Proposed Operating Reserve Demand Curve
Supply Offers – 30-minute Reserve (SE-72)
Meeting October 11, 2011
30-minute Reserve Background Information
1. NPCC requires IESO to carry 30-minute reserve equal to ½ of second largest contingency loss. For Ontario,
this requirement is normally 435 MW i.e. half of the loss of a large nuclear unit.
2.
NPCC allows IESO to be short of 30-minute reserve for up to 4 hours with no penalty. There is also no
formal NPCC penalty for being short of 30-minute reserve for longer than 4 hours.
3.
Current CAOR offer of 30-minute reserve: 400 MW at $30/MW in real-time sequences only.
Principles for Establishing ORDC Supply Offer Quantities
1. The quantities of the offers should be from 0 MW to the normal Ontario operating reserve requirement:
2.
a.
10-minute total reserve requirement equal to largest contingency
b.
10-minute synchronized reserve requirement equal to 25% of the 10-minute total requirement;
c.
30-minute reserve requirement equal to 50% of the second largest contingency.
Within the standing offers, there may be multiple laminations for an individual reserve type in order to
reflect the respective values of different quantities of that reserve.
3.
The ORDC supply offer quantities should, to the extent practicable and while still maintaining simplicity in
implementation, take into account that the size of the largest and second largest contingencies can increase
for potentially extended periods of time due to power system configurations or outages.
Application of Quantities Principles
1. The 30-minute reserve requirement, under normal conditions, is 435 MW, which is 50% of the loss of a
single large nuclear unit. However there have been periods where the second largest contingency is the
loss of 2 smaller nuclear units and the resulting 30-minute reserve requirement has been approximately 500
MW.
Pricing Principles for ORDC supply offers
1. Offer price(s) should be reflective of the value of energy at that level of reserve: i.e. price required to
provide sufficient incentive to market to create the reserve.
2.
Offer price(s) should be reflective of the market cost of creating 30-minute reserve through IESO action.
3.
Offer price(s) should be consistent with the applicable operating reserve demand curve or reserve shortage
pricing mechanism in neighbouring markets.
Application of Pricing Principles
1. Price Required to Provide Incentive to Market to Create 30-minute Reserve
30-minute reserve can be provided by domestic resources and imports. OR prices include lost energy
revenues if unit energy output reduced in order to provide reserve. Therefore, the market incentive to
create 30-minute reserve would be the market energy price i.e. reserve provider should be financially
indifferent as to whether they provide energy or reserve.
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2.
Market Cost of Creating 30-minute Reserve through IESO Action
a.
If a 30-minute reserve shortfall exists or is forecast, the IESO relies on market mechanisms to resolve
the shortfall. The IESO would identify such shortfalls through publication of SAAs, SSRs, Adequacy
Reports and pre-dispatch reports. There is no incremental cost, attributable to the forecasted 30-minute
shortage, to the market for the publication of these reports as the IESO publishes these reports as a
normal part of its business.
b.
If a 30-minute reserve shortfall is forecast to last for more than four hours, the IESO could take the
following actions:
i. Manually constrain dispatch if the DSO has not already done so: e.g. constrain imports on or
dispatchable loads down etc in order to reduce domestic generation energy output so as to create
reserve.
ii. Purchase emergency energy – formula established in applicable interconnection agreements, but is
generally a multiplier of applicable reference market energy price.
However, in the past the IESO has not and, in the future, likely would not take action to create 30-minute
reserve, regardless of the actual or expected duration of the shortage, instead relying on the market to
resolve the shortage. Therefore, we cannot determine any market cost related to IESO action.
3.
Consistency with Neighbouring Markets
a.
NYISO system-wide 30-minute reserve demand curve prices are1:
i. 200 MW at $50/MW
ii. 200 MW at $100/MW
iii. 200 MW at $200/MW
b.
ISO-NE system-wide 30-minute reserve constraint penalty function (RCPF): $100/MW2
c.
MISO and PJM do not have a 30-minute reserve requirement.
Proposed ORDC supply offers for 30-minute reserve:
• 150 MW at $50/MW
•
150 MW at $100/MW
•
150 MW at $200/MW
Rationale:
a. 30-minute reserve has limited value relative to 10-minute reserves and energy. NPCC has no
formal penalties for shortages of 30-minute reserve. So ORDC offer prices for 30-minute reserve
shortages should not be set far above expected prevailing market prices.
NYISO 30-minute reserve prices derived in 2002-2003 in their “exports as reserves” initiative. Prices appear to be set so as to
not result in frequent use of “exports as reserves”. Pricing analysis to support “exports as reserves” appears to target these
prices relative to NY 30-minute reserve shadow price as follows: $50 is 96% percentile; $100 is 97% percentile; $200 is 97.4%.
Prices carried over to the ORDC in 2003 because “exports as reserve mechanism has functioned exactly as a reserve demand
curve...” NYISO Presentation “Demand Curve Definitions 27 Aug 2003.
2 ISO-NE RCPF values described as follows: (i) set to reflect cost of re-dispatch to create desired reserve (ii) prevent market from
incurring extraordinary costs for little or no reliability benefit (iii) associated with a certain contingency that requires the
deployment of reserves and can be considered a “virtual” reserve resource that ISO operations can deploy upon a contingency
at a cost of the RCPF value. ISO-NE RCPF values were developed to be consistent with the corresponding demand curve price
structure at NYISO. Also, ISO-NE wanted the sum of the system RCPFs to mirror the energy offer price cap of $1000.
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b.
The offer price points are consistent with NY and NE, our neighbouring NPCC markets with
comparable requirements. Comparison with MISO and PJM is not applicable as those markets do
not have a 30-minute reserve requirement.
c.
The total offer quantity of 450 MW is a trade-off between the normal requirement (435 MW), the
temporarily increased requirements witnessed in recent times and simplicity in implementation.
Having a constant offer quantity that is generally equal to the requirement is simpler to implement
and therefore preferred to changing the offer quantities every time the requirement changes or
having an offer quantity that is well below the requirement for extended periods.
d. Laminations will result in increasing OR prices as quantity of ORDC scheduled increases,
providing increasing price signals to the market of potential and actual shortages of 30-minute
reserve.
Relationship of Proposed Offer Prices to Market Prices, Shadow Prices and Market Offers (August 1, 2010 to
July 31, 2011)
Price ($/MW)
99%ile
99.9%ile
99.95%ile
30 minute OR
25.75
73.35
153.11
Energy
70.00
171.47
231.48
4
Constrained – Richview Bus
30-minute OR
57.35
478.22
522.57
Energy
84.84
208.92
295.54
The proposed offer prices would exceed pre-dispatch 30-minute OR prices approximately 99% of the time.
Proposed offer prices would exceed pre-dispatch energy prices somewhat less than 99% of the time.
Pre-Dispatch Hour-Ahead
Schedule3
Market
Commodity
Price ($/MW)
99%ile
99.9%ile
99.95%ile
Market
30 minute OR
30.00
74.90
99.90
Energy
98.98
208.81
255.92
Constrained – Richview Bus
30-minute OR
31.97
103.18
2000.00
Energy
138.19
611.58
2000.00
The proposed offer prices would exceed real-time 30-minute OR prices over 99% of the time. The proposed
offer prices would exceed real-time energy prices somewhat less than 99% of the time.
Real-Time Schedule
Commodity
The hour-ahead pre-dispatch prices were analysed because (i) pre-dispatch would best represent “market offer-only OR
pricing” as PD does not currently include any CAOR and (ii) the hour-ahead pre-dispatch would under most circumstances
have the same market OR offers as used in real-time.
4The pre-dispatch constrained schedule 30-min OR prices are very high relative to the constrained schedule energy prices and
the OR offer curves. The very high OR prices occurred in May and June 2011, when OR is often provided by generation
resources that have offered in energy at negative prices and OR at high prices i.e. the resources really wants to provide energy,
not reserve. Such a resource, when actually scheduled to provide reserve, has to forego energy production to provide OR. In this
situation, OR price includes the lost opportunity cost of backing off energy production. That lost opportunity cost is the
difference between the negative offer price and the energy MCP and this difference can be very large.
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Price ($/MW)
Cumulative Offer Curve - 30R
$120
$110
$100
$90
$80
$70
$60
$50
$40
$30
$20
$10
$0
0
1000
2000
3000
4000
5000
6000
7000
8000
Cumulative Offer Quantity (MW)
Fall 30R
Winter 30R
Spring/Freshet 30R
Summer 30R
The above offer curves were derived from the actual market participant offers on sample days within the
seasons noted. On the basis of these offer curves:
• The proposed upper tranche of ORDC offers, priced at $200, would not interfere with market offers.
•
The proposed middle tranche of the ORDC offers, priced at $100, would (i) have minimal interference
with market offers in the spring and summer seasons5, and (ii) potentially interfere6 with market offers
in the fall and winter seasons.
•
The proposed lower tranche of the ORDC offers, priced at $50, would potentially interfere6 with
market offers in the all seasons.
Extremely small amounts of 30-minute reserve were offered in at $100/MW during these seasons.
“Potentially interfere” because most of the capacity offered as reserve is actually scheduled to provide energy and so is not
available to provide reserve.
5
6
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