The document provides an overview and updates from a Market Performance and Planning Forum held on December 7, 2016. It includes: 1) A review of key market performance topics such as a November 9 frequency deviation event, adjustment to regulation capacity requirements, and an update on the new Flexible Ramping Product. 2) Sharing of updates to 2016 release plans based on stakeholder input and information on initiatives to support market participants. 3) A focus on implementation planning timelines and discussing external impacts, as well as launching a joint implementation planning process. The agenda includes presentations on specific topics such as real-time transfer limit increases, the November 9 event, market performance and quality, and details on

1. Market Performance and Planning
Forum
December 7, 2016

2. Objective: Enable dialogue on implementation
planning and market performance issues
• Review key market performance topics
• Share updates to 2016 release plans, resulting from
stakeholders inputs
• Provide information on specific initiatives
–to support Market Participants in budget and
resource planning
• Focus on implementation planning; not on policy
• Clarify implementation timelines
• Discuss external impacts of implementation plans
• Launch joint implementation planning process
Slide 2

3. Market Performance and Planning Forum
Agenda – December 7, 2016
12:00 – 1:00 Lunch
1:00 – 1:30 Market Results – PSE and APS
Integration Gabe Murtaugh
1:30 – 2:00 Policy Update Brad Cooper
2:00 – 3:00 • Release Update
• Annual Functional Release Lifecycle
Janet Morris
Time: Topic: Presenter:
10:00 – 10:05 Introduction, Agenda Kristina Osborne
10:05 – 10:20 Real-Time Transfer Limit Increases Danny Johnson
10:20 – 10:45 November 9 Frequency Deviation Event John Phipps
10:45 – 12:00 Market Performance and Quality Update Guillermo Bautista Alderete
Warren Katzenstein
Amber Motley
Slide 3

4. Real-Time Transfer Limit Increases
Danny Johnson
Sr. Operations Engineer, Operations Planning - South
Slide 4

5. Increase Transfer Capability on WECC Paths
Slide 5

6. Aliso Canyon Authority
• CAISO received authority to “reserve internal transfer
capability into Southern California”
• Have since moved to retire this authority as we believe
we can instead use Peak RC SOL methodology to
increase Real Time transfer if needed.
Page 6

7. Justification for Real Time Uprate
Peak RC System Operating Limit (SOL) Methodology
– Section 6 specifies that in ‘sub-seasonal’ time
horizons the acceptable performance for Credible
Multiple Contingencies can be relaxed if system
conditions do not allow for the planned level of
performance
– This means in Real Time operations limits established
using more stringent criteria for CMC can be
revaluated during emergency
NERC EOP-002-3.1
– Section 3.4 allows for a revision to SOL limits given
RT information following the issuance of a EEA
(Energy Emergency Alert) by the ISO.
Slide 7

8. Path Limits
Slide 8
• Path limits are based upon offline powerflow studies
• Does not account for Seasonal Variations or changing
load profiles
• Path limits are often pre-contingency proxy MW limits
across multiple transmission elements
– Doesn’t account for minor changes in neighboring
network topology due to outages
– Doesn’t account for voltage conditions.
• Equipment ratings are based upon Amp rating.
• MVA = Amp*Voltage;
• MW limits are converted from MVA limits based
upon studied or assumed power factor, not
RT/Operational power factor

9. How would CAISO implement?
CAISO RT Operations can utilize Real Time Contingency
Analysis (RTCA) to monitor the actual element the path
limit is trying to protect for
More accurate limit because:
• Rather then limiting flows to the pre-contingency proxy
limit, CAISO can monitor and protect against post
contingency overloads on the actual limiting element
• Allows for utilization of Real Time voltage conditions in
monitoring limit
• Accounts for changes in neighboring area topology
• RTCA RAS functionality allows for incorporating Real
Time congestion relief offered via RAS operation
Slide 9

10. Use Case – Path 26 (North-to-South)
Path Details
- 4000 MW limit from transfer capability of three transmission lines
- Is composed of Midway-Vincent #1 + Midway-Vincent #2 +
Midway-Whirlwind #1 transmission lines
- Is thermally limited by CMC of two of the three lines composing
path
- Path limit is based upon assumed RAS operation at time of study;
Gen Drop in PG&E and Load Shed in SCE
If necessary CAISO can increase Real Time limit by
monitoring CMC in RTCA
– Accounts for additional load being armed in SCE; Load armed by
RAS has increased significantly since Path Limit was set in 2006
– Controls to a MVA limit based upon Amp rating and post-
contingency voltage.
– Real Time limit above posted SOL achievable
Slide 10

11. Impact on Market Operation
• CAISO plans to use this methodology to increase limits
in Real Time only during emergency conditions. This will
be following exhaustion of all available generation and
utilization of all available demand response
– Due to the Real Time data required this can not be
implemented in IFM. IFM and RTM under normal
conditions will continue to operate with the current
ratings from CAISO Transmission Register
• Real Time Transfer Increases will NOT be posted in TTC
• Will be used to avoid pre-contingency load shedding
Slide 11

12. November 9 Frequency Deviation Event
John Phipps
Director, Real-Time Operations
Slide 12

13. Slide 13
November 9 Frequency Deviation Event
– Event Description
– At 11:00 a normal data transfer process with inputs for the market
occurred on schedule. A conflict in the process corrupted an input
that was then transferred into the market software. The next
market run at 11:15 failed and advisory results were sent out
based on the last successful run at 10:59. The issues and
troubleshooting continued through the hour until the issue was
found and fixed around 12:10. Additional related issues were
discovered and fixed at approximately 12:39.
– Around 11:59, the market runs started producing undesirable
results. The ISO System Operators intervened by identifying and
blocking the undesirable dispatches. This continued until 13:35 in
order to keep the undesirable instructions from being sent to the
market participants via ADS. During this time period the ISO
System Operators sent out multiple market messages to
Scheduling Coordinators in order to raise awareness and prevent
resources from following undesirable startup or shutdown
instructions. Scheduling Coordinators were encouraged to call the
ISO to validate instructions before starting or shutting down any
units.

14. Slide 14
November 9 Frequency Deviation Event
– 13:33 the ISO market software sent out decremental
dispatch instructions of approximately 2500 MW to multiple
generator resources via the Automatic Dispatch System
(ADS) before the ISO’s System Operators could block or
override the dispatch instructions. The ISO’s Operators
verbally instructed Scheduling Coordinators to not follow
the dispatches, but 1214 MW of the dispatch included fast
moving resources and 730 MW of additional resources
which automatically responded to the dispatch signal and
reduced their output over an 11 minute period. This
reduction in generation output caused the CAISO ACE and
System Frequency to deviate.
– At 13:35 BAAL was exceeded. At 13:45 ACE was at its
lowest point -3245MW and Frequency was 59.834 HZ.
– 13:53 BAAL was within limits, ACE and Frequency were
recovered.

15. Slide 15
November 9 Frequency Deviation Event
Event Follow-up
• Action Items
– Review both automated and manual controls for
improvement
– Review ramp rates and expectations of units to ramp
over 5 minutes
– Lessons learned training and delivery by operators
involved in the event

16. Market Performance and Quality Update
Guillermo Bautista Alderete, Ph.D.
Manager, Market Validation and Quality Analysis
Warren Katzenstein
Lead Engineering Specialist
Amber Motley
Manager, Short Term Forecasting
Slide 16

17. Adjustment to Regulation Capacity
Requirements
Slide 17

18. Control Performance and variable energy resources’
production affect the quantity of regulation procured
• Control Performance
– Measures the ability to adequately support the
interconnection frequency
– Exceedance of Balancing Authority Ace Limits (BAAL)1
– Noticed a decline in real-time CPS1 performance
– Led to procured regulation up/regulation down depletion
during high renewable penetration/low load periods
• High renewable penetration/low load periods
– Windy and cloudy conditions exacerbate wind and solar
production variability causing larger deviations from
forecast
– Erratic weather (seasonal) during low load periods
Slide 18

19. Method for Determining Regulation Capacity
• For each hour, the ISO determines a percentage of forecasted
demand to set regulation capacity
• The amount of regulation capacity for a given month is informed by:
– Forecast Uncertainty Related To:
• Demand Forecast Deviations
• Solar Forecast Deviations
• Wind Forecast Deviations
– Seasonal/Daily Parameters
• New considerations
– Separation of Regulation Need in relation to Regulation Up and
Regulation Down
– Hourly Analysis of Historical Regulation Dispatch
– Anticipated variability / forecast uncertainty in weather conditions
Slide 19

20. Method for Determining Regulation Capacity Cont.
• Historical Need
– For each hour, examine the 95th percentile of regulation
required as calculated by the control algorithm
– Use data from the same month last year to inform
procurement for the current month (i.e. Oct 2015 informs
Oct 2016)
• Anticipated variability / forecast uncertainty
– Examine performance from recent days that had higher
forecast uncertainty in order to inform change in
procurement related to weather
– Example is a large weather system moving across
California causing variability in cloud cover and wind
speed/direction.
Slide 20

21. 0
50
100
150
200
250
300
350
400
450
500
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
RegulationUpMinimumCapacity
(MW)
Hour Ending
Jan Feb Mar Apr May Jun Jul Aug SEP OCT NOV DEC
Seasonal Trends are Present with New Method
(Regulation Up)
Slide 21
Values above are based on historical information and are subject to change.

22. 0
100
200
300
400
500
600
700
800
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
RegulationDownMinimumCapacity
(MW)
Hour Ending
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Seasonal Trends (Regulation Down)
Slide 22
Values above are based on historical information and are subject to change.

23. May 2016 Regulation Procurement Versus October
2016 Procurement
Slide 23
-1000
-800
-600
-400
-200
0
200
400
600
800
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
RegulationRequirement(MW)
Hour of the Day (Hour Ending)
Spring 2016 Regulation Capacity
Oct 2016 Regulation Capacity

24. October 2016 Results
Slide 24
Percentage of time with insufficient capacity: 1%

25. Flexible Ramp Product Update
Slide 25

26. Flexible Ramp Product
• Flexible Ramp product went live on November 1, 2016
• There is both upward and downward definitions for the
product.
• Each EIM area has its own requirement, and there is
also a system-wide EIM area enforced in the real-time
market.
• There is also a flexible ramp sufficiency test done prior to
the real-time market.
• Requirements are based on historical data and
calculated in the Balancing Area Ramp Requirement
(BARR) application.
Slide 26

27. What is the Balancing Area Ramp Requirement Tool?
• The Balancing Area Ramp Requirement (BARR) tool
calculates the uncertainty requirement and the demand
curves for the Flex Ramp Product
• The uncertainty requirements are hourly values
calculated every day using the BARR tool
• Uncertainty requirements are based on net load forecast
error
Net load = Load – Wind - Solar
• The demand curves are the prices the system is willing
to pay for a given quantity of flex ramp capacity
Slide 27

28. Flexible Ramp Uncertainty Requirement: 5-minute
Real-Time Dispatch (RTD)
Slide 28
RTD Net Load Forecast Error is difference between the binding
interval net load forecast and the prior market run first advisory net
load forecast

29. Flexible Ramp Uncertainty Requirement: 15-minute
Real-Time Pre-Dispatch (RTPD)
Slide 29
RTPD Net Load Forecast Error is maximum difference between the
three RTD binding interval net load forecasts and the associated
RTPD first advisory net load forecast
RTPD

30. Example of the Hourly Distribution of Data that
Comprises the Histogram for Each EIM Entity
Slide 30

31. Example of the Hourly Distribution of Data and the
Calculated Uncertainty Requirements (Red Lines)
Slide 31

32. An Example of the Flex Ramp Product Uncertainty
Calculation
• Flex Up and Down Uncertainty Requirement could be calculated as
follows:
– For each hour, gather the set of recent net load forecast errors
for the appropriate market uncertainty
– Group weekdays and weekends separately due to characteristic
differences
• Weekdays use last 40 days of net load forecast error
• Weekends use last 20 days of net load forecast error
– The flex up uncertainty requirement is the 97.5 percentile
– The flex down uncertainty requirement is the 2.5 percentile
• Daily thresholds are calculated using a similar process but with a
larger set of data
– Significant reduction in % of time thresholds are setting the
requirement compared to the Flex Ramp Constraint
Slide 32

33. Demand Curves
• The demand curves are used to determine how much
flexible ramp capacity the system will procure
• One demand curve for each EIM entity and ISO plus the
EIM Total Area (including ISO) for 7 total demand curves
• The demand curves are the distribution of net load errors
multiplied by the energy penalty price cap or floor
– The penalty price cap is $1000 per MWh
– The penalty price floor is $-150 per MWh
• The maximum price is $247 per MW
• The minimum price is $-155 per MW
Slide 33

34. Constructing a Demand Curve
• A demand curve starts with the probability distribution of net
load forecast errors
– This is the same set of data that is used for determining
the uncertainty requirement
• The flex ramp up demand curve is built by calculating the
percent of data that is greater than a given MW value
• The flex ramp down demand curve is built by calculating the
percent of data that less than a given MW value
• The percentage is converted a price by multiplying by either
the energy penalty price cap or price floor
• Finally, the curve is transformed from MW to Relaxation
Capacity by subtracting the MW values from the uncertainty
requirement
Slide 34

35. Constructing a Demand Curve (Cont.)
• The OASIS published demand curves are comprised of two
components
– The amount of capacity to relax the uncertainty
requirement
– The price associated for relaxing the uncertainty
requirement
• Example
– With an uncertainty requirement of 100 MW, a relaxation
capacity of 15 MW, and a price of $25 per MW
– This means the market procured 85 MW of flexible
capacity at a price of $25 per MW
Slide 35

36. 0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
0 20 40 60 80 100 120 140 160
PercentofDataGreaterthanAGivenNetLoadForecast
Error(%)
Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW)
Example of Constructing a Flex Up Demand Curve:
Start with Probability Distribution of Net Load Forecast
Errors
Slide 36
Curves are limited to the flex up or down
uncertainty requirement

37. Convert Percentage to Price by Multiplying the Curve
by the Energy Penalty Price Cap ($1000 per MWh)
Slide 37
0
50
100
150
200
250
300
350
400
450
0 20 40 60 80 100 120 140 160
Price($/MW)
Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW)

38. Convert x-axis to Relaxation MW by Subtracting the Net Load
Forecast Errors From the Uncertainty Requirement
Slide 38
0
50
100
150
200
250
300
350
400
450
020406080100120140160
Price($/MW)
Relaxaion Capacity (MW)

39. The Curve is then Segmented for Use in the Market
Optimization
Slide 39
0
50
100
150
200
250
300
350
400
450
020406080100120140160
Price($/MW)
Relaxation Capacity (MW)

40. Finally, the Curve is Capped (if Required) at the
Minimum or Maximum Price ($-155/MW or $247/MW)
Slide 40
0
50
100
150
200
250
300
350
020406080100120140160
Price($/MW)
Relaxation Capacity (MW)
The segmented demand curve is then
capped at a price of $247 per MW

41. FRP performance
Slide 41

42. FRP requirements and prices driven by the hourly
profile needs
Slide 42

43. With FRP construct, the EIM area generally drives the
overall procurement
Slide 43
-2,500
-2,000
-1,500
-1,000
-500
0
500
1,000
1,500
2,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
FlexRamp(MW)
APS NV Energy PSE PACW PACE ISO Credit Upward/Downward requirement

44. Flexible Ramp requirements adjusted with FRP activation
Slide 44

45. Hourly profile of ISO FRP requirements
Slide 45

46. Gas Price Update
• FERC clarified use of daily ICE gas price index
• Normal cycle calculates blended gas price indices the
prior night which is used for both DAM and RTM
markets.
• With new provisions, the ICE index available in the
morning is used for the DAM market run.
• When no ICE price index is available, it defaults to use
previous night blended index.
Slide 46

47. Gas price difference of using morning ICE gas price
update
Slide 47

48. Gas price difference of using morning ICE gas price
update
Slide 48
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25% 25-Oct
27-Oct
29-Oct
31-Oct
2-Nov
4-Nov
6-Nov
8-Nov
10-Nov
12-Nov
14-Nov
16-Nov
18-Nov
20-Nov
22-Nov
24-Nov
26-Nov
28-Nov
30-Nov
2-Dec
4-Dec
%ofVolumeTraded
%PriceDifference($/MMBTu)
Volume SCE CityGate Hub

49. Gas price difference of using morning ICE gas price
update
Slide 49
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25% 25-Oct
27-Oct
29-Oct
31-Oct
2-Nov
4-Nov
6-Nov
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14-Nov
16-Nov
18-Nov
20-Nov
22-Nov
24-Nov
26-Nov
28-Nov
30-Nov
2-Dec
4-Dec
%ofVolumeTraded
%PriceDifference($/MMBTu)
Volume KRN Del Pool Hub

50. EIM Update
• Arizona Public Service (APS) and Puget Sound (PSE)
joined the EIM market on October 1, 2016.
• In the first hours after the activation, market observed
minor transitional issues.
• Both entities are under the six-month transitional period,
under which price discovery provisions apply.
Slide 50

51. APS and PSE have passed the balancing test in over
90% of the time
Slide 51
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
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12-Oct
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22-Oct
23-Oct
24-Oct
25-Oct
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27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Passed Test Underscheduling Overscheduling
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
11-Oct
12-Oct
13-Oct
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20-Oct
21-Oct
22-Oct
23-Oct
24-Oct
25-Oct
26-Oct
27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Passed Test Underscheduling Overscheduling
AZPS Area
PSEI Area

52. Power balance constraint infeasibilities in both APS
and PSE have been less than 0.3% of the time in
October
Slide 52
0%
10%
20%
30%
40%
50%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
11-Oct
12-Oct
13-Oct
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19-Oct
20-Oct
21-Oct
22-Oct
23-Oct
24-Oct
25-Oct
26-Oct
27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Valid FMM Under-supply Infeasibility Correctable Infeasibilities
0%
10%
20%
30%
40%
50%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
11-Oct
12-Oct
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20-Oct
21-Oct
22-Oct
23-Oct
24-Oct
25-Oct
26-Oct
27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Valid RTD Under-supply Infeasibility Load Bias Limiter Correctable Infeasibilities

53. Power balance constraint infeasibilities in PSE have
been less than 0.3% of the time in October
Slide 53
0%
10%
20%
30%
40%
50%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
11-Oct
12-Oct
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22-Oct
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24-Oct
25-Oct
26-Oct
27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Valid RTD Under-supply Infeasibility Load Conformance Correctable Infeasibilities
0%
10%
20%
30%
40%
50%
1-Oct
2-Oct
3-Oct
4-Oct
5-Oct
6-Oct
7-Oct
8-Oct
9-Oct
10-Oct
11-Oct
12-Oct
13-Oct
14-Oct
15-Oct
16-Oct
17-Oct
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19-Oct
20-Oct
21-Oct
22-Oct
23-Oct
24-Oct
25-Oct
26-Oct
27-Oct
28-Oct
29-Oct
30-Oct
31-Oct
Valid FMM Under-supply Infeasibility Correctable Infeasibilities

54. EIM Price trends
Slide 54

55. Transfer capabilities in EIM areas
Slide 55

56. Market Update
Slide 56

57. Slide 57
Good price convergence between IFM and RTD in
September and October.

58. Slide 58
RT prices higher than DA prices for both NP 15 and SP 15
in September but lower than DA in SP15 in October.

59. Slide 59
Insufficient upward ramping capacity in ISO increased in
October.

60. Slide 60
Insufficient downward ramping capacity remained low in
2016.

61. Slide 61
Congestion revenue rights market revenue inadequacy
without including auction revenues.

62. Slide 62
Congestion revenue rights market revenue sufficiency
including auction revenues.

63. Slide 63
Exceptional dispatch volume in the ISO area continued at low
levels.

64. Slide 64
Daily exceptional dispatches by reason

65. Slide 65
Real-time Bid cost recovery dropped in October

66. Slide 66
Bid cost recovery (BCR) by Local Capacity Requirement area

67. Slide 67
Minimum online commitment (MOC)

68. Slide 68
Pmax of MOC Cleared Units

69. Slide 69
Enforcement of minimum online commitments in
September and October
MOC Name
Number (frequency) of hours in
September and October
Humboldt 7110 1436
MOC TABLE MTN 504
HNTBH 7820 187
Orange County 7630 134
MOC East Nicolaus 4385234 125
SCIT MOC 67
MOC NP15 11
MOC SAN ONOFRE BUS 10
SDGE 7820 3

70. Slide 70
IFM under-scheduling of solar generation

71. Slide 71
IFM under-scheduling of wind generation declined in
September and October

72. Slide 72
Renewable (VERS) schedules including net virtual supply
and aligns with VER forecast in September and October
http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=EFF75C
2E-F28E-4087-B88B-8DFFAED828F8

73. Slide 73
RTD renewable (VERS) curtailment rose since August

74. Slide 74
RTD renewable (VERS) curtailment versus avoided
curtailment

75. Slide 75
Hourly distribution of maximum RTD renewable (VERS)
curtailment in October

76. Slide 76
Wind, solar and hydro production

77. Monthly wind (VERS) downward flexibility in FMM
Slide 77

78. Monthly solar (VERS) downward flexibility in FMM
Slide 78

79. Monthly solar (VERS) downward flexibility in FMM from
11 AM to 5 PM
Slide 79

80. Slide 80
ISO area RTCO and RTIEO remains at relatively low levels in
September and October.
2015 2016 (YTD)
RTCO $55,489,221 $49,049,744
RTIEO $13,817,548 $380,581
Total Offset $69,306,769 $49,430,324

81. Slide 81
Price correction events increased in September and October
0
1
2
3
4
5
6
7
8
9
10
Jan-15
Feb-15
Mar-15
Apr-15
May-15
Jun-15
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Oct-15
Nov-15
Dec-15
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
CountofEvents
Process Events Software Events Data Error Events Tariff Inconsistency

82. Page 82
EIM BCR in September and October

83. Slide 83
EIM Exceptional Dispatch in September and October

84. Day-ahead load forecast
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0% Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAPE
Slide 84

85. Day-ahead peak to peak forecast accuracy
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAPE
Slide 85

86. Day-ahead wind forecast
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAE
Slide 86

87. Day-ahead solar forecast
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAE
Slide 87

88. Real-time wind forecast
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
4.5%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAE
Slide 88

89. Real-time solar forecast
0%
1%
2%
3%
4%
5%
6%
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014 2015 2016
MAE
Slide 89

90. Real-time solar forecast
0%
1%
2%
3%
4%
5%
6%
Oct
2014 2015 2016 2016_withCurtailedMW
MAE
2016’s October MAE
becomes more comparable
to previous years when the
Curtailed Solar MW are
added back into Actuals.
Slide 90

91. Load Forecast Adjustments
Gabe Murtaugh
Sr. Market Monitoring Analyst,
Department of Market Monitoring
Slide 91

92. Growth in EIM transfer capacity significantly increases
market competiveness.
Slide 92
Puget
300 MW
300 MW
PacifiCorp
West
126 MW85 MW
CAISO 899 MW
872 MW NV
Energy
924 MW
1,874 MW
APS
PacifiCorp
East
468 MW
710 MW
0 MW
293 MW
216 MW 321 MW
Total average transfer capacity (May-Oct 2016)

93. Congestion into EIM areas is very infrequent.
Puget
1%
(187 MW)
1%
(205 MW)
PacifiCorp
West
20%
(27 MW)
2%
(221 MW)
CAISO 2% MW
(790 MW)
.2%
(611 MW)
NV
Energy
0%
.3% (143 MW)
APS
PacifiCorp
East
.3%
(156 MW)
7%
(463 MW)
4% (105 MW)
7%
(150 MW)
1%
(119 MW)
Frequency of congestion in 15-minute market (May-Oct 2016)*
* Average transfer
MW during
congested intervals
in parentheses.
23% (0 MW)
Slide 7

94. EIM areas separated by congestion from the ISO
only 1-3 percent of intervals.
Slide 94

95. Settlement prices in Arizona largely reflected prices in
the ISO during October.
Slide 95
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Averagehourlyprice($/MWh)
Arizona Public Service settlement price
Southern California Edison settlement price
Bilateral price benchmark

96. Settlements prices in Puget Sound were lower than
the ISO and reflected PacifiCorp West prices.
Slide 96
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Averagehourlyprice($/MWh)
Pacific Gas and Electric settlement price
Puget Sound Energy settlement price
PacifiCorp West settlement price
Bilateral price benchmark

97. Positive load adjustments were more frequent in NV
Energy and the ISO, while negative load adjustments
were more frequent in the PacifiCorp areas.
Slide 97
Percent of
intervals
Average
MW
Percent of
total load
Percent of
intervals
Average
MW
Percent of
total load
California ISO
15-minute market 44% 471 1.4% 14% -274 1.1% 169
5-minute market 56% 438 1.4% 27% -300 1.1% 162
PacifiCorp East
15-minute market 5% 91 1.6% 42% -101 1.9% -38
5-minute market 9% 88 1.5% 63% -125 2.4% -71
PacifiCorp West
15-minute market 3% 38 1.5% 43% -49 2.2% -20
5-minute market 4% 42 1.7% 49% -58 2.6% -27
NV Energy
15-minute market 48% 132 2.3% 1% -171 3.6% 62
5-minute market 44% 95 1.7% 11% -83 1.7% 32
Positive load adjustments Negative load adjustments Average
hourly bias
MW

98. Load adjustments in NV Energy tended to be greatest
in the late afternoon, while PacifiCorp East adjusted by
the greatest quantity in the morning.
Slide 98
-150
-100
-50
0
50
100
150
200
250
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
15-minute market (PacifiCorp East) 5-minute market (PacifiCorp East)
15-minute market (PacifiCorp West) 5-minute market (PacifiCorp West)
15-minute market (NV Energy) 5-minute market (NV Energy)

99. Policy Update
Brad Cooper
Manager, Market Design and Regulatory Policy
Slide 99

100. Ongoing policy stakeholder initiatives
• Contingency modeling enhancements
– Technical analysis results targeted Dec
– Stakeholder call on technical analysis targeted Dec
– May 2017 Board Meeting
• Generator contingency and remedial action scheme
modeling
– Revised straw proposal targeted Jan 2017
– Jul 2017 Board Meeting
• Stepped transmission constraints
– New schedule being developed
– Board Meeting TBD
Slide 100

101. Ongoing policy stakeholder initiatives (continued)
• Flexible resource adequacy criteria and must-offer
obligation – phase 2
– Stakeholder call on supplemental issue paper Dec 9
– Revised straw proposal Feb 2017
– Board Meeting TBD
• Bid cost recovery enhancements
– Draft final proposal Dec 2016
– Q1 2017 Board meeting
– Projected Fall 2018 implementation
• Self schedules BCR allocation
– Added to the bid cost recovery enhancements
initiative
Slide 101

102. • Commitment Costs and Default Energy Bid Enhancements
– February 2017 Straw proposal
– July 2017 Board Meeting
– 2018 Implementation
• Metering rules enhancements
– Dec 2016 Board Meeting
• Energy storage and distributed energy resources (ESDER)
Phase 2
– Q1 2017 Board Meeting
Slide 102
Ongoing policy stakeholder initiatives (continued)

103. Ongoing policy stakeholder initiatives (continued)
• Aliso Canyon - Phase 2
– FERC Order accepting filing Nov 28
– Jan 2017 Implementation
• Stakeholder initiatives catalog
– Final 2017 policy initiatives roadmap Dec 15
– Stakeholder call Dec 22
– Feb 2017 EIM Governing Body and Board Meeting
• Frequency response – phase 2
– Issue paper targeted Dec 2016
– Schedule TBD
Slide 103

104. Ongoing policy stakeholder initiatives (continued)
• Regional integration and EIM greenhouse gas compliance
– Stakeholder meeting on straw proposal Dec 1
– Draft final proposal Jan 5
– Board Meeting TBD
• Transmission access charge options
– Framework published Dec 6
– Stakeholder meeting Dec 13
– No planned Board action at this time
• Regional resource adequacy
– Framework published Dec 1
– Stakeholder meeting Dec 8
– No planned Board action at this time
Slide 104

105. Policy stakeholder initiatives coming soon
• Planned to start in Q1 2017
– Resource adequacy enhancements
– Economic and maintenance outages
Slide 105

106. Release Plan Update
Janet Morris
Director, Program Office
Slide 106

107. The ISO offers comprehensive training programs
Slide 107
Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx
Contact us - markettraining@caiso.com
Date Training
January 11 Welcome to the ISO (webinar)
February 7 Settlements 101 (Folsom)
February 8 Settlements 201 (Folsom)

108. Release Plan 2016
Slide 108
Implementations by end of 2016
• Demand Response Registration Enhancements
• ADS Client Replacement (Mandatory)
• Acceptable Use Policy - CMRI

109. Release Plan 2017
Slide 109
Independent 2017
• RTD Local Market Power Mitigation (LMPM) Enhancements
• CRR Clawback Modifications
• MRI-S ACL Groups+ CPG Enhancements (formerly OMAR Replacement)
• PIRP System Decommissioning
• Reactive Power Requirements and Financial Compensation – no system changes
• RIMS Functional Enhancements
• Metering Rules Enhancements
Fall 2017 (tentative, to be confirmed)
• Bidding Rules Enhancements – Part B
• Reliability Services Initiative Phase 1B
• Reliability Services Initiative Part 2
• Commitment Cost Enhancement Phase 3
• EIM 2017 Enhancements
• EIM Portland General Electric (PGE)

110. Release Plan – 2018 and subject to further planning
Slide 110
Spring 2018
• EIM 2018 Idaho Power Company
Fall 2018 – tentative, subject to impact assessment
• Stepped Transmission Constraints
• Bid Cost Recovery Enhancements
• Generation Contingency and Remedial Action Scheme
• Flexible Resource Adequacy Criteria and Must-offer Obligation Phase 2
• ESDER Phase 2
• Regional Resource Adequacy
• Transmission Access Charge Options
• ADS User Interface Replacement
Subject to further release planning:
• Additional Data Transparency Enhancements (OASIS API changes) – work starting after Fall
2016 release; ISO will make it available for market participants to adopt as they need.
• Contingency Modeling Enhancements

111. 2016 – Demand Response Registration Enhancements
Project Info Details/Date
Application Software Changes
Enhance Demand Response Registration functionality and processes
Develop new registration user interface for DRRS
Develop new APIs for support of enhanced registration processes
BPM Changes Metering
Business Process Changes Automation of internal registration-related processes
Slide 111
Milestone Type Milestone Name Dates Status
Board Approval Board Approval N/A
BPMs Publish Final Business Practice Manuals (Metering) Aug 29, 2016 
Post Draft BPM changes (Metering) Aug 04, 2016 
External BRS
External BRS - Enabling Demand Response Phase 2 -
Registration
Jun 04, 2015 
Tariff Tariff N/A
Config Guides Config Guide N/A
Tech Spec Tech Specs - DRRS Phase 2 - Registration Sep 17, 2015 
Market Sim Market Sim Window Sep 19, 2016 - Nov 18, 2016 
Production Activation Post-Mrkt Consol - DRRS Phase 2 - Reg Nov 30, 2016 

112. 2016– ADS Client Replacement (Mandatory)
Project Info Details/Date
Application Software Changes
Scope includes updates to work with TLS version 1.0. After
January 6, 2017, all prior supported ADS client versions (which
includes 5.2.8.0 and 5.2.4.0) will be decommissioned and
inaccessible.
Slide 112
ADS Client certified for Windows 7 and 10
Milestone Type Milestone Name Dates Status
Board Approval Board Approval N/A
BPMs BPMs N/A
External BRS External BRS N/A
Tariff Tariff N/A
Config Guides Config Guide N/A
Tech Spec Tech Spec N/A
Market Sim Market Sim Window Oct 12, 2016 - Jan 06, 2017
Production Activation ADS TLS Risk Remediation Jan 06, 2017

113. 2016 – Acceptable Use Policy – CMRI
Project Info Details/Date
Application Software Changes
Scope includes enforcement of Acceptable Use Policy for CMRI
services to support the full implementation of 1 call per service per
identity (as designated by certificate) every 5 seconds. An error
code of 429 will be returned for any violation instance of the use
policy.
Slide 113
Milestone Type Milestone Name Dates Status
Board Approval Board Approval N/A
BPMs BPMs N/A
External BRS External BRS N/A
Tariff Tariff N/A
Config Guides Config Guide N/A
Tech Spec Tech Spec N/A
Market Sim Market Sim Window Aug 23, 2016 - Sep 23, 2016 
Production Activation Acceptable Use Policy - CMRI Jan 06, 2017

114. Slide 114
2016 CMRI URL Standardization
Service Version #
Existing URL
https://wsstas.caiso.com:4445/sst/runtime.asvc
https://wsstas.ecn.wepex.net:4445/sst/runtime.as
vc
Standardized URL
https://ws.caiso.com/sst/cmri
https://ws.ecn.wepex.net/sst/cmri
MarketAwards
v2 Decommission on 12/01/2016 None exists
v3 Decommission on 12/01/2016 Supported
v4 None exists Supported
MarketSchedules
v1 Decommission on 12/01/2016 None exists
v2 Decommission on 12/01/2016 Supported
v3 None exists Supported
SchedulePrices
v2 Decommission on 12/01/2016 None exists
v3 Decommission on 12/01/2016 Supported
v4 None exists Supported
ExpectedEnergy
AllocationDetails
v1 Decommission on 12/01/2016 None exists
v2 Decommission on 12/01/2016 Supported
v3 None exists Supported
GreenHouseGas
CapData
v1
None exists Supported
EIMInterchange
ScheduleData
v1
ResourceMovementP
oint
v1
ResourceLevel
Movement
v1
EIRForecast v1
ElectricityPriceIndex v1
All other pre Fall 2016
existing services
existing Decommission on 12/01/2016 Supported

115. Slide 115
2016-2017 Projects - Major Milestones Summary
Project Market Simulation Deployment/Activation Decommissioning
Demand Response Registration Enhancements Completed Completed N/A
ADS Client Replacement (Mandatory)
ADS Client ver 6.0.0.0
made available for testing in
MAP Stage on 10/12/2016
ADS Client production-level
version 6.0.x available as of
10/28/2016
Availability of production level
ADS version started a grace
period of approx 2 months for
market participants to transition
to the new version
After January 6, 2017, all prior
supported ADS client versions (which
includes 5.2.8.0 and 5.2.4.0) will be
decommissioned and inaccessible.
Acceptable Use Policy - CMRI Completed Jan 6, 2017 N/A
ACL Groups (formerly OMAR Replacement and
PIRP Decommissioning)
TBD TBD
ISO decommissions PIRP based upon a
two-month buffer period between ACL
group functionality being active in
Production.
MRI-S Customer Partnership Group identified
enhancements (formerly OMAR Replacement)
TBD TBD
OMAR will be decommissioned after a
four month grace period starting when
MRI-S enhancements deploy to MAP
Stage (market simulation).

116. 2017 - Real Time Dispatch Local Market Power Mitigation
Project Info Details/Date
Application Software Changes
• CMRI – Display mitigated bids from RTD process
• OASIS (Open Access Sametime Information System): Display RTD
reports for Market Clearing, the Pnode clearing, similar to current
RTPD reports
• RTM (Real Time Market)
• RTPD: Perform the LMPM run as an integral part of the binding
interval RTPD run
• RTD: Proposed mitigation in RTD run would work the same way
as the current RTPD run
BPM Changes
• Energy Imbalance Market (EIM): under the proposed RTD method,
bids are not necessarily mitigated for the whole hour
• RTD MPM will work the same way as the current RTPD MPM
Business Process Changes
• Manage Markets & Grid
• ATF – System Operations: Add MPM Application to Real Time and
annotate inputs and outputs
• ATF – System Operations, Real Time: Add MPM to diagram with inputs
and outputs
• Level II – Manage Real Time Operations – maintain balancing area
Slide 116

117. 2017 - Real Time Dispatch Local Market Power Mitigation (cont.)
Slide 117
Project
CMRI OASIS ADS
RTD LMPM Update (add RTD results):
MPMResults v3
Update (add RTD results)-
- PRC_MPM_RTM_LMP
- PRC_MPM_RTM_NOMOGRAM
- PRC_MPM_RTM_NOMOGRAM_CMP
- PRC_MPM_RTM_FLOWGATE
- PRC_MPM_CNSTR_CMP
- PRC_MPM_RTM_REF_BUS
-ENE_MPM
N/A
Milestone Type Milestone Name Dates Status
Board Approval Board of Governors (BOG) approval Mar 24, 2016 
BPMs Posted Market Operations BPM PRR 945 Nov 04, 2016 
Post draft EIM BPM Dec 29, 2016
External BRS Post External BRS Apr 05, 2016 
Tariff Received FERC approval Nov 08, 2016 
Config Guides Configuration Guide N/A
Tech Spec Publish Technical Specification - OASIS Apr 08, 2016 
Publish Technical Specification - CMRI Apr 14, 2016 
Market Sim Market Sim Window Jan 17, 2017 - Feb 03, 2017
Production Activation RTD - Local Market Power Mitigation Enhancement Mar 01, 2017

118. 2017 – Congestion Revenue Rights (CRR) Clawback Modifications
Project Info Details/Date
Application Software Changes
MQS/CRR Clawback:
If import bid <= day-ahead price, then the import is not considered a virtual award.
If export bid >= day-ahead price, then the export is not considered a virtual award.
If an import/export bid/self-schedule in real-time market is less than the day-ahead
schedule, then the difference shall be still subject to CRR Clawback rule.
CRR Clawback rule should include convergence bids cleared on trading hubs and
load aggregation points in the flow impact used to determine if the 10% threshold
is reached.
Inform Market Participants of CRR annual allocation/auction for 2017.
BPM Changes Market Operations Appendix F
Business Process Changes TBD
Slide 118
Milestone Type Milestone Name Dates Status
Board Approval Board of Governors Approval Jun 28, 2016 
BPMs Publish Final Business Practice Manuals Jan 30, 2017
External BRS Post External BRS Nov 29, 2016 
Tariff File Tariff Jan 20, 2017
Receive FERC order Mar 21, 2017
Production Activation CRR Clawback Modification Apr 01, 2017

119. 2017 - MRI-S ACL Groups+ CPG Enhancements
Project Info Details/Date
Application Software Changes
The MRI-S metering (MRI-S) application cannot currently support ACL (Access Control
List) groups functionality for defining a subset of resources belonging to an SCID.
Enhancements to the Application Identity Management (AIM) application will enable the
use of ACL groups for SCID-level read-only access for MRI-S.
Conducted a Customer Partnership Group meeting on October 20 and reviewed
proposed solutions.
BPM Changes None
Business Process Changes
Potential Level-II business process changes under –
• Manage Market & Reliability Data & Modeling
• Manage Operations Support & Settlements
Slide 119
Milestone Type Milestone Name Dates Status
Board Approval Board Approval N/A
BPMs Metering BPM Changes N/A
External BRS Post External BRS Nov 14, 2016 
Tariff Pre-Tariff Filing QRB N/A
Tech Spec Publish Tech Specs Nov 02, 2016 
Market Simulation Phase 1 - ACL Groups TBD
Phase 2 - MRI-S Metering Enhancements TBD
Production Activation Phase 1 - ACL Groups TBD
Phase 2 - MRI-S Metering Enhancements TBD

120. MRI-S ACL Groups + CPG Enhancements
Slide 120
* ACL group creation to filter for a read only role at the resource level is not
currently available
# System Summary Status Estimated Fix
Date
1 MRI-S CIDI 183777, 183993 - MRI-S for Metering Limitation of
100,000 records.
Under review See previous slide
2 MRI-S Option to choose UOM is missing on the UI
3 MRI-S CIDI 184018 - Time zone is missing on the UI
4 MRI-S CIDI 183777, 183993 - Modification to AUP policy on data
retrieval to include querying by last updated time
5 MRI-S Option to request for data in various time interval in UI
6 MRI-S Ability to view log files within the same organization
7 MRI-S Ability to provide SC ID in the data retrieve request
MRI-S *ACL Group – filter read-only at the resource level In process See previous slide

121. 2017 – PIRP Decommissioning
Project Info Details/Date
Application Software Changes:
PIRP/CMRI
• Forecast Data Reporting (resource-level) that was performed in PIRP will be done in
CMRI. Rolling Hour Ahead, Locked Hour Ahead, and Rolling Day-Ahead forecasts.
• PIRP Decommissioning to occur in 2017
• CMRI to receive the Electricity Price Index for each resource and publish it to the
Market Participants.
• 60 Day PIRP / CMRI parallel production to start when AIM/ACL becomes available.
BPM Changes CMRI Technical Specification; New APIs will be described.
Data Transparency
• Independent changes, won’t
impact existing services
• Will be made available in
Production and cutover
schedule is discretionary
Atlas Reference:
1. Price Correction Messages (ATL_PRC_CORR_MSG)
2. Scheduling Point Definition (ATL_SP)
3. BAA and Tie Definition (ATL_BAA_TIE)
4. Scheduling Point and Tie Definition (ATL_SP_TIE)
5. Intertie Constraint and Scheduling Point Mapping (ATL_ITC_SP)
6. Intertie Scheduling Limit and Tie Mapping (ATL_ISL_TIE)
Energy
• EIM Transfer Limits By Tie (ENE_EIM_TRANSFER_LIMITS_TIE)
• Wind and Solar Summary (ENE_WIND_SOLAR_SUMMARY)
Prices
• MPM Default Competitive Path Assessment List (PRC_MPM_DEFAULT_CMP)
Business Process Changes MPs will receive the VER reports from CMRI rather than PIRP.
Slide 121

122. 2017 – PIRP Decommissioning
Slide 122
Milestone Type Milestone Name Dates Status
Board Approval Board Approval N/A
BPMs Publish Draft Business Practice Manuals (Market Instruments; PRR 936) Sep 06, 2016 
External BRS External Business Requirements Jun 29, 2015 
Tariff Tariff Filing Activities N/A
Config Guides Settlements Configuration N/A
Tech Spec Publish Technical Specifications (CMRI: PIRP Decommissioning) Feb 05, 2016 
Publish Technical Specifications (CMRI; Wind and Solar) Apr 15, 2016 
Market Sim CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Aug 23 - Sep 23, 2016 
PIRP Decommissioning TBD
Production Activation CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Oct 01, 2016 
AIM / ACL Production Deployment TBD
OASIS API Enhancements; 9 Reports TBD
PIRP Decommissioning TBD

123. 2017 – Reactive Power Requirements and Financial Compensation
Project Info Details/Date
Application Software Changes None
BPM Changes
Generator Interconnection and Deliverability Allocation Procedures
• Reactive power delivery interconnection condition for asynchronous resources.
Generator Interconnection Procedures
• Reactive power delivery interconnection condition for asynchronous resources.
Generator Management
• Generators’ AVR Requirements.
Business Process Changes
Develop Infrastructure (DI) (80001)
• Level II - Manage Generator Interconnection Process (GIP) (Logical Group):
Slide 123
Milestone Type Milestone Name Dates Status
BPMs Draft BPM changes TBD
Post Draft BPM changes TBD
Publish Final Business Practice Manuals TBD
Tariff File Tariff 12/5/2016 
Tariff Receive FERC order 2/1/2017
Production Activation Reactive Power and Financial Compensation activation 4/1/2017

124. 2016 – RIMS Functional Enhancements
Project Info Details/Date Status
Application Software Changes
Functional enhancements resulting from the Customer Partnership Group CPG.
More details to be provided in the future.
BPM Changes
Generator Interconnection and Deliverability Allocation Procedures
Generator Interconnection Procedures
Managing Full Network Model
Metering
Generator Management
Transmission Planning Process
Customer Partnership Group 10/16/15
Application and Study Webinar 3/31/16
Slide 124
Milestone Type Milestone Name Dates Status
Board Approval Board approval not required N/A
BPMs Generator Interconnection and Delivery Allocation Apr 29, 2016 
External BRS External BRS not Required N/A
Tariff No Tariff Required N/A
Config Guides Configuration Guides not required N/A
Tech Spec No Tech Specifications Required N/A
Production Activation RIMS5 App & Study Mar 21, 2016 
RIMS5 Queue Management, Transmission and Generation TBD

125. 2017 – Metering Rules Enhancements
Project Info Details/Date
Application Software Changes N/A
BPM Changes
Metering
• EIM BPM will be updated to explain Metering data reporting access
based on transitions from ISOME to SCME (shall transition to
submission of SQMD meter data to Metering Data submission portal) or
SCME to ISOME (shall be able to review historical meter data in MRI-S
when resource was SCME).
Definitions & Acronyms BPM Changes
• New Tariff and Business Process/System acronyms.
Business Process Changes
• Manage Transmission & Resource Implementation
• Manage Market & Reliability Data & Modeling (MMR) (80004)
• ISO Meter Certification (MMR LII)
• Metering Systems Access (Production) (MMR LII)
• Metering System Configuration for Market Resources (MMR
LII)
• Station Power Implementation (MMR LIII)
• Application Flow - Billing & Settlements
• Analyze Missing Measurement Report (MOS LIII)
• Manage Market Billing & Settlements (MOS LII)
• Manage Market Quality System (MOS LII)
• Manage Rules of Conduct (MOS LII)
• Meter Data Acquisition & Processing (MOS LII)
• SCME Self Audit (MOS LII)
Slide 125

126. 2017 – Metering Rules Enhancements
Slide 126
Milestone Type Milestone Name Dates Status
Board Approval Obtain Board of Governors Approval Dec 14, 2016
BPMs Metering BPM TBD
Energy Imbalance Market BPM TBD
Publish Final Business Practice Manuals TBD
External BRS External Business Requirements N/A
Tariff File Tariff N/A
Receive FERC order N/A
Config Guides Settlements N/A
Tech Spec Tech Specs N/A
Market Sim Market Sim Window N/A
Production Activation Metering Rules Enhancements Apr 01, 2017

127. Fall 2017 - Bidding Rules Enhancements – Part B
Slide 127
Project Info Details/Date
Application Software Changes
• MasterFile:
• Provide ability to submit requests for new fuel regions (Policy Section 8.1.1.3)
• Include resource-specific start-up electricity costs in proxy costs based on wholesale
projected electricity price, unless resource verifies costs incurred are retail rates (RDT
change)
• Allow ability to submit a weighting when using a more than one fuel region.
• Automation of the Aliso Canyon process for creating NEW Fuel Regions
• OASIS:
• Publish fuel regions (public information)
Business Process Change
• Manage Transmission & Resource Implementation
• Manage Entity & Resource Maintenance Updates
• Manage Full Network Model Maintenance
• Manage Market Quality System (MQS)
BPMs Market Instruments, Market Operations, Reliability Requirements
Milestone Type Milestone Name Dates Status
Board Approval BOG Approval Mar 25, 2016 
BPMs Draft BPM changes TBD
Post Draft BPM changes TBD
Publish Final Business Practice Manuals TBD
External BRS Post External BRS Dec 15, 2016
Tariff File Tariff TBD
Receive FERC order TBD
Config Guides Prepare Draft Configuration Guides Apr 01, 2017
Tech Spec Create ISO Interface Spec (Tech spec) Apr 01, 2017
Market Sim Market Sim Window Jul 05, 2017 - Jul 31, 2017
Production Activation Bidding Rules Part B Oct 01, 2017

128. Fall 2017 - Reliability Services Initiative Phase 1B
Project Info Details/Date Status
Application Software Changes
Developments under consideration include:
Scope:
• Default flexible qualifying capacity provisions for phase 2 consideration (we might need data collection
performed in order to support RSI Phase 2
• Redesign of Replacement Rule for System RA and Monthly RA Process
• RA Process and Outage Rules for implementation for 2017 RA year
• Scope not delivered in RSI Phase 1A (Grandfathered Contracts, RAAM Decommissioning – SCP & CPM
screens from RAAM to CIRA, Acquired Contracts, OASIS reporting, web services related to APIs for CSP
offers, APIs for Generic/Flex Substitutions, and Release of Generic/Flex Subs – UI & API)
Impacted Systems:
• CIRA
• OASIS
• Integration (B2B)
• Settlements
• Decommission RAAM
Business Process Changes Manage Market & Reliability Data & Modeling
Slide 128
Milestone Type Milestone Name Dates Status
Board Approval Board Approval May 12, 2015 
BPMs Draft BPM Changes - Outage Mgmt, Reliability Reqmts TBD
Post Draft BPM changes TBD
Publish Final Business Practice Manuals TBD
External BRS Post External BRS Dec 16, 2016
Tariff File Tariff TBD
Receive FERC order TBD
Config Guides Config Guide Apr 01, 2017
Tech Spec Create ISO Interface Spec (Tech spec) Apr 01, 2017
Market Sim Market Sim Window Jul 05, 2017 - Jul 31, 2017
Production Activation Reliability Services Initiative Phase 1B Oct 01, 2017

129. Project Info Details/Date
Application Software Changes
Scope:
1. Clarify use-limited registration process and documentation to determine opportunity
costs
2. Each submission evaluated on a case-by-case basis to determine if the ISO can
calculate opportunity costs
• ISO calculated; Modeled limitation
• Market Participant calculated; Negotiated limitation
3. Enhanced definition of “use-limited” in response to FERC’s rejection of the proposed
definition in Cost Commitment Enhancements Phase 2
4. Change Nature of Work attributes (Outage cards)
1. Modify use-limited reached for RAAIM Treatment
2. Add new demand response nature of work attribute for RDRR and PDR
5. Market Characteristics
1. Maximum Daily Starts
2. Maximum MSG transitions
3. Ramp rates
Impacted Systems:
1. CIRA
2. CMRI
3. IFM/RTN
4. SIBR
5. MasterFile
6. OASIS
7. OMS
8. Settlements
BPM Changes
Market Instruments, Outage Management, Reliability Requirement, Market Operations,
Settlements & Billing
Business Process Changes
Level II – Manage Reliability Requirements
Level II – Manage Day Ahead Market
Slide 129
Fall 2017 - Commitment Cost Enhancements Phase 3

130. Slide 130
Fall 2017 - Commitment Cost Enhancements Phase 3 (cont.)
Milestone Type Milestone Name Dates Status
Board Approval Board of Governors (BOG) Approval Mar 25, 2016 
BPMs Draft BPM changes TBD
Post Draft BPM changes TBD
Publish Final Business Practice Manuals TBD
External BRS Post External BRS Dec 30, 2016
Tariff File Tariff TBD
Receive FERC order TBD
Config Guides Config Guide Apr 01, 2017
Tech Spec Create ISO Interface Spec (Tech spec) Apr 01, 2017
Market Sim Market Sim Window Jul 05, 2017 - Jul 31, 2017
Production Activation Commitment Costs Phase 3 Oct 01, 2017

131. Fall 2017 – EIM Enhancements 2017
Project Info Details/Date
Application Software Changes
​Addresses the following enhancements identified by policy, operations,
technology, business and market participants.
The following requirements are being defined:
• EIM Entity access reports
• BAAOP provisioning in AIM
• EIM Data report enhancements to support EIM Entity settlements
• Joint Owned Units modeling
• Allow MSG resource to send actual configuration in telemetry for RTM
• Comprehensive model for startup and transition energy in DAM, RTM,
RTBS, MQS
BPM Changes TBD
Business Process Changes TBD
Slide 131

132. Slide 132
Fall 2017 – EIM Enhancements 2017 (cont.)
Milestone Type Milestone Name Dates Status
Board Approval Obtain Board of Governors Approval N/A
BPMs Draft BPM changes TBD
Post Draft BPM changes TBD
Publish Final Business Practice Manuals TBD
External BRS External BRS complete Dec 30, 2016
Tariff File Tariff TBD
Receive FERC order TBD
Config Guides Design review - BPM and Tariff SMEs Apr 01, 2017
Tech Spec Publish Technical Specifications Apr 06, 2017
Market Sim Market Sim Window Jul 05, 2017 - Jul 31, 2017
Production Activation EIM Enhancements 2017 Oct 01, 2017

133. Fall 2017 – EIM Portland General Electric
Project Info Details/Date
Application Software Changes Implementation of Portland General Electric as an EIM Entity.
BPM Changes
EIM BPM will be updated to reflect new modeling scenarios identified
during PGE implementation and feedback from PGE.
Market Simulation
ISO promoted market network model including PGE area to non-
production system and allow PGE exchange data in advance of Market
Simulation.
Parallel Operations August 1 – September 30, 2017
Slide 133
Milestone Type Milestone Name Dates Status
Board Approval Board approval not required N/A
BPMs BPMs N/A
External BRS No external BRS N/A
Tariff Tariff filing at FERC N/A
Config Guides Settlements N/A
Tech Spec Tech Specs N/A
Market Simulation Market Sim Environment Window Jun 29, 2017 – Jul 31, 2017
Production Activation EIM - Portland General Electric Oct 01, 2017

134. Annual Functional Release Lifecycle
Slide 134
The ISO has published the Annual Functional Release Lifecycle draft on the
Release Planning page
• http://www.caiso.com/Documents/AnnualFunctionalReleaseLifecycle.pdf
This document describes the planning through execution phases of the ISO annual
functional release lifecycle process including
• Introduction
• Background
• Scope
• Annual Functional Release Lifecycle
• Exceptions
• Contingency Planning
• External Deliverables
• Process Interfaces
• Stakeholder Implementation Interactions
The ISO encourages Market Participants to review the document and provide any
feedback.

135. Market Performance and Planning Forum
2017 Schedule – Mark Your Calendars
• January 18
• March 14
• May 16
• July 18
• September 19
• November 14
Questions or meeting topic suggestions:
Submit through CIDI - select the “Market Performance and
Planning Forum” category
Slide 135