Operating Reserve Market Redesign Post Implementation Review Date:

Operating Reserve Market Redesign
Post Implementation Review
Date:
December 18, 2014
Prepared by:
Jenny Chen
Senior Market Design Specialist
Prepared for: Mike Law
Vice President, Market Services
Table of Contents
1
2
3
Executive Summary ............................................................................................................................. 1
Background ........................................................................................................................................... 2
Post Implementation Review ............................................................................................................... 4
3.1
3.2
3.3
Assessing the OR Market Against the Redesign Objectives ........................................................................ 4
3.1.1
Reduced AESO Influence in the OR Market .................................................................................. 4
3.1.2
Improved Market Transparency ..................................................................................................... 5
3.1.3
Created Better Alignment with the Energy Market ......................................................................... 5
3.1.4
Simplified the Design ..................................................................................................................... 6
Assessing the Post-Redesign OR Market Using Market Metrics .................................................................. 7
3.2.1
OR Supply and Demand ................................................................................................................ 7
3.2.2
Total Cost of OR Procurement ..................................................................................................... 10
3.2.3
Unit Cost of OR Procurement ...................................................................................................... 12
3.2.4
Observations from the OR Market metrics ................................................................................... 16
Assessing Unimplemented Recommendations .......................................................................................... 21
4 Next Steps ........................................................................................................................................... 23
Appendix I: Market Clearing and Pricing Mechanisms on Watt-Ex and the OTC.............................. 25
Appendix II: Multiple Trade Prices of the Same Active OR Product of the Same Delivery Day ...... 27
1 Executive Summary
This report summarizes the post implementation review of the operating reserve market redesign
implemented in 2010 and 2011. The purpose of the review is to assess the redesigned operating reserve
market against the redesign goals, identify the areas where further improvements can be made, and
propose next steps.
The operating reserve market is where operating reserves are procured. Operating reserves are used by
the AESO to maintain system reliability. Prior to the implementation of the redesign recommendations,
the operating reserve market featured dual procurement platforms, multiple trading days for the same
product, and the AESO’s active engagement in day-to-day trading strategies. In 2007, the AESO
published a discussion paper that identified that “extensive market design issues” existed in the operating
1
reserve market.
In order to address the issues, the AESO consulted with industry with the objective of improving the OR
market design. In October 2010, the AESO proposed the operating reserve market redesign
recommendations in its “Revised AESO Recommendation Paper – Operating Reserves Market Redesign”
2
with four key redesign goals:

Reducing AESO influence in the market

Improving market transparency

Creating better alignment with the energy market

Simplifying the design
Subsequently, the AESO implemented a range of changes to the operating reserve market in two phases.
Phase I operating reserve market redesign implementation occurred between July 2010 and March 2011.
The key change to the operating reserve market in this phase was to move multi-day trading of the same
operating reserve product to one day trading. Phase II operating reserve market redesign implementation
occurred between August 2011 and December 2011. The key change was to cease over-the-counter
daily trading and establish a new transparent market clearing mechanism for the standby operating
reserve products. These redesign initiatives were mostly focused on the procurement practice and the
financial aspects of the OR market, not the redesign of OR products or altering the physical structure of
the OR market.
In 2014 the AESO conducted a post redesign implementation review of the operating reserve market. The
review assessed the redesigned operating reserve market against the redesign goals, analyzed the
market metrics and evaluated the unimplemented recommendations. This report is a summary of the
review.
Assessing the redesigned OR market against the redesign objectives, the review concluded that the
operating reserve market redesign implementation achieved the objectives of reducing the AESO
influence in the market, improving market transparency, and simplifying the market design. The OR
market redesign improved the alignment with the energy market from the perspective of matching the OR
procurement costs with the hourly consumption in ISO Tariff calculation. However, it did not align the OR
procurement or dispatch in conjunction with the real time energy market.
The market metrics analysis in the review also provided several observations:
1
2
The AESO, Operating Reserve Market Improvements, October 2007, P1
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P1.
Page 1

Although having achieved the redesign objectives, the redesign implementations did not lead to lower
operating reserve cost

The unit costs of OR procurement consistently exceeded the spark spread in the energy market
across all OR products.

The price relationship between Regulating Reserve and Spinning Reserve is not consistent with the
fact that Regulating Reserve is a higher quality product than Spinning Reserve and has the ability to
replace Spinning Reserve

Higher-than-actual activation rates used in the ‘blended’ price calculation in the selection of standby
operating reserve products likely incented sellers to offer at higher premiums
The Review also evaluated the unimplemented recommendations and proposed that the immediate next
step should be focused on making improvements to the current operating reserve market by exploring
ways to allow the market to correct inefficient price outcomes reflected in the trade price differential
between Regulating Reserves and Spinning Reserves and adopting activation rates that better reflect the
actual activation rates in the standby operating reserve selection process. Over time, the OR market is
expected to continue to evolve in conjunction with other market initiatives such as wind integration,
storage integration, intertie restoration and allowing non-traditional resources to participate in the
operating reserve market.
2 Background
The operating reserve (OR) market is where operating reserves are procured. Operating reserves are
used by the AESO to maintain system reliability when operating the wholesale electricity market and the
transmission system. Currently three OR products are procured by the AESO, regulating reserves (RR),
spinning reserves (SR) and supplemental reserves (SUP). For each OR product, there are two types,
3
active OR products and standby OR products.
Prior to the implementation of the redesign recommendations, the OR market featured dual procurement
platforms, multiple trading days for the same product, and the AESO’s active engagement in day-to-day
4
trading strategies:

Dual procurement platforms
Prior to the redesign, the procurement of OR products occurred on two different platforms, Watt-Ex
and over-the-counter (OTC). These two platforms used different market clearing and pricing
5
mechanisms.

Multiple trading days for the same delivery period
Under the original OR market design, the same OR product was procured on Watt-Ex throughout the
5 business days before the delivery period (D-5 through D-1). Different trade prices for the same OR
product on the same delivery day were determined on different trading days. Occasionally, products
were also procured using monthly term contracts on Watt-Ex, and the monthly procurement would
yield another trade price for the same OR product in addition to the trade prices set on the 5 trading
3
Detailed descriptions of OR products can be found in the AESO “Ancillary Services Participant Manual” Edition 3, January 2012.
Detailed descriptions of the original OR market design can be found in the AESO’s Operating Reserve Market Improvements,
October 2007, PP4-8.
5
Appendix I.
4
Page 2
days. The Watt-Ex index was calculated using the volume weighted trade prices and often differed
6
from the trade prices.

The AESO’s active engagement in day-to-day trading strategies
In the pre-redesign OR market, the AESO actively engaged in trying to optimize trade price, volume,
and the selection process of standby OR on Watt-Ex and the selection process of the volume traded
on OTC. These procurement and selection strategies were not transparent to the market and resulted
in unpredictability of market outcomes for OR suppliers.
In October 2007, the AESO published a discussion paper titled “Operating Reserve Market
Improvements” (the Discussion Paper). In the Discussion Paper, the AESO stated that the OR market at
7
the time was unsustainable due to “extensive market design issues”. The Discussion Paper summarized
8
the issues in the OR market:

The equilibrium pricing, while encouraging participation, also created a no-risk upside for the
9
providers

Insufficient liquidated damages and liberal force majeure options created perverse incentives

The AESO’s active participation in the market might have undue impact on market prices

The OR market was bifurcated by competing platforms (Watt-Ex and OTC)

There was lack of transparency of OTC procurement

The financial incentives in the Hydro Power Purchase Arrangement (the Hydro PPA) might result in
perverse outcomes

The complexity of the OR market impacted the willingness of participants to offer the products in the
market and their ability to offer efficiently
In order to address some these issues, the AESO consulted with industry with the objective of improving
the OR market design. Based on comments received from stakeholders, the AESO developed OR market
10
redesign recommendations in January 2009. Additional feedback was received from the stakeholders
which assisted the AESO with refining and revising the recommendations. In March 2010, the AESO
published its “Revised AESO Recommendation Paper – Operating Reserves Market Redesign” (the
Revised Recommendation Paper). The Revised Recommendation Paper established reducing AESO
influence in the market, improving market transparency, creating better alignment with the energy market
11
and simplifying the design as the key objectives of the operating reserve market redesign.
The Recommendation Paper specified changes that needed to be made in the OR market redesign and
proposed a phased implementation. Subsequent to the Revised Recommendation Paper, the AESO
implemented a range of changes to the OR market.
Phase I OR market redesign implementation occurred between July 2010 and March 2011. The key
change to the OR market was to move multi-day trading of the same OR market product to one day
6
Appendix II.
The AESO, Operating Reserve Market Improvements, October 2007, P1.
8
The AESO, Operating Reserve Market Improvements, October 2007, PP8-12.
9
However, through stakeholder consultation, the AESO retained equilibrium pricing as it “leads to economically efficient results for
homogenous products…”. The AESO, Consultation Summary - Operating Reserve Market Redesign Concepts – for Discussion,
July 30, 2008.
10
The AESO, Recommendation Paper, Operating Reserves Market Redesign, January 2009.
11
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P1.
7
Page 3
trading. Phase II OR market redesign implementation occurred between August 2011 and December
2011. The key change was to cease using the OTC mechanism as a daily trading platform and establish
a new transparent market clearing mechanism for standby OR products. Specifically, the OR market
redesign implementation brought about the following changes:

Established a new procurement practice by eliminating multi-day trading and ceasing to use OTC as
the daily trading platform

Discontinued the practice of frequently altering bid prices of active OR and posting bids near the
close of trading sessions, and stopped posting standby bid prices

Established the transparent ‘blended approach’ to clear standby OR market based on the ranking of
the ‘blended’ prices

Allowed loads with less than 5 MW to be able to provide supplemental reserve through aggregators

Provided daily reports on trade prices and trade volumes of the OR products

Aligned the OR cost with hourly energy consumption in the ISO tariff calculation
These initiatives were mostly focused on the procurement practice and the financial aspects of the OR
market, not the design of OR products or the physical structure of the OR market.
3 Post Implementation Review
In 2014, the AESO conducted a post redesign implementation review. The purpose of this review is to
assess the redesigned operating reserve market against the original redesign goals, enhance the
understanding of the redesigned OR market and help identify potential areas for further improvement.
3.1
Assessing the OR Market Against the Redesign Objectives
The key objectives set out in the Revised Recommendation paper were:

Reducing AESO influence in the market

Improving market transparency

Creating better alignment with the energy market

Simplifying the design
3.1.1
12
Reduced AESO Influence in the OR Market
As part of the OR market redesign, the AESO ceased the practice of actively changing active OR bid
prices. The bid prices posted by the AESO became more stable. Since the trade price of the active OR is
set at the mid-point between the AESO’s bid price and the offer price associated with the volume that
clears the active OR market, more stable bids posted by the AESO reduced its influence on the day-today active OR trade prices.
The elimination of multi-day trading also removed the chances of the AESO varying daily bid volume and
price of the OR products for the same delivery day. As a result, the total procurement volume of a specific
OR product on each trading day is determined by the forecasted OR requirements, and is not influenced
by the AESO’s trading strategy. The elimination of multi-day trading also reduced the chances of cash
12
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P1.
Page 4
flow asymmetry of the Hydro PPA because with only one trading day, the Watt-Ex trade index and the
13
Watt-Ex trade price became identical.
For standby OR the AESO ceased posting premium and activation prices and implemented a ‘blended
approach’ to create a single bid price based on which the AESO selects standby OR volume. With this
approach, the chances of standby OR prices being influenced by the selection process used by the
AESO was removed.
3.1.2
Improved Market Transparency
Prior to the OR market redesign, the trade volume and the price of OR products, and the activation rate of
standby OR were not published by the AESO. However, these are important indicators that offer
transparency to the OR market and help market participants understand the dynamics of OR trading. The
implementation of the Active Operating Reserve Price Report and the Standby Operating Reserve Price
Report allowed OR market participants and observers to obtain the most up-to-date trading information to
aid their analysis and business decision making.
The adoption of the procurement practice in which the AESO posts bid prices and volumes of active OR
well ahead of the close of trading sessions provided transparency with respect to the volume that the
AESO plans to procure and the maximum price that the AESO is willing to pay, and allowed sellers to
respond to the information. The implementation of a consistent and transparent market clearing process
for standby OR provided the market with a clear indication on how to compare the competitiveness of
offer prices, thus focusing competition between sellers on a clearly defined price.
3.1.3
Created Better Alignment with the Energy Market
The OR market redesign addressed the issue of misalignment with the energy market by aligning OR
costs with hourly energy consumption so that the deferral account rider amounts could be minimized. As
part of the 2010 Tariff Application, the AESO consulted with the industry on deferral account riders and
the reconciliation process with the intention of better aligning OR costs with hourly energy consumption.
Since July 2011, the ISO Tariff has allocated hourly OR costs based on metered load consumption for the
same hour. This change significantly reduced the deferral account rider amounts caused by OR costs
(Figure 1). The reduction of the deferral account rider amounts provides loads with better information on
their OR costs. However, the AESO did not implement a real time OR market that aligns with the energy
market in which the energy offers ‘lockdown’ at two hours before the delivery hour (the T-2 energy
14
market), as the AESO considered it as a longer term solution to the existing design.
13
14
With the exception of RR in the ‘super peak’ hours of which there are two trade prices.
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P18.
Page 5
Figure 1: Deferral Account Rider Amounts Attributed to OR
Charge
$3.00
Charge and Refund ($/MWh)
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
-$0.50
Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2010 2011 2011 2011 2011 2012 2012 2012 2012 2013 2013 2013 2013 2014 2014 2014
-$1.00
-$1.50
Refund
3.1.4
Simplified the Design
Compared with the original design (Figure 2), the current OR market design is notably simplified (Figure
3). The elimination of multi-day trading and ceasing the use of OTC as a daily trading platform greatly
reduced the complexity of pricing and the procurement process.
Overall, the OR market re-design achieved the objectives of reducing the AESO influence in the market,
improving market transparency and simplifying the design. The AESO considers that aligning the OR
market with the T-2 energy market is a longer term design solution and requires further analysis and
stakeholder process.
Page 6
Figure 2: OR Market Structure Pre-Redesign Implementation
OR Procurement (forecast OR volume)
OTC
Standardized instruments
On-peak regulating
On-peak spinning
On-peak supplemental
Off-peak regulating
Off-peak spinning
Off-peak supplemental
Shaped instruments
Regulating
Spinning
Supplemental
Watt-Ex
Standardized instruments
On-peak regulating
On-peak spinning
On-peak supplemental
Off-peak regulating
Off-peak spinning
Off-peak supplemental
Standby OR
Selection not
transparent
Pay as Bid
D-1
D-1
Active OR
Selection not
transparent
Pay as Bid
D-1
D-2
D-3
D-4
Standby OR
Selection not
transparent
Pay as Bid
D-5
D-1
D-2
D-3
D-4
D-5
Monthly
Active OR
Selection process
transparent
Uniform pricing
Figure 3: OR Market Structure Post-Redesign Implementation
OR Procurement (forecast OR volume)
Watt-Ex
Standardized instruments
Super peak AM regulating
Super peak PM regulating
On-peak regulating
On-peak spinning
On-peak supplemental
Off-peak regulating
Off-peak spinning
Off-peak supplemental
Standby OR
Selection process
transparent
Pay as Bid
Active OR
Selection process
transparent
Uniform pricing
D-1
3.2
3.2.1
D-1
Assessing the Post-Redesign OR Market Using Market Metrics
OR Supply and Demand
Page 7
The simplified OR market design encouraged participation in the OR market. Compared with 2009, both
the number of participants and the total qualified capacity increased (Table 1). All of the increased
qualified OR capacities are from new participants in the OR market.
Table 1: Number of Participants and Qualified Capacity in the OR Market
Number of Participants
Qualified Capacity (MW)
Regulating Reserve
Spinning Reserve
Supplemental Reserve
2009
18
2012
23
June 2014
26
1710
3066
3263
1765
3131
3332
1765
3205
3651
While more participants and more qualified OR capacity entered to the OR Market, there was no increase
in the average hourly procurement volume until 2012, when a moderate increase (Figure 4) in the active
OR procurement volume occurred. This increase was mainly due to the fact that, starting August 2011,
OTC ceased to be a daily trading platform for OR procurement and that all OR procurement was
consolidated to Watt-Ex using higher block purchase volumes.
Figure 4: Average Hourly Procurement of Active OR
300
250
MW
200
150
100
50
0
2009
2010
2011
RR
2012
SR
2013
YTD Oct 2014
SUP
Prior to OTC ceasing to be a daily trade platform in December 2011, approximately 90% of the OR
volume was procured through Watt-Ex. Figure 5 is the average hourly supply cushion (the offered volume
not procured) on Watt-Ex. It can be seen that in 2012 and 2013, there were obvious increases in the
supply cushion across all three active OR products after all the OR procurement volumes were
consolidated to Watt-Ex. Although the supply cushions dropped in the first ten months of 2014, they
remained higher than the levels seen in 2009 - 2011.
Page 8
Figure 5: Average Hourly Supply Cushion of Active OR
400
350
300
MW
250
200
150
100
50
0
2009
2010
2011
RR
2012
SR
2013
YTD Oct 2014
SUP
The creation of the AM and PM Super Peak Active RR products in August 2011 made it possible to
reduce standby RR procurement volume. Figure 6 shows that, compared with 2009 and 2010, the
average hourly standby RR procurement volume has been lower since 2011, while the average hourly
standby SR and standby SUP procurement volumes remained flat.
Figure 6: Average Hourly Procurement of Standby OR
140
120
100
MW
80
60
40
20
0
2009
2010
2011
RR
2012
SR
Page 9
SUP
2013
YTD Oct 2014
With the implementation of the ‘blended approach’ in the standby OR selection, the AESO now is able to
compile more accurate standby OR supply cushion data. Figure 7 indicates greater supply cushions in
the standby OR market since 2012.
Figure 7: Average Hourly Supply Cushion of Standby OR
600
500
MW
400
300
200
100
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Jan-12
Feb-12
Mar-12
Apr-12
May-12
Jun-12
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
Oct-14
0
RR
SR
SUP
In the past 5 years, the qualified capacity increased more than the active OR procurement volume. In
addition, standby RR procurement volume dropped and the standby SR and standby SUP volumes
remained flat. The supply and demand balance became more relaxed in the OR Market.
3.2.2
Total Cost of OR Procurement
15
However, the more relaxed supply and demand balance in the OR Market did not result in lower OR
procurement cost. As shown in Figure 8, the OR procurement costs increased across the board in the
post redesign period. While the post redesigned OR Market achieved the objectives of simplifying the
market, increasing transparency, and reducing influence from the AESO, the OR procurement cost
increased.
15
The 2014 year-to-date costs only include the first ten months of 2014.
Page 10
Figure 8: Total OR Procurement Cost
$400
$350
Million $
$300
$250
$200
$150
$100
$50
$0
2009
2010
2011
2012
2013
YTD Oct 2014
Total OR Procurement Cost
The total OR procurement cost consists of three parts: the active OR cost, the standby OR premium cost
and standby OR activation cost.
Figure 9 shows that the active OR procurement cost between 2011 and 2013 were substantially higher
than the previous years. The active OR procurement cost in the first ten months of 2014 has already
surpassed the annual active OR procurement costs in 2009 and 2010 but are tracking below 2011
through 2013 costs.
Page 11
Figure 9: Active OR Procurement Cost
400
350
300
Million $
250
200
150
100
50
0
2009
2010
2011
2012
2013
YTD Oct 2014
Procurement Cost of Active OR
An obvious increase in standby OR premium costs occurred in 2012. In 2013, while standby OR
premiums decreased from the 2012 level, both the premium and the activation costs of standby OR were
higher than in 2009-2011. (Figure10).
Figure 10: Standby OR Premium and Activation Cost
30
25
Millions $
20
15
10
5
0
2009
2010
2011
Premium
3.2.3
Unit Cost of OR Procurement
Page 12
2012
Activation
2013
YTD Oct 2014
Since there was no significant increase in the procurement volume, higher total procurement costs
observed in 2011 – 2013 were primarily due to higher unit costs (per MW cost), particularly higher unit
costs of the active OR. Figure 11 shows that the unit costs of active and standby OR. It can be seen that
the unit costs of active OR were significantly higher in the 2011 through 2013 period but are trending
down in 2014.
Figure 11: Unit Cost of OR
70.00
60.00
$/MWh
50.00
40.00
30.00
20.00
10.00
0.00
Active RR
Active SR
2009
2010
Active SUP
2011
2012
Standby RR
2013
Standby SR
Standby SUP
YTD Oct 2014
Due to the difference in OR payment structures, the elements that directly influence the unit costs of
active OR and standby OR are different. The active OR providers are paid max [0, (pool price + trade
price)]. As a result, the unit cost is directly influenced by the pool price and the trade price. In contrast, the
standby OR providers are paid a premium and, if activated, also an activation price. Therefore, the unit
cost of standby OR is directly influenced by the premium, the activation price and the activation rate.

Active OR unit cost and the pool price
One factor that directly influences the unit cost of the active OR is the pool price. Figure 12 is a plot of
the unit cost of active OR cost and the pool price. It is evident that the change in the unit cost of
active OR tracks the movement of the pool price.
Page 13
Figure 12: Active OR Unit Cost Influenced by Pool Price
90.00
80.00
70.00
$/MWh
60.00
50.00
40.00
30.00
20.00
10.00
0.00
2009
2010
RR

2011
SR
2012
SUP
2013
YTD Oct 2014
Pool Price
Active OR unit cost and the trade price
The other component of the active OR unit cost comes from the trade price. Figure 13 adds the
average active OR trade price to the active OR unit cost and the pool price graph. However, the
change in OR unit cost did not track trade price change as well as it tracked the pool price change. It
appears that the pool price has been the main driver of the active OR unit cost.
Page 14
Figure 13: Active OR Unit Cost Influenced by Trade Price
100.00
80.00
60.00
40.00
$/MWh
20.00
0.00
2009
2010
2011
2012
2013
RR Trade Price
YTD Oct 2014
-20.00
-40.00
-60.00
-80.00
-100.00

RR Unit Cost
SR Unit Cost
SUP Unit Cost
SR Trade Price
SUP Trade Price
Pool Price
Standby OR unit cost influenced by unit premium and unit activation payments
The change in standby OR unit cost was predominately driven by the standby premium payment.
Figure 14 and Figure 15 show that standby OR unit cost tracked the movement of the standby OR
premium payment more closely than it tracked the movement of the activation payment.
Figure 14: Standby OR Unit Cost and Premium Payment Per MWh Procured
$18.00
$16.00
$14.00
$/MWh
$12.00
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
2009
RR Premium Cost
2010
SR Premium Cost
2011
SUP Premium Cost
Page 15
2012
RR Unit Cost
2013
SR Unit Cost
YTD Oct 2014
SUP Unit Cost
Figure 15: Standby OR Unit Cost and Activation Payment Per MWh Procured
$18.00
$16.00
$14.00
$/MWh
$12.00
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
2009
RR Activation Cost
2010
2011
SR Activation Cost
2012
SUP Activation Cost
2013
RR Unit Cost
SR Unit Cost
YTD Oct 2014
SUP Unit Cost
If the ‘blended approach’ is used to estimate and compare the ‘blended’ price of standby OR, the data
suggest that the ‘blended’ prices of all three products in 2012 exceeded the levels seen in the
previous 3 years (Figure 16). Although the blended prices dropped in 2013, they remained at levels
higher than 2009 and 2010. In 2014, the ‘blended’ prices have been in line with the pre-redesign
16
period.
Figure 16: Standby OR ‘Blended’ Price
$25.00
$90.00
$20.00
$70.00
$60.00
$15.00
$50.00
$40.00
$10.00
$30.00
$20.00
$5.00
$10.00
$0.00
$0.00
2009
2010
2011
RR
3.2.4
SR
2012
SUP
2013
Pool Price
Observations from the OR Market metrics
Several observations are obtained from analyzing OR market metrics.
16
Based on January 1, 2014 – October 31, 2014 data.
Page 16
YTD Oct 2014
Pool Price ($/MWh)
Standby OR 'Blended Price' ($MWh)
$80.00

The post redesign OR market did not naturally lead to a lower OR trade price
Although the post redesigned OR market attracted more participants and increased the qualified OR
capacity, the redesign did not naturally lead to a lower OR trade price. This is because in addition to
the volume offered and procured (supply and demand), the OR trade price is also influenced by other
factors, such as the opportunity cost of providing OR products, the AESO’s bid (in the case of active
OR) and the sellers offer behavior. The opportunity cost of providing OR products, in particular, is
driven by factors external to the introduced OR market redesign changes. This is discussed further
below.
o
Active OR
Capacity sold to the AESO to provide active OR forgoes the opportunity of participating in the
energy market. Therefore, the opportunity cost of providing active OR is the forgone energy
market profit. Since the sellers of active OR receive a trade price indexed to the pool price, as
long as the sum of the trade price and the pool price is greater than the difference between the
pool price and the dispatch cost to produce energy, the opportunity cost of providing active OR is
17
compensated by the OR payment. Typically, the energy dispatch cost is lower when fuel cost is
lower and lower dispatch cost means higher opportunity cost of providing active OR for a given
pool price. The opposite is also true. Therefore, a unit is expected to submit higher offer price in
the active OR market when the fuel cost is lower, and to submit lower offer price when the fuel
18
price is higher. Figure 17 depicts the relationship between active OR trade price and fuel cost. It
can be seen that in most years, there is an inverse relationship between active trade price and
fuel cost.
17
The exception is RR, of which the opportunity cost (or additional profit) also includes the possible loss when pool price is lower
than energy dispatch cost or the possible extra energy revenue when pool price is higher than fuel cost during load following.
18
Suppose a gas unit has a heat rate of 10 and a non-fuel variable cost of $5/MWh. If the gas price is $8/Gj, the unit’s dispatch cost
to produce energy is $8 X 10 + $5 = $85. In the energy market, the unit will get paid max (pool price - $85, $0). Therefore, it has to
offer $-85 or higher in the active OR to ensure that it’s not worse off providing active OR than producing energy. However, if the gas
price is $4/Gj, the unit’s dispatch cost to produce energy becomes $4 X 10 + $5 = $45. The unit would have to raise the offer price
to at least $-45 to ensure that it’s not worse off providing active OR than producing energy. If this unit clears the market and the
AESO’s bid price for the active OR is $40, with the gas price of $8/Gj, the trade price is ($40 - $85)/2 = -$22.5; with the gas price of
$4/Gj, the trade price is ($40 - $40)/2 = $0.
Page 17
Figure 17: Active OR Trade Price vs. Fuel Cost
$60.00
$40.00
$20.00
$/MWh
$0.00
2009
2010
2011
2012
2013
YTD Oct 2014
($20.00)
($40.00)
($60.00)
($80.00)
($100.00)
RR Trade Price
SR Trade price
SUP Trade price
8 Heat Rate Fuel Cost
9 Heat Rate Fuel Cost
10 Heat Rate Fuel Cost
11 Heat Rate Fuel Cost
12 Heat Rate Fuel Cost
The opportunity cost of providing active OR can also be illustrated by plotting the unit costs of
active OR procurement against the potential dispatch cost of gas-fired generating units in the
energy market. Figure 18 shows that the change in unit costs of active OR procurement and gas
generator dispatch costs are highly correlated. As increasing dispatch costs were essentially
exogenous to the introduced changes in OR procurement practices, this is indicative that much of
the increase in OR prices observed in the 2011 through 2013 period was not due to the
implementation of the OR market changes.
Page 18
Figure 18: Active OR Unit Cost vs Gas Unit Dispatch Cost
$70.00
$60.00
$50.00
$40.00
$30.00
$20.00
$10.00
$0.00
2009
2010
2011
2012
2013
YTD Oct 2014
($10.00)
o
Active RR
Active SR
Active SUP
10 Heat Rate Fuel Cost
11 Heat Rate Fuel Cost
12 Heat Rate Fuel Cost
Standby OR
Standby OR does not have to forgo the opportunity to participate in the energy market unless it is
activated. When a standby OR product is activated, the seller receives the activation price and
forgoes the pool price. Therefore, a higher expected pool price is one factor that causes sellers to
increase the ‘blended’ price by either increasing the premium or the activation price. Figure 16 in
3.2.3 shows that the ‘blended’ price of standby OR was moderately correlated with pool price
during the review period.

SR price higher than RR
The OR market metrics revealed that, with the exception of 2009, the average trade price of the
active SR was higher than that of active RR (Figure 13 in section 3.2.3), and that the ‘blended’ price
of standby SR was higher than that of standby RR between 2008 and 2014 (Figure 16 in section
3.2.3). This suggests a potential opportunity for the AESO to increase the procurement volume of RR
to replace the SR required.

Higher-than-actual activation rates used in ‘blended’ price calculation
The analysis of standby activation rates revealed that the activation rates currently used to calculate
the ‘blended’ price are higher than the recent historical averages across all standby OR products
(Table 2).
Page 19
Table 2: Actual Standby Activation Rate vs. Activation Rate Used in ‘Blended’ Price Calculation
Average 2009YTD Oct 2014
Activation
Rate in
‘Blended’
Price
Calculation
2009
2010
2011
2012
2013
YTD Oct
2014
Off-Peak RR
1.0%
0.8%
1.1%
1.0%
2.2%
1.7%
1.2%
On-Peak RR
0.5%
0.2%
0.3%
0.5%
1.1%
0.9%
0.5%
1%
Off-Peak SR
2.3%
3.4%
2.2%
3.7%
5.5%
3.8%
3.4%
10%
On-Peak SR
4.5%
5.9%
4.1%
4.5%
5.5%
4.6%
4.9%
10%
Off-Peak SP
4.8%
3.1%
2.2%
4.7%
5.3%
4.7%
4.0%
10%
On-Peak SP
5.1%
5.7%
4.8%
3.7%
3.2%
4.1%
4.5%
10%
3%
Using a higher than actual activation rate for standby OR selection likely has incented sellers to use
the combination of a higher premium and a lower activation price in order to achieve the desired
payment while maximizing the chances of being selected. By offering a combination of higher
premium and lower activation price the ‘blended’ price appears to be lower and more competitive than
the combination of a lower premium and higher activation price, and therefore increases the chance
of being selected.
For example, if the actual activation rate is 5%, a seller who is willing to provide standby OR for $15
can either offer at $10/MW premium and $100/MWh activation price, or at a $5/MW premium and
$200/MWh activation price. If the activation rate in the ‘blended price’ calculation is 6% (higher than
the actual activation rate of 5%), the ‘blended price’ of $10/MW premium and $100/MWh activation
price is $16/MWh ($10 + $100 x 6%), lower than the ‘blended price’ of $5/MW premium and
$200/MWh activation price, which is $17/MWh ($5 + $200 x 6%). . If the activation rate in the ‘blended
price’ calculation is 4% (lower than the actual activation rate of 5%), the ‘blended price’ of $10/MW
premium and $100/MWh activation price is $14/MWh ($10 + $100 x 4%), higher than the ‘blended
price’ of $5/MW premium and $200/MWh activation price, which is $13/MWh ($5 + $200 x 4%).
Figure 19 shows that a drastic increase in standby premium occurred after the ‘blended approach’
was implemented in August 2011.
Page 20
Figure 19: Monthly Average Standby Premium 2010 – 2012
$45.00
$40.00
$35.00
Implementation of the
'blended approach'
$/MWh
$30.00
$25.00
$20.00
$15.00
$10.00
$5.00
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Jan-12
Feb-12
Mar-12
Apr-12
May-12
Jun-12
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
Oct-14
$0.00
Off-Peak RR
On-Peak RR
Off-Peak SR
On-Peak SR
Off-Peak SUP
On-Peak SUP
In summary, the OR market metrics show that despite an increased supply cushion in both the active and
standby OR market, OR procurement costs increased after the OR redesign implementation. The active
OR procurement costs are impacted mainly by the pool price, and the trade price typically moves in the
opposite direction of the gas price. The increase in standby OR procurement costs are mostly driven by
higher premiums of the standby OR. Thus, much of the increase in OR costs since the OR market
changes were made is likely due to higher pool prices and spark spreads during this period. The OR
market metrics revealed that over the past 5 years the trade price of SR was consistently higher than that
of RR. The OR market metrics further identified that the activation rate used in the ‘blended price’
calculation are higher than the actual activation rates and might have caused sellers to prefer offering
higher premiums.
3.3
Assessing Unimplemented Recommendations
From July 2010 to December 2011, the AESO implemented the majority of the recommendations
proposed in the Revised Recommendation Paper. However, a few recommendations were not
implemented. Some recommendations were not implemented because they were not expected to yield
19
efficient outcomes. Some recommendations were replaced with different initiatives that helped achieve
20
the same redesign objectives. The remaining unimplemented recommendations are assessed below:

The AESO posts un-priced volume requirement and OR price is capped at the energy price cap in
active OR procurement.
This pricing mechanism differs from the one currently implemented in that, without a bid price, the
active OR trade price cannot be set at the midpoint between the bid price and the highest offer price
that clears the market. Therefore, the trade prices of active OR products would be set at the highest
offer price that clears the market.
19
For example, during the consultation, it was agreed that the recommendation of removing virtual units should not implemented.
See AESO OR Market Redesign Revised Recommendation Paper Stakeholder Comment Matrix May 27, 2010.
20
One such recommendation is creating hourly OR instruments. A revised format is to create AM and PM super peak active RR and
increase the block purchase of SR and SUP.
Page 21
If the active OR market is sufficiently competitive, there would be minimal difference between the
trade price calculated by taking the midpoint between the bid price and the marginal offer price or
simply the marginal offer price because competition in the market will drive the trade price to
converge on the opportunity cost of the marginal unit that clears the active OR market. If the market
lacks supplier-on-supplier competition, the AESO’s inclusion of a bid price provides some safe guard
against possible market power in the OR market.
Given that the AESO currently posts stable and transparent bid prices that are sufficiently higher
than the opportunity cost of providing active OR to avoid the interference of the daily OR market,
further changes to the active OR pricing scheme are not considered necessary at the present time.

Allow for flexible and inflexible offers
21
Partial contracting may occur to an offer block during OR trading when the block happens to be the
marginal block that clears the market and only part of the volume from the offered block is selected.
If the block is inflexible to provide the partially selected block, the seller cannot fulfill the contract
obligation. Some sellers have expressed that the reason that they do not offer particular units is
because of the possibility that the inflexible block of the unit will be only partially contracted. In the
Revised Recommendation Paper, the AESO recommended allowing sellers to designate their offer
blocks as an ‘inflexible block’ and “if the OR offer is only partially required, and the seller has
22
designated it as inflexible, the offer will be skipped”.
Over the past few years, the OR market has seen an increased number of participants, higher
qualified OR capacity, and a more relaxed OR market supply cushion. This suggests that not being
able to identify an ‘inflexible block’ in the OR procurement has not been an undue barrier which has
prevented qualified OR capacity from participating in the OR market. Therefore, changing the current
market clearing algorithm for the purpose of accommodating the offers from inflexible blocks does
not seem warranted at this time and the AESO is not currently intending to implement this change.

Facilitate third party asset substitution
The purpose of allowing third-party asset substitution is to provide the sellers with a venue to ‘buy
out of’ the OR position and to physically hedge operational risks such as unexpected outages at the
units that are contracted to provide OR.
The AESO has examined the feasibility of third party asset substitution and identified a few issues:
21
22
o
The implementation of third party asset substitutions needs to ensure confidentiality of sellers’
information and therefore requires significant change to the AESO’s information system.
o
Third party asset substitution essentially forms a secondary bilateral OR market, which adds
complexity to the existing OR market, i.e. it adds a secondary OR market and changes the
centralized nature of OR procurement. First, this is a deviation from the original OR market
redesign objective of simplifying the market. Secondly, since when encountering unexpected
outages, the sellers have the option to declare force majeure and are only subject to the ‘clawback’ calculated based on the day-ahead trade price, purchasing third party substitution only
makes sense if the cost of third party substitution is lower than the ‘claw-back’. However, if the
third party asset is willing to provide OR at a lower price than the day-ahead trade price based
on which the ‘claw-back’ is calculated, the third party’s asset is likely to have already been
selected in the day-ahead market. Therefore, it is unlikely that the secondary OR market is very
liquid. Thirdly, OR products are ‘system products’ and the total demand of the products are
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P9.
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P9.
Page 22
centrally determined by the AESO based on reliability standards. Implementing a bilateral
market, i.e. a decentralized mechanism, to procure OR may require other changes to the
current OR market design to ensure that the procurement obligation of individual buyer has to
be fulfilled.
The AESO does not anticipate that implementing third party asset substitution will create a liquid
enough secondary OR market that results in less frequent standby OR activation or justifies the cost
to change the AESO’s existing information system. Therefore, the AESO does not plan to implement
this recommendation without further analyzing under what conditions the third party asset
substitution is beneficial to the overall market and what further market design change it might entail.

Provide clarity around acceptable/unacceptable behavior and potential consequences
In the Revised Recommendation paper, the AESO identified that the existing liquidated damages
“can incent perverse behavior or price arbitrage” and that there is “a lack of clarity around what is
23
permissible versus non-permissible behavior”.
If the liquidated damage scheme incents price arbitrage, it essentially turns OR, which are reliability
products by nature, into financial-like products. The lack of physical commitment of reliability services
is not desirable for system reliability. Therefore, the AESO is of the view that the liquidated damages
should be imposed in such a way to remove the incentive of price arbitrage or at least high enough
to fully cover the additional cost caused by contract non-compliance.
In summary, based on assessment of the unimplemented recommendations, the AESO believes that the
practice of posting bid price in the procurement of active OR should be continued. The AESO is not
convinced that the Watt-Ex clearing algorithm should be changed to accommodate the sale of inflexible
blocks or a secondary OR market should be established at this time. The AESO is of view that liquidated
damages that remove or reduce the incentive of price arbitrage should be enforced.
4 Next Steps
Given the fact that the OR market redesign achieved the objectives of reducing AESO influence in the
market, improving market transparency and simplifying the design set out in the Revised
Recommendation Paper, the AESO’s immediate focus will be on continuously identifying areas where
adjustments can be made to improve the price signal and reduce perverse incentives. In the near term,
the AESO will focus on making improvements to the OR market in the following areas:

Examining the merit and feasibility of allowing one reserve product to be replaced by a higher
“standard” product during procurement if the trade price of the higher standard product is lower. For
example, SR might be replaced by RR during procurement if the trade price of RR is lower than SR.
Alternatively, non-contracted offered volumes of RR could potentially be included in the supply stack
for SR.

Adopting activation rates that better reflect the actual activation rates in the standby OR ‘blended
price’ calculation
In the longer term, changes in the electric system and resource mix may require further evolution of the
OR market and the OR product mix. Further changes to the OR market, including the outstanding
objective of aligning OR market with the T-2 energy market and third party asset substitute will be
examined from the perspective of promoting the efficient and reliable operation of the system through a
fair, efficient and openly competitive OR market, and in conjuncture of other market initiatives, such as
23
The AESO, Revised AESO Recommendation Paper – Operating Reserves Market Redesign, March 2010, P13.
Page 23
wind integration, intertie restoration and energy storage integration. Any potential changes to the OR
market will be consulted on as they are identified.
Page 24
Appendix I: Market Clearing and Pricing Mechanisms on
Watt-Ex and the OTC
Prior to the OR market redesign, the OR products were procured through two different mechanisms,
through the Watt-Ex exchange platform and bi-laterally through over the counter (OTC) transactions.
These two methods used different market clearing and pricing mechanisms.

Watt-Ex Platform
On Watt-Ex, the active OR used a market clearing process that simultaneously equated supply and
demand to establish a uniform trade price. During the trading session of each active OR product, the
sellers posted offer prices and volumes and the AESO posted bid prices and volumes. At the end of the
trading session, the offers were ranked according to the offer prices, and the volume with the lowest offer
price was selected first until all bid volumes were cleared or until the offer price reached the bid price. For
active OR product, there was a uniform trade price, i.e. the market clearing price set at the mid-point
between the AESO’s bid price and the offer price of the asset that cleared the market. All the sellers who
were selected in the OR procurement and subsequently fulfilled the OR obligation would receive the
same payment equal to the maximum of 0 and the sum of the pool price and the trade price (Exhibit 1).
This market clearing and pricing mechanism for active OR is still used in under the current OR market
design.
Exhibit 1
Active OR Market Clearing and Pricing on Watt-Ex
Suppose the AESO bids 100 MW for an active OR product and there are five sellers in the market, and the bid and
offers are as follows:
Bid
Volume (MW)
AESO
Seller One
Seller Two
Seller Three
Seller Four
Seller Five
Offer
Volume (MW)
Price ($/MWh)
100
Price ($/MWh)
-50
25
20
25
35
10
-800
-200
-150
-100
-60
The market clearing process occurs at the end of the trading session of this active OR product. A total of 100 MW are
selected as follows:
25 MW is selected from Seller One
20 MW is selected from Seller Two
25 MW is selected from Seller Three
30 MW is selected from Seller Four
Therefore, the offer from Seller Four clears the market. Since the AESO’s bid price is -50 and the offer price
associated with the last MW that clears the market is -100, the trade price is set at $ (-50 – 100)/2 = - $75, which is
the mid-point between the AESO’s bid price and Seller Four’s offer price.
If in the delivery hour the pool price is $80/MWh, all four active OR providers receive $5/MWh for the volume provided
(max(0, (80-75))=$5. If the pool price is $70/MWh, they will receive nothing (max(0, (70-75)=$0).
Key takeaway:
All successful active operating reserve sellers on Watt-Ex are paid a uniform trade price indexed to the pool
price.
With standby operating reserve traded on Watt-Ex, the sellers posted offers and the AESO posted bids.
Both the offers and the bids consisted of a premium and an activation price. The standby operating
reserve volume could only be procured when either a seller’s offer was lifted by the AESO or the AESO’s
bid was hit by a seller, i.e. the price of the product was agreed upon between a seller and the AESO. The
market clearing is a continuous ‘pick’ process, not one that simultaneously equates supply with demand.
Page 25
In addition, there was no uniform price established. Depending on what actions the AESO and the sellers
took and how the AESO selected the sellers, the price outcomes could be different (Exhibit 2). Successful
sellers of the standby operating reserve were paid their individual bid prices (the ‘pay-as-bid’ price). They
were paid the premium for all the hours included in the operating reserve product. If the volume is
activated in real time, the sellers were also paid the activation price during the hours when the volume
was activated. This market clearing process was replaced by the ‘blended’ approach during the OR
market redesign.
Exhibit 2
A Few Scenarios of Standby OR Market Clearing and Pricing on Watt-Ex
Suppose the AESO bids for 50 MW of an on-peak standby operating reserve and there are two sellers in the market,
and the bid and offers are as follows:
Bid
Volume
(MW)
AESO
Seller One
Seller Two
Premium
($/MWh)
50
Offer
Volume
(MW)
Activation Price
($/MWh)
5
Premium
($/MWh)
Activation Price
($/MWh)
80
25
30
7
2.5
100
150
Scenario 1: No agreement in prices
If there is no change in these bids and offers, i.e. there is no agreement in prices, no volume will be procured.
Scenario 2: AESO’s bid is hit by Seller One
If before the trade session closes, Seller One hits the AESO’s bid by altering the offer premium to $5/MWh and
activation price to $80/MWh but Seller Two maintains its offer, 25 MW will procured from Seller One and Seller One will
be paid $5/MWh premium in every hour of the 16 on-peak hours covered by the on-peak contract and $80/MWh
activation price in the hours of activation.
Scenario 3: Seller One’s offer is lifted by the AESO
If before the trade session closes, the AESO lifts the offer from Seller One by altering the bid premium to $7/MWh and
the activation price to $100/MWh, 25 MW will be procured from Seller One and Seller One will be paid $7/MWh
premium in every hour of the 16 on-peak hours covered by the on-peak contract and $100/MWh activation price in the
hours of activation.
Scenario 4: Seller Two’s offer is lifted by the AESO
If before the trade session t closes, the AESO lifts the offer from Seller Two by altering the bid premium to $2.5/MWh
and the activation price to $150/MWh, 30 MW will be procured from Seller two and Seller Two will be paid $2.5/MWh
premium in every hour of the 16 on-peak hours covered by the on-peak contract and $150/MWh activation price in the
hours of activation.
Scenario 5: The AESO and the Sellers move towards each other
Suppose the AESO splits the original bid into two bids: 25 MW with a premium of $6/MWh and an activation price of
$90/MWh; and 25 MW with a premium of $2/MWh and an activation price of $120/MWh. If Seller One hits the bid of
$6/MWh premium and $90/MWh activation price, and Seller Two hits the bid of $2/MWh premium and $120/MWh
activation price, all 50 MW will be procured. Seller One will be paid $6/MWh premium in every hour of the 16 on-peak
hours covered by the on-peak contract and $90/MWh activation price in the hours of activation. Seller Two will be paid
$2/MWh premium in every hour of the 16 on-peak hours covered by the on-peak contract and $120/MWh activation
price in the hours of activation.
Key takeaway:
Depending on the specific actions the AESO or the sellers took, the price outcome could be different and each
individual seller was paid the price he or she offered at.

The OTC Platform
After the Watt-Ex procurement was completed, the remaining OR volumes required were solicited by the
AESO via email. The AESO selected the volume from the participants who responded to the email.
Successful sellers of each product received their individual offer price. Neither the selection process nor
the procurement prices were visible to the market at the time of procurement or after the procurement. As
part of the OR market redesign, the AESO ceased using the OTC as a daily procurement platform.
Page 26
Appendix II: Multiple Trade Prices of the Same Active OR
Product of the Same Delivery Day
In the pre-redesigned OR market, the same active OR product of the same delivery day may have
multiple trade prices on different trading days:
Exhibit 3
Multiple Trade Prices of the Same Active OR Product of the Same Delivery Day – Assuming Two
Trading Days
Suppose the AESO needs to procure a total 250 MW of an active OR product for the delivery day D.
On D-2 the AESO bids 100 MW and there are five sellers in the market and the bid and offers are as follows:
Bid
Volume (MW)
AESO
Seller One
Seller Two
Seller Three
Seller Four
Seller Five
Offer
Volume (MW)
Price ($/MWh)
100
Price ($/MWh)
-50
25
20
25
35
10
-800
-200
-150
-100
-60
Therefore, a total of 100 MW are selected as follows:
25 MW is selected from Seller One
20 MW is selected from Seller Two
25 MW is selected from Seller Three
30 MW is selected from Seller Four
The resulting D-2 traded volume is 100 MW, the D-2 trade price is (-50 – 100)/2 = - $75, and the volume to be
procured on the remaining trading day is 150 MW.
On D-1 the AESO bids 150 MW and there are six sellers in the market and the bid and offers are as follows:
Bid
Volume (MW)
AESO
Seller One
Seller Two
Seller Three
Seller Four
Seller Five
Seller Six
Offer
Volume (MW)
Price ($/MWh)
150
Price ($/MWh)
-50
25
20
25
35
10
45
-800
-200
-150
-100
-60
-20
Therefore, a total of 150 MW are selected as follows:
25 MW is selected from Seller One
20 MW is selected from Seller Two
25 MW is selected from Seller Three
35 MW is selected from Seller Four
10 MW is selected from Seller Five
35 MW is selected from Seller Six
The D-1 trade price is (-50 – 20)/2 = - $35. Using the volume weighted average, it can be calculated that the Watt-Ex
index is [(-75)*100 + (-35)*150]/250 = - $51, which is different from any of the trade prices.
Key takeaway:
The same multi-day trading yields different trade prices for the same OR product of the same delivery day.
Page 27