NUG Framework Assessment Report

NUG Framework Assessment
Opportunities for Non-Utility Generators to Compete in Meeting
Anticipated System Needs - Analysis and Recommendations
Report to Minister of Energy
September 1, 2015
1
Executive Summary
In the early 1990s, Ontario Hydro began contracting with private power developers, known as the NonUtility Generators (NUGs), for new generation facilities that would operate primarily as baseload
resources. In the mid 2000’s, when the first of the initial 20 year contracts were nearing expiry, it was
recognized that if these facilities were to continue operating it would be necessary to convert them to
function as load-following resources to match evolving system conditions. Facilitating this transition
would require capital investments that were not expected to be recovered through market revenues
alone, as new sources of revenue would be required to enable the continued operation of these facilities.
In response to this situation, on November 23, 2010, the Minister of Energy directed the IESO 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 consumers. Under this
directive, the IESO contracted with nine NUG facilities, representing approximately 550 megawatts (MW)
of installed capacity, using a form of contract that provided the same incentives to operate as a merchant
generation facility.
In light of changing supply conditions, on December 19, 2014, the Minister of Energy directed the IESO to
suspend any pending negotiations with NUGs and prepare an assessment of the framework for NUG
recontracting in the province, with a report back by September 1, 2015. In preparing the assessment, the
IESO was to consider:
• the current process for contracting NUGs under the terms of the 2010 NUG Direction
• the IESO’s work to develop a capacity auction in Ontario
• changes to the supply and demand forecasts since the 2013 Long-Term Energy Plan (LTEP)
• any other appropriate considerations.
In developing the report’s recommendations, the IESO was guided by the principle of ensuring system
reliability, while minimizing ratepayer costs over the long-term, and meeting government policy objectives
communicated through Ministerial direction. This approach explicitly excluded consideration for any nonratepayer impacts of NUG facilities.
A critical step in the development of this report was the assessment of current and forecast provincial
system needs. Updated supply and demand forecasts result in a need for additional capacity (the
“Capacity Gap”) beginning in 2021, as opposed to the 2019 date stated in the 2013 LTEP. This change in
need date is largely driven by the 500 MW capacity exchange agreement with Hydro Quebec, as well as
the expected operation of certain units at Pickering Nuclear Generating Station (NGS) to the end of 2020.
The magnitude and type of capacity needed remains unchanged (approximately 2,000 to 3,000 MW of
effective peaking resources). Although there is a capacity need, Ontario’s forecast resource portfolio
(including resources that are existing, committed and directed) meets the system’s anticipated energy and
operability requirements.
The IESO also examines regional system needs. Each of the NUGs that have not yet entered into a new
contract with the IESO and that will expire prior to the end of 2020 was assessed to determine whether
they can provide value in supporting local supply reliability. The result of this assessment was that 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. The Sudbury North and East regional
planning studies will begin immediately to determine the value of the Kapuskasing and Calstock NUGs
2
to their respective local areas and whether any action by the IESO is required to ensure reliability in these
areas.
Following the assessment of provincial and local system needs, the IESO then examined a number of
additional considerations prior to developing recommendations. These considerations included:
•
•
•
•
Reviewing options available to meet anticipated system needs
o In addition to NUGs, all potential types of resources that could help address the
anticipated system needs were assessed. A wide variety of potential resources could be
considered to meet future system needs, and these resources could be procured through
a variety of procurement mechanisms.
Lessons learned from negotiations with NUGs to date
o Key lessons from the negotiation experience with NUGs to date were documented and
reviewed. This review highlighted that there are challenges associated with negotiating
contracts without the competition that is present in other procurement mechanisms.
Status of the development of capacity auction and capacity export opportunities
o The IESO assessed whether the development timelines and objectives of the capacity
auction and capacity export opportunities would align with anticipated system needs.
The capacity auction is expected to be available to begin procuring resources by 2017,
which is well in advance of any expected future system need.
Stakeholders input
o The IESO engaged stakeholders to gather feedback on potential IESO recommendations.
Key messages from stakeholders related to (i) their belief that local economic benefits
should be considered when deciding whether to re-contract with NUGs, and (ii) their
concerns about relying on capacity auctions for which limited details have been released.
In light of the delayed arrival of the Capacity Gap and the additional considerations listed above, the
IESO developed the following recommendations:
1.
2.
3.
Continue the current pause in the recontracting of NUGs – given the current strong supply
outlook and other considerations, entering into long-term contracts for additional NUG
generation capacity is not recommended at this time.
Actively monitor evolving sector conditions and impacts on system need – these
recommendations should be revisited as sector changes are clarified, particularly those related to
decisions around the continued operation of Pickering NGS, the rollout of capacity auction and
capacity export opportunities, and the introduction of cap-and-trade legislations.
Continue development of the capacity auction and capacity export markets with consideration
given to facilitating broad participation, including that of NUGs – the IESO recommends that
NUGs compete with other resources in these opportunities.
These recommendations were developed to ensure system needs are met while minimizing ratepayer
costs over the long term. Should the government decide that re-contracting of specific NUG facilities is
advisable to meet broader government policy objectives, the IESO can provide recommendations on the
appropriate mechanism based on system considerations.
3
Table of Contents
Executive Summary ........................................................................................................................ 2
1.0
Introduction .......................................................................................................................... 5
1.1 Background ...................................................................................................................... 5
1.2 NUG Procurement to Date ............................................................................................... 6
2.0
Scope and Principles ............................................................................................................ 9
2.1 Scope ................................................................................................................................ 9
2.2 Principles ........................................................................................................................ 10
3.0
Assessment of System Needs............................................................................................. 11
3.1 Planning the Ontario Electricity System ........................................................................ 11
3.2 Defining System Needs .................................................................................................. 11
3.3 Forecast of Provincial System Needs ............................................................................. 13
3.4 Forecast of Regional System Needs ............................................................................... 15
4.0
Addressing System Needs.................................................................................................. 17
4.1 Resources Available to Address System Needs ............................................................. 18
4.2 Methods Available to Procure Future Needs ................................................................. 22
5.0
IESO Considerations in Making Recommendations ......................................................... 23
5.1 Complexities Encountered While Negotiating New NUG Contracts ............................ 23
5.2 Development of Capacity Auction and Export Opportunities ....................................... 29
5.3 NUG Attributes .............................................................................................................. 31
5.4 Stakeholder Input ........................................................................................................... 32
6.0
Recommendations .............................................................................................................. 38
6.1
6.2
Recap of Key Considerations and Observations ............................................................ 38
Recommendations .......................................................................................................... 40
Appendix A
NUG-Related Directives ..................................................................................... 41
Appendix B
Summary of NUG Facilities Re-contracted To Date .......................................... 53
Appendix C
Historical Pricing Basis Used by IESO in Re-contracting NUGs ....................... 54
Appendix D
List of NUG Facilities Referenced in November 2010 Direction ....................... 56
Appendix E
Summary of System Resources ........................................................................... 58
Appendix F
Stakeholder Input ................................................................................................ 63
Appendix G NUG Facilities Likely to be Impacted in the Near-Term by the
Recommendations of this Report .................................................................................................. 78
Appendix H
Alternate Re-contracting Mechanisms ................................................................ 79
4
1.0 Introduction
On December 19, 2014, the Minister of Energy issued a direction (the “Directive”) to the Independent
Electricity System Operator, (IESO), at the time of issue the Ontario Power Authority (OPA), 1 regarding
Non-Utility Generator facilities (the “NUGs”). The Directive suspended any pending negotiations with
NUGs and requested an assessment of the framework for NUG contracting 2 with a report back to the
Minister by no later than September 1, 2015. 3
The Directive provided the following considerations in assessing the framework:
• the current process for contracting NUGs
• the IESO’s work to develop a capacity auction in Ontario
• changes to the supply and demand forecasts since the 2013 Long-Term Energy Plan (LTEP)
• any other appropriate considerations.
This report has been developed in response to the Directive and provides an assessment of the
framework for NUG contracting in Ontario including recommendations on moving forward.
1.1
BACKGROUND
In the early 1990s Ontario Hydro entered into multiple long-term power purchase agreements (PPAs)
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. 4 The contracted NUGs were
fuelled by a variety of sources, with natural gas accounting for over 1,400 MW and the remainder largely
being a mix of hydroelectric and biomass. This report focuses on non-hydroelectric NUGs, most of which
had contract terms of 20 years.
In 1998, Ontario Hydro was reorganized into five successor companies, one of which was the Ontario
Hydro Financial Corporation, 5 later renamed to the Ontario Electricity Financial Corporation (OEFC). As
part of its mandate, the OEFC was given the responsibility to manage the debt of the former Ontario
Hydro, including management of contracts with the NUGs. 6
It is important to note that NUGs were originally contracted by Ontario Hydro and designed to operate
primarily as baseload resources. However, by the late 2000s when the first agreements were beginning to
expire, changing system conditions in Ontario resulted in an excess of baseload generation capacity and a
need for additional load-following resources (i.e., peaking and intermediate resources). To extend the life
1
2
3
4
6
The IESO and the OPA merged on January 1 2015. To avoid confusion, the name OPA will not be used throughout the body of
this report. Unless otherwise noted, any use of the name IESO that mentions events prior to January 1, 2015, will refer to the
actions of the OPA.
“Re: Non-Utility Generator Projects.” Directive from Ministry of Energy: December 19, 2014.
http://www.powerauthority.on.ca/sites/default/files/NUG-direction-Dec-19-2014.pdf
The original date for the directive was was subsequently amended on April 22, 2015, by the “Procurements” directive that
modified the date by which the report was due from July 1 to September 1, 2015. http://www.ieso.ca/Documents/MinisterialDirectives/MC-2015-904-Outgoing-IESO-Letter-of-Direction-1.pdf
“Ontario Government Makes Accounting Decision on Non-utility Electricity Generator Contracts.” Newsroom: March 18,
2005. http://news.ontario.ca/archive/en/2005/03/18/Ontario-government-makes-accounting-decision-on-nonutility-electricitygenerator.html
5
Bill C35, Energy Competition Act, 1998: June 1998.
http://www.ontla.on.ca/bills/bills-files/36_Parliament/Session2/b035.pdf
“2012 Annual Report.” Ontario Electricity Financial Corporation, 2012: http://www.oefc.on.ca/pdf/oefc_ar_2012_e.pdf
5
of NUG facilities and transition these facilities to a dispatchable 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. 7
In response to this situation, on November 23, 2010, the Minister of Energy directed the IESO to enter into
negotiations with eligible NUGs for new contracts. 8 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 be structured in such a way as to provide clear signals to encourage operation of the
facilities when power is highly valued.
On December 16, 2013, the Ministry of Energy issued a second NUG-related direction to the IESO
regarding NUGs that were 100 per cent fuelled by biomass, with a capacity of 15 MW or less. 9 This
direction specified a contract price, hours during which the price would apply, and a maximum contract
length in addition to other contract terms. See Appendix A for copies of all directives issued to the IESO
in relation to NUGs.
1.2
NUG PROCUREMENT TO DATE
As of December 19, 2014, the IESO had re-contracted nine NUG facilities, representing a total capacity of
approximately 550 MW, under the terms of the Ministerial directives noted above. A brief summary of
the re-contracted facilities is provided in Appendix B.
Form of Contract
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. At a high level, the CES style contract establishes a
contract price based on the average monthly fixed costs the generator is expected to incur over the life of
the contract to build, operate and maintain the facility (i.e., the “Net Revenue Requirement”). Each
month, an algorithm determines how much revenue the facility notionally would be expected to earn in
the market (the “Deemed Market Revenue”). The Deemed Market Revenue is then subtracted from the
7
8
9
In certain limited circumstances some NUGs could continue to operate by virtue of their behind-the-meter connection and/or
thermal supply arrangements. Alternatively, NUGs could choose to lay up their facilities in anticipation of future opportunities.
“Re: Negotiating New Contracts with Non-Utility Generators.” Directive from Ministry of Energy: November 23, 2010.
http://www.powerauthority.on.ca/sites/default/files/new_files/about_us/pdfs/doc20101123173916.pdf
“Re: 100 Per cent Biomass Non-Utility Generators.” Directive from Ministry of Energy: December 16, 2013.
http://www.powerauthority.on.ca/sites/default/files/news/December-16-2013-Directive-Biomass-Generator.pdf
6
Net Revenue Requirement to determine how much the generator will be paid by the IESO. Essentially,
the CES contract structure results in the ratepayer taking on the market operation risk in order to provide
the generator with greater assurance that each month they will receive their Net Revenue Requirement
(from a combination of IESO payments and market revenues).
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). 10
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 successfully utilized to re-contract a number of NUGs. Key to this success
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).
Pricing Basis
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.
At a high level, the methodology used to establish contract pricing was as follows:
1. Establish capacity need - Using median conditions, the IESO identified a need for additional
bulk system capacity resources (the “Capacity Gap”) to arise in approximately 2019. Specifically
the identified need in 2019 was for peaking capacity only, with very limited incremental energy
requirements over the planning horizon.
2. Determine alternative capacity price - NUGs could potentially address a portion of this Capacity
Gap, but only if they are cost competitive against other options identified in the LTEP and Supply
Mix Directive. The alternate form of capacity used to establish maximum price that the IESO was
willing to pay (i.e., the “benchmark price”) was based on the cost of a new build peaker (i.e.,
simple-cycle, gas turbine or “SCGT”)
3. Calculate contract price – based on the start date of the NUG’s new contract and the anticipated
start of the Capacity Gap, a levelized capacity price that would be paid to the NUG was
calculated.
o full value of the “benchmark price” was recognized in years with a Capacity Gap
10
Heat rate of 13,000 Btu/kWh was used as the threshold for establishing the MCF to represent the notional highest heat rate
natural gas resource that would be expected to be dispatched on the system, hence any NUG would be expected to operate as
least as much as such a resource.
7
zero value of the “benchmark price” was recognized in years without a Capacity Gap
A net present value calculation was then used to bring the potential value streams back
to the start of the contract and then smoothed out over the contract’s term to allow the
NUG to start receiving payments in years prior to the anticipated Capacity Gap. 11
Add Locational Gas Delivery & Management – in addition to the capacity portion of the
contract price paid to each NUG that was based on a generic SCGT, there was also an amount
paid in relation to the lowest cost bundle of Gas Delivery & Management (“GD&M”) services
needed for each specific NUG to meet the obligations in the contract. 12
o
o
4.
For further details on the methodology used to establish pricing for new contracts entered into by the
IESO with NUGs, please refer to Appendix C.
The above 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. It
should be noted that the IESO recognized the potential for certain negotiations with NUG counterparties
to not result in new contracts, as the economics of some facilities would not align with the price offered
by the IESO for their capacity.
11
Smoothing of payments (i.e., beginning contract payments in year one of the contract) was necessary from a cash flow
perspective for the NUGs.
12
In certain circumstances the amount the IESO was willing to recognize was capped. Please refer to Appendix C for further
details.
8
2.0 Scope and Principles
2.1
SCOPE
While this report considers a broader framework that includes other procurement initiatives, it is not
intended to be used to evaluate these procurements going forward.
This report relates to the framework and assessment of contracting with NUG facilities that were
identified in the November 23, 2010, directive that do not yet have a contract with the IESO. A complete
list and location map of all eligible NUG facilities can be found in Appendix D.
Table 1 provides information regarding NUGs with contracts that expire up to the end of 2020 that are
most likely to be impacted in the short term by the recommendations of this report. 13 Although
negotiations were initiated with NUG facilities whose OEFC contract expired in May 2015 or earlier, not
all resulted in agreements being reached. It should also be noted that the IESO understands that certain
NUG contracts include provisions for possible extensions to their OEFC contract for a certain period,
generally for 12-60 months, post the original expiry date. While the IESO has been informed that no
extensions have been executed as of yet, the expiry dates set out below may change should the OEFC
enter into extensions with specific NUG facilities.
Table 1: Summary of NUGs with OEFC Contracts Expiring Up to the End of 2020
Owner
Facility
Name
HJ Heinz
Canada
H.J. Heinz
Brookfield
Lake Superior
Power
Northland
Power
Cochrane
Eastern
Power
Keele Valley
LFG
Northland
Power
Kingston (aka
Destec) Cogen
Atlantic
North Bay
Power Plant
Atlantic
Kapuskasing
Power Plant
Fuel
Natural
Gas
Natural
Gas
Natural
Gas
Wood
Waste
Landfill
Gas
(LFG)
Natural
Gas
Natural
Gas
Waste
Heat
Natural
Gas
Waste
Heat
Capacity
(MW)
Location
7
Leamington
110
Sault St.
Marie
27
Cochrane
11
Expiry
1-Aug2011
1-May2014
12-May2015 14
12-May2015
30
Vaughan
1-Dec2015
115
Bath
1-Feb2017
North Bay
31-Dec2017
31
9
30
Kapuskasing
10
31-Dec2017
Comments/
Considerations
Host facility currently closed, connected
behind the meter.
Facility is currently idled while Brookfield
explores restart options.
Northland issued termination notices to
employees 60 days after contract expiry,
believes facility can restart upon receipt of
new contract 15
LFG fuel supply sufficient for <10 MW and
falling annually. Option to co-fire with
natural gas at very high heat rate.
Not currently operating as a cogen
following the closure of thermal host
(INVISTA)
Compressor stations rarely used, therefore
waste heat unlikely to be available for recontracting
Compressor stations rarely used, therefore
waste heat unlikely to be available for recontracting
13
Note – there are also three NUGs, representing about 270 MW of capacity, whose contracts will expire after the end of 2020
Cochrane’s OEFC contract (both natural gas and wood waste) was originally set to expire on January 12, 2015, but was
extended four months.
15
Northland Press Release – http://www.northlandpower.ca/Investor-Centre/News-Events/Recent_Press_Releases.aspx?MwID=1967791
14
9
Owner
TransAlta
Calpine
Canada
Atlantic
Facility
Name
Fuel
Mississauga
Cogen
Whitby
Cogen
Calstock
Power
Natural
Gas
Natural
Gas
Wood
waste
Total =
2.2
Capacity
(MW)
Location
110
Mississauga
50
Whitby
31
Hearst
Expiry
Comments/
Considerations
31-Dec2018
4-May2019
17-Jun2020
No longer a cogen following closure of
thermal host (McDonnell Douglas / Boeing)
Operates as a CHP plant with Atlantic
Packaging as thermal host
No steam host, purchases wood waste from
local industry
540
PRINCIPLES
Consistent with the recontracting principles used to date and recent government statements (refer to
Section 5.1.1 for further details), this assessment and the resulting recommendations were guided by the
fundamental principle that:
The IESO seeks to ensure system reliability while minimizing ratepayer costs over the long term and
meeting government policy objectives communicated through Ministerial direction
In applying this principle, this report took the following views on certain considerations:
Resource Equality – all resources (e.g., generation, transmission, conservation) available to address a
given system need were treated without bias, and based solely on their specific cost and performance
characteristics. NUGs need to compete against all resources going forward.
Environmental Impacts – differences in environmental impacts, either those deemed positive or
negative, of various resources were not considered when making recommendations. It is expected that
quantifiable financial impacts related to the environmental impacts of various resources will be priced in
as necessary by generators when determining the price they are willing to accept in any future
procurement.
Local Economic Impacts – the local economic impacts of any individual NUG were not considered in
determining recommendations for the future framework for addressing NUGs.
10
3.0 Assessment of System Needs
3.1
PLANNING THE ONTARIO ELECTRICITY SYSTEM
When planning the Ontario electricity system, the IESO’s primary objective is to develop a sustainable
system for ratepayers and a market through which participants can offer their products.
The planning process is driven primarily by reliability assessments that are completed in order to identify
the need for additional resources. Feasible options are then identified and assessed primarily based on
their contribution to reliability and the associated cost to the ratepayer. Additionally, consideration may
be given to the environmental performance and social acceptance of resources that are considered feasible
based on policy direction from the government. In particular, the Ontario government’s announcement to
introduce a cap-and-trade regime for carbon is expected to quantify the greenhouse gas (“GHG”) impact
of options under consideration.
Resources must comply with all required laws and regulations (including environmental, health and
safety, labour, etc.) during all aspects of their development and operation.
3.2
DEFINING SYSTEM NEEDS
The following section explains the three most critical elements the IESO examines when planning a
sustainable electricity system. It also explains how these elements ultimately drive decisions to meet
future system needs.
1. Capacity
Both provincial and local area capacity reliability criteria are set by the North American Electric
Reliability Corporation (NERC) and the Northeast Power Coordinating Council (NPCC). These
organizations set reliability standards for interconnected jurisdictions within their purview. The
standards are laid out in IESO’s Ontario Resource and Transmission Assessment Criteria (ORTAC)
manual. 16 The IESO ensures there is sufficient capacity available to meet these reliability standards
and comply with ORTAC requirements.
2. Energy
Energy assessments look at forecasted system needs, a function of forecasted gross load and
forecasted system resources, to determine the most cost-effective resource portfolio to implement
while maintaining system reliability. These assessments determine if the energy need is peaking,
intermediate, or baseload, which in turn drives what type of resource the IESO identifies as being
required to meet system needs.
3. Operability
Operability refers to the capability of system resources to react to real-time changes in system
conditions on short notice. This includes modifying generation output to address changes in:
demand, available supply, and output from intermittent/variable generation. In addition to ensuring
16
Ontario Resource and Transmission Assessment Criteria (ORTAC) manual:
http://www.ieso.ca/Documents/marketAdmin/IMO_REQ_0041_TransmissionAssessmentCriteria.pdf
11
there are sufficient resources to react to these changes, sufficient capacity is required to be on standby
to meet unanticipated real-time contingencies, which is accomplished through the Operating Reserve
(OR) market. The IESO also contracts for reliability must-run facilities, as well as four ancillary
services to help ensure the reliable operation of the power system: black-start capability, regulation
service, reactive support and voltage control service. The IESO monitors operability needs and
considers them in resource selection.
Resource Selection
The three elements discussed above, and policy direction, are all considered together by the IESO when
implementing market rule changes or developing supply mix recommendations. This ensures a
sustainable electricity system at the best value to the Ontario ratepayer.
An overview of various system resources, their ability to meet system needs, and their impact on the
Ontario system are included in Appendix E.
12
3.3
FORECAST OF PROVINCIAL SYSTEM NEEDS
As a key step in the development of this report, the IESO refreshed its planning scenario to ensure the
most recent data was considered when developing recommendations (the “Updated IESO Planning
Scenario”). The following section outlines the differences between the 2013 LTEP and the Updated IESO
Planning Scenario. Updates to the assumptions used in the 2013 LTEP can be found in Figure 1 and Table
2 below.
Effective Capacity at System Peak (MW)
IESO Scenario minus 2013 LTEP
2,500
2,000
1,500
1,000
500
0
(500)
(1,000)
Year
Peak Demand
Demand Response
Hydro
Natural Gas
Non-Hydro Renewables
Nuclear
Other
Figure 1: Differences in Effective Capacity at System Peak – Updated IESO Planning Scenario vs. 2013 LTEP
The Updated IESO Planning Scenario reflects changes to both anticipated peak demand as well as
changes in resource availability. The table below explains the changes from the 2013 LTEP, including the
impact on near-term capacity needs.
Table 2: Description of Updated IESO Planning Scenario
Category
Peak Demand
Demand Response
Hydro
Description – Change From 2013 LTEP
The forecast of net peak demand plus planning reserve (the
“Peak Demand”) has increased since the 2013 LTEP. The
updated demand forecast includes the impact of expanding
the Industrial Conservation Initiative (ICI) and increased
uptake through the Industrial Electricity Incentive (IEI)
program.
Consistent with 2013 LTEP.
No change in net capacity from 2013 LTEP, however, inservice dates of specific projects have been refined.
Impact on
Near-Term
Capacity Need
Increase
None
None
13
Category
Description – Change From 2013 LTEP
Natural Gas
There is a net increase in installed gas generation capacity an increase from NUG facilities recontracted to date and a
slight reduction in capacity from projects contracted through
the Combined Heat and Power Standard Offer Program
(CHPSOP).
Non-Hydro
Renewables (Bio,
Solar, Wind)
Nuclear
Note that the in-service date for the Napanee Generating
Station has been delayed by one year, although it is still
expected to be in-service prior to the start of the Capacity
Gap.
Installed capacity by the end of the planning horizon is
consistent with 2013 LTEP; however the renewable capacity
mix has changed, which will impact contributions to system
peak.
Under the 2013 LTEP, Pickering Nuclear Generating Station
(NGS) units were expected to begin retiring between 2018
and 2020.
Impact on
Near-Term
Capacity Need
Decrease
Decrease
Decrease
In the current Updated IESO Planning Scenario, the outage
schedule for the Pickering NGS units has been revised to
reflect all units operating through to the end of 2020. 17
Other
The beginning of the refurbishment sequence for Bruce and
Darlington is consistent with 2013 LTEP.
Includes the capacity exchange agreement entered into with
Hydro Quebec, 18 additional energy-from-waste capacity, and
capacity from energy storage, none of which were included
in 2013 LTEP.
Decrease
The net impact of the changes identified above result in a delay of the Capacity Gap from 2019 (as
forecasted in the 2013 LTEP) to 2021. The magnitude of the forecasted Capacity Gap, approximately 2,000
to 3,000MW of additional effective capacity, remains generally consistent with the 2013 LTEP (see Figure
2 below).
17
18
Note: operation until the end of 2020 is pending regulatory approval from the Canadian Nuclear Safety Commission (CNSC)
Hydro Quebec agreement allows for the exchange of up to 500 MW of capacity. Ontario will import clean hydro electric
capacity from Quebec when required to meet Ontario’s summer peaking needs, in exchange Ontario will provide capacity
when required by Quebec to meet their winter peaking needs.
14
Effective Capacity at System Peak (MW)
Surplus (+) / Def icit (-)
3,000
2,000
1,000
0
(1,000)
(2,000)
(3,000)
(4,000)
Year
Updated IESO Planning Scenario
2013 LTEP
Figure 2: Provincial Capacity Adequacy Assessment
Although a significant amount of baseload capacity will cease operation over the duration of the Capacity
Gap, forecasted energy requirements are expected to be addressed by existing and committed resources
(mostly combined cycle gas turbine, “CCGT”). System simulations show that adding peaking supply, as
the notional resource to meet the Capacity Gap, results in said supply operating at less than 2 per cent
Annual Capacity Factor (“ACF”). These simulations confirm that peaking resources are the appropriate
resource type to address needs during the Capacity Gap.
Ontario’s forecast resource portfolio (existing/committed/directed) meet the system’s anticipated
operability requirements.
It is expected that a future LTEP will provide further detail regarding changes to the forecast of system
supply and demand.
3.4
FORECAST OF REGIONAL SYSTEM NEEDS
While NUGs were initially contracted as system-wide resources without consideration for regional
supply needs; they may provide, in some cases, valuable support in maintaining reliability to the local
system where they are connected. This potential for local value was included in the assessment
conducted by the IESO for each NUG listed in Table 1. The result of this assessment indicates that none of
the NUGs, with the potential exception of the Kapuskasing and Calstock NUGs, are required for the
purpose of meeting local reliability needs.
The Kapuskasing and Calstock NUGs provide some value in supporting supply reliability in the
Hearst/Kapuskasing area. The transmission system in the identified area supplies a large industrial
customer with some critical load. While the system can adequately supply the area’s loads without these
two NUGs when all transmission facilities are available, the Kapuskasing and Calstock NUGs would
reduce the risk of load interruptions when transmission facilities are forced out of service.
That being said, it should also be noted that the two NUGs in question contribute to congestion on the
transmission system north of Timmins. This is exacerbated by the recent expansion of the Mattagami
15
River hydro generation facilities. At times, high transfers from the combined output of these and other
plants in the region could exceed the capability of the transmission system north of Timmins and
generation may need to be curtailed.
In order to determine the value of the Kapuskasing and Calstock NUGs to the reliability of the grid in
their respective local areas a more detailed study is required. As the local reliability and congestion issues
in this area are broad and complex in scope, the study would be more appropriately considered as part of
a regional planning study. For this reason, the IESO has decided to initiate the Sudbury North and East
regional planning study immediately instead of at the end of this year. The scope of that study will
include assessing the adequacy of the existing supply to the area north of Timmins, with and without the
Kapuskasing and Calstock NUGs, identifying and evaluating reliability improvement options if required,
conducting economic/cost assessments, and considering congestion and future needs.
16
4.0 Addressing System Needs
Multiple types of resources could be employed to address the system needs outlined in Section 3.0 of this
report. Resources are often selected and located to meet multiple system needs and ensure a sustainable
system. This section outlines some of the operating characteristics of other resources against which
NUGs would need to be considered for the IESO to make meaningful recommendations regarding future
re-contracting opportunities.
17
4.1
RESOURCES AVAILABLE TO ADDRESS SYSTEM NEEDS
Table 3 below provides information regarding resources that could be considered as options to meet future system needs:
Demand Side Resources
Table 3: Resources available to meet future capacity needs
Resource
Current Outlook
Conservation
The 2013 Long-Term Energy Plan (LTEP) indicated a
target reduction in electricity consumption of 30 TWh
in 2032 (this represents a 16% reduction over 2012
consumption).
Future Options
Whether additional cost-effective conservation
opportunities exist and could be relied upon to
meet future needs would need to be explored.
The IESO currently provides financial incentives to
businesses that undertake energy efficiency or selfgeneration projects under the Industrial Accelerator
Program (IAP). Some of these programs include:
• Retrofit;
• Process & Systems; and
• High-Performance New Construction
Demand Response (DR)
The 2013 LTEP indicated a target of using DR to meet
10 percent of peak demand by 2025.
DR currently contributes to meeting peak demand
through the:
• responses of consumers to time-of-use pricing
• peaksaver program
• Industrial Conservation Initiative
• Capacity-Based Demand Response program
• active participation of dispatchable load in the
real-time energy market
Whether additional cost-effective DR
opportunities exist to meet future system needs
would need to be explored.
The cost-effectiveness of pursuing additional DR
resources in excess of current targets is expected
to be informed by the results of the DR auction
and demand response pilot program.
Considered together, the contribution of these demand
response resources already reduces peak demand by
an average of 1200 MW, or approximately 5 per cent of
peak demand.
18
Resource
Supply Side Resources
Firm Capacity Imports
Coal-to-Gas Conversion
Current Outlook
The IESO will hold the first DR Auction in December
2015 which will provide a competitive platform to
select demand response capacity resources for
operation beginning in May 2016. The IESO’s demand
response pilot program, which will also become
operational in May 2016, will explore new
opportunities for demand response resources to meet
system needs.
IESO was directed 19 to:
• negotiate and enter into a seasonal capacity
sharing agreement with HQ Energy Marketing
Inc.; and
• investigate opportunities to obtain other
electricity products (e.g., energy, capacity,
regulation, black start and operating reserve) from
Hydro-Quebec and other market participants
In May 2015, Ontario entered into a 10-year seasonal
firm capacity sharing agreement with HQ Energy
Marketing Inc for up to 500 MW of capacity. The
agreement will become effective as of December 2015
and will support reliability by taking advantage of the
provinces’ complementary seasonal peaks. 20
OPG is currently maintaining their closed Lambton
coal plant to enable a potential conversion to natural
gas firing in the future should an opportunity arise.
Future Options
Whether further firm capacity import
arrangements could be entered into with
neighbouring jurisdictions in time to meet future
capacity needs would need to be explored.
Expansion of the interties and transmission
system may be required to allow for further
reliance on capacity imports in some
circumstances.
Converting Lambton to fire on natural gas could
provide up to 900 MW of system capacity, but
may require significant transmission upgrades
and would be a relatively short term solution (i.e.,
expected useful life of approximately 10yrs).
19
“Re: Procurements.” Directive from the Ministry of Energy: April 22, 2015. http://www.ieso.ca/Documents/Ministerial-Directives/MC-2015-904-Outgoing-IESO-Letter-ofDirection-1.pdf
20
18 Month Outlook: An Assessment of the Reliability and Operability of the Ontario Electricity System from July 2015 to December 2016. IESO. 2015.
http://www.ieso.ca/Documents/marketReports/18MonthOutlook_2015jun.pdf
19
Resource
Energy Storage (new build)
Current Outlook
The IESO has contracted with approximately 34 MW
of energy storage and is currently undertaking an RFP
procurement process for the remaining 16 MW that
were directed to be procured. The IESO will review
the outcomes of the procurement and report to the
Minister of Energy by March 1, 2016.
Energy From Waste (EFW)
The IESO currently has EFW contracts with DurhamYork and Elementa Algoma. The combined capacity
from these projects of 23 MW is scheduled to be in
service by late 2018.
On April 22, 2015 the IESO was directed to develop a
procurement for up to 75MW additional of EFW. 21
Gas Generation (new build)
Nuclear
There are currently no active natural gas fired
procurements underway.
Pickering NGS (3,100 MW) is expected to be in service
until 2020. 22
Future Options
Additional energy storage procurements targeting
capacity resources could be contemplated to meet
capacity needs. The potential cost effectiveness
and operability implications of any expanded role
for energy storage is expected to be informed by
results from recent IESO procurement initiatives
and the Grid Energy Storage report being
developed by the IESO.
The number of MWs the EFW procurement is
seeking to contract could in theory be increased.
Additional studies would be required to
determine whether additional projects are feasible
given the finite amount of waste fuel available.
Projects contracted under the EFW procurement
are not expected to begin operations until 2020 or
later.
Procurement for new build gas generation could
be commenced to meet future needs, likely
targeting peaking capacity (SCGT). Alternatively,
the existing CHPSOP program, which is not
currently accepting applications, could also be
continued. Any future procurement process
would need to ensure regional planning and siting
considerations are taken into account.
The continued operation of Pickering NGS
beyond the currently assumed end of service in
2020 could be explored. Technical and financial
viability of such an extension is unknown at this
time.
21
Link to directive “Moving forward with a new Energy-from-Waste (EFW) Procurement Process”: http://www.ieso.ca/Documents/Ministerial-Directives/MC-2015-904Outgoing-IESO-Letter-of-Direction-2.pdf
22
The Updated IESO Planning Scenario assumes all Pickering units remain in-service until 2020, however formal regulatory approval for this decision has not yet been obtained.
20
Resource
NUGs
Renewable Generation
(new build)
Other
Other Resources Facilitated
by Capacity Auctions
Investments in Transmission
and Distribution Systems
Current Outlook
There are thirteen (13) NUGSs that have not been recontracted representing over 800 MW of capacity.
The current Large Renewable Procurement (LRP) is
targeting a total of 565 MW of new renewable
generation (300 MW wind, 140 MW solar, 75 MW
waterpower, and 50 MW bioenergy) that is currently
included in the current expectation of available
resources to meet future system needs.
n/a
In the context of meeting local area needs only,
investments in local transmission infrastructure (e.g.
new transmission lines, new/expanded capacitor
banks etc.) could be considered instead of adding new
supply and/or demand-side resources.
Future Options
Existing NUG facilities could be recontracted to
meet anticipated system needs.
Expanding LRP targets could be considered to
secure additional capacity. However, there would
be a need to consider whether additional capacity
secured through the LRP could be online in time
for the start of the Capacity Gap.
Capacity auctions have the potential to facilitate
the participation of certain resources in meeting
future capacity needs. This could include
expansions or refurbishments of existing
generation projects, emergency generation,
aggregators, etc.
Any investments in new resources to meet local
needs will be compared against the cost of
transmission upgrades and bulk system capacity
during the Capacity Gap.
When considering the feasibility and desirability of pursuing each of the above options, certain considerations should be noted:
• Based on the anticipated start of the Capacity Gap, it is expected sufficient lead time exists to implement most, but not necessarily all, of
the above options.
• The availability of some of the options above are speculative (e.g., further firm capacity imports), while others would be anticipated to be
readily obtainable in the market (e.g., new build gas generation).
• Some of the above resources are better suited than others to address forecasted system needs (i.e., a need for peaking capacity).
• There may also be broader government policy drivers that need to be considered when selecting between options (e.g., GHG regulations,
economic development, etc.).
Consistent with the principle expressed in Section 2.2 above, the IESO believes all resources should be given the opportunity to compete against
one another to find the minimum cost option to meet system needs while, at the same time, meet government policy objectives that have been
communicated through Ministerial directions.
21
4.2
METHODS AVAILABLE TO PROCURE FUTURE NEEDS
The process(es) ultimately selected to procure the resource types identified in the previous section could
include:
o
o
o
o
o
Competitive RFP
Auction (for capacity or DR products)
Bilateral Negotiations (e.g., firm imports, OPG, NUGs, imports.etc.)
 For NUGs only - continue existing or modified version of contracting process
used to date
Standard Offer (e.g., FIT, CHPSOP, energy storage, etc.)
Reliability Must Run (RMR) contracts if required to maintain reliability on a short term
basis
The final decision on which procurement process(es) to utilize will need to consider the specific resource
type that is targeted, the lead time before the resource is expected to become operational, the length of
time the resource is required, results from regional planning studies, and other specific policy objectives
that may need to be addressed.
Detailed recommendations on specific aspects of any required future procurement process(es) were
considered outside the scope of this report. Following review of the report, the IESO understands that it
is the Minister of Energy’s intention to provide the IESO with further direction concerning the framework
for NUG contracting. Should the Minister of Energy issue a direction regarding any future initiative, it is
expected that the IESO would undertake analysis and engage with stakeholders to develop
recommendations based on the system needs at that time.
22
5.0 IESO Considerations in Making Recommendations
5.1
COMPLEXITIES ENCOUNTERED WHILE NEGOTIATING NEW NUG CONTRACTS
Through the process of negotiating new contracts with the owners of NUG facilities, there were a number
of issues that proved challenging to address. Many of these issues could be expected to arise during any
bilateral negotiation for existing resources, while other issues were a result of the specific procurement
process and circumstances related to NUGs.
The key lessons learned from NUG negotiations to date that were considered in developing the
recommendations contained in this report are provided below.
5.1.1 Expectations Regarding Consideration for “Local Economic Impacts"
The November 2010 directive included nine “Details of the Initiative” that outlined certain elements of
the NUG procurement. 23 After these nine details, there was also a statement that allowed the IESO to
“take into account the local economic impact of NUG facilities.” The November 2010 directive can be
found in Appendix A of this report.
In interpreting this directive, the IESO took the position that “local economic impacts” were not an
element that would be explicitly priced into the contract. Contract price offers were based on value to
ratepayers only for the following reasons:
1. The impact of the NUG on the local economy of the area in which the NUG facility is located is
something that the IESO was not in a position to assess or value. Determining where ratepayer
value ends and taxpayer value begins is extremely challenging and outside the IESO’s area of
responsibility and expertise.
2. There were concerns that higher contract prices that were in theory being provided to ensure
continued “local economic benefits” would simply result in either higher economic returns for
the owners of the NUG facilities, or subsidized energy costs for local industry that would have
continued to operate even if forced to pay market rates for their energy.
3. While the November 2010 directive did include a single statement regarding considering “local
economic impacts,” the clear focus of the directive was in relation to ensuring any new contracts
provided value to ratepayers. This can be seen in the “Details of the Initiative” section of the
directive, which included the following statements: “the IESO to determine the need for, and
value of, each NUG facility as a preliminary step,” “each New Contract will be on terms that
reflect a reasonable cost Ontario electricity consumers and the value of the NUG facility output to
Ontario electricity consumers,” “the outcome of the negotiations set out in this initiative should
be to significantly reduce payments made by Ontario electricity consumers under the Global
Adjustment related to NUG facilities.”
This position was aligned with statements made by the government in both the 2013 LTEP, which stated
that the IESO was directed to “enter into new contracts with the NUGs after the current ones have expired, but
23
“Re: Negotiating New Contracts with Non-Utility Generators.” Directive from Ministry of Energy: 23 Nov 2010.
http://www.powerauthority.on.ca/sites/default/files/new_files/about_us/pdfs/doc20101123173916.pdf
23
only if the contract results in cost and reliability benefits to Ontario ratepayers 24” and the 2013 Ontario
Economic Outlook and Fiscal Review, which stated, “As Ontario negotiates new power purchase agreements
with existing Non-Utility Generators (NUGs), it will be done with an eye to ensuring maximum value to
ratepayers. If a NUG is not required for power system needs, then a new contract will not be executed. 25” The IESO
took the position that if there was a government policy decision to recognize other non-electricity system
value drivers, then either a directive could be issued to the IESO defining how these should be valued or
funding from taxpayer sources could be utilized.
As part of the procurement process, once bilateral negotiations commenced, the IESO required that all
NUG counterparties sign a Non-Disclosure Agreement (NDA) to ensure that negotiations would be kept
between the IESO and the specific NUG and would be free of external influence or interference. In
certain situations, the IESO granted partial waivers to the NDA to allow the NUGs to discuss their
concerns with government.
Lesson:
Introducing non-ratepayer considerations into procurements should be avoided as it
creates significant complexity and is not something that the IESO is in the best position to
determine or quantify.
5.1.2 Information Asymmetry
Historically, the majority of IESO natural gas generation contracts have relied upon the competitive
tension present in a Request for Proposals (“RFP”) process to establish the contract parameters used in
settlement (e.g., contract price, heat rate, etc.) In bilateral negotiations with the NUGs where each facility
was unique (in terms of configuration, technology, fuel source, thermal host agreements, geographic
location, etc.), and the facility owner had more information regarding the facility’s true costs, revenue
streams, and actual technical characteristics, the IESO was challenged to ensure that ratepayers did not
overpay for capacity. This information asymmetry was a key driver in the decision to implement a
capacity form of contract that did not rely upon as many parameters as used in CES-style contracts.
Lesson:
Any future procurement would need to recognize and mitigate challenges with
accurately establishing contract parameters given the inherent information asymmetry
involved with negotiating for an existing facility.
5.1.3 Appropriate Level of Gas Delivery and Management Services
The notional cost of Gas Delivery and Management (GD&M) services required to meet the obligations in
the NUG form of contract are included in the contract price offered to NUGs (refer to Appendix C for
details on how this cost was established). Pricing for these services varies for each NUG depending on the
specific bundle of services selected, the geographic location of the facility, and the gas trading hub from
which gas will be supplied. If transportation and delivery of gas is not available from the nearest or most
economic trading hub theoretically available to the facility, the NUG may be required to procure gas from
24
Achieving Balance – Ontario’s Long-Term Energy Plan http://www.energy.gov.on.ca/en/files/2014/10/LTEP_2013_English_WEB.pdf
25
2013 Ontario Economic Outlook and Fiscal Review - http://www.fin.gov.on.ca/en/budget/fallstatement/2013/chapter1a.html
24
other hubs which may result in higher transportation costs and/or higher commodity costs. NUGs also
faced challenges with matching the length of their GD&M services contracts with the terms for their new
IESO contract (e.g., in recent gas contracts, certain facilities were required to sign fixed 15-year term
contracts).
The GD&M component of the contract price was established by the IESO based on the lowest cost option
available to a specific NUG that would enable them to meet the contract requirements. However, NUGs
are free to select the actual GD&M services they physically procure in the market based on their risk
appetite and views on how best to maximize their profitability.
Given that these resources were being re-contracted to address a peaking capacity need, the IESO’s
approach was to seek out the lowest fixed cost (and hence highest variable cost) bundle of GD&M
services that would be recognized in the contract price. The NUG counterparties, on the other hand, had
an incentive to try and shift as much GD&M costs into the fixed element of the contract price and away
from the variable cost since lower variable costs would be expected to result in increased market revenue
which is to their benefit.
A specific issue to highlight is that NUGs located in northern Ontario do not currently have access to the
same supply options and service bundles as generators located in southern Ontario. During negotiations
it became apparent that GD&M services were significantly more expensive in the north than in the south
(often by a factor of two or more). Union Gas, the IESO, and certain northern NUGs have established a
working group to explore how to address some of the supply challenges in the north.
An additional complexity that was encountered when attempting establish appropriate GD&M costs in
the contract price was the uncertainty present in the Ontario gas supply markets introduced by a number
of developments, including, but not limited to:
•
Shale Gas Developments - the shale gas available from the Marcellus and Utica shale deposits in
the NE United States may provide an opportunity for increased diversity of gas supplied to
Ontario, hence creating the potential for lower gas prices in the future
•
TransCanada Energy East - project includes a plan to convert an existing natural gas pipeline to
an oil pipeline; this may affect the supply and price of natural gas to the province
o The route the pipeline will follow is still subject to public and regulatory review 26
•
TransCanada Mainline Rate Hearings – in late 2014 the National Energy Board approved
revised tolls and tariffs for the TransCanada Mainline system. However, the tolls are only set for
the period of between 2015 and 2020, following which there is uncertainty in the long term rates
that will be charged.
Lesson:
26
(i) Any future procurement will need to consider issues related to availability of
competitively priced gas supply and risk allocation between generators and ratepayers.
(ii) Very significant differences in GD&M costs exist based on geographic location in the
province.
TransCanada Energy East Pipeline Route Map. TransCanada. March 31, 2015:
http://www.energyeastpipeline.com/home/route-map
25
(iii) The holistic cost of contracting with a facility needs to be considered (i.e., capacity
cost + GD&M cost) when comparing the NUGs to potential alternatives.
5.1.4 Unique Facility Attributes
It is important to recognize that NUGs represent a non-homogeneous group of generation facilities. Table
4 below exemplifies the various attributes of NUG facilities:
Table 4: Unique Attributes of NUG Facilities
Attribute
Variability
OEFC Contract Expiry Date
Expire between November 2009 and August 2031
Generation Technology
Fuel
Fuel Supply Arrangements
Thermal Host Arrangements
Geographical Location
SCGT, CCGT, CHP, Rankine Cycle, Reciprocating
Engine, Incinerators
Fuel sources - single or multiple types
Fuel type – natural gas/biomass/waste heat/landfill
gas/solid waste
Located in various service territories (Enbridge, Union)
and supplied via various gas supply hubs (Dawn,
Empress, Iroquois)
Certain facilities are integrated with thermal hosts
Located in all regions of the province
The uniqueness of each NUG made the use of a strictly standardized form of contract challenging, and in
response, certain sections of the form of contract were modified to account for specific individual NUG
facility issues.
Lesson:
While competitive processes such as RFPs are generally the preferred generation
procurement mechanism when contracting for similar types of resources, the unique
nature of each existing NUG facility can result in significant challenges for contracts and
processes that are rigidly standardized. Establishing a basis by which the NUGs can be
comparatively evaluated would also likely prove to be challenging.
5.1.5 Uncertainty Regarding the Start of the Capacity Gap
Due to changing system demands and forecasts, as well as uncertainty regarding asset life and
availability of nuclear facilities, it was difficult to definitively determine the start of the Capacity Gap at
the time the new NUG contracts were being negotiated. In order to determine the contract price for each
facility the IESO was required to take a view on when the Capacity Gap would begin.
The IESO used the anticipated year in which it was believed that the Capacity Gap would occur in
establishing pricing for each NUG (see Section 1.2). While NUGs felt that they provided value to the
system during the years prior to the Capacity Gap, and hence wanted to receive full value during these
years, the IESO did not believe that attributing full value to the NUGs during years in which a surplus
existed was justified.
26
The uncertainty in determining the year in which the Capacity Gap would commence resulted in risk for
both the NUGs and the IESO. If the Capacity Gap occurred earlier than forecast, the NUG had recontracted at a price that was less than the value the facility could actually provide to the system.
Conversely, if the Capacity Gap occurred later than forecast, the IESO would have overpaid for capacity
during a period of surplus.
Lesson:
Any future procurement should try and minimize risk incurred by ratepayers related to
either overpaying if the Capacity Gap arrives later than anticipated or being exposed to
being short of capacity if the gap arrives earlier than anticipated.
5.1.6 Risk Profile and Performance Security
IESO generation contracts generally require that suppliers post security that the IESO is able to draw
upon should Suppliers fail to meet the operational requirements outlined in their contract (commonly
referred to as “Completion and Performance Security”). In the case of the NUG contracts, ratepayer’s risk
related to “completion” (i.e., the risk of the resource not being operational by the agreed upon date in the
contract) is reduced due to the fact that that these facilities are already built and operational. 27 However,
for NUG contracts taking effect prior to the start of the anticipated Capacity Gap and receiving valuebased payments levelized over the term of the contract, ratepayers are essentially “pre-paying” for
capacity that will be required in the future (refer to Section 1.2 for further details regarding contract
pricing basis), and therefore there is an increased “performance” risk (i.e., the risk that the supplier does
not meet the operational requirements established in the contract). In cases where the NUG is being paid
for a period of time in advance of when the capacity is actually required and ceases to operate for
whatever reason, ratepayers would not have recovered the value associated with those effective prepayments.
To reflect this modified risk exposure, the IESO significantly increased the level of Completion and
Performance Security that was required to be posted relative to levels in CES-style contracts. While
ratepayer exposure could in theory be up to 3+ years’ worth of contract payments, the IESO recognized
that posting this amount of performance security would not be seen to be commercially reasonable by
generators. As a result, performance security requirements were capped at one year’s worth of contract
payments.
It should be noted that even at this capped level many NUGs expressed concern with posting the
required performance security. At the same time, ratepayers were not fully protected from the risk of a
default.
Lesson:
27
Commencing contracts prior to when the resource is required to meet system needs
results in increased “performance” risk exposure for ratepayers that must be addressed
in a commercially reasonable manner.
Note that some level of residual “completion” risk is still present as majority of NUGs require capital investments
related to life extension and the transition to a dispatchable mode of operation
27
5.1.7 Challenges of Single Buyer Negotiations
Acting as the single buyer for capacity in the province through bilateral negotiations presented a number
of challenges during negotiations. NUG counterparties consistently claimed that the IESO was exercising
its monopsony power to artificially drive down the price paid for capacity. In addition, the NUGs wanted
to verify analysis completed by the IESO and/or its consultants regarding items such as the anticipated
start date of the Capacity Gap and valuation of the NUG facility. Some NUGs suggested an open book
approach while others insisted on third party verification.
NUG counterparties frequently took the position that their facility was worth more to the system than the
IESO was willing to recognize. Certain negotiations proceeded until the IESO reached the maximum it
could justify paying and would conclude with a final offer from the IESO that the counterparty would
need to decide if it was willing and able to accept. Additionally, without a liquid and transparent market
for capacity in the province, it was difficult to ensure that the IESO was not overpaying for capacity.
Lesson:
It is important that all procurement processes are seen to be transparent and fair to
ensure that accusations of abuse of market power can be avoided.
5.1.8 Lead Time Required for Negotiations
Owners of NUG facilities may require a certain degree of certainty as to whether they will be able to
continue operation post expiry of their OEFC contracts well in advance of milestones for implementing
major capital projects required to ensure the continued operation of their facility (e.g., ordering long lead
time equipment, completing detailed design, lining up contractors, securing capital, etc.)
Additionally, NUGs frequently raised concerns regarding the challenges of retaining skilled labour in
light of uncertain job security when the fate of the facility is unknown. This issue was claimed to be
especially challenging in situations where the workforce was unionized and collective bargaining
agreements needed to be negotiated. As well, some facilities are located in areas with a limited skilled
labour pool (small Northern communities).
As mentioned above, each NUG facility also has its own set of unique characteristics and considerations;
as such, negotiating contracts takes a significant amount of time and effort from both the IESO and the
NUG owner. Sufficient lead time needs to be allocated to ensure that negotiations can be completed on a
schedule that allows for a thorough and reasoned exploration of all issues that arise during negotiations.
Finally, from a system planning perspective, negotiations need to be concluded sufficiently far in advance
of any forecasted system needs, such that if terms for a new agreement cannot be reached, alternative
options can be pursued.
Lesson:
Timing constraints and limitations need to be considered when determining potential
future approaches to NUG re-contracting.
28
5.2
DEVELOPMENT OF CAPACITY AUCTION AND EXPORT OPPORTUNITIES
The IESO is currently in the process of developing market mechanisms, including capacity auction and
capacity export opportunities, towards ensuring Ontario’s resource adequacy needs are met cost
effectively. Results from the capacity auction will also inform market participants, including NUGs, as
well as the province, the IESO and other sector agencies on the value of capacity in Ontario.
5.2.1 Capacity Auction
A capacity auction will provide an opportunity for resources to compete against other providers of
equivalent capacity, such as generators, imports and demand response resources. These capacity offers
will be cleared annually against a demand curve representing Ontario’s forecasted peak demand and
reserve requirements and the lowest cost set of providers will be selected (all resources will receive a
single clearing price). The selected providers, regardless of their resource type, will then have a common
obligation to make this capacity available to the real-time energy market through bids and offers in
exchange for receiving capacity payments based on the auction clearing price.
Capacity auctions are intended to send a competitive and transparent price signal to the market which
will allow investors and/or existing asset owners, to make decisions of whether to:
• invest in a new asset or refurbish an existing asset
• continue operation of an existing asset
• idle an existing asset
• retire an existing asset
The owner of an existing asset would be expected to examine its anticipated capacity, energy and
operating reserve revenues and decide whether those revenue streams are sufficient to support continued
operation.
An asset that is unsuccessful in a capacity auction for a given year would have the option to participate in
future auctions. For example, the owner of a facility may anticipate energy and operating reserve profits
in future years to increase, thereby increasing that facility’s competitiveness in future auctions. In this
scenario, a decision might be made to incur the ongoing costs associated with idling a facility for a period
of time until supply and demand dynamics change sufficiently that the facility can successfully clear in a
future auction. Additionally, an owner of an existing asset might also decide to invest in their asset if they
believe such an investment will make it more competitive in earning market revenues in future years.
The IESO is currently in the process of developing the capacity auction and has begun a stakeholder
consultation on the high level design. The IESO is currently proposing that the first capacity auction will
take place three to four years prior to the year in which capacity resources are needed, and is therefore
focusing on developing a detailed design including the implementation of the market rules over the next
18 to 24 months. This timeline implies that the earliest a capacity auction could be held would be mid2017 to meet system needs arising in 2020. Given that the Capacity Gap is forecasted to arise in 2021, the
capacity auction is expected to be able to procure resources to address forecasted system capacity needs.
In terms of implications for NUGs specifically, the launch of a capacity auction could provide a means for
NUGs to recover their fixed costs that would not be expected to be recovered in the energy market.
29
However as has been noted above, NUGs may face certain challenges with participating in a capacity
auction related to 28:
• addressing cash flow issues between the start of the Capacity Gap (i.e., when they would receive
capacity payments should they be successful in a capacity auction) and the end of their existing
OEFC contracts
• maintaining their labour force during any temporary mothballing of the facility (especially in
Northern Ontario)
• justifying the expense associated with idling the facility that will be incurred without having any
certainty that the facility will successfully clear in an as yet to be finalized capacity auction
• securing gas supply on terms that align with an unknown ability to clear in a capacity auction on
an ongoing basis
While the above challenges may exist to some degree for all generators, a capacity auction would allow
these issues to be priced in to offers as each generator deems appropriate.
5.2.2 Capacity Exports
A key design feature of the capacity auction is the ability to trade capacity with interconnected regions.
Certain regions in the US already provide for the ability of resources that are outside of their areas to
provide capacity to supply their resource needs. Neighbouring electricity markets, such as NYISO and
MISO, may soon require additional capacity which presents a potential opportunity for existing assets to
participate in external markets. This can be advantageous both to those markets, which would have
access to a new pool of resources, and also to successful Ontario-based resources that would have access
to new revenue streams in exchange for meeting the obligations of neighbouring markets.
Considering that Ontario currently has capacity available in excess of what is needed to meet internal
needs, the IESO has begun a stakeholder consultation on the potential for exporting capacity from
Ontario resources not required for Ontario reliability prior to the first capacity auction taking place. The
IESO plans to continue to work with stakeholders to consider a broad range of generators and potential
export markets. This will provide such generators with the prospect of deriving additional value from
their existing assets and at the same time inform the design of a key element of the capacity auction.
In terms of implications for NUGs specifically, the ability to export capacity to neighbouring jurisdictions
could provide a means for NUGs to recover their fixed costs through the capacity payments they receive
from those jurisdictions. This would supplement any Ontario energy market revenues that they would
receive when generating in the IESO-administered markets. The opportunity to export capacity can help
to address some of the challenges identified regarding the timing of the capacity auction by:
• assisting in making decisions about continued operation, idling, or retirement in the years
leading up to a capacity auction; and
• bridging the gap between expected capacity revenues in Ontario, thereby addressing the cash
flow and labour force issues identified above.
As existing resources, NUG facilities may prove to be competitive against new and/or upgraded capacity
providers in neighbouring markets.
28
Refer to Section 5.4 for a summary of stakeholder engagement input
30
The IESO will report back to stakeholders on the scope and timing of the second stage of the stakeholder
consultation on the export of capacity in the fall of 2015. The IESO intends to have market rules and
coordinating agreements between Ontario and neighbouring markets in place by the end of 2016.
5.3
NUG ATTRIBUTES
Table 5 below lists some of the key advantages and disadvantages specifically related to re-contracting
with NUGs as compared to securing other types of resources to meet future capacity needs.
Table 5: NUGs Attributes
Pros
• Existing facilities with minimal development or
siting risk
•
Certain facilities (e.g. combined cycle/CHP
facilities) may be able to act as intermediate
generation sources due to their lower heat rates
•
Existing locations may not align with local
system needs (e.g., not located near load
centres that require additional supply)
•
If recontracting to meet bulk system needs,
then high gas supply costs in Northern Ontario
may result in the IESO paying more for certain
NUG facilities than alternate generation in
Southern Ontario
•
20-year old facilities will generally offer less
operational flexibility (e.g., longer minimum
run times, slower ramp rates, etc.) and higher
heat rates compared to new build facilities
•
•
•
•
Depreciated assets mean contract prices should
be lower than for new build of similar size;
note however there is no guarantee that NUGs
would be cheaper than other equivalent
resources (e.g., imports, DR, etc.)
Generally provide some level of improved
local reliability/operability benefits (although
difficult to quantify)
Recontracting NUGs even during periods
when their capacity contribution is not needed
may provide limited system benefits (i.e.,
reduced HOEP in certain hours, increased
redundancy [insurance for contingencies], etc.)
Cons
Majority of NUGs are <~100MW in size, which
means they do not benefit from the same
economies of scale as larger facilities
31
5.4
STAKEHOLDER INPUT
This section contains stakeholder feedback provided by NUGs, APPrO and other relevant parties during:
stakeholder engagement while preparing this report, negotiations conducted prior to issuance of the
Directive, and subsequent discussions.
5.4.1 Stakeholder Feedback Received During Development of this Report
As part of the development of this report, the IESO engaged with both individual NUG facility owners
and their industry association, the Association of Power Producers of Ontario (APPrO), to solicit
feedback. APPrO and the NUGs were encouraged to submit feedback by completing a questionnaire that
was circulated by the IESO. Responses to the questionnaire provided by the NUGs and APPrO can be
found in Appendix F.
In general, APPrO/NUGs believed that the NUG facilities are unique in many respects and as such there
are a number of items that should be accounted for when deciding whether or not to re-contract. A
number of key themes emerged from this engagement, which have been summarized in Table 6 below.
Table 6: Summary of Stakeholder Feedback
Issue
APPrO/NUG Position
Applying
NUGs suggested that any future
“Lowest Cost to
procurement should focus on
Ratepayer”
recontracting using a “just and
Principle
reasonable cost” principle on the basis
that NUGs are sufficiently different
from other generation resources in the
province to justify not applying the
same principles used by the IESO in
other generation procurements.
IESO Comments
The IESO believes it is appropriate to focus
on ensuring system reliability at the lowest
long-term cost to ratepayers.
32
Issue
Valuing NonRatepayer
Considerations
APPrO/NUG Position
NUGs believe that it is appropriate to
consider non-ratepayer factors (e.g. a
NUG’s local economic impact, support
for industrial and northern
development opportunities, job
creation, environmental benefits, etc.)
when determining the price that
ratepayers should be willing to pay for
a specific NUG facility.
Local political and business interests
also expressed concern regarding the
potential of NUG facilities shutting
down as it would impact tax revenue
for the municipality and may result in
loss of experienced and qualified staff
(including secondary impacts on local
companies that supply goods and
services to the facility).
Temporary
Shutdown or
Idling of NUG
Facilities
NUGs expressed the opinion that idling
a facility can be a challenge as there are
additional costs related to maintaining
the facility and compensating staff.
In addition, NUGs were of the opinion
that without a means by which costs
associated with idling the facility could
be recovered (or at least certainty that
such an opportunity would arise in the
future), it would be infeasible to justify
the risk and expense to preserve a
speculative future option.
IESO Comments
The IESO believes that any increased costs
deemed appropriate to secure local
economic benefits associated with the
continued operation of a NUG should be
funded via the taxpayer, not the ratepayer.
It would be difficult to ensure that
additional amounts paid to NUGs in
notional recognition of local economic
benefits would (a) in fact ensure the
continuation of those benefits and (b) not
result in unnecessarily higher economic
returns for the NUGs.
There is also a risk of overpaying for local
benefits that are not easily quantified or
would continue absent the continued
operation of the NUG. Additionally, it is
difficult to assess the economic value of a
specific NUG relative to the economic
benefit of other local resources that might
otherwise be used (e.g., the value of
demand response to an energy intensive
industrial, or repurposing another asset).
The IESO agrees that incurring these costs
may be difficult to justify for certain NUG
facilities. However, each NUG owner will
need to explore the costs and benefits
associated with idling or shutting down its
facility in light of opportunities that are
expected to be available in the near future.
33
Issue
Use of Existing
Resources
Reliance on
Capacity
Auctions
APPrO/NUG Position
NUGs/APPrO believe that the IESO
should maximize the use of existing
resources before supporting the
building of new resources.
NUGs believe that there are significant
issues with relying on capacity auctions
including:
• Challenges during the period
of time between the expiry of
their OEFC contracts and the
start of the capacity auction
delivery period (e.g., employee
retention, planning capital
investments, securing longterm gas contracts).
• Uncertainty regarding timing
of implementation and how the
auctions will be structured
NUGs with contracts that will expire
prior to the first year of capacity auction
payments are likely to face unique
challenges from a cash flow
perspective.
Regional
Planning
Initiatives
NUGs expressed concerns that regional
planning does not sufficiently take into
account regional growth forecasts or the
value of individual NUGs to meeting
local system needs.
IESO Comments
While the use of existing resources may
provide certain benefits (e.g. reduced
siting and/or construction risk) the IESO
believes these attributes should be factored
into prices offered by NUGs during any
future procurement process where NUGs
may need to compete against other new
build resources.
Additionally, whether capacity is required
in the area in which a NUG is located, and
whether the NUG can provide the services
needed by the local system, are factors that
need to be considered. The IESO does not
support the recontracting of existing
resources that do not address system
needs.
The capacity auction is still under
development and the IESO will ensure that
all stakeholders, including NUGs, have a
chance to provide input.
NUGs, as discussed in Section 5.3, have
certain advantages that are expected to
allow them to be cost competitive with
other alternatives.
The IESO agrees that NUGs with contracts
that expire prior to the first year of the
capacity auction delivery period may face
unique challenges, but expects that
opportunities to export their capacity to
neighbouring jurisdictions, if feasible,
should help mitigate such challenges.
At this time, regional planning is focused
on ensuring reliable supply to load
customers, which includes accounting for
regional growth factors. Should it be
determined that additional resources are
required to meet reliability needs in a
specific area, all options will be considered
and assessed as required.
34
Issue
Pricing Basis
Timing
APPrO/NUG Position
NUGs believe that the IESO should be
transparent when modelling
assumptions and determining
benchmark prices.
NUGs believe that negotiations should
commence as soon as possible with
NUGs whose contracts have already
expired, and that negotiations with
other NUGs should be completed at
least two years prior to expiry of
existing OEFC contracts.
NUG facilities will require sufficient
lead time in order to secure GD&M
services, obtain environmental
approvals, and order/install new
equipment, as required.
IESO Comments
The IESO believes it is appropriate to share
fundamental assumptions used in
establishing prices. Negotiations with
NUGs to date have been transparent in
sharing assumptions, including the sharing
of: alternate cost of capacity, GD&M cost
build-up, years of capacity need, and
methodology for smoothing payments
between value and non-value years.
However, certain information used by the
IESO in forecasting system need is
confidential and cannot be shared.
The IESO agrees it is generally preferable
for facility owners to have certainty
regarding the future operation of their
assets to facilitate the decision making
process regarding long-term investments
needed to allow for the continued
operation of the asset.
Procurement recommendations by the
IESO will seek, where possible, to ensure
timelines result in facility owners having
clarity on the future of their assets
sufficiently far in advance to facilitate
necessary capital investment decisions.
In addition, the IESO believes it is
necessary to consider benefits to the
facility owner against potential costs to
ratepayers, arising from future changes in
market conditions and system needs, when
securing capacity in advance of the
Capacity Gap.
35
5.4.2 Stakeholder Feedback Relating to Broader Government Policy Objectives
During the course of negotiations with NUG owners, and as part of the stakeholder feedback received in
preparing this report, NUGs consistently expressed the view that there are broader government policies
that apply to the NUG facilities which should be considered going forward. As expressed by the NUGs,
these policies and their related implications include:
a) Renewable Energy Policy
• Certain NUG facilities are at least partially fuelled by renewable fuel sources (i.e., biomass,
landfill gas, or waste heat). The government has previously supported the development of
similar new build generation resources through various procurement initiatives (e.g., FIT,
LRP).
• Additionally, the “100 percent Biomass Non-Utility Generator Projects” direction was
previously issued to provide a basis for the re-contracting of a subset of biomass NUGs. 29
• In the case of facilities at least partially fuelled by biomass, it has also been noted by
stakeholders that local industry is often reliant on the NUG as an economic source of biomass
disposal (which otherwise may be disposed of in landfills).
• While NUG facilities are already built and operating, and hence may have different value
propositions compared to similar new build facilities, NUGs/APPrO believe that the
government should provide similar opportunities for their facilities (potentially including
allowing these facilities to participate in planned renewable energy procurement initiatives).
b) CHP Policy
• Certain NUG facilities operate, at least to some extent, as CHP facilities. The government has
supported the development of CHP projects in the province through a variety of initiatives
(e.g., the CHPSOP procurements, the Industrial Accelerator Program, etc.).
• NUGs/APPrO believe that the government should provide similar opportunities for their
facilities (potentially including allowing these facilities to participate in planned CHP-related
procurement initiatives).
c)
29
Climate Change Policy
• NUGs may be impacted by a cap-and-trade program to reduce greenhouse gas emissions in the
province.
• Certain facilities (i.e., generally those fuelled by biomass or landfill gas) may help to reduce
overall carbon pricing risk.
• There is currently limited detail available regarding how a cap-and-trade program would be
implemented
• Potential climate change policy objectives as it relates to the continued operation of NUG
facilities should be considered.
Link to the Directive - http://powerauthority.on.ca/sites/default/files/news/December-16-2013-Directive-BiomassGenerator.pdf
36
d) Economic Development Policy
• Stakeholders have consistently provided feedback that certain NUG facilities have become
deeply integrated into their local communities and provide significant local economic benefits
to their region.
• The IESO has not to date included any non-ratepayer related factors when determining
whether there is value in recontracting with a given NUG facility.
• NUGs/APPrO believe it would be appropriate for the Ministry of Energy, in consultation with
other areas of the Government of Ontario, to assess whether specific NUG facilities result in a
net benefit for the province, and provide guidance to the IESO on how such value should be
recognized in any future procurement process.
37
6.0 Recommendations
6.1
RECAP OF KEY CONSIDERATIONS AND OBSERVATIONS
The previous sections of this report present a number of key points that were considered when
developing recommendations regarding the future of NUG re-contracting:
•
A number of significant challenges arose while negotiating new NUG contracts using the
bilateral negotiation approach employed to date.
•
The IESO currently forecasts the Capacity Gap to start in 2021.
•
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). 30
•
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.
•
The next LTEP will provide further clarity into the long-term supply and demand forecast.
Figure 3 on the next page depicts some of the key initiatives and decision points that will have
implications for the electricity sector and are taking place over the same timeframe as the expiry of
existing NUG contracts that are within the scope of this report.
The figure highlights the fact that there are a large number of initiatives and decision points that have
uncertain schedules and outcomes that could impact the potential value of re-contracting NUG facilities.
In addition, uncertainties in the timeline of initiatives included in the figure could impact the start of the
Capacity Gap.
30
Further studies are underway to determine whether Kapuskasing NUG and Calstock NUG are exceptions to this statement.
38
#
NUG
Capacity
(MW)
11
Northland (Cochrane)
38
22
Eastern (Keele Valley)
30
33
Northland (Kingston)
115
44
Atlantic (North Bay)
40
55
Atlantic (Kapuskasing)
40
66
TransAlta (Mississauga)
110
77
Calpine (Whitby)
50
8
Calstock (Hearst)
41
2013 LTEP
anticipated
Capacity gap
Start of Capacity Gap
based on current
projections
Energy East In-Service
Cap & Trade Development
Cap & Trade Implementation
Cap & Trade Compliance & Further Development
DR Auction
DR Delivery Period
LRP RFP/RFQ Process
LRP Projects Commence Operations
Capacity Auction
Capacity Auction - Rebalancing
Capacity Market –Delivery Period
Pickering Decision
LTEP
Capacity Export
Implementation
1
2015
2
2016
Capacity Exports
3
2017
4
5
6
2018
2019
Capacity Related Initiatives
8
7
2020
2021
2022
2023
Policy Related Initiatives
Figure 3: Expected Timeline of Relevant Electricity Sector Initiatives
39
6.2
RECOMMENDATIONS
In light of the above considerations, the IESO has developed the following three key recommendations in
relation to the future of NUG recontracting in Ontario:
1.
Continue the current pause in the re-contracting of NUGs
• Given the current strong supply outlook in the province, and the complexities encountered
throughout the previous NUG procurement, entering into long-term contracts for additional
NUG generation capacity is not currently recommended.
• It should be noted that a continuation of the current pause in re-contracting will result in
certain NUG contracts with the OEFC expiring prior to the commencement of the Capacity
Auction (please refer to Appendix G for further discussion of these NUGs).
2.
Actively monitor evolving sector conditions and impacts on system need
• A number of significant structural changes that are contemplated in the sector over the near
term (e.g., decision on continued operation of Pickering NGS, 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.)
• In light of this uncertainty, it is advisable to closely monitor developments in the sector and
revisit the recommendations of this report as necessary over the coming years. The
recommendations of this report should be considered during the development of the next
LTEP.
3.
Continue development of capacity auction and capacity export opportunities with
consideration given to facilitating broad participation, including that of NUGs
• Given the significant amount of uncertainty regarding the amount and timing of a need for
additional system resources, combined with the inherent flexibility of the proposed auction
process, allowing NUGs to compete with other resources in the capacity auction and capacity
export processes is recommended.
• It is assumed that the first window of the planned capacity auction will be run within the
same general timeframe as the expiry of NUG contracts that are within the scope of this
report.
• Should capacity auction or capacity export opportunities be delayed (or forecasted system
needs evolve in the short term), it may be advisable to consider exploring alternate
mechanisms to support the continued operation of NUGs (please see Appendix H for further
details).
The recommendations in this report 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 (such as those outlined in
Section 5.4), the IESO would anticipate providing specific recommendations on the appropriate
mechanism for re-contracting; and that 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.
40
Appendix A
NUG-Related Directives
41
42
43
44
45
46
47
48
49
50
51
52
Appendix B
Summary of NUG Facilities Re-contracted To Date
Table B-1: Summary of NUG facilities Re-contracted to Date
Term
(yrs)
15
Contract
Capacity
(MW)
10.30
Term
Commencement
Date
1-Jun-15
Fuel
Configuration/
Equipment
Municipal Solid
Waste + Natural
Gas
Incinerators +
steam turbine &
SCGT
Chapleau
Wood Waste
CHP
8
5.00
1-Jan-14
INVISTA
Maitland
Natural Gas
CHP
20
45.96
1-Jan-16
TransAlta
Ottawa Health
Sciences
Natural Gas
Combined Cycle
CHP
20
73.70
1-Jan-14
Capstone
Cardinal
Natural Gas
CCGT
20
156.34
1-Jan-15
Atlantic
Tunis
Natural Gas and
Waste Heat
15
38.00
1-Jan-18
CCGT
Owner
Emerald
Facility
Emerald EFW
Tembec
Northland
Kirkland Lake
Peaker
Natural Gas
SCGT
20
29.87
23-Jul-15
GDF Suez
West Windsor
Power
Natural Gas
CCGT
15
126.78
1-Jun-16
TransAlta
Windsor
Cogen
Natural Gas
CCGT
15
72.28
1-Dec-16
Sum
558.23
53
Appendix C
Historical Pricing Basis Used by IESO in Re-contracting NUGs
For renegotiated NUG Contracts entered into prior to the end of 2015, the contract price offered to a
specific NUG was established using the following approach:
•
As specified in the November 2010 Direction, NUG contracts with the IESO could commence
immediately after the expiry of their existing OEFC contract, with terms of between five and 20 years.
•
The IESO determined that it was appropriate to pay NUGs the equivalent cost that would be incurred
by ratepayers to meet capacity needs during years when a capacity shortfall was anticipated (at the
time the need was anticipated to start in approximately 2019).
•
The equivalent cost for needed new capacity, or the “benchmark cost”, was based on the estimated
cost of the likely alternate source of capacity that would have been procured to meet the need. A new
SCGT facility was assumed to be the alternate resource type.
•
As ratepayers would only be expected to incur the cost for new build capacity during years in which
there was a capacity need, zero benchmark value was allocated prior to the commencement of the
Capacity Gap and full benchmark value was allocated during capacity need years. The total value
over the life of the contract was first brought to a net present value (NPV) and then levelized back out
over all contract years.
•
The IESO agreed with NUG counterparties that levelizing the contract payments across all years in
the contract’s term was necessary from a cash flow perspective. It would be difficult for the NUGs to
continue operating for multiple years during the upfront capacity surplus years without receiving
some form of capacity payments to cover their fixed costs. Figure B-1 shows a graphical example of
how this calculation works for a hypothetical NUG facility whose contract started in 2014 with a 15year term).
Figure C-1: Sample NUG Pricing Basis
•
The other element of contract pricing that needed to be established was the amount that would be
included in recognition of Gas Delivery and Management (GD&M) costs. GD&M costs were
determined on a project-specific basis. Some complexities associated with establishing this included:
o Pricing for these services varies for each NUG depending on the specific bundle of services
selected, the geographic location of the facility and the gas trading hub supplying the gas.
o If gas is not available from the nearest trading hub to the facility, the NUG may be required to
procure gas from other more expensive hubs.
54
o
•
Challenges with matching the length of GD&M contracts with the term of their IESO contract
exist
Given that NUGs located in northern Ontario are subject to GD&M costs that can be multiples of
what a similar facility in southern Ontario would incur, GD&M price recognition was capped at an
amount in line with what would be paid to a peaking resource in southern Ontario.
55
Appendix D
List of NUG Facilities Referenced in November 2010 Direction
Table D-1: List of NUG Facilities Referenced in November 2010 Direction
#
CURRENT OWNER
Facility Name
Fuel
Location
1
2
3
4
5
6
7
8
9
10
11
12
Westbrook Greenhouse
White River BioMeg
Fort Frances
Tembec Power Plant
Brock West LFG
Heinz
KMS Peel Inc.
Rosa Flora
Chapleau Cogen
University of Toronto
Invista Power Plant – Maitland
Ottawa Cogen Plant
Natural Gas
Wood Waste
Biomass
Wood Waste
Land Fill Gas
Natural Gas
Solid Waste
Natural Gas
Wood Waste
Natural Gas
Natural Gas
Natural Gas
Beamsville
White River
Fort Frances
Smooth Rock Falls
Pickering
Leamington
Brampton
Dunville
Chapleau
Toronto
Maitland
Ottawa
Lake Superior Power
Natural Gas
Sault St. Maire
110
14
Westbrook Greenhouses
Rentec
Resolute (former AbiBo)
Tembec Holdings Inc.
Eastern Power Ltd.
H.J Heinz Canada Ltd.
Algonquin Power
Rosa Flora Ltd.
Tembec Holdings Inc.
University of Toronto
Invista
TransAlta (50%)
Brookfield Renewable
Power
Brock University
OEFC
Capacity
(MW)
1.5
7.5
103
13
27
7
8
1.6
7
6
20
68
Brock University Power Plant
Natural Gas
St. Catharines
6.6
15
Labatt Brewery
Labatt Breweries Ont.
Natural Gas
London
4.2
16
Capstone Infrastucture
Cardinal Power
Cardinal
17
Atlantic Power
Tunis Power Plant
18
Northland Power
Cochrane Power Corp.
19
20
21
22
23
Eastern Power Ltd.
SUEZ North America
TransAlta
E.S Fox Ltd.
Northland Power
Keele Valley LFG
West Windsor Power
Windsor Cogen
Beare Road Power
Kingston Cogen
24
Atlantic Power
North Bay Power Plant
25
Atlantic Power
Kapuskasing Power Plant
26
27
TransAlta
Calpine Canada
Mississauga Cogen
Whitby Cogen
28
Atlantic Power
Calstock Power Plant
29
Northland Power
Iroquois Falls
30
Atlantic Power
Nipigon Power Plant
Natural Gas
Natural Gas
Waste Heat
Natural Gas
Wood Waste
Land Fill Gas
Natural Gas
Natural Gas
Land Fill Gas
Natural Gas
Natural Gas
Waste Heat
Natural Gas
Waste Heat
Natural Gas
Natural Gas
Waste Heat
Wood Waste
Natural Gas
Natural Gas
Waste Heat
Natural Gas
Wood Waste
Natural Gas
165
39
9
27
11
30
116
74
5
115
31
9
30
10
110
50
10
31
126
32
8
90
13
30
13
31
Northland Power
Kirkland Lake Power - Base
Load
Kirkland Lake Power – Peaker
Tunis
Cochrane
Vaughan
Windsor
Windsor
Scarborough
Bath
North Bay
Kapuskasing
Mississauga
Whitby
Hearst
Iroquois Falls
Orient Bay
Kirkland Lake
OEFC PPA
Expiry Date
Nov-2009
Jun-2009
Oct-2009
Mar-2010
16-Feb-2011
1-Aug-2011
2-Mar-2012
2-Nov-2012
1-Jan-2013
1-May-2013
18-Dec-2013
31-Dec-2013
1-May-2014
6-Jun-2014
11-Sep-2014
31-Dec-2014
31-Dec-2014
12-Jan-2015
1-Dec-2015
31-May-2016
1-Dec-2016
24-Jan-2017
1-Feb-2017
31-Dec-2017
31-Dec-2017
31-Dec-2018
4-May-2019
17-Jun-2020
1-Jan-2022
31-Dec-2022
23-Aug-2031
23-Aug-2031
22-Aug-2015
56
57
Figure D-1: Map of NUG Facilities in November 2010 Direction
Appendix E
Summary of System Resources
Table E-1: Summary of System Resources
Resource
Type
“Fuel”
Resource Capability
(Capacity, Energy, Operability)
Conservation
EE can be achieved through codes and
standards, IESO/LDC incentive programs, or
early movers switching to more efficient
technologies.
Energy
Efficiency
(EE)
EE measures can take on a number of shapes.
They can be targeted at loads that are constant in
all hours or they can more closely track the
system load shape.
Demand Management
Depending on the measure savings profile, EE
can lower peak demand and/or lower the system
variable electricity cost (system heat rate).
DR is a form of load management. It can take
the form of load shifting or load reduction.
Demand
Response
(DR)
Energy
Storage (ES)
DR is commonly operated and evaluated as a
peaking supply resource. It has the potential to
provide both capacity and operability value.
ES has three primary characteristics: maximum
output, duration at maximum output, and
round-trip efficiency. Since ES’s charge time is
greater than its discharge time, and there are
losses as the energy is held, ES is less than 100%
efficient, and a net consumer of energy.
Considering the range of technologies, ES has
Markets and Services
(Operating Reserve,
Ancillary)
Although EE does not
directly participate in
markets or services, it
does impact system needs
and reliability, and may
indirectly change
requirements for markets
and services (e.g.,
reliability criteria
thresholds or absolute
amount of resources
needed to meet the
thresholds).
As a peaking “supply”
resource, DR has the
potential to provide
operating reserve and
ancillary services.
Ontario System Implications
EE measures often eliminate load indefinitely,
especially if achieved through codes and standards.
Eliminated load is 100% reliable versus the reliability
of the supply or transmission alternative. This EE
reliability lowers the planning reserve margin
requirement (currently evaluated to be 20%).
Increasing EE during Ontario’s energy surplus periods
will increase the level of SBG, and stress resources that
provide SBG mitigation.
New forms of EE, to match potential system needs, are
currently being explored.
Ontario’s current DR framework incents participants
to reduce their load (relative to an established
baseline) at the time of system peak, or during other
times when the system is constrained.
Ex-ante performance and program limitations (call
windows and duration) reduce the capacity and
operability value of DR.
Considering the range of
technologies, ES has the
potential to provide
operating reserve and
ancillary services.
New forms of DR, to match potential system needs,
are currently being explored.
Without contracts or market rule changes, the case for
ES in Ontario is determined by price arbitrage (charge
and discharge electricity price differential). Under
current and forecast Ontario electricity prices, the
economic case for ES is marginal.
Depending on the system need, shorter duration
windows will reduce ES value.
58
Resource
Type
“Fuel”
Resource Capability
(Capacity, Energy, Operability)
Markets and Services
(Operating Reserve,
Ancillary)
the potential to meet capacity, energy, and
operability needs.
Examples of ES technologies include: batteries,
capacitors, compressed air, flywheels, hydrogen,
and pumped hydro.
Nuclear is a baseload resource intended to run
between 90% and 95% ACF. It provides capacity
and energy, but without steam bypass, it
provides little flexibility.
IESO is currently conducting a study on ES to
determine technical capability (across the range of
technologies), and how that capability aligns with
Ontario system needs.
Nuclear is not suitable to
provide operating reserve
or ancillary services.
Supply
Natural
Gas (NG)
Rankine - Peaking resource; provides capacity
and operability.
SC - Peaking resource; provides capacity and
operability.
CC - Intermediate resource; provides capacity,
energy, and operability (less than Rankine and
SC).
Nuclear provides close to half of Ontario’s electricity
requirements.
The configuration at Bruce NGS enables some
flexibility to mitigate SBG – 300 MW/unit using steam
by-pass. In times of deep surplus, Bruce units may be
called upon to shutdown (minimum 48 hour
shutdown time).
Nuclear
NG technologies include gas turbines (aero
derivative or frame type), reciprocating engines,
and boilers. Configurations include Rankine
cycle, simple cycle (SC), combined cycle (CC),
and combined heat and power (CHP).
Ontario System Implications
The aero derivative,
reciprocating engine, and
boiler based
configurations have the
most potential to provide
operating reserve and
ancillary services.
The timing of Pickering NGS end-of-life, and the
refurbishment sequence at Darlington and Bruce
NGSs, have major impacts on the timing and
magnitude of the Capacity Gap.
NG resources have taken on the majority of the
operability, operating reserve, and ancillary service
burdens left by the coal phase-out.
Keeping units on without immediate need, but in
anticipation of ramp requirements, contributes to SBG
due to higher minimum loading points versus coal.
Current and forecast NG prices make NG supply an
attractive resource, but the introduction of a carbon
cap-and-trade regime in Ontario is expected to
negatively impact this value
Over-reliance on NG supply poses a risk to ratepayers
(e.g., due to increased fuel prices) and the reliability of
the system (e.g., a decrease in the availability of fuel).
59
Resource
Type
“Fuel”
Resource Capability
(Capacity, Energy, Operability)
CHP - Depending on dispatchability (operated to
system needs or thermal host needs) will run as
intermediate or baseload resources; provides
capacity and energy.
Bio fuels can include biomass, biogas, landfill
gas, and wood. The availability of fuel has an
impact on value and performance.
Bio
Bio facilities can be dispatchable, fuelconstrained dispatchable, or baseload (CHP
configuration or uses fuel as it is available, e.g.,
landfill gas).
Markets and Services
(Operating Reserve,
Ancillary)
To the extent thermal host needs and Ontario system
needs are misaligned, the value of CHP decreases.
The dispatchable
reciprocating engine and
boiler-based
configurations have the
most potential to provide
operating reserve and
ancillary services.
Dispatchable and fuel-constrained dispatchable
bio have similar performance characteristics to
NG Rankine, SC, and CHP above (CC
configuration is non-typical).
Hydro facilities can be baseload or peaking, or a
combination of both, depending on specific
characteristics of the river system; the location
along that system; and supplementary
infrastructure.
Hydro
Baseload hydro, which provides capacity and
energy, is considered “run-of-the-river” and uses
water as it is available, with no potential for
storage.
Ontario System Implications
Peaking hydro, its ramp
almost instantaneous, is
one of the best resources
to provide operating
reserve and ancillary
services.
Bio fuel in Ontario remains an issue. Since fuel is
scarce, facilities are generally small and therefore
cannot benefit from the same economies of scale as
larger facilities. This generally results in bio-fuelled
facilities being less competitive than resources with
other fuel sources
Attempts at large scale operations:
• Atikokan (211 MW converted from coal to run on
biomass) is fuel-limited, running at 8% ACF.
• Thunder Bay (150 MW converted from coal to run
on advanced biomass), is also fuel-limited, and
expected to run at a very low ACF. The fuel is
produced specifically for Thunder Bay GS,
sourced from Scandinavia.
The most cost effective hydro resources have, for the
most part, already been developed; however, new
potential sites continue to be evaluated as costs come
down and value goes up.
Beck PGS is the most utilized peaking hydro asset in
Ontario with respect to operating reserve and ancillary
services.
Peaking hydro can be spilled, and is another resource
used to mitigate SBG.
The flow of water is dependent on naturally
occurring hydro cycles (inter-year), freshet
(intra-year), environmental regulations, and to
some extent, tourism.
60
Resource
Type
“Fuel”
Wind
Solar
Photovoltaic
(PV)
Resource Capability
Markets and Services
(Capacity, Energy, Operability)
(Operating Reserve,
Ancillary)
Peaking hydro can be stored (daily, weekly,
seasonally) and dispatched according to system
needs, providing capacity, operability, and
potentially energy.
Wind turbines are a baseload resource,
providing emission-free electricity. Although
wind typically blows more during certain times
in the year (winter) and certain times of the day
(night), wind production for the most part
cannot be forecast with complete accuracy more
than a day or so in advance.
Wind is not suitable to
provide operating reserve
or ancillary services.
To the extent a wind resource has already been
dispatched, there is potential to provide ramp,
up or down, to the system. However it should be
noted that wind resources that are already
operating at their full capability given the wind
conditions at a given point in time, which may
be less than the rated capacity, will not be able to
ramp up.
Solar PV is a baseload resource, providing
emission-free electricity. Although solar
irradiance can be forecast, almost to the minute,
cloud cover cannot, which results in intermittent
output.
To the extent a solar PV resource has already
been dispatched, there is potential to provide
ramp, up or down, to the system. However, it
should be noted that solar resources that are
already operating at their full capability given
the solar irradiance at a given point in time,
which may be less than the rated capacity, may
not be able to ramp up.
Ontario System Implications
On average, current and forecast, the ACF of the
Ontario wind fleet is 30%.
On average, current and forecast, the effective capacity
contribution of the Ontario wind fleet, for winter and
summer, is 33% and 14%, respectively.
The IESO has the ability to dispatch market participant
wind facilities to mitigate SBG, or for other reliability
purposes.
The IESO has developed a centralized wind forecast
tool to anticipate reliability requirements, resulting in
valuable price signals to all market participants.
Solar is not suitable to
provide operating reserve
or ancillary services.
On average, current and forecast, the ACF of the
Ontario solar fleet is 15%.
On average, current and forecast, the effective capacity
contribution of the Ontario solar fleet, for winter and
summer, is 4% and 30%, respectively.
The IESO has the ability to dispatch market participant
solar facilities to mitigate SBG, or for other reliability
purposes.
61
Transmission
Resource
Type
“Fuel”
Lines/
Stations/
Other
Resource Capability
(Capacity, Energy, Operability)
Building transmission infrastructure has the
potential to further integrate an electricity
system and make it more efficient.
Markets and Services
(Operating Reserve,
Ancillary)
Transmission
infrastructure projects
have the potential to
unlock area constrained
resources that may be able
to provide operating
reserve or ancillary
services.
Ontario System Implications
A number of transmission projects have been proven
cost effective by increasing the integration and
efficiency of the Ontario system.
62
Appendix F
Stakeholder Input
Feedback received from APPrO on July 21, 2015:
63
64
65
66
67
68
Feedback received from Northland Power on July 10, 2015:
69
70
71
72
73
74
Feedback received Eastern Power on July 22, 2015
75
76
77
Appendix G
NUG Facilities Likely to be Impacted in the Near-Term by the
Recommendations of this Report
Given the IESO’s recommendation that the negotiation of long-term contracts for NUGs be ceased and
that the capacity auction be developed with the objective of ensuring broad participation, including that
of NUGs; the IESO believes it is appropriate to ensure that the Ministry of Energy is aware of the
following details of certain NUG facilities which are likely to be impacted by the recommendations of the
report in the near term:
•
Northland Power - Cochrane Power NUG (biomass – 11 MW, natural gas – 27 MW)
o Potential Policy Linkages – Renewable Energy, CHP, Climate Change, Economic
Development
o The facility’s OEFC contract expired on May 12, 2015 and the facility is currently not
operating but is being maintained for a potential restart in the future. This IESO entered
into negotiations for this facility but was unable to reach terms based on ratepayer value
alone.
o Northland Power, local businesses, and community leaders have engaged the IESO
seeking to highlight the importance of this facility to the local economy.
o The IESO understands that the biomass portion of this facility is of particular importance
to the region as it provides a cost effective waste disposal option for local forestry
businesses, provides free heat to the community centre, and is responsible for a
significant portion of the municipality’s revenues.
o The IESO understand that it is unlikely that this facility would be able to continue
operation until the expected start of the Capacity Gap absent some form of additional
revenue
•
Eastern Power - Keele Valley NUG (LFG/natural gas – 30MW)
o Potential Policy Linkages – Renewable Energy, Climate Change
o This facility’s OEFC contract will expire on December 1, 2015.
o Given that the earliest that the first capacity auction window is expected to be run is 2017
for a 2020 delivery, the IESO understands that it is unlikely that this facility would
continue operating past the expiry of its current contract absent additional revenue
streams.
o The facility is a generation project within the GTA that is fuelled by a combination of
landfill gas (LFG) and natural gas.
78
Appendix H
Alternate Re-contracting Mechanisms
The recommendations in this report assume that NUGs will be able to participate in upcoming capacity
auction and capacity export opportunities. However, in certain circumstances there may be a rationale to
enter into contracts with certain NUGs for the various reasons outlined below. In each circumstance the
IESO has provided some preliminary comments on potential mechanisms to address the scenario,
however the specific situation and objectives at the time would need to be considered prior to the IESO
being able to provide any definitive recommendations.
(A) Capacity Auction and Capacity Gap Timelines Not Aligned
Should the launch of the capacity auction be delayed or there is a dramatic change in supply and
demand conditions this may result in the Capacity Gap beginning sooner than anticipated. In either
case, the outcome could be that the capacity auction is unable to secure the necessary resources on a
timeline to meet system needs. In such a scenario it may be appropriate to consider re-contracting
with NUGs.
Considerations:
• Extending existing OEFC agreements is unlikely to be efficient from either a financial or
operational perspective
• In this scenario, there is anticipated to be a need to secure resources for a short duration prior
to when the capacity auction would be available, as such any new contract should be short
term in duration.
• Could employ similar pricing basis and contract structures to those used to re-contract NUGs
under the November 2010 Directive.
• NUGs should continue to be required to compete for new contracts against the lowest cost
alternative capable of providing the capacity required by the system. The lowest cost
alternative must be technically viable given timing considerations (e.g., DR or firm import
resources may potentially be secured with short lead times, while new build CCGT may not).
(B) Desire to Achieve Specific Government Policy Objectives
There may be a desire to re-contract individual NUGs, or classes of NUGs, to meet specific
government policy objectives.
Considerations:
• Extending existing OEFC agreements is unlikely to be efficient from either a financial or
operational perspective
• The IESO is best suited to establishing value of re-contracting a NUG as it relates to
ratepayers. Should there be a desire to re-contract a NUG to achieve non-ratepayer policy
objectives, other appropriate external sources are likely to be in the best position to quantify
the value derived from meeting those objectives. The value to ratepayers and the value of
meeting other objectives, along with details of the NUG’s cost and revenue structure, could
then be used to establish an appropriate contract price.
o Any contract resulting from such an initiative should include a mechanism to adjust the
price should the NUG facility no longer support the stated policy objective.
• Consider whether existing IESO procurements exist that could be leveraged to address the
policy objective. For example, the mandatory requirements needed to qualify for the LRP
could be amended to allow existing resources to participate.
79
(C) Local System Need Is Identified
Should a NUG currently be addressing a local system reliability need such that if the NUG ceased to
operate the capacity auction would not be expected to ensure the need is addressed, there may be a
need to explore securing additional resources.
Considerations:
• Extending existing OEFC agreements is unlikely to be efficient from either a financial or
operational perspective
• Whether the need is met going forward by the NUG or by other system resources (e.g.,
generation, DR, transmission, etc.) would depend on the option that is the most cost effective
and feasible given timing constraints.
• The IESO currently utilizes Reliability Must Run (“RMR”) contracts to address situations
where the retirement of a facility would result in reliability standards not being met. RMR
contract prices are set using an open book cost pass through approach that is subject to many
of the same challenges as expressed in Section 5.1.
• While RMR contracts for specific NUGs may be necessary in certain circumstances where no
alternate resource is currently available, longer term solutions would need to consider either
upgrades to the local transmission system or whether running a targeted RFP process would
result in the most cost effective solution.
80