Province).  As part of its mandate, the OEFC was given the responsibility to manage the debt and other liabilities (not assumed by successor companies) of the former Ontario Hydro, including management of contracts with the NUGs. 

Among the liabilities assumed by OEFC on April 1, 1999 was an amount of $4.3 billion.  This was in regard to power supply contracts/agreements as entered into by the former Ontario Hydro with NUGs located in Ontario.  These contracts provided the purchase of power at prices in excess of future market price giving rise to a deficiency/losses booked as a liability on a discounted basis of $4.3 billion.  This is a function of proper accounting but would not represent actual dollars.  I could not find an actual dollar number.

Some six years later under legislated reforms to the electricity market, OEFC no longer incurred such losses and began receiving actual contract prices for power from ratepayers effective January 1, 2005.  The liability was estimated to be eliminated over 12 years as existing contracts expired.  So the liability of $4.3 billion has since been amortized to OEFC revenue over a 12 year period ending 2017.  A balance of about $300 million remains as at 31 March 2016.

In essence there was a benefit given to NUGs since they were getting paid more for power than market would warrant.  The cost of paying NUGs for electricity in excess of market value was passed on to ratepayers.  One measure of this cost transfer is the $4.3 billion liability now nearly eliminated from OEFC books (see Attachment A).

As mentioned, OEFC is mandated to manage the contracts of old Ontario Hydro with an objective of cost-effectiveness. OEFC kindly provided a list of the “remaining” NUG facilities it presently has a remaining active contract for (see Table 1 below).  The names of the facility owners were not provided and OEFC does not have information on the status of NUGs once their power purchase agreement has expired with the OEFC.


Facility Name

Expiry Date

Kingston Cogen


Fenelon Falls GS


Whitby Cogen


Campbellford Seymour GS


Calstock Power Plant


Dryden Hydroelectric Facilities/Sundridge Eagle River


Charlton Dam


Iroquois Falls Power


Nipigon Power Plant


Twin Falls GS


Ternt-Severn/Batawa Lock 4 GS


Kirkland Lake Power - Base Load


Serpent River GS


Cameron Falls GS


Carmichael Falls GS


Wawatay GS


Nipigon High Falls GS/


Cordova Lake


Valerie Falls GS


Nagagami (Shekak) GS


Long Sault Rapids



As mentioned previously, a comprehensive and complete historical and to date list is not readily available (that I could find) disclosing NUG owners, facilities, and basic contract details. This means there could be other NUG facilities that may have been previously contracted with the OEFC but now contracted with the IESO (see next section) or other NUG facilities with “new” contracts with the IESO (See Attachment B) or NUGs that no longer have a contract with the Province but at one time did. 

As it is, over a 17 year period OEFC incurred power supply contract costs of $16.7 billion and recovered $16 billion from ratepayers (see Attachment A).   I am informed by the IESO that spending pursuant to its re-contracted or new replacement contracts (see Attachment B) is to commence in 2017.  So no spending to report as yet by the IESO. 

What is clear from OEFC audited financial statements is that repayment of old Ontario Hydro liabilities did not end with the Debt Retirement Charge.  Hydro customers have been paying costs with respect to electricity produced by NUGs at a rate covering OEFC contract losses.  One measure of this is $4.3 billion liability as originally booked by the OEFC – being a present value calculated by discounting estimated future losses at a given rate of interest.  The cost is not reported in actual dollars.  This would be a number greater than $4.3 billion.


First, a little about the current player for NUG contracting, the Independent Electricity System Operator (IESO.  The IESO is a not-for-profit non-taxable corporate entity established in 1998 by the Electricity Act of Ontario.  It is governed by a Board appointed by the Government of Ontario.  Its fees and licences to operate are set by the Ontario Energy Board and it operates independently of other participants in the electricity market. 

IESO describes itself as being at the centre of the hydro system – planning and managing a complex jig saw puzzle.  This is an apt description. 

IESO annual revenues consist mainly of system fees of $181 million (2015 financial statement figures) and smart metering charges of $46 million.  The bulk (72%) of its annual expenses is made up of payroll of $112 million plus professional and consulting expenses of $43 million.  It has staff of about 720.  IESO has an accumulated operating deficit of $81.8 million. 

Through amendments to the Electricity Act, the operations of the IESO and the Ontario Power Authority (OPA) were merged on January 1, 2015, bringing together real-time operations of the grid with long-term planning, procurement and conservation efforts.

The scope of IESO activity is broad.  This is reflected in the IESO’s eighteen member Stakeholder Advisory Committee representing five constituencies.  Electricity consumers are represented by three members; one is from the Consumers Council of Canada, one from Loblaw, one from AMPC.  There are three members representing Ontario communities (e.g. Hamilton). The remaining 12 members represent generators of electricity (e.g. Association of Power Producers Ontario), distributors and transmitters (e.g. Hydro One, North Bay Hydro), and business/services (e.g. Brookfield Energy Marketing). 

Now to NUG contracting.

In the early 1990s Ontario Hydro entered into long-term power purchase agreements with various NUGs located in Ontario. The contracts represented approximately 1,700 megawatts (MW) of generating capacity, with contract terms of between 15 and 50 years.  NUGs have helped to meet Ontario electricity demand for the past two decades by providing a steady supply of energy, many operating close to 24/7.

NUGs were originally contracted to operate primarily as baseload resources.  However, this changed.  By the late 2000s when the first agreements were beginning to expire, there was an excess of baseload generation capacity and a need for additional load-following resources (i.e., peaking and intermediate resources).

It was recognized that to meet this changed system condition and to extend the life of NUG facilities and transition them to a dispatch able mode of operation, in most cases, would require significant capital investments by the facilities’ owners.  Electricity market revenue alone was not expected to allow for the recovery of the required new capital investments or other ongoing fixed costs that NUGs would incur (e.g., labour, insurance, O&M, etc.).

In order for the NUGs to continue operating past the expiry of their OEFC contracts, it was generally recognized that additional sources of revenue would be required. 

In response to this situation, in November 2010 the Minister of Energy directed the IESO (not the OEFC) to enter into negotiations with eligible NUGs for new contracts.  Contracts were only expected to be entered into where the facility could provide cost and reliability benefits to Ontario electricity customers.  Contracts were required to provide clear signals to encourage operation of the facilities when power is highly valued.

In December 2013, the Ministry of Energy issued a second direction to the IESO regarding NUGs that were 100 per cent fuelled by biomass, with a capacity of 15 MW or less.  This direction specified a contract price, hours during which the price would apply, and a maximum contract length in addition to other contract terms. 

The IESO NUG Framework Assessment Report of September 2015 indicates that as of December 2014, the IESO had re-contracted (term extension) with nine NUG facilities, representing a total capacity of approximately 550 MW. These were previously contracts with the OEFC.  IESO informs it has also arranged replacement contracts with five other NUGs; for a total of 14 contracts out of 32 possible.

Attachment B gives a list of NUGs and some basic information about contracts housed with the IESO.  As mentioned previously, the OEFC retains its own set of contracts remaining as inherited from old Ontario Hydro (as per Table 1 earlier).  Again, a singular comprehensive and consolidating list of all NUGs and basic contract information was not located. 

While I found some information about the cost of NUG power in the audited financial statements of OEFC, I could not find disclosed what the value is of all NUG contracts either held by OEFC or the IESO.  

Just how much in total is spent on NUG power is a question mark because IESO does not report on NUG spending as the settlement for NUGs is handled through the “global adjustment”.  If you want to know more about global adjustment, try this link: Monthly Market summary report.  Perhaps amounts as reported by the OEFC does represent the Provincial total assuming it is the only entity paying NUGs. This is probable, but I did not check for this.

New IESO contracts are reportedly different from previous contracts or other contracts still applied. Unless immersed in the hydro world, it is hard to understand them and grasp what they mean for ratepayers.  If you wish to learn about the re-contracting methods and process then view the September 2015 NUG Framework Assessment Report of the IESO.

Some things noted in the IESO 2015 NUG Framework Report about NUG re-contracting are:

  • The original contract that the NUGs entered into with the OEFC provided a fixed contract price for every megawatt-hour (MWh) of energy injected into the grid.  This fixed contract price was generally in excess of the marginal cost of operating the NUG facilities and as such tended to result in a baseload mode of operation.

  • To ensure that any re-contracted NUG would only be incented to operate when needed by the system, the IESO developed a new form of contract that in effect provided the NUG with the same incentives a merchant generation facility operating in the IESO-Administered Market would be exposed to.

  • The payment and operational mechanics of this new form of contract differed significantly from the “Clean Energy Supply” (CES) agreements that have been used to contract most new natural gas generation in the province over the past decade.

  • The new form of NUG contract does not employ the same deeming mechanism used in CES style contracts.  Instead it uses the following key elements to incent the desired operations:

  • Each NUG facility has an obligation to offer their full contract capacity into the IESO’s Day Ahead Commitment Process (DACP) on all business days during peak hours (i.e., 7 a.m. – 11 p.m., or a “5x16” basis).

  • Obligation to maintain a “Minimum Capacity Factor” (MCF) to ensure that the NUG facility operates at least as frequently as a notional 13,000 Btu/kWh resource would be expected to operate (on a Dawn gas pricing basis).

  • Financial risks and rewards for market operations are to the NUG's account (no Deemed Market Revenue or Net Revenue Requirement as in the CES form of contract).

  • This new form of contract was utilized to re-contract a number of NUGs.  Key to this was that the form of contract allowed for (I) streamlined negotiations (i.e., required the negotiation of fewer contract parameters) and (ii) flexibility to employ a lower cost Gas Delivery and Management (“GD&M”) solution than would have been required under a CES style contract that is also better aligned with the system need for which NUGs were being contracted (i.e., peaking capacity rather than intermediate / baseload). 

  • The process used to establish the pricing offered to NUGs by the IESO to date was based on the principle that the IESO was not willing to pay more than the cost ratepayers would incur for the alternate source of capacity required to meet forecasted system needs. 

  • The process was designed such that the resulting contract pricing would never exceed what ratepayers would pay for a new build peaking facility. This pricing represented the maximum price that would be offered to NUGs and, if terms for a new contract could not be agreed to at this price, then the IESO took the view that ratepayers would be better off in procuring alternate new build capacity.  

The IESO identified in its Report significant matters impacting not only NUGs but the hydro system as a whole.  These included:

  • Given the current strong supply outlook and the complexities encountered throughout the previous NUG procurement, entering into long-term contracts for additional NUG generation capacity is not recommended.  In this context, the IESO further informed me that not contracting “additional” NUG generation capacity means both not contracting beyond what was already contracted and not re-contracting existing capacity beyond the terms of current contracts.

  • A number of significant structural changes that are contemplated in the sector over the near term (e.g., decision on continued operation of Pickering Nuclear Generating Station, rollout of capacity auction and capacity export opportunities, introduction of cap-and-trade legislation and resulting implications for the electricity sector and generation contracts, etc.) 

The IESO also included:

  • Final decisions have not yet been made on the retirement schedule of Pickering NGS and the refurbishment sequence for Darlington NGS and Bruce NGS. These decisions will have a significant impact on the forecasted start of the Capacity Gap and therefore on the value proposition of re-contracting NUGs prior to the start of the Capacity Gap. 

  • No individual NUG has been identified as currently addressing a local reliability need (i.e., each NUG could cease operating without requiring any remedial action be taken).

  • NUGs are one of a variety of potential resources that exist that could be pursued to address anticipated system needs, although not necessarily the cheapest option.

  • It is anticipated that NUGs will be able to participate in upcoming capacity export and capacity auction opportunities within the next few years.

  • None of the NUGs, with the potential exception of the Kapuskasing and Calstock NUGs, was identified as being required to ensure local reliability standards are maintained.  This would be further studied.

Accordingly, in September 2015 the IESO recommended:

  1. Continue the current pause in the re-contracting of NUGs.
  2. Actively monitor evolving sector conditions and impacts on system need.
  3. Continue development of capacity auction and capacity export opportunities with consideration given to facilitating broad participation, including that of NUGs.
In making these recommendations, the IESO stated:
  • The recommendations were developed to ensure system needs are met while minimizing ratepayer costs over the long term (i.e., non-ratepayer considerations were explicitly excluded). 

  • Should the government decide that the re-contracting of specific NUG facilities (or specific classes of NUG facilities) is advisable to meet broader government policy objectives, the IESO would anticipate providing specific recommendations on the appropriate mechanism for re-contracting; and these recommendations would be developed based on system considerations and the identified policy objectives that apply to the specific NUG prior to the Minister of Energy issuing further direction. 

All the forgoing gives a sense of the complexity of the system and the variety of things going on that the uninitiated would find difficult to understand.    

Interesting that IESO recognizes that NUGs could continue to be contracted even though they may not be needed to meet hydro system needs but to meet other government policy objectives.  This might include, for example, sustaining a local economy and employment. Should this be the case, then I hope it would be made transparent if ratepayers (or taxpayers) are footing the bill.

The Report does not indicate whether the lowest price possible or a “fair” price is being paid for NUG power.  IESO does not state that ratepayer costs have in fact been “minimized” and if so to what extent.  “Minimizing ratepayer costs over the long term” is a comforting but vague phrase.  Its meaning could be made concrete and clear; demonstrated if you will. 

In conducting its 2015 Study Report, the IESO consulted stakeholders.  Stakeholders included the Association of Power Producers of Ontario and other parties.  Other parties are not named but appear to have been local politicians and business interests.  These stakeholders naturally have a vested interest and voiced their concerns and desires including wanting contracts renewed.  There appears to have been no direct input on behalf of ratepayers.

In January 2017 I posed some questions to the IESO to update on the 2015 Study.  The IESO kindly informed of the following:

  • The recommendations were considered by the Minister of Energy and helped to inform a directive dated Dec. 14, 2015.  The directive instructed the IESO to:
    discontinue negotiations for new contracts for NUGs, continue engaging stakeholders, including NUG representatives as relevant in the IESO'S development of an Ontario capacity auction, and rules and protocols for Ontario-based capacity exports, and continue to consider NUGs as options to maintain regional reliability.

  • The IESO continues to recommend a pause in extending NUG contracts.

  • Of the 22 NUGs not re-contracted, none have entered into new contracts that extend the length of the term that the facility is under contract with the Province. However, some have had their existing OEFC contracts replaced with IESO contracts. This includes Kapuskasing, North Bay, Nipigon, TransAlta Mississauga and Iroquois Falls.  

  • Under the new replacement contracts with the IESO, NUGs will instead need to make their production decisions based on electricity market conditions.  However, IESO also expects that some NUG production will be replaced with existing lower-cost energy reflective of the current market. This will result in both ratepayer savings and emission reductions over the final months and years of the respective NUG contracts.

  • A Planning Study was initiated to investigate the bulk and local needs in the Kapuskasing area considering existing operational issues as well as the fact that local non-utility generators at Kapuskasing and Calstock would be reaching the end of their contract term. A number of integrated options were considered and evaluated based on their ability to meet the set of bulk and local needs identified as well as their cost-effectiveness.  It was determined that transmission system enhancements were the most cost-effective options to meet the entire set of needs. These enhancements consist of voltage support and protection and control improvements at an existing Transformer Station, and upgrading a section of an existing 115 kilovolt transmission line in the Kapuskasing area.

  • A capacity auction and capacity export opportunities are two different initiatives. 

    • Developing a capacity auction is part of a large, multi-year Market Renewal initiative on which the IESO has been working with stakeholders.  A benefits case is currently being developed.  NUGs are encouraged to participate as this may represent an opportunity for them to compete with other resources to provide capacity.

    • On capacity exports, the IESO has enabled Ontario generators to export their capacity to New York State and with stakeholders continues to explore further opportunities.  Capacity exports maximize the value of Ontario assets for the benefit of producers and consumers and improve the efficiency of energy markets.  Eighty-eight megawatts of Ontario-based capacity export capacity was allocated for the New York Independent System Operator capacity auction for the six-month Winter 2016/17 period.  The high-level, aggregate results of this auction are publicly available at


  • In January 2016, the Ontario government approved Ontario Power Group’s plan to pursue continued operation of the Pickering Generating Station beyond 2020 up to 2024.  More information on the continued operation of Pickering is available on the Ontario Power Group (OPG) website.

  • The refurbishment of the four units at Darlington Nuclear Generating Station has begun, with the first unit (unit 2) coming offline in October 2016. The refurbishment of the four units is expected to be completed by 2026.

  • In December 2015, the IESO updated its contract with Bruce Power. The agreement secured 6,300 MW of baseload generation supply from the site for the long term and will enable the refurbishment of the remaining six nuclear units at Bruce, which is expected to begin in 2020. More information on the 2015 agreement is available on the IESO website.

Summing up, NUG contracting and costs are divided between two provincial entities making it difficult to obtain a complete and clear picture.  NUG spending would be at least $16 billion for the past 17 years. The status of NUGs is in a state of flux and uncertain for those whose contracts are yet to be renewed or replaced.  

Whether or not NUGs have rendered value for money is a matter requiring much more investigation.  Only IESO and/or the OEFC can give such explicit assurance with supporting evidence.  There are representations to this effect – words suggesting they have been cost-effective etc.


To this point I have taken you on a deep dive with a lot to absorb.  In so doing, I have come to appreciate the subject of debt retirement and NUGs are part of a bigger issue.  They illustrate a system in need of improved transparency. 

In my view, the electricity system is complicated, compartmentalized and layered such that it is hard to know how the pieces all fit together and who is accountable for what.   Governance of the Ontario electricity system should be fully transparent as to results and costs so people who pay for it can better understand what is going on and why. 


For further evidence of a governance issue, please look at the 2015 Report of the Auditor General of Ontario.  Bonnie Lysyk observed on Electricity Power System Planning.  Here are some highlights:

  • No independent technical plan for the System has been prepared in the last 10 years and submitted to the Ontario Energy Board for approval to ensure it is prudent and cost-effective. While policy plans have been prepared they have not been reviewed and approved by the Ontario Energy Board and are not sufficient for addressing system needs and for protecting electricity consumer’s interests.

  • While the checks and balances of the legislated planning process were not followed, the Ministry made a number of decisions about power generation through 93 ministerial directives and decisions issued to the Ontario Power Authority (OPA).  Some went against OPA’s technical advice. These decisions resulted in significant costs to electricity consumers.

  • From 2006 to 2014 the amount that residential and small business consumers paid for the commodity portion of their bill (including Global Adjustment fees) increased 70%, from 5.32 cents/kWh to $9.06.

  • Global Adjustment fees are payments to generators over market price – amounting to $37 billion from 2006 to 2014 and projected to cost electricity consumers (ratepayers) $133 billion from 2015 to 2032.

  • Consumers have had to pay $9.2 billion more (IESO would say closer to $5.3 billion) for renewables over the 20-year contract terms than they would have paid under the previous procurement program.

  • The average cost for power from the Lower Mattagami hydro project is $135/MWh compared to $46/MWh at two other recent hydro projects – this after OPA expressed concerns to the Minister in January 2010.

  • The Ministry directed the Ontario Power Authority to convert a Thunder Bay coal plant into a biomass facility despite OPA advice that the conversion was not cost-effective.  The cost from that facility for power is $1,600/MWh – 25 times higher than the average cost at other biomass facilities in Ontario.

  • The Ministry directed the Ontario Power Authority to cancel contracts for two gas plants planned for the greater Toronto area and relocate them to Napanee and Lambton – costing $950 million in cancellation costs.

  • Ontario has large oversupply of electricity.  While conservation effort requires long term commitment, investing $4.9 billion on conservation in time of excess supply actually contributes to expensive electricity curtailments and exports.

  • Due to excessive surplus, Ontario had to pay generators $339 million from 2009 to 2014 to reduce production of 11.9 million MWh of surplus electricity, and $3.1 billion more to produce 95.1 MWh of exported power in excess of what Ontario received in export revenue.  Ontario paid other exporters a net of $32.6 million to take our power.

  • Lack of sound regional planning had ongoing negative effects on the transmission system, including reliability concerns and congestion issues that cost $407.6 million in payments to generators.

The Auditor General made five recommendations containing 16 actions to address her findings. 

The Auditor’s findings boggles the mind as to how such could happen.  The findings do not exactly square with claims of efficiency or cost-effectiveness etc.

She also observed on declining performance levels of Hydro One in managing its transmission and distribution assets.  But now that Hydro One is becoming privatized through sale of shares the Auditor General indicates that would be her last value-for-money/performance audit of Hydro One.  A window of transparency has been closed.


A full one page open letter from Hydro One addressed to its “valued customers” was published in the January 21, 2017 Ottawa Citizen (and likely in many other newspapers across Ontario).  It is a public relations exercise.

The President and CEO assures he is very aware of frustrations with the cost of electricity and assures they are working hard to keep their own costs down, keeping delivery rates down, and proud of what 5,000 employees are doing for 1.3 million rural customers. 

However, the President intimates hydro cost is mostly not their nickel and draws a line for their responsibility.  He does this by passing 63% of the buck on stating that 51% of their bill to consumers pays for electricity generated by nuclear, hydroelectric and wind and solar and 12 % goes to federal sales tax and other charges. The remaining 37% goes to Hydro One – a responsibility readers are assured they take very seriously.  Good to know, but what about responsibility and accountability for the other 63% of the pie?  Customers would have to look to others.    

In the letter, the President is pleased to announce the Ontario Energy Board has authorized a reduction in distribution delivery charges for most residential customers effective January 2017.  No details are given and the letter does not indicate how much Hydro One annual revenue of $6.5 billion (per 2015 audited financial statements) would be reduced (in $ or as a %). 

However, before the open letter was issued, an information brochure about reductions was put in with the latest monthly bills.  It provides information about the delivery rate reduction. 

How much of a delivery rate reduction is experienced by a customer depends on which of four categories the customer is in.  The reduction reportedly ranges from 0.3% (.42c a month based on 350 kWh of use) for residential seasonal customers to 14.2% ($29.19) for those in the residential low density category - based on using 750 kWh.  The later ($29.19) includes the proposed rural or remote rate protection credit increase of $29 (from $31.50 to $60.50 per month) – meaning I would assume a delivery rate reduction of .19 cents.

Just who will bear the financial cost of the proposed remote rate protection credit is not stated.  Perhaps it is the Province and not Hydro One.

For customer convenience, Hydro One also showed the bill impact for the 8% Ontario HST rebate. This rebate makes the bigger difference. With this added in, the total of reductions range from $9.17 (for a seasonal customer) to $41.70 (low density customer) per month (including the proposed rate protection credit).  The 8% sales tax rebate would of course impact the Provincial treasury and not Hydro One’s bottom line.  There is no indication for how long the 8% sales tax rebate might be in effect – I guess until further notice. 

The majority of customers would logically be in the high or medium residential density area categories.  They would experience a “typical” bill reduction of 2.2% or 1.2% respectively as a result of the delivery charge rate reduction.  For them, the total reductions (delivery and 8% tax rebate) average about $14 per month – indicated to be about an 8.2% or 9.1% reduction in total monthly hydro bill based on 750 kWh use (presumably an average monthly bill of $155 for high density and $180 for medium density customers). 

Accordingly, reductions will help but not all that much for many customers especially those having a monthly bill in excess of $200.  Every bit counts though.

Here is the point.  Information about hydro is available everywhere, but at any one point in time or at any one place, we only get a piece of the picture.  An integrated system view tends to be missing.  If the electricity system is a jigsaw we are missing the most important piece – the picture.  Getting a full or complete system understanding requires a lot more effort.  This is where sites such as Energy Insider (Aird & Berlis LLP) may come in featuring commentary, analysis and news from A&B’s energy lawyers. 

Coming back to the Hydro One brochure, we are left to assume the 750 kWh is an average or typical usage.  Simple averages can be misleading. We have no idea what the full range is for hydro use and cost and how many households there are in each category.  

I have read some Hydro One household customers pay in excess of $1,000 a month.  Another example is the Arnprior Curling Club which, according to CTV news is experiencing bills of $24,000 a month making the future of the rink uncertain. This small but historical facility is seen as vital to the town as one of the few places for people to exercise and socialize during long winter months. There could many similar stories across Ontario.

Some important pieces for a full story are missing from the letter and the brochure.  For example, information is not provided for the cost/revenue impact side to Hydro One and/or the Provincial treasury.  That information would have to be hunted elsewhere if one cared to.

Then, at a system level, given the largest part the total reduction is the 8% Ontario tax rebate, do we at least not have to ask if this is shifting dollars from the hydro bill to the income tax bill at some point down the line?  Eventually all out of the same pocket is it not?

It could be argued customers do not need to know such things, at least not in a letter or simple brochure.  Such system understandings, are after all, complex matters and the domain of experts and those in position of authority acting on our behalf.  Well, the attitude taken depends on where one sits and how much one believes in transparency and accountability and is prepared to ask for on one hand and to render on the other. 

All I might say is that transparency and accountability is the price for being in a position of public trust. Trust in public institutions depends on it. Without trust, the inherent social contract weakens and breaks.  And as we know, trust once lost is hard to regain.  Hence the open letter from Hydro One and recent action by the Provincial government.

Information has currency too.  A little more insight provided might have gone a long way in addition to telling customers about rate reductions and how seriously they take things.  Perhaps the President of Hydro One might have taken the opportunity in his open letter to briefly inform what action Hydro One has taken in response to the 2015 Report of the Auditor General of Ontario.

That said, once Hydro One completes further sale of shares (possibly up to 60%), am not sure it would qualify as a public institution since it would no longer be fully or majority owned by the Province. The accountability relationship with the Province as a public utility could shift more toward relationships with investors, shareholders, and the bottom line. You can already see this orientation on its website. Hopefully the greater public good will be sustained and other windows of transparency not closed.


There are things the Minister of Energy might explain and in terms for the “average” electricity consumer to understand.  Here are examples (am sure there are many others):

  1. What is the basic plan now for Ontario hydro?  Are there consumer goals and rate targets?

  2. Why are consumers paying for a commodity in excess of market price?

  3. Has a system been built and Ontario consumers encouraged to conserve so that as a consequence the Province has electricity for export to the United States? 

  4. How does capacity export translate to lower consumer rates in Ontario?  Have they and if so by how much?  Are we exporting electricity to the U.S. at a price higher or lower than what Ontario consumers are paying?  If lower, how does this help keep rates down in Ontario?

  5. How does “evolving the province’s wholesale electricity market” going to benefit hydro customers in Ontario?

  6. How will a “capacity auction” lower consumer rates? And if so, by how much? 

  7. Why would the advice of experts be ignored by the Minister?  If other policy objectives were being served – how was that made transparent? 

  8. In terms of results, what happened to competitive rates as promised from the breakup of old Ontario Hydro and the stranded debt ratepayers are paying to service in the billions of dollars?   

  9. Why is Hydro One shares being sold (up to 60% ownership) and how is such privatization in the public interest and in the interest of customers?  What assurances are there rates will not be further increased?

  10. What risks are involved in transitioning from publicly owned to privatized hydro delivery by Hydro One?  For example, might public easements or use of privately owned land across which transmission towers and lines have passed for many decades be affected?  Does Hydro One and its shareholders automatically get this free?

  11. What has the Provincial government (the Ministry) done in response to the 2015 Auditor General’s Report?  Is Bill 135 the answer? 

According to the Energy Insider, Bill 135 was passed by the Ontario Legislature in June 2016.  This bill expands the role of the Minister of Energy in developing long term energy plans – placing responsibility in the hands of the Minister.  The IESO and the OEB are placed in a support role. The Minister is also given power to issue directives to them; something the Minister was doing anyway.  I’m confused – more questions could be asked.

I look forward to what the Auditor General may say when she does a follow up to her 2015 Report.


As Mike Meyers said in his recent book – Canada is a place that for eighteen days of the year we are only 48 hours from freezing to death without an artificial source of heat.  

For me, hydro is an essential public service.  It’s also complicated. 

Hydro is not exactly a free and open competitive market but not a monopoly either given there are multiple producers of electricity as well as retailers and wholesalers.  Economics 101 does not seem to apply in terms of consumer price being a function of supply and demand – how does one reconcile increasing prices with excess electricity supply while at the same time promoting energy conservation?  Somehow wholesale, export and capacity auctions supposedly helps keeps domestic rates down – something that could use explaining.   

Hydro is also regulated given rates require authorization from a government body.  Finally, there is considerable limitation in consumer choice.  If a consumer cannot afford the hydro bill, they have to move or procure an alternative supply of energy. That’s costly too of course.

For something as essential as electricity, none of us can afford unaccountable decisions by elected officials, appointed directors or senior management.  This is where transparency and accountability comes in.

Transparency is one of the latest “buzz” words.  It is often and easily used but difficult to put in practice.  The engineering question is how and what?  A few thoughts follow.

Entities involved in the electricity system already publish thick annual reports and put out all kinds of information on websites for people to access as they wish. So what is the good of more?  If one word might suffice it would be insight.  Opening up the world of hydro for “average” eyes to comprehend will not be easy.  Some ingenuity will be required along with a measure of courage to break new ground. 

Key will be forging a pro-active communication strategy focussed on results – in particular consumer rates.  Here the goal might be for the Minister of Energy to explain key reasons for proposed rate changes and supporting them with evidence of “cost-effectiveness” or “minimizing rate payer costs” or “low as possible rates.” Another goal could be providing cogent answers to a select set of core questions in a pro-active manner and perhaps periodically putting them in with every hydro bill. 

All this might mean sharing some of the information the Minister might get in his or her briefing binder or whatever else may be used to keep the Minister systematically apprised about the electricity system.  In might also entail a little more opening up of what transpires in Board meetings and decisions taken there.

And, it would be equally important to account for what has happened as the result of past policy decisions and to communicate evidence based decisions for the future and what the public can expect.  It should be about open, clear and honest communication in the public interest to understand what is going on and why.


Repayment of old Ontario Hydro liabilities did not end with the Debt Retirement Charge amounting to $13 billion thus far.  In addition, and as part of their hydro bill, customers have been paying costs with respect to electricity produced by NUGs at a rate covering OEFC contract losses inherited from old Ontario Hydro; one measure of which is $4.3 billion.

NUGs operate in the background.  Information about NUG contracts and spending is available but is fragmented and limited.  Using annual figures reported in the audited financial statements of the OEFC, I was able to tabulate OEFC spending on NUG power of $16.7 billion for the past 17 years with an almost equivalent amount recovered from ratepayers.

The payment of old Ontario Hydro debt involving the debt retirement charge and non-utility generators are only part of a bigger issue. 

I argue governance for the electricity system needs improving in terms of transparency especially given its transformation and complexity.  Costs have been greater than need be and by extension rates.  

There are many things that could be made more complete and clear for both hydro customers and taxpayers.  Change not only the rates but also the way the system is made transparent as a function of governance.   It is in the public interest.


Hydro resembles an industrial complex with many players operating at various levels; a unique world with a language all its own.  My work is only one look into it.  I hope it has made you more aware of what lies behind your hydro bill and may prompt you to ask questions of your political representatives and hydro supplier.



Table 1:  Changes in OEFC financial position from 1999-2000 to 2015-2016 $ billion


Balance sheet items of OEFC








Debt held by the Province (owed to the Province)



+ 8.5

Debt held by others - guaranteed by the Province



- 15.4

Total debt



- 6.9

Power purchase contracts (note 2)



-  4.0

Nuclear risk funding (note 3)



-  2.5

Current liabilities (accounts payable etc.)



- 0.4





Total debt and other liabilities



- 13.8









Notes & loans receivable from the Province




Notes & loans receivable from Ontario Power Group



+ 0.4

Notes & loans receivable from Hydro One



- 4.8

Notes & loans receivable from others



 - 0.1

Total notes & loans receivable (note 5)



- 4.4





Electricity sector income due from Province (see note 4 & 5)



+ 4.0

Deferred debt costs



- 0.9

Current assets (cash, accounts receivable etc.)  (note 5 explains recent increase)








Total Assets



+ 1.8





Unfunded Liability (total liabilities minus total assets)



- 15.6

        Source:  OEFC financial statements


  1. Debt is comprised of amounts maturing anywhere from 1 to 50 years out and are repayable in various currencies.  In 2015-16 the effective rate of interest on the debt was 5.14% (compared to 8.29% in 2000).

  2. Power purchase contracts and support agreements were inherited by OEFC from Ontario Hydro as were entered into with Non-Utility Generators (NUGs).  Contracts provide for the purchase of power from NUGs in excess of future market price.  The contracts expire on various dates out to 2048.  Accordingly, a liability was recorded on April 1, 1999 of $4.3 billion on a discounted cash-flow basis when the former Ontario Hydro continued as the OEFC.  Subsequently, under the Electricity Restructuring Act, 2004, the OEFC began receiving actual contract prices for power from electricity consumers and no longer incurs losses on these contracts.  As a result, the bulk of the liability would be eliminated and is being amortized to revenue over 12 years

  3. Nuclear risk funding represent a liability arising from nuclear waste management and asset removal.  Just how this liability was eliminated from OEFC books is not determined here. 

  4. As established by the stranded debt retirement plan, the Province committed to dedicate the cumulative combined income of the Ontario Power Group (OPG) and Hydro One in excess of the Province’s interest cost of its investment in its electricity subsidiaries.  The Province recoups all interest on its investments before any income can be recognized by OEFC. The $4.3 billion represents the cumulative amount due from the Province each year after deducting the Province’s $520 million interest cost of its investment in Ontario Power Group and Hydro One.

  5. In its last/latest fiscal year 2015-16, OEFC revenue exceeded expenses by about $3.7 billion.  This was primarily due to receiving $2.7 billion in a one-time payment from Hydro One (and certain subsidiaries) as a departure tax as a consequence of Hydro One leaving the payment-in lieu of taxes (PIL) regime.  This results from the Province completing the first phase of its plan to broaden Hydro One ownership –selling 16% of the Province’s common shares at a price of $20.50 per share through an Initial Price Offering (IPO) and through related share sales to electricity sector union trusts.  Related sub-points are:

  1. Also noted is that on 19 February 2016, OEFC received $800 million from the Province which the Province had received as a special dividend payment from Hydro One.  This amount reduced the amount owed by the Province to OEFC with respect to the cumulative electricity sector dedicated earnings that were owed to OEFC by the Province as have been accrued each year by OEFC as being due (receivable) from the Provinces.  In other words, the $800 was treated as payment of a receivable and not as revenue (income) in the year.

  2. Legislation restricts the Province from selling more than 60% of the voting securities of Hydro One.  In April 2016 the Province was to initiate a secondary share offering which on completion would reduce the Province’s holdings of Hydro One to approximately 70%.

  3. Going forward (and as a result of amendment to the Electricity Act), Provincial corporate income taxes payable by Hydro One Inc. will be due and payable by the Province to OEFC. 

  1. Readers are encouraged to view OEFC annual reports (available on line) to get more information.

Some things to observe from Table 1: 

  1. Who holds the stranded debt has shifted.  Most of the stranded debt is now held by the Province. The Province holds about $18.1 billion in debt instruments or about 72% of total OEFC liabilities. The rest of debt ($6 billion) is guaranteed by the Province.

  2. There has been more in debt turnover than retirement – unless you consider replacement of debt to be a retirement. The Province has, in effect, replaced about half the debt held by others.  In 2000, Provincial debt represented 1/3 of total stranded debt.  In 2016 it accounted for over 2/3.  More interest revenue for the Province.

  3. Total debt is reduced by a reported $6.9 billion over seventeen years (about 22%) with a further reduction in other liabilities of $6.9 billion coming from reduction in power purchase contract liabilities and the nuclear risk funding liability (how nuclear liability was paid was not traced - disposition unknown).  The reduction in power purchase contract liabilities arises from changes in legislation (as per note 2 above) and not from debt payment.

  4. Except for Hydro One notes ($4.8 billion) that were sold in 2002-03 for a profit of $206 million, the amounts (notes & loans receivable) due from the Province and hydro companies essentially remain the same since 2000 (although they may have been turned over and/or increased when notes matured).   

Table 2: A 17 year summary of OEFC Revenues & Expenses 1999-2000 to 2015-2016


$ million


Debt Retirement Charge



Payments-in-lieu of tax



Electricity sector dedicated income



Sub - total of planned revenues for retiring stranded debt



Other Revenue:



Power supply contract recoveries



Net reduction of power purchase contracts (see note 5 below)






Revenue pool residual (ending in 2002-03)



Gain on sale of Hydro One notes (2002-03)



Benefit from Province related to disposition of Hydro One Shares - 2015






Sub-total of all other revenues



Total revenues from fiscal year 1999-2000 to 2015-2016









Debt interest



Debt guarantee fee (presume paid to the Province)



Interest on nuclear funding liability (for eight years ending in 2006-07)



Electricity Consumer Price Protection Fund (2003 & 2004 only)



Power supply contract costs



Temporary generation supply (2003-04 only)



Amortization of deferred charges (ending in 2011-12)






Industrial electricity incentive program costs (two years 2014-16)



Total expenses from fiscal year 1999-00 to 2015-2016






Excess of Revenues over Expenses



Unfunded liability of OEFC beginning



Net adjustments to unfunded liability (decrease)



Unfunded liability of OEFC as at March 31, 2016



Source:  OEFC annual reports & table – not audited

Some things to note from Table 2 along with other information:

  1. DRC revenue of $13.3 billion is comingled with other revenues for the OEFC to use in meeting all its mandate.  DRC accounts for 19.6% of total revenues.  As with other revenue streams, the DRC is not set aside to service or pay any debt in particular.  The DRC is a contribution to a pot.

  2. Power supply contract revenues and costs (approximately $16 billion) roughly offset each other. This is because effective January 2005 OEFC began receiving actual contract prices for power from ratepayers and no longer incurs losses on power supply contracts with Non-utility Generators (NUGs) in Ontario. 

  3. Debt retirement related revenue has not kept pace with debt related servicing costs. The DRC revenue ($13.3 billion) plus other dedicated revenue ($18.0 billion) intended for retiring stranded debt total $31.3 billion.  This just covers total debt interest of $31billion – without considering debt guarantee fees paid of $2.4 billion.  So if we were speaking debt repayment in ordinary terms (principal and interest), no amount of principal would be paid down as the result of debt retirement charges. If not for other revenues (primarily interest) and change in legislation (eliminating liability and losses on power supply contracts), there would be no reduction in hydro debt or the net unfunded liability of the OEFC.

  4. There is money moving from left to right pockets in terms of the Province both receiving and paying interest on amounts due from and to itself.

  5. As the result of legislative reform in 2004 to the electricity market, the liability for estimated future losses ($4.3 billion) on power purchase contracts as inherited from old Ontario Hydro is being amortized by the OEFC as revenue over a 12 year period since losses are no longer incurred on power purchase contracts.  This is reflected in the $3.9 billion of net reduction in power purchase contracts as reported as revenue by the OEFC.

  6. In regard to power supply contract costs ($16.7 billion) and recoveries ($16.0 billion) since 2000 more or less offset each other.  The 2004 legislation (Electricity Restructuring Act) shifted the burden of power purchase contract losses from the OEFC to hydro ratepayers.  Previously, the OEFC purchased power from the NUGs and sold the power at market prices lower than cost, thus incurring losses.  Starting in January 2005, the OEFC began receiving actual contract prices for power from ratepayers thus eliminating losses going forward on power purchase contracts.

  7. The same Act also resulted in a combination of regulated and competitive electricity sector pricing with different generators receiving prices set through a variety of mechanisms.  Electricity pricing is complicated with consumers paying a blend of costs including pass-through of regulated prices for OPG’s regulated plants, the full costs for existing and new contracts for generation, and spot market prices for other generation facilities.  This no doubt a complex a variable pricing structure.



This list was compiled using various tables published in the IESO – September 2015 Report – NUG Framework Assessment.  It was constructed starting with the list contained in Appendix D that identifies NUG facilities as referenced in the November 2010 Directive of the Minister of Energy.  It was then augmented with information from other tables in the Report and with additional information supplied by the IESO.  

A “?” indicates data not found.

This list does not contain NUGs as currently contracted with the OEFC (see Table 1 in the body of this paper).

NUG Owner Facility Name Facility Location OEFC PPA/Contract Expiry Date M/Year IESO Re-contract Commence-term extension Contract Term Years
Westbrook Greenhouse Westbrook Greenhouse Beamsville Nov-09 Presumed expired ?
Rentec White River BioMeg White River Jun-09 Presumed expired ?
Resolute Fort Frances Cogen Plan Fort Frances Oct-09 Presumed expired ?
Eastern Power Ltd. Brock West LFG Pickering Feb-11 Presumed expired ?
H.J. Heinz Canada Ltd. Heinz Leamington Aug-11 Presumed expired ?
Algonquin Power KMS Peel Inc. Brampton Mar-12 Presumed expired ?
Rosa Flora Ltd. Rosa Flora Dunville Nov-12 Presumed expired ?
Tembec Holdings Inc. Chapleau Cogen Chapleau Jan-13 Jan-14 8
Tembec Holdings Inc. Tembec Power Plant Smooth Rock Falls Mar-10 Presumed expired ?
University of Toronto University of Toronto Toronto May-13 Presumed expired ?
Invista Invista Power Plant Maitland Dec-13 Jan-16 20
TransAlta (50%) Ottawa Health Sciences Ottawa Dec-13 Jan-14 20
TransAlta Windsor Cogen Windsor Dec-16 Dec-16 15
TransAlta Mississauga Cogen Mississauga Dec-18 *Replaced with IESO contract ?
Brookfield Renewable Power Lake Superior Power Sault St Marie May-14 Presumed expired ?
Brock University Brock University Power Plant St Catherines Jun-14 Presumed expired ?
Labatt Brewery Labatt Brewery Ont London Sep-14 Presumed expired ?
Capstone Infrastructure Cardinal Power Cardinal Dec-14 Jan-15 20
Northland Power Cochrane Power Corp. Cochrane Jan-15 Presumed expired ?
Northland Power Iroquois Falls Iroquois Falls Jan-22 Contract still with OEFC but also indicated as *Replaced with IESO contract ?
Northland Power Kirkland Lake Power - Peaker Kirkland Lake Aug-15 July-15 20
Northland Power Kirkland Lake Power – Base Load Kirkland Lake Aug-31 Still with OEFC ?
Northland Power Kingston Cogen Bath Feb-17 Still with OEFC ?
Eastern Power Ltd. Keele Valley LFG Vaughan Dec-15 Presumed expired ?
GDF SUEZ North America West Windsor Power Windsor May-16 Jun-16 15
E.S. Fox Ltd Beare Road Power Scarborough Jan-17 Presumed expired ?
Atlantic Power Tunis Power Plant Tunis Dec-14 Jan-18 15
Atlantic Power North Bay Power Plant North Bay Dec-17 *Replaced with IESO contract ?
Atlantic Power Calstock Power Plant Hearst Jun-20 Still with OEFC ?
Atlantic Power Kapuskasing Power Plant Kapuskasing Dec-17 *Replaced with IESO contract ?
Atlantic Power Nipigon Power Plant Orient Bay Dec-22 Contract still with OEFC but also indicated as *Replaced with IESO contract ?
Calpine Canada Whitby Cogen Whitby May-19 Still with OEFC ?
Emerald Emerald EFW Mississauga ? Jun-15 15

An update received from IESO in January 2017 informs the following:

Of 22 not re-contracted, none have entered into new contracts that extend the length of the term that the facility is under contract with the Province of Ontario. However, *some have had their existing OEFC contracts replaced with IESO contracts. This includes Kapuskasing, North Bay, Nipigon, TransAlta Mississauga and Iroquois Falls.  The terms of the replacement contracts have not been extended beyond the original OEFC contract expiration dates, which can be found along with their contract capacity, in Appendix D of the IESO’s NUG Framework Assessment Report.

Initial contracts with NUGs were signed in the 1990s primarily to provide baseload power, and the incentive structure of the contracts was designed accordingly. These NUGs have helped to meet Ontario electricity demand for the past two decades by providing a steady supply of energy, many operating close to 24/7. Under the new replacement contracts with the IESO, NUGs will instead need to make their production decisions based on electricity market conditions. However, IESO also expects that some NUG production will be replaced with existing lower-cost energy reflective of the current market. This will result in both ratepayer savings and emission reductions over the final months and years of the respective NUG contracts.

Disclaimer:  The information used in this article comes from publicly available sources.  The analysis and conclusions are those of the author and do not represent the views of any organization the author may be associated with.