20160506Solar Integration Study Report.pdf

April 2016 ©
2016 Idaho Power
Solar Integration
Study Report
Idaho Power Company Solar Integration Study Report
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TABLE OF CONTENTS
Table of Contents ............................................................................................................................. i
List of Tables .................................................................................................................................. ii
List of Figures ................................................................................................................................ iii
List of Appendices ......................................................................................................................... iii
Executive Summary .........................................................................................................................v
Acknowledgments.......................................................................................................................... vi
Introduction ......................................................................................................................................1
Geographic Dispersion...............................................................................................................2
2014 Solar Integration Study .....................................................................................................3
Data Gathering and Scenario Development .....................................................................................3
Statistical-Based Analysis of Solar, .................................................................................................6
Wind, and Load Data .......................................................................................................................6
Reserve for Load Combined with Wind ..................................................................................13
Reserve for Load Combined with Wind and Solar ..................................................................14
Example Reserve Application..................................................................................................16
Production Cost Simulation Analysis ............................................................................................17
Design of Simulations ..............................................................................................................17
Simulation Inputs .....................................................................................................................18
Simulation model .....................................................................................................................19
Contingency Reserve Obligation .............................................................................................20
Flexible Capacity Resources ....................................................................................................20
Results ............................................................................................................................................20
Energy Imbalance Market Sensitivity Analysis .......................................................................22
Study Findings .........................................................................................................................22
Hour-ahead Solar Production Forecasting .........................................................................22
Comparison to Wind Integration .......................................................................................24
Geographic Dispersion and Solar Variability ....................................................................24
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Transmission and Distribution ...........................................................................................25
Solar Integration Cost Elements ........................................................................................25
Hells Canyon Complex Spill .............................................................................................26
Spring-Season Integration ..................................................................................................26
Conclusions ....................................................................................................................................26
Literature Cited ..............................................................................................................................28
LIST OF TABLES
Table 1
Solar build-out scenarios studied ..................................................................................................v
Table 2
Average integration cost per megawatt-hour (MWh) for solar build-out scenarios ................... vi
Table 3
Solar build-out scenarios studied ..................................................................................................4
Table 4
Solar data site latitude, longitude, and elevation used in IPC’s solar integration study ...............5
Table 5
Coefficients for bidirectional solar reserve by solar build-out ...................................................15
Table 6
Average INC/DEC base and test cases by solar build-out (water year [WY] 2011–2013) ........15
Table 7
Inputs for the solar integration study hourly production cost simulations ..................................18
Table 8
Integration cost per MWh for solar build-out scenarios .............................................................21
Table 9
Average integration cost per MWh for solar build-out scenarios ...............................................21
Table 10
Incremental integration cost results for solar build-out scenarios ..............................................22
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LIST OF FIGURES
Figure 1
A comparison of 5-minute solar PV production on July 5, 2013. ................................................2
Figure 2
Solar data sites used in IPC’s solar integration study ...................................................................5
Figure 3
Wind production deviations (5-minute wind production minus hour-ahead forecast
hourly average wind production). Period of record December 2012 through November
2015. ..............................................................................................................................................9
Figure 4
Wind production deviations with fitted trend lines for bidirectional wind reserve as
function of hour-ahead forecast wind production .......................................................................10
Figure 5
Solar production deviations (5-minute solar production minus hour-ahead forecast
hourly average solar production). Period of record October 2010 through September
2013. 800-MW solar build-out. Period of day 12:00–15:00. ......................................................11
Figure 6
Solar production deviations (5-minute solar production minus hour-ahead forecast
hourly average solar production). Period of record October 2010 through September
2013. 800-MW solar build-out. Period of day 12:00–15:00. Fitted trend lines for
bidirectional solar reserve as function of hour-ahead forecast solar production. .......................13
Figure 7
Installed nameplate wind capacity under contract, water years 2011–2013. ..............................19
Figure 8
Distributions of daily MWh by month for wind and solar (800-MW solar build-out). ..............24
LIST OF APPENDICES
Appendix 1
Solar integration study appendix .................................................................................................30
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EXECUTIVE SUMMARY
The development of solar photovoltaic (PV) resources has received markedly increased attention
over recent years. The increased attention given to solar PV is a result of multiple factors:
1.Decline in solar PV module prices
2.Federal energy policy, including tax incentives, favoring carbon-free generation
resources
3.Electricity customers interest in self generation
4.Increase in number of Public Utility Regulatory Policies Act of 1978 (PURPA) solar
projects under contract in Idaho Power’s service area
Electric power from solar PV resources is widely acknowledged to exhibit greater uncontrolled
variability and near-term uncertainty than energy from conventional generators. Because of the
greater variability and uncertainty, electric utilities incur increased costs when the existing
dispatchable generators are called on to integrate PV solar plant generation. The increased costs
occur because power systems are operated less optimally to successfully plan for and react to
solar plant generation without compromising the reliable delivery of electrical power to
customers. Idaho Power has studied the operational modifications it must make to integrate solar
PV power plant generation connecting to its system.
The objective of this solar integration study is to estimate the costs of the operational
modifications necessary to integrate the intermittent generation from solar plants, where the
operational modifications are in the form of differing system reserve requirements. This study
determines these costs for four solar build-out scenarios provided in Table 1.
Table 1
Solar build-out scenarios studied
Installed Capacity of Solar Build-Out Scenarios
Site Data Source 400 megawatts
(MW)
800 MW 1,200 MW 1,600 MW
Parma, ID USBR AgriMet 50 100 150 200
Murphy Flats, ID SolarAnywhere 25 50 75 100
Boise, ID USBR AgriMet 25 50 75 100
Grand View, ID SolarAnywhere 75 150 225 300
Orchard, ID SolarAnywhere 100 200 300 400
Bliss, ID SolarAnywhere 25 50 75 100
Twin Falls, ID USBR AgriMet 50 100 150 200
Aberdeen, ID USBR AgriMet 50 100 150 200
Total MW 400 800 1,200 1,600
The study determines solar integration costs through paired simulations of the Idaho Power
system for each solar build-out scenario. Each pair of simulations consists of a test case in which
extra capacity in reserve is required of dispatchable generators to allow them to respond to
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unplanned changes in solar generation and a base case in which no extra capacity in reserve is
required. The solar integration costs indicated by the simulations are provided in Table 2.
Table 2
Average integration cost per megawatt-hour (MWh) for solar build-out scenarios
0–400 MW 0–800 MW 0–1,200 MW 0–1,600 MW
Integration cost (2016$) $0.27/MWh $0.57/MWh $0.69/MWh $0.85/MWh
ACKNOWLEDGMENTS
Idaho Power acknowledges the important contribution of the Technical Review Committee
(TRC) in this solar integration study. The TRC has been involved from the study outset in
February 2015 and has provided substantial guidance. Idaho Power especially thanks the TRC
for the collegial discussions of solar integration during TRC meetings. These discussions helped
shape the study methods followed and are consistent with the TRC guidelines as provided by the
Utility Variable-Generation Integration Group (UVIG) and the National Renewable Energy
Laboratory (NREL) (UVIG and NREL n.d.). The following are members of the Idaho Power
solar integration study TRC:
Brian Johnson, University of Idaho
Cameron Yourkowski, Renewable Northwest
Clint Kalich, Avista Utilities
Kurt Myers, Idaho National Laboratory
Barbara O’Neill, NREL
Michael Milligan, NREL
Above representatives from NREL participated in the early stages of the study, and contributed
to the study’s foundational development. However, NREL funding did not permit their active
participation through study completion. Idaho Power continued to include NREL on electronic
correspondence related to the study through study completion.
Staff from the Idaho and Oregon regulatory commissions have participated as observers
throughout the process. The following staff have been observers of the process:
Brittany Andrus, Public Utility Commission of Oregon (OPUC) staff
John Crider, OPUC staff
Rick Sterling, Idaho Public Utilities Commission (IPUC) staff
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TRC members and regulatory observers serve either voluntarily or are paid by their own
employers and receive no compensation from Idaho Power. The company is grateful for the
TRC’s time spent supporting the study and recognizes this support has led to a better study.
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INTRODUCTION
The development of solar photovoltaic (PV) resources has received markedly increased attention
over recent years. The increased attention given to solar PV is a result of multiple factors:
1.Decline in solar PV module prices
2.Federal energy policy, including tax incentives, favoring carbon-free generation
resources
3.Electricity customers interest in self generation
4.Increase in number of Public Utility Regulatory Policies Act of 1978 (PURPA) solar
projects under contract in Idaho Power’s service area
Idaho Power currently has 320 megawatts (MW) of utility-scale solar PV from PURPA contracts
scheduled to be on-line by year-end 2016. Idaho Power also currently has about 5 MW of solar
PV systems interconnected through the company’s net metering service. However, while the
prevalence of rooftop solar PV systems is growing, the far greater magnitude of potential
capacity from utility-scale solar PV necessitates this study’s focus on the integration of
utility-scale solar PV alone. This solar integration study did not analyze rooftop solar and
potential integration impacts on Idaho Power's distribution system.
Electric power from solar PV resources is widely acknowledged to exhibit greater uncontrolled
variability and near-term uncertainty than energy from conventional generators. Because of the
greater variability and uncertainty, electric utilities incur increased costs when the existing
dispatchable generators are called on to integrate PV solar plant generation. The increased costs
occur because power systems are operated less optimally to successfully plan for and react to
solar plant generation without compromising the reliable delivery of electrical power to
customers. Idaho Power has studied the operational modifications it must make to integrate solar
PV power plant generation connecting to its system. The objective of this solar integration study
is to estimate the costs of the operational modifications necessary to integrate the intermittent
generation from solar plants, where the operational modifications are in the form of differing
system reserve requirements. This report is intended to describe the operational modifications
and the resulting costs.
Idaho Power organized the study into four primary steps:
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Geographic Dispersion
It is recognized that the variability and uncertainty from solar PV resources, just like wind
resources, are less severe where the installed capacity is geographically dispersed as compared to
clustered. Analysis conducted for this study supports this principle. The solar futures,
or build-outs, considered for this study are widely dispersed; solar PV capacity is spread east to
west along the Snake River Plain from Aberdeen, Idaho to Parma, Idaho (Figure 2). The effect of
dispersion is exemplified in Figure 1, which shows production for July 5, 2013 for three time
series: 1) the 400-MW solar PV build-out assumed for the study, 2) a highly clustered build-out
with 400 MW of solar PV sited at Grand View, Idaho, and 3) a less clustered build-out with 400
MW of solar PV sited evenly between Grand View, Idaho and Orchard, Idaho. A comparison of
the plotted production for the three time series clearly indicates greater challenges associated
with integration of the clustered build-outs; the steeper and more dramatic changes in production
for the clustered build-outs are indicative of potential challenges in system integration. The solar
integration costs identified in this study are relatively small. The small costs suggest solar PV
resources can be inexpensively integrated without significant impact to system operations.
However, these results are highly dependent on the level of dispersion in the solar PV resource.
Impacts and costs associated with build-outs more clustered than assumed for this study are
likely markedly greater than found by this study.

Figure 1
A comparison of 5-minute solar PV production on July 5, 2013.
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2014 Solar Integration Study
The first Idaho Power solar integration study was completed in June 2014. The first study
investigated integration of four solar PV build-outs: 100 MW, 300 MW, 500 MW, and 700 MW.
The costs from the first study were the basis for solar integration costs included in Idaho Public
Utilities Commission (IPUC) Schedule 87, which was part of a settlement stipulation approved
by the IPUC in Order No. 33227 in February 2015 (Case No. IPC-E-14-18). In addition to
Schedule 87, the parties to the settlement stipulation agreed that a second study of solar
integration was to be initiated in January 2015 and completed as “expeditiously as possible with
the goal of not exceeding 12 months”. The parties also agreed that Idaho Power and the
Technical Review Committee (TRC) formed for the second solar integration study will
determine whether the following issues should be included as part of the second study:
 Alternative water-year types (e.g., low-type and high-type), range of water years or
normalized water year
 Intra-hour trading opportunities
 Shortening the hour-ahead forecast lead time from 45 minutes to 30 minutes
 Clustered solar build-out scenarios
 Other solar plant technologies (e.g., tracking systems or varied fixed-panel orientation)
 Correlation between solar, wind, and load variability, uncertainty, and forecasting error
 Improved forecasting methods
 Energy imbalance markets, or other market structures
 Voltage/frequency regulation
 Increased transmission capacity, changes in operation of hydroelectric facilities, addition
of demand-side technologies
 Gas price forecasts
 Modeling of sub-hourly scheduling of load and generation
 Identification of the existence of low occurrence events that contribute to proportionately
higher integration costs and possible remedies, including operational or contractual
solutions to mitigate these events and reduce integration costs and charges
Idaho Power solicited from the TRC their feedback, including a prioritization, on the above
issues. Idaho Power’s reporting on this feedback is included in Appendix 1 as the Technical
Review Committee Study Plan. The settlement stipulation is also provided in Appendix 1.
This study’s treatment of correlation between solar, wind, and load is particularly noteworthy.
Specifically, Idaho Power’s statistical analysis accounted for combining effects occurring when
these three components of the load and resource balance—solar, wind, and load—are netted.
DATA GATHERING AND SCENARIO DEVELOPMENT
A critical element of the solar integration study is the solar generation data developed for the
studied solar build-out scenarios. For Idaho Power’s solar integration study, the solar build-out
scenarios in Table 3 were studied.
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Table 3
Solar build-out scenarios studied
Installed Capacity of Solar Build-Out Scenarios
Site Data Source 400 MW 800 MW 1,200 MW 1,600 MW
Parma, ID USBR AgriMet 50 100 150 200
Murphy Flats, ID SolarAnywhere 25 50 75 100
Boise, ID USBR AgriMet 25 50 75 100
Grand View, ID SolarAnywhere 75 150 225 300
Orchard, ID SolarAnywhere 100 200 300 400
Bliss, ID SolarAnywhere 25 50 75 100
Twin Falls, ID USBR AgriMet 50 100 150 200
Aberdeen, ID USBR AgriMet 50 100 150 200
Total MW 400 800 1,200 1,600

The above build-out scenarios were developed in consultation with the TRC to represent
geographically dispersed build-outs of solar power plant capacity as informed by locations of
proposed solar power plants in southern Idaho and eastern Oregon. Three years of solar data
were developed for each build-out scenario: water years 2011, 2012, and 2013. By convention,
a water year is from October 1 to September 30 and is designated by the calendar year in which
the 12-month period ends. For example, water year 2013 is the 12-month period from October 1,
2012 through September 30, 2013.
The sites from the solar build-out scenarios are part of the established United States Bureau of
Reclamation (USBR) AgriMet Network (AgriMet) and modeled data from SolarAnywhere.
AgriMet is a satellite-based network of automated agricultural weather stations operated and
maintained by the USBR. The stations are located in irrigated agricultural areas throughout the
Pacific Northwest and are dedicated to regional crop water-use modeling, agricultural research,
frost monitoring, and integrated pest and fertility management. Idaho Power worked directly
with the USBR Pacific Northwest Region AgriMet manager to obtain data for the sites.
AgriMet data was augmented with data from the University of Oregon Solar Radiation
Monitoring Laboratory when AgriMet data was incomplete.
An alternative data-gathering approach was necessary for the Grand View, Murphy, Orchard,
and Bliss sites, for which only 15-minute or no data was available. To acquire 5-minute data for
these sites, Idaho Power contracted with SolarAnywhere to provide high-resolution modeled
solar data. SolarAnywhere uses hourly satellite images processed using the most current
algorithms developed and maintained by Dr. Richard Perez at the University at Albany (SUNY).
The algorithm extracts cloud indices from the satellite’s visible channel using a self-calibrating
feedback process capable of adjusting for arbitrary ground surfaces. The cloud indices are used
to modulate physically-based radiative transfer models describing localized
clear-sky climatology.
The eight sites are spread across southern Idaho and cover over 220 miles from east to west
(Figure 2). Sites represent elevations ranging from 2,300 feet to 4,900 feet (Table 4). All data
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used in the integration study are 5-minute interval global horizontal irradiance data from each
site. The use of high-resolution (5-minute interval) data is critical to characterizing the variability
of solar.

Figure 2
Solar data sites used in IPC’s solar integration study
Table 4
Solar data site latitude, longitude, and elevation used in IPC’s solar integration study
Station Latitude (N) Longitude (W) Elevation (feet) Elevation (meters [m])
Parma, ID 43.80 116.93 2,305 702
Murphy Flats, ID 43.21 116.43 3,029 923
Boise, ID 43.60 116.18 2,720 829
Grand View, ID 42.91 116.06 2,580 786
Orchard, ID 43.27 115.88 3,223 982
Bliss, ID 42.95 114.85 3,443 1,049
Twin Falls, ID 42.55 114.35 3,920 1,195
Aberdeen, ID 42.95 112.83 4,400 1,341

Wavelet-Based Variability Model
The available solar data represents conditions at a single point. To better reflect conditions at a
solar plant size, Idaho Power used the wavelet-based variability model (WVM) developed by Dr.
Matt Lave of Sandia National Labs (Lave et al. 2013a,b). WVM is designed for simulating solar
PV power plant output given a single irradiance point-sensor time series. The application of the
WVM to the point-sensor time series produces a variability reduction reflecting an upscaling of
the point-source data to a solar plant-sized area. Research and use of the WVM showed it is not
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useable at time steps (intervals) greater than 10 minutes and that time steps greater than
5 minutes may under-represent variability in dispersed systems.
Solar Plant Characteristics
This study assumes solar plants comprising the build-out scenarios occupy 7 acres per MW
of installed capacity. Solar plant sizes in the build-out scenarios, as well as figures presented for
solar generation, are in terms of AC (alternating current) MW. PV panels are assumed to be of
standard crystalline silicon manufacture. Panels are assumed to be single-axis tracking and tilted
at latitude. Illustrations and data summarizing the solar production of the studied build-outs are
provided in Appendix 1.
STATISTICAL-BASED ANALYSIS OF SOLAR,
WIND, AND LOAD DATA
The impacts and costs of integrating an intermittent energy source, such as solar, are driven by
the inherent variability and uncertainty in level of production. The variability and uncertainty in
level of production has the impact of requiring dispatchable generators to carry additional
capacity in reserve to enable the bulk power system to maintain a balance between customer
demand and generation. Thus, the two critical components of studying the integration of solar, or
other intermittent energy sources, are as follows:
1. The statistical-based analysis to determine the extent to which solar brings additional
variability and uncertainty to system balancing
2. The follow-on analysis to translate the additional variability and uncertainty to additional
capacity in reserve required on dispatchable generators.
In considering the impact of variability and uncertainty from the perspective of integration
impacts and costs, the focus is primarily on shorter-term operations. That is, for the system
operator responsible for maintaining system balancing, integration impacts arise because of
variability and uncertainty over the coming minutes, hours, or perhaps days. Viewed from this
perspective, the relevant components of system balancing which bring variability and uncertainty
are customer demand (load) and intermittent sources of energy (solar and wind). Because of the
relevance of these three components—load, solar, and wind—to the challenges with maintaining
shorter-term system balancing, the statistical-based analysis performed for this study takes into
account variability and uncertainty for the three components, as well as possible
interrelationships in variability and uncertainty between the three.
The statistical-based analysis for the study first focused on separate characterizations of
variability and uncertainty for load, wind, and solar. The products of the separate
characterizations are defined mathematical relationships expressing the extent of variability and
uncertainty for each of load, wind, and solar as functions of certain conditions. An August 2012
NREL Conference Paper (Ibanez et al. 2012) describes this approach as defining the operating
reserves needed for each of load, wind, and solar as a function of explanatory variables,
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where differences in the amount of needed reserves can be expressed as a function of the
explanatory variables.
After defining the amount of reserves needed separately for each of load, wind, and solar,
the statistical-based analysis focused on determining how to combine the separately defined
reserve amounts in an appropriate manner for the combination of load with wind, and for the
combination of load with wind and solar. This step of the analysis necessarily takes into account
the combining effects occurring when netting load with wind, or load with wind and solar.
Because of the combining effects that occur when netting load, wind, and solar, the separately
determined reserve amounts for each of the three are not added arithmetically, but instead are
added through mathematical operations that properly account for the combining effects taking
place (e.g., root-sum-of-squares operation). The derivation of the mathematical operations is
described later in this section of the report.
Hour-Ahead Forecasting
This study was focused on the assessment of variability and uncertainty as occurring from the
perspective of hour-ahead forecasting. This assessment for each of load, wind, and solar was
based on the extent to which 5-minute observations differ from hour-ahead forecasts.
These differences, or deviations, between intra-hour observations and hour-ahead forecasts drive
the need to carry operating reserves to maintain system balancing. Thus, at a fundamental level,
the statistical-based analysis to characterize variability and uncertainty was an analysis of
deviations between 5-minute observations and hour-ahead forecasts. Further, explanatory
variables were identified that explain patterns in the deviations, and these explanatory variables
were then used to more precisely define the operating reserve requirements.
Load—Analysis of Variability and Uncertainty
This study found the amount of operating reserve necessary for load variability and uncertainty
can be expressed as a function of the following explanatory variables:
 Month (January, February, …, December)
 Clock hour of day (00:00-01:00, 01:00-02:00, …, 23:00-00:00)
Hour-ahead forecast for load is based on a persistence of load occurring during the period from
45 to 30 minutes prior to the start of the hour being forecast, with a scaling factor applied equal
to the percentage change for the same hour for the previous day. For example, the load forecast
for June 15, 12:00–13:00 would be the observed load during the period from 11:15–11:30
multiplied by the ratio of 12:00–13:00 load to 11:15–11:30 load for June 14.
Deviations are calculated as the difference between observed 5-minute load and the
corresponding hour-ahead hourly average load forecast (observed minus forecast). A positive
deviation represents intra-hour load greater than hour-ahead forecast, an event requiring
dispatchable generators to have generating capacity in reserve that can be turned up to respond.
Conversely, a negative deviation represents intra-hour load less than hour-ahead forecast,
requiring dispatchable generators to have generating capacity in reserve that can be turned down
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to respond. The period of record for the load data analyzed is December 2009 through
November 2015.
The objective of the analysis of deviations is to determine the bidirectional reserve amounts
capturing a target percentage of the deviations. For this study, the bidirectional reserve amounts
were designed to capture a target of 99 percent of the deviations (one-half percent at each tail).
The deviation data were binned based on month and then clock hour. Two values were then
calculated for each bin: 1) P0.5, which is the 0.5th-percentile value for the deviation data,
and 2) P99.5, which is the 99.5th-percentile value for the deviation data. Thus, for each
combination of month and clock hour (12 x 24 = 288 combinations), the amount of load-caused
bidirectional reserve can be specified.
For the purposes of this study, Idaho Power adopted the term INC for the up-direction reserve
and DEC for the down-direction reserve. In the assessment of load variability and uncertainty,
the P0.5 value represents DEC reserve and the P99.5 value represents INC reserve.
The target to capture 99 percent of deviations for this study is considered appropriate in ensuring
generators have sufficient reserve requirements for all but approximately 90 hours per year.
Importantly, the targeted 99 percent is the criterion held for both simulations performed for this
study: the base case simulation of load combined with wind, and the test case simulation of load
combined with wind and solar. This ensures both simulations are designed to bring about an
equivalent level of system reliability, rendering the selected reliability level relatively immaterial
from the perspective of comparing production cost differences between paired simulations.
Wind—Analysis Variability and Uncertainty
This study found the amount of operating reserve necessary for wind variability and uncertainty
can be expressed as a function of the following explanatory variable:
 Hour-ahead forecast for wind production
Hour-ahead forecast for wind production is based on a persistence of wind production occurring
during the period from 45 to 30 minutes prior to the start of the hour being forecast. For example,
the wind production forecast for June 15, 12:00–13:00 would be the observed wind production
during the period from 11:15–11:30.
Deviations are calculated as the difference between observed 5-minute wind production and the
corresponding hour-ahead hourly average wind production forecast (observed minus forecast).
To illustrate, the population of deviations for the wind production data analyzed is plotted in
Figure 3. The plot illustrates the magnitude of deviations as a function of hour-ahead forecast
wind production on the horizontal axis. The plot notes that a positive deviation represents intra-
hour wind production greater than hour-ahead forecast, an event requiring dispatchable
generators to have generating capacity in reserve that can be turned down to respond.
Conversely, a negative deviation represents intra-hour wind production less than hour-ahead
forecast, requiring dispatchable generators to have generating capacity in reserve that can be
turned up to respond. The period of record for the wind production data analyzed is December
2012 through November 2015. The wind production data are observed production for wind
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projects having long-term energy sales agreements with Idaho Power during the period of record.
The energy sales agreements are both through PURPA and power purchase agreement (PPA),
and total installed capacity of the wind projects analyzed is 678 MW.

Figure 3
Wind production deviations (5-minute wind production minus hour-ahead forecast hourly average wind
production). Period of record December 2012 through November 2015.
The objective of the analysis of deviations is to determine the bidirectional reserve amounts
capturing a target percentage of the deviations. For this study, the bidirectional reserve amounts
were designed to capture a target of 99 percent of the deviations (one-half percent at each tail).
It is evident from the plot in Figure 3 that the magnitude of deviations varies as a function of
hour-ahead forecast wind. Thus, the bidirectional reserve amounts can be more precisely defined
if calculated after binning the data based on the level of hour-ahead forecast wind production.
The deviation data were divided into 20 equal-sized bins based on level of hour-ahead forecast
wind production. Three values were calculated for each bin: 1) the median hour-ahead forecast,
2) P0.5, which is the 0.5th-percentile value for the deviation data, and 3) P99.5, which is the
99.5th-percentile value for the deviation data. Figure 4 illustrates the P0.5 and P99.5 values for
the example deviations, as well as third-order polynomial trend lines fitted to both data streams.
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The fitted trend lines were used to define the amounts of bidirectional reserve associated with
wind variability and uncertainty. In the assessment of wind variability and uncertainty, the P0.5
value represents INC reserve, dispatchable generating capacity in reserve that can be turned up in
response to lower than expected wind production. The P99.5 value represents DEC reserve,
dispatchable generating capacity in reserve that can be turned down in response to higher than
expected wind production.

Figure 4
Wind production deviations with fitted trend lines for bidirectional wind reserve as function of hour-ahead
forecast wind production
As a result of the analysis of wind production data, the amount of wind-caused bidirectional
reserve can be defined for any given hour based on the level of hour-ahead forecast
wind production.
Solar—Analysis of Variability and Uncertainty
This study found the amount of operating reserve necessary for solar variability and uncertainty
can be expressed as a function of the following explanatory variables:
 Hour-ahead forecast for solar production
 Time of day (eight, 3-hour blocks: 00:00–03:00, 03:00–06:00, …, 21:00–00:00)
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Hour-ahead forecast for solar production is based on a persistence of percentage of clear-sky
production, where clear-sky production is the physically determinable maximum production
level for a given date and time. The forecast is based on the observed percentage of clear-sky
production occurring during the period from 45 to 30 minutes prior to the start of the hour being
forecast. For example, the solar production forecast for June 15, 12:00–13:00 would be the
observed percentage of clear-sky production during the period from 11:15–11:30.
Deviations are calculated as the difference between observed 5-minute solar production and the
corresponding hour-ahead hourly average solar production forecast (observed minus forecast).
To illustrate, the population of deviations for the three years of solar production data at the 800-
MW build-out for the time of day from 12:00–15:00 is plotted in Figure 5. The plot illustrates the
magnitude of deviations as a function of hour-ahead forecast solar production on the horizontal
axis. The plot notes that a positive deviation represents intra-hour solar production greater than
hour-ahead forecast, an event requiring dispatchable generators to have generating capacity in
reserve that can be turned down to respond. Conversely, a negative deviation represents intra-
hour solar production less than hour-ahead forecast, requiring dispatchable generators to have
generating capacity in reserve that can be turned up to respond.

Figure 5
Solar production deviations (5-minute solar production minus hour-ahead forecast hourly average solar
production). Period of record October 2010 through September 2013. 800-MW solar build-out. Period of
day 12:00–15:00.
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The objective of the analysis of deviations is to determine the bidirectional reserve amounts
capturing a target percentage of the deviations. For this study, the bidirectional reserve amounts
were designed to capture a target of 99 percent of the deviations (one-half percent at each tail).
It is evident from the plot in Figure 5 that the magnitude of deviations varies as a function of
hour-ahead forecast solar. Thus, the bidirectional reserve amounts can be more precisely defined
if calculated after binning the data based on the level of hour-ahead forecast solar production.
The deviation data were divided into 24 equal-sized bins based on the level of hour-ahead
forecast solar production. Three values were calculated for each bin: 1) the median hour-ahead
forecast, 2) P0.5, which is the 0.5th-percentile value for the deviation data, and 3) P99.5, which is
the 99.5th-percentile value for the deviation data. Figure 6 illustrates the P0.5 and P99.5 values
for the example deviations, as well as second-order polynomial trend lines fitted to both data
streams. The fitted trend lines were used to define the amounts of bidirectional reserve associated
with solar variability and uncertainty. Similarly derived trend lines were determined for the other
seven time-of-day periods, although it is noted that the first two time-of-day periods (00:00–
03:00, 03:00–06:00) have no deviation data and consequently no solar-caused reserve
requirements, and the last time-of-day period (21:00–00:00) has minimal data and small
solar-caused reserve requirements. The process was replicated for each solar build-out.
In the assessment of solar variability and uncertainty, the P0.5 value represents INC reserve,
dispatchable generating capacity in reserve that can be turned up in response to lower than
expected solar production. The P99.5 value represents DEC reserve, dispatchable generating
capacity in reserve that can be turned down in response to higher than expected solar production.
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Figure 6
Solar production deviations (5-minute solar production minus hour-ahead forecast hourly average solar
production). Period of record October 2010 through September 2013. 800-MW solar build-out. Period of
day 12:00–15:00. Fitted trend lines for bidirectional solar reserve as function of hour-ahead forecast solar
production.
As a result of the analysis of solar production data, the amount of solar-caused bidirectional
reserve can be defined for any given hour based on two explanatory variables: 1) hour-ahead
forecast solar production, and 2) time of day.
Reserve for Load Combined with Wind
The base case production cost simulations assumed operating reserve necessary to manage
variability and uncertainty for load combined with wind. As noted earlier in this section,
because of combining effects that occur when netting load and wind, the amount of operating
reserve necessary for the combination is not the arithmetic addition of the separately determined
operating reserve amounts. In fact, wind and load are widely recognized as independent
(near zero correlation), and the operating reserve for the combined wind and load is commonly
considered to be theoretically formed by combining the separately determined operating reserve
amounts for load and wind through the root sum of squares (RSS) operation (Ela et al. 2009).

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The RSS formulas for INC and DEC are stated as follows:
INCload with wind = sqrt(INCload2 + INCwind2)
DECload with wind = sqrt(DECload2 + DECwind2)
Thus, for any given hour in the study’s production cost simulations, the separate amounts of
INC/DEC associated with load and wind variability can be determined based on the explanatory
variables occurring for the hour (e.g., level of wind production forecast), and the amount of
INC/DEC for the combined load and wind is then based on combining the separate amounts
through the RSS operation provided above.
The effectiveness of the RSS operation in covering variability and uncertainty occurring when
load and wind are combined was tested by applying the RSS to observed load and wind data for
water year 2013. When the separate INC/DEC amounts are combined through the RSS
operation, the percentage of intra-hour (i.e., 5-minute) observations for load combined with wind
occurring outside of the hourly INC/DEC reserve levels are 0.4 and 0.3 percent for the INC and
DEC reserve bounds, respectively. Recalling that the separately determined INC/DEC reserve
amounts for load and wind are based on a 99 percent confidence level (P99.5 and P0.5),
the percentages of observations not covered by the RSS-determined INC/DEC reserve levels
support the appropriateness of the RSS operation.
Reserve for Load Combined with Wind and Solar
The base case production cost simulations are compared to test case simulations, where the test
case simulations have INC/DEC necessary to manage variability and uncertainty in load netted
with wind and solar. As noted previously, because of combining effects, the amount of
INC/DEC reserve necessary when load, wind, and solar are netted is not the arithmetic sum of
the separately determined INC/DEC amounts. The preceding subsection of this report describes
the appropriateness of the RSS operation in determining the amount of INC/DEC reserve for
load combined with wind.
A challenge in deriving the amount of reserve for the test case (i.e., for load combined with wind
and solar) is determining the amount of solar-caused INC/DEC reserve to add to the
RSS-determined base case amount. Because of combining effects, the use of 100 percent of the
solar-caused INC/DEC is excessive, and results in fewer occurrences of insufficient INC/DEC
reserves than occurring in the base case. However, because of the incremental variability and
uncertainty associated with solar, it is also recognized that ignoring the solar-caused INC/DEC
(i.e., using 0 percent) is incorrect, and results in a frequency of insufficient INC/DEC reserves
exceeding that of the base case. Idaho Power determined the amount of incremental solar-caused
INC/DEC reserve to add to the RSS-determined base case level empirically by adjusting the
amount of solar-caused INC/DEC reserve (between 0 and 100 percent) until the frequency of
INC/DEC reserve insufficiencies matches that of the base case (0.4 and 0.3 percent respectively
for INC and DEC reserve bounds). This empirical approach ensures base and test case
simulations are held to the same standard with respect to stringency of reserve obligations.
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The formula statements for INC/DEC reserve for the load combined with wind and solar are
as follows:
INCload with wind and solar = sqrt(INCload2 + INCwind2) + X∙INCsolar
DECload with wind and solar = sqrt(DECload2 + DECwind2) + Y∙DECsolar
Where: Coefficients X and Y are determined empirically such that INC/DEC insufficiencies
for load with wind and solar match the frequency of INC/DEC insufficiencies for
load with wind

The empirically determined coefficients applied to solar-caused INC/DEC are provided in
Table 5. It is noted that for the 400-MW solar build-out the coefficient yielding the equivalent
frequency of DEC insufficiencies is 0.00.
Table 5
Coefficients for bidirectional solar reserve by solar build-out
Solar Build-Out INC Coefficient DEC Coefficient
400 MW 0.23 0.00
800 MW 0.43 0.25
1,200 MW 0.56 0.37
1,600 MW 0.64 0.40

The amounts of INC/DEC averaged over all hours for the three simulated water years for the two
cases are provided in Table 6.
Table 6
Average INC/DEC base and test cases by solar build-out (water year [WY] 2011–2013)
Solar Build-Out Base Case
Average INC
(MW)
Test Case
Average INC
(MW)
Base Case
Average DEC
(MW)
Test Case
Average DEC
(MW)
400 MW 169 175 226 226
800 MW 169 193 226 242
1,200 MW 169 215 226 263
1,600 MW 169 239 226 279
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Example Reserve Application
A key objective of the statistical analysis of variability and uncertainty is the development of
operating reserve guidelines, or rules, which provide to the system scheduler the appropriate
amount of reserve for any given load, wind, and solar combination. This subsection of the report
illustrates an example application of the operating reserve rules.
The following conditions are assumed for the example hour:
Hour being scheduled: June 15, 13:00–14:00
Hour-ahead wind forecast: 400 MW
Hour-ahead solar forecast: 500 MW (assume 800 MW of installed solar capacity)
Hour-ahead load forecast: 2,100 MW
For wind, Figure 4 provides that for an hour having a 400 MW hour-ahead forecast:
WindINC ≈ 250 MW (based on third-order polynomial below the zero axis)
WindDEC ≈ 180 MW (based on third-order polynomial above the zero axis)
For solar, Figure 6 provides that for an hour during the period 12:00–15:00 and having a 500
MW hour-ahead forecast:
SolarINC ≈ 190 MW (based on third-order polynomial below the zero axis)
SolarDEC ≈ 155 MW (based on third-order polynomial above the zero axis)
For load, analysis of deviations in hour-ahead load forecasts for June hour 13:00–14:00 provides:
LoadINC ≈ 95 MW
LoadDEC ≈ 85 MW
Given this information, the hour-ahead system scheduler for this example hour would schedule
the following reserve amounts on dispatchable generators for the base case (i.e., for the load
combined with wind case):
INC = sqrt(952 + 2502) = 267 MW
DEC = sqrt(852 + 1802) = 199 MW
The reserve amounts for the test case (i.e., for the load combined with wind and solar case) are:
INC = 267 MW + 0.43*(SolarINC) = 267 MW + 0.43*190 MW = 349 MW
DEC = 199 MW + 0.25*(SolarDEC) = 199 MW + 0.25*155 MW = 238 MW
Finally, the system scheduler for both cases is assured of the appropriateness of the reserve
amounts on the basis of the rigor of the supporting statistical analysis of load, wind, and solar
data. That is, the statistical analysis indicates scheduling the above-calculated reserve amounts
positions the system in both cases to cover approximately 99 percent of possible observations
for both time series (load combined with wind, and load combined with wind and solar).
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PRODUCTION COST SIMULATION ANALYSIS
Hourly production cost simulations for the study were performed using a paired, base case versus
test case design. The critical difference between the cases is the amount of capacity in reserve
(i.e., INC/DEC). The amount of capacity in reserve for the base case simulation is based on that
carried for the load combined with wind time series described in the preceding section, whereas
the amount of capacity in reserve for the test case is based on that carried for the load combined
with wind and solar time series. All other inputs are identical between the paired simulations.
The incremental reserve requirements of the test case (summarized in Table 6) lead to production
cost differences between it and the base case. Over a simulated year, the test case costs exceed
those of the base case. Because inputs between the cases are identical with the exception of the
amount of capacity in reserve, the greater costs of the test case can be attributed to its
incremental reserve requirements. This production cost difference is considered the cost to
integrate solar.
Design of Simulations
Three water years were simulated for the production cost simulations: water years 2011, 2012,
and 2013. The three simulated water years correspond well to high-type (2011), medium-type
(2012), and low-type (2013) water years for the Snake River Basin. An illustration of the water
conditions for 2011–2013 in relation to other historical years is provided in Appendix 1.
The Idaho Power generating and transmission system as it exists at the time of issue of this
report is assumed for the production cost simulations. Critical elements of the simulated system
of generating resources include 17 hydroelectric facilities totaling 1,709 MW of nameplate
capacity, 3 coal-fired facilities totaling 1,118 MW of nameplate capacity, and 3 natural gas-fired
facilities totaling 762 MW of nameplate capacity. An illustration of the generating resources is
provided in Appendix 1.
Idaho Power’s critical interconnections to the regional market are over the Idaho–Northwest,
Idaho–Utah (Path C), and Idaho–Montana paths. For the solar integration study modeling,
the separate paths were combined to an aggregate path for off-system access. Purchases from the
regional market are treated separately from sales to the regional market. Net firm purchases from
the market are limited on a monthly basis to only the capacity and energy required to serve
Idaho Power’s retail load. Sales to the market are limited to 500 MW in every hour. This profile
of purchases and sales reflects the current capabilities of Idaho Power’s transmission system.
Idaho Power is pursuing the development of the Boardman to Hemingway Transmission Project
(B2H), which will increase Idaho Power’s access to the Northwest to make additional purchases
and sales. However, the transmission line’s current in-service date is at least five years into the
future. Previous integration studies have shown that unless there is a liquid capacity balancing
market, B2H will not significantly impact the solar integration cost. Idaho Power is actively
engaged in discussions about regional markets that could exist when B2H is completed. The
benefits of a market are highly dependent on its design. This study investigated as a sensitivity
analysis a market design similar to that existing for the California Independent System Operator
(CAISO) Energy Imbalance Market (EIM).
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Simulation Inputs
Table 7 provides key inputs to the solar integration study hourly production cost simulations of
water years 2011, 2012, and 2013. To capture interrelationships between variables, inputs to the
simulations are synchronous, with the exception of production from non-wind PURPA resources
and geothermal PPAs, which is not interrelated to the other inputs.
Table 7
Inputs for the solar integration study hourly production cost simulations
Input Water Year 2011 Water Year 2012 Water Year 2013
Solar production Water year 2011 Water year 2012 Water year 2013
Snake River streamflows Water year 2011 Water year 2012 Water year 2013
Customer demand Water year 2011 Water year 2012 Water year 2013
Nymex—Natural gas prices Water year 2011 Water year 2012 Water year 2013
Mid-C—Electric power market prices Water year 2011 Water year 2012 Water year 2013
Non-wind PURPA1 ------------Forecast calendar year 2016----------
Wind (PURPA and PPA)1 Water year 2011 Water year 2012 Water year 2013
Geothermal PPAs -----------------Water year 2015---------------------
1 PPA and PURPA represent facilities from which generation is contractually purchased as a PPA or under PURPA.

Wind capacity under contract more than tripled during the three consecutive water years being
simulated; capacity under contract was 208 MW at the start of water year 2011 and grew to the
current level of 678 MW by January 2013. Because of the substantial growth in wind capacity,
observed wind generation occurring prior to reaching the current capacity level was adjusted
upwards to normalize this production to the current capacity level. For example, observed wind
production occurring during October through December 2010 was adjusted upwards by a factor
of 3.3 (678 MW ÷ 208 MW) to normalize the observed production from the 208 MW actually
on-line during the 3-month period to the current capacity level of 678 MW. The expansion in
wind capacity under contract is illustrated as Figure 7. Monthly wind energy production used in
the modeling, at unadjusted and adjusted levels, is included in Appendix 1.
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Figure 7
Installed nameplate wind capacity under contract, water years 2011–2013.
Energy purchased from non-wind PURPA qualifying facilities is input to the simulations as
forecast in April 2015 for calendar year 2016. The monthly energy from the non-wind PURPA
facilities is included in Appendix 1.
Baseload generation from geothermal facilities contractually selling to Idaho Power under PPAs
is input as currently projected from these facilities. The amount of baseload generation delivered
from these facilities varies seasonally. The amount used in the production cost simulations
ranges from 22 MW to 32 MW.
Simulation model
Idaho Power used an internally developed system operations model for the solar integration
study. The model determines optimal hourly scheduling of dispatchable hydro and thermal
generators with the objective of minimizing production costs while honoring constraints imposed
on the system. System constraints used in the model capture numerous restrictions governing the
operation of the power system, including the following:
 Reservoir headwater constraints
 Minimum reservoir outflow constraints
 Reservoir outflow ramping rate constraints
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 Generator minimum/maximum output levels
 Market purchase/sale constraints
 Generator ramping rates
The model also stipulated that load and resource were exactly in balance and, importantly, that
hourly reserve requirements were satisfied. The differing amount of capacity in reserve held to
manage variability and uncertainty in solar production drives the production cost differences
between the study’s two cases. The derivation of the capacity in reserve for the two simulation
cases is described previously in this report.
Contingency Reserve Obligation
The study of integration impacts and costs focuses on the need to carry bidirectional capacity in
reserve for maintaining compliance with reliability standards. However, balancing authorities,
such as Idaho Power, are also required to carry unloaded capacity in reserve for responding to
system contingency events, which have traditionally been viewed as large and relatively
infrequent system disturbances affecting the production or transmission of power (e.g., the loss
of a major generating unit or major transmission line). System modeling for the solar integration
study imposes a contingency reserve intended to reflect this obligation equal to 3 percent of load
and 3 percent of generation, setting aside this capacity for both study cases (i.e., base and test).
Flexible Capacity Resources
The focus of the production cost simulations for the solar integration study is the real-time
market activities occurring as part of hour-ahead system scheduling. The study assumes
hour-ahead schedulers require the delivery of hour-ahead forecasts for load, wind, and solar
30 minutes prior to the start of the operating hour being scheduled. Hour-ahead scheduling is
then assumed binding, and excursions from hour-ahead forecast levels occurring during the
operating hour being scheduled must be managed by Idaho Power’s system.
To manage the excursions from hour-ahead forecasts during the operating hour, Idaho Power
must schedule bidirectional (INC/DEC) capacity in reserve on dispatchable generators. In the
modeling for the study, this capacity in reserve is scheduled on Hells Canyon Complex (HCC)
hydroelectric generators (Brownlee, Oxbow, and Hells Canyon), natural gas-fired generators
(Langley Gulch, Danskin, and Bennett Mountain), and Jim Bridger coal-fired generators.
The allocation of reserve to these generators matches Idaho Power’s practice for balancing
variations in wind production and load.
RESULTS
The objective of the Idaho Power solar integration study is to determine the costs of the
operational modifications necessary to integrate solar PV power plant generation. The integration
costs are driven by the need to carry extra capacity in reserve to allow bidirectional response
from dispatchable generators to unplanned changes in solar production. The simulations
performed for the Idaho Power solar integration study indicate the following costs associated
with holding the extra solar-caused capacity in reserve (Table 8). Integration costs are provided
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in nominal terms for the simulated years and in terms assuming a base year of 2016. The costs
are not averaged or levelized over the life of a solar plant.
Table 8
Integration cost per MWh for solar build-out scenarios
Solar Build-
Out
Scenario
Water Year
with Hydro
Level
Test – Base
Cost Difference
Solar MWh Nominal Solar
Integration Costs per
megawatt-hour (MWh)
2016$ Solar
Integration Costs
per MWh1
2011 (high) $303,954 607,961 $0.50 $0.56
400 MW 2012 (med) $85,288 607,960 $0.14 $0.15
2013 (low) $58,014 607,529 $0.10 $0.10
2011 (high) $1,079,810 1,219,244 $0.89 $0.99
800 MW 2012 (med) $338,632 1,225,743 $0.28 $0.30
2013 (low) $496,770 1,217,423 $0.41 $0.44
2011 (high) $1,654,781 1,831,956 $0.90 $1.01
1,200 MW 2012 (med) $730,371 1,844,933 $0.40 $0.43
2013 (low) $1,088,246 1,828,441 $0.60 $0.64
2011 (high) $2,492,214 2,451,006 $1.02 $1.13
1,600 MW 2012 (med) $1,307,219 2,475,258 $0.53 $0.58
2013 (low) $1,914,841 2,451,870 $0.78 $0.83
1 Escalation to 2016 base year using 2015 Integrated Resource Plan (IRP) general operations and maintenance (O&M)
escalation rate of 2.2%.

The integration costs provided in Table 8 indicate a consistent pattern of higher integration costs
for higher water conditions. Idaho Power has discussed this result with the TRC, and has
communicated that during higher water years system flexibility can be highly constrained.
Averaging over the three simulated water years yields the following integration costs (Table 9).
Table 9
Average integration cost per MWh for solar build-out scenarios
0–400 MW 0–800 MW 0–1,200 MW 0–1,600 MW
Integration cost
(2016$)
$0.27/MWh $0.57/MWh $0.69/MWh $0.85/MWh

The integration cost results in Table 9 are the cost per MWh (2016$) to integrate the full
installed solar power plant capacity at the respective scenarios studied. For example,
the integration cost results indicate the total solar power plant capacity making up the 400 MW
build-out scenario brings about costs of $0.27 for each MWh integrated.
Integration costs can be expressed alternatively in terms of incremental costs. Integration costs
when expressed incrementally assume early projects are assessed lesser integration costs,
and later projects need to make up the difference to allow full cost recovery for a given build-out
scenario. For example, if solar plants comprising the first 400-MW build-out are assessed
integration costs of $0.27/MWh, then plants comprising the increment between 400 MW and 800
Solar Integration Study Report Idaho Power Company
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MW need assessed integration costs of $0.88/MWh to allow full recovery of the $0.57/MWh
costs to integrate 800 MW of solar plant capacity. Incremental solar integration costs are
provided in Table 10.
Table 10
Incremental integration cost results for solar build-out scenarios
0–400 MW 400–800 MW 800–1,200 MW 1,200–1,600 MW
Integration cost
(2016$)
$0.27/MWh $0.88/MWh $0.92/MWh $1.31/MWh
Energy Imbalance Market Sensitivity Analysis
Idaho Power is currently investigating costs and benefits of participation in EIMs such as that
managed by the Western EIM (formerly referred to as the California Independent System
Operator or CAISO). Among the benefits commonly associated with an EIM is its capability to
provide flexibility for balancing variable energy sources, such as solar. It is noted that Idaho
Power’s current investigation of EIM costs and benefits is a comprehensive analysis focusing on
benefits beyond those associated with integration of variable energy sources.
Idaho Power conducted a sensitivity analysis for the solar integration study to provide
preliminary assessment of EIM benefits related to solar integration. For this preliminary EIM
sensitivity analysis, the company assumed wholesale energy market trading is performed on a
15-minute window instead of hourly. The shortened trading window is assumed to allow a
reduction in operating reserve requirements. The EIM sensitivity analysis indicates potential
integration benefits associated with EIM participation, including the potential for reduced
integration costs. Idaho Power emphasizes that contemplated EIMs are not expected to trade
capacity products (i.e., operating reserves); thus, the capability to satisfy all or part of INC/DEC
reserve requirements through EIM participation is not anticipated.
The sensitivity’s indication of integration benefits is considered preliminary. Idaho Power will
continue its ongoing investigation of costs and benefit of participating in an EIM. Once that
investigation is completed, the company will have more information for estimating the potential
level of impact an EIM might have on solar integration costs.
Study Findings
Hour-ahead Solar Production Forecasting
Analyses suggest a persistence-based forecast with adjustment to account for known changes
in the sun’s position provides a reasonable production forecast for hour-ahead operations
scheduling. The persistence-based, hour-ahead solar production forecast used for the study is
based on observed production and, consequently, could be readily adopted in practice.
While a day-ahead solar production forecast would be necessary in practice for a balancing
authority integrating solar, this study assumes deviations from the day-ahead forecast can be
Idaho Power Company Solar Integration Study Report
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managed through a combination of market transactions and operations modifications,
and, consequently, the study imposes no reserve requirement to cover deviations for day-ahead
solar production forecasts.
Compared to wind, system operators managing a balancing authority integrating solar would
have the benefit of at least 6 hours at the start of day with no or little solar production.
During this period of no or little solar production, system operators could evaluate the day-ahead
solar production forecast using information from updated weather forecast products and begin to
plan for necessary actions to manage deviations from the day-ahead solar production forecast.
Figure 8 plots daily production (MWh) versus month for the 678 MW of wind capacity Idaho
Power integrates (January 2013–September 2015 data) and for the 800-MW solar build-out
(data for water years 2011–2013). The graph (Figure 8) demonstrates that daily production for
solar follows an intuitive seasonal pattern of high summer and low winter production, and that
the distribution of daily production is markedly narrower for solar compared to wind. The lower
variability in daily solar production, evident by the narrower distribution for all months, is
indicative of the relative challenges associated with day-ahead forecasting of wind and
solar production.
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Figure 8
Distributions of daily MWh by month for wind and solar (800-MW solar build-out).
In contrast to day-ahead production forecasting, deviations from the hour-ahead solar production
forecast can only be covered by Idaho Power’s dispatchable generators. By design, the analysis
for the solar integration study determines the amounts of bidirectional capacity in reserve that
system operators would need to schedule to position dispatchable generators to cover possible
deviations from the hour-ahead solar production forecast. The integration costs found by the
study are a result of the solar-caused capacity in reserve, specifically the sub-optimal scheduling
of dispatchable generators associated with the extra reserve amounts.
Comparison to Wind Integration
This study indicates solar plant integration costs are substantially lower than wind plant
integration costs found by Idaho Power studies of wind integration. The lower integration costs
associated with solar are fundamentally the result of less variability and uncertainty.
As described in the preceding section, the study assumes deviations in solar plant production
from day-ahead forecast levels can be managed through a combination of market transactions
and operations modifications, allowing day-ahead generation scheduling to avoid extra reserve
burden. Therefore, reserve carried for solar generation can be focused on readying dispatchable
generators to respond to unplanned solar excursions from hour-ahead production forecasts.
Qualitatively, the study data suggest solar is more predictable than wind generation connected to
the Idaho Power system. Sunrise and sunset times, as well as the time of solar noon, are a
certainty. The theoretical maximum level of production can be readily derived, reflecting
patterns on daily, monthly, and seasonal time scales. Finally, land requirements for a solar power
plant are likely to promote a relatively high level of dispersion, which is critical to the mitigation
of impacts from severe and abrupt ramps in production exhibited by individual panels in
response to passing clouds. The effects of geographic dispersion are discussed further in the
following section.
Geographic Dispersion and Solar Variability
Production for a single solar PV panel exhibits severe and abrupt intermittency during variably
cloudy conditions. The effect of severe and abrupt intermittency is commonly attributed to the
absence of inertia in the PV process. While the intermittency effect is severe for a single panel,
dampening occurs when considering the production from a solar plant-sized aggregation of
panels, and even further dampening occurs when considering the production from several solar
plants spread over a region such as southern Idaho. Therefore, geographic dispersion has
significant influence on solar integration impacts and is perhaps of greater importance for solar
than wind.
The four studied solar build-out scenarios each have capacity installed at eight southern Idaho
locations spread over more than 220 miles from east to west. Because of the substantial
geographic dispersion, severe instantaneous ramps in solar production for the study data are
relatively infrequent. If solar plant development in southern Idaho occurs in a more clustered
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fashion than assumed for this study, actual integration impacts and costs will be higher than the
results of this study.
The study’s characterizations of solar variability and uncertainty are based on solar production
time series as derived from AgriMet and SolarAnywhere point-source data; actual production
data for solar power plant locations in the southern Idaho area were not available for the study.
As production data become available over the coming years from solar projects connecting to the
Idaho Power system, the actual production data will be analyzed to compare their variability and
uncertainty characteristics to those of the derived production data used for the study.
The evidence of significant disparities in variability and uncertainty between the actual and study
production data will require a re-examination of the results of this study.
Transmission and Distribution
The focus of Idaho Power’s solar integration study is a macro-level investigation of the
operations modifications necessary to maintain balance between power supply and customer
demand for a balancing authority integrating PV solar plant generation. The objective is to
understand the impacts and costs of the sub-optimal operation of dispatchable generating
capacity. The study is not an investigation of integration issues related to the delivery of energy
from proposed solar PV power plants to the retail customer; these issues are addressed in
individual interconnection studies performed on a plant-by-plant basis.
Solar Integration Cost Elements
Idaho Power and the TRC engaged in several conceptual-level discussions on solar integration as
part of TRC meetings. These discussions are valuable opportunities to further the collective
conceptual-level understanding of Idaho Power and the TRC with respect to factors driving solar
integration costs and impacts. These discussions also highlighted the need to provide a listing of
those factors, or elements, considered to influence costs, and conversely those elements not
considered to influence costs. Based on this solar integration study, Idaho Power considers the
following as key elements influencing solar integration costs:
The need to carry bidirectional capacity in reserve on dispatchable generators to respond
to next-hour variability and uncertainty
Incremental Hells Canyon Complex spill attributable to solar-caused capacity in reserve
requirements
Conversely, the following are not considered as elements influencing solar integration costs:
Uncertainty in day-ahead forecasting of solar production
Solar production profiles, specifically coincidence between solar production and high/low
load, or coincidence between solar production and high/low wholesale electric power
market prices
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Hells Canyon Complex Spill
The results indicate that spill at the Hells Canyon Complex increases with increasing solar build-
out. Corresponding to the increase in spill is a decrease in Hells Canyon Complex production.
For example, the decrease in simulated Hells Canyon Complex production for water year 2012
from the 400 MW to 1,600 MW solar build-out was about 250,000 MWh, which represents
approximately 13 percent of the incremental generation of the additional 1,200 MW of installed
solar capacity. The 250,000 MWh of lost Hells Canyon Complex generation is not included in
the integration costs in this report.
The finding of increased spill with increasing solar build-out is roughly equivalent for the paired
simulations; that is, spill increases for the base cases and test cases alike. This suggests that the
increased spill is more the result of energy oversupply than driven by solar-caused operating
reserves, noting that the paired simulations are energy equivalent and differ only in their
INC/DEC reserve requirements.
The lost hydro generation is partially an artifact of a modeling assumption of keeping the weekly
volumetric reservoir releases in the simulations equal to the historical record and partially a cost
that would be borne by the excessive development of solar via the avoided cost process. The
historic hydro operation would likely be modified in anticipation of the solar energy in an
attempt to use the hydro in the most economic way possible and reducing the spilled energy. The
avoided cost process with an increase of zero marginal cost energy has more hours where the
highest cost marginal resource is zero. The solar energy value during these hours is zero and
consequently does not “cost” the system anything. The solar is valued at the cost of the
displaced hydro which is zero.
Spring-Season Integration
The production cost simulations suggest reserve requirements are particularly problematic when
hydroelectric resources are highly constrained, such as frequently occurs during spring-season
periods characterized by high water, low customer demand, and high generation from variable
generating resources, such as wind and solar. Experience has shown wind integration to be
particularly challenging during these periods, and the simulations suggest similar challenges
integrating solar. This study finding is corroborated by NREL in the Western Wind and Solar
Integration Study Phase 2 (Lew et al. 2013), which reports the need for flexibility is notably high
during the spring and that during these periods the curtailment of variable generation is one
source of flexibility along with dispatchable generators enabling the balancing of generation and
customer demand. Under futures with high penetrations of solar and wind, the production from
the solar and wind resources could conceivably exceed customer demand for the Idaho
Power system. Even for the current system without high penetrations of solar, issues related to
energy oversupply are periodically encountered because of high wind production and must-run
generation (e.g., run-of-river hydro).
CONCLUSIONS
The cost to integrate the variable and uncertain delivery of energy from solar PV power plants is
driven by the need to carry extra capacity in reserve. This extra capacity in reserve is necessary
Idaho Power Company Solar Integration Study Report
Page 27
to allow bidirectional response from dispatchable generators to unplanned excursions in solar
production relative to hour-ahead forecasting. The simulations performed for this Idaho Power
solar integration study indicate costs as provided in the Results section associated with holding
the extra capacity in reserve (Tables 8 through 10).
The four studied build-outs have solar capacity dispersed widely across southern Idaho.
The extent of this geographic dispersion is considered to strongly influence the impacts and costs
of integration. As solar capacity is developed in the coming years, Idaho Power will evaluate the
geographic dispersion of the built-out capacity in comparison to that assumed for this study.
In particular, observed production data will be reviewed when available to verify this study’s
assessment of solar variability and uncertainty.
Solar Integration Study Report Idaho Power Company
Page 28
LITERATURE CITED
Ela E., M. Milligan, B. Parsons, D. Lew, and D. Corbus. 2009. The evolution of wind power
integration studies: Past, present, and future. IEEE Power & Energy Society General
Meeting, 2009 PES ‘09.
Ibanez, E., G. Brinkman, M. Hummon, and D. Lew. 2012. A solar reserve methodology for
renewable energy based on sub-hourly variability analysis. NREL/CP-5500-56169.
Golden, CO: National Renewable Energy Laboratory.
http://www.nrel.gov/docs/fy12osti/56169.pdf. Accessed February 2016.
Idaho Power. 2014. Solar Integration Study Report. Boise, ID: Idaho Power.
Idaho Power. 2013. Wind Integration Study Report. Boise, ID: Idaho Power.
Lave, M., A. Ellis, and J. Stein. 2013a. Simulating solar power plant variability:
A review of current methods. Sandia report—SAND2013-4757.
http://energy.sandia.gov/wp/wp-content/gallery/uploads/SAND2013-
4757_Simulating_Solar_Power_Plant_Variability__A_Review_of_Current_Methods_FI
NAL.pdf. Accessed February 2016.
Lave, M., J. Kleissl, and J. S. Stein. 2013b. A wavelet-based variability model (WVM) for solar
PV power plants. IEEE Transactions on Sustainable Energy, Vol. 4, No. 2.
Lew, D., G. Brinkman, A. Ibanez, A. Florita, M. Heaney, B. M. Hodge, M. Hummon, G. Stark,
J.King, S. A. Lefton, N. Kumar, D. Agan, G. Jordan, and S. Venkataraman. 2013.
Western Wind and Solar Integration Study Phase 2. NREL/TP-5500-55588. Golden, CO:
National Renewable Energy Laboratory. http://www.nrel.gov/docs/fy13osti/55588.pdf.
Accessed February 2016.
[UVIG and NREL]. Utility Variable-Generation Integration Group and National Renewable
Energy Laboratory. No date. Principles for Technical Review Committee (TRC)
involvement in studies of variable generation integration into electric power systems.
http://www.uvig.org/wp-content/uploads/2009/05/TRCPrinciplesJune2012.pdf.
Accessed February 2016.
Idaho Power Company Solar Integration Study Report
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Solar Integration Study Report Idaho Power Company
Page 30
Appendix 1
Solar integration study appendix
Table of Contents
Introduction
Technical Review Committee
List of TRC Members
Regulatory Commission Staff Observers
Data Inputs and Assumptions
Natural Gas Price Assumptions
Market Power Price Assumptions
IPC Customer Load Data
Idaho Power Existing Generation
Hydroelectric Generation Data
Run-of-River Projects
Wind Generation Data
Aggregate PPA and PURPA Projects
Non-Wind PURPA Generation Data
Solar Production Data
Settlement Stipulation
Technical Review Committee Study Plan
Idaho Power Company Solar Integration Study Report
Page 31
INTRODUCTION
This appendix contains supporting data and explanatory materials used to develop Idaho Power’s
2016 Solar Integration Study.
The main document, the 2016 Solar Integration Study, contains a full narrative of Idaho Power’s
process for studying solar integration costs. For information or questions concerning the study,
contact Idaho Power:
Idaho Power—Power Supply Planning
1221 W. Idaho St.
Boise, Idaho 83702
208-388-5365
TECHNICAL REVIEW COMMITTEE
The Technical Review Committee (TRC) was formed during early 2015 to provide input,
review, and guidance for the study. It is comprised of participants from outside Idaho Power that
have an interest and/or expertise with the integration of intermittent resources onto
utility systems.
Representatives from National Renewable Energy Laboratory (NREL) participated in the early
stages of the study, and contributed to the study’s foundational development. However,
NREL funding did not permit their active participation through study completion. Idaho Power
continued to include NREL on electronic correspondence related to the study through
study completion.
List of TRC Members
Brian Johnson...................University of Idaho
Cameron Yourkowski ......Renewable Northwest
Clint Kalich ......................Avista Corporation
Kurt Myers .......................Idaho National Laboratory
Barbara O’Neill ................National Renewable Energy Laboratory
Michael Milligan ..............National Renewable Energy Laboratory

Solar Integration Study Report Idaho Power Company
Page 32
Regulatory Commission Staff Observers
Brittany Andrus ................Public Utility Commission of Oregon (OPUC) staff
John Crider .......................OPUC Staff
Rick Sterling ....................Idaho Public Utilities Commission (IPUC) staff

DATA INPUTS AND ASSUMPTIONS
Natural Gas Price Assumptions
Table 1
Actual monthly average Idaho Citygate natural gas price for water years 2011–2013
Month
Water Year (WY) 2011
Average Monthly Price
WY 2012
Average Monthly Price
WY 2013
Average Monthly Price
October $3.15 $3.30 $3.32
November $3.63 $3.33 $3.48
December $4.00 $3.18 $3.35
January $4.22 $2.68 $3.38
February $3.91 $2.53 $3.32
March $3.76 $2.05 $3.71
April $3.93 $1.83 $3.92
May $3.98 $2.21 $3.82
June $4.23 $2.16 $3.22
July $4.00 $2.55 $3.36
August $3.80 $2.61 $3.05
September $3.73 $2.63 $3.21

Idaho Power Company Solar Integration Study Report
Page 33
Market Power Price Assumptions
Table 2
Actual average Mid-Columbia dollars/megawatt-hour (MWh) for water years 2011–2013
Month
WY 2011
Average Monthly Price
WY 2012
Average Monthly Price
WY 2013
Average Monthly Price
October $28.78 $24.27 $26.92
November $31.13 $27.40 $25.42
December $31.59 $28.96 $20.04
January $25.22 $24.51 $27.37
February $20.70 $21.64 $25.24
March $15.78 $13.61 $27.89
April $16.93 $7.02 $20.10
May $16.57 $6.56 $19.99
June $13.09 $4.40 $25.15
July $18.51 $7.90 $27.68
August $25.29 $19.16 $31.28
September $28.14 $22.63 $29.80

IPC Customer Load Data
Table 3
Actual average megawatt (MW) for water years 2011–2013
Month
WY 2011
Average Monthly Load
WY 2012
Average Monthly Load
WY 2013
Average Monthly Load
October 1,417 1,400 1,453
November 1,577 1,559 1,474
December 1,699 1,731 1,640
January 1,745 1,683 1,912
February 1,650 1,600 1,624
March 1,509 1,463 1,442
April 1,411 1,505 1,502
May 1,489 1,737 1,802
June 1,823 2,111 2,162
July 2,275 2,393 2,419
August 2,128 2,200 2,232
September 1,807 1,683 1,660
Solar Integration Study Report Idaho Power Company
Page 34
Idaho Power Existing Generation
Figure 1
Existing Idaho Power generating resources
Idaho Power Company Solar Integration Study Report
Page 35

Figure 2
Brownlee Reservoir inflow by water year
Hydroelectric Generation Data
Run-of-River Projects
Table 4
Actual monthly average MW (aMW) for water years 2011–2013
Month
WY 2011
aMW
WY 2012
aMW
WY 2013
aMW
October 435 451 191
November 374 423 166
December 470 419 177
January 346 360 178
February 373 369 188
March 348 383 178
April 505 391 164

Solar Integration Study Report Idaho Power Company
Page 36
Table 4 (Continued)
Month
WY 2011
aMW
WY 2012
aMW
WY 2013
aMW
May 517 256 351
June 510 341 231
July 418 295 227
August 435 254 218
September 458 211 197

Wind Generation Data
Aggregate PPA and PURPA Projects
Table 5
Actual monthly aMW for water years 2011–2013, unadjusted and adjusted (normalized) to 678 MW
on-line capacity level
WY 2011 WY 2012 WY 2013
Month aMW Online
capacity
Adjusted
aMW
aMW Online
capacity
Adjusted
aMW
aMW Online
capacity
Adjusted
aMW
October 51 208 167 95 395 164 151 638 161
November 74 208 241 190 417 309 201 638 214
December 84 208 272 120 500 162 221 638 234
January 80 273 200 194 500 264 181 678 181
February 110 373 200 167 500 227 261 678 261
March 125 373 228 191 500 259 240 678 240
April 141 373 257 172 500 233 267 678 267
May 141 395 241 166 500 225 209 678 209
June 119 395 205 163 500 221 176 678 176
July 93 395 160 144 523 187 152 678 152
August 79 395 135 131 638 139 141 678 141
September 73 395 125 116 638 123 196 678 196

Idaho Power Company Solar Integration Study Report
Page 37
Non-Wind PURPA Generation Data
Table 6
Based on April 2015 projections for calendar year 2016
Month WY 2011
aMW
WY 2012
aMW
WY 2013
aMW
October 78 78 78
November 49 49 49
December 48 48 48
January 45 45 45
February 47 47 47
March 51 51 51
April 81 81 81
May 122 122 122
June 127 127 127
July 125 125 125
August 119 119 119
September 108 108 108

Solar Integration Study Report Idaho Power Company
Page 38
Solar Production Data

Idaho Power Company Solar Integration Study Report
Page 39

Figure 3
400 MW build-out production graphs
Solar Integration Study Report Idaho Power Company
Page 40

Figure 4
800-MW build-out production graphs
Idaho Power Company Solar Integration Study Report
Page 41

Figure 5
1,200-MW build-out production graphs
Solar Integration Study Report Idaho Power Company
Page 42

Figure 6
1,600-MW build-out production graphs
Idaho Power Company Solar Integration Study Report
Page 43
SETTLEMENT STIPULATION
The first Idaho Power solar integration study was completed in June 2014. The first study
investigated integration of 4 solar PV build-outs: 100 MW, 300 MW, 500 MW, and 700 MW.
The costs from the first study were the basis for solar integration costs included in the IPUC
Schedule 87, which was part of a settlement stipulation approved by the IPUC in February 2015
(IPUC Case No. IPC-E-14-18). The settlement stipulation associated with the first Idaho Power
solar integration study is provided here.

DONOVAN E.WALKER (ISB No.5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O.Box 70
Boise,Idaho 83707
Telephone:[phone]
Facsimile:[phone]
dwalkercidahopower.com
Attorney for Idaho Power Company
E CE i
?i5 _9 I:37
tiTL.fl,:
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION TO
IMPLEMENT SOLAR INTEGRATION
RATES AND CHARGES.
)
)CASE NO.IPC-E-14-18
)
)SETTLEMENT STIPULATION AND
)MOTION TO APPROVE
)SETTLEMENT STIPULATION
)
This settlement stipulation (‘Settlement Stipulation”)is entered into between
Idaho Power Company (“Idaho Power”or “Company”);Idaho Public Utilities
Commission Staff (“Staff”);the Idaho Conservation League (“ICL’),the Sierra Club,and
the Snake River Alliance (“SRA”),hereafter jointly referred to as “Parties.”The Parties
hereby agree as follows.
I.INTRODUCTION AND MOTION
1.The terms and conditions of this Settlement Stipulation are set forth
herein.The Parties agree that this Settlement Stipulation represents a fair,just,and
reasonable compromise of the dispute(s)between the Parties and that this Settlement
Stipulation is in the public interest.The Parties maintain that the Settlement Stipulation
as a whole and its acceptance by the Idaho Public Utilities Commission (“Commission”)
represent a reasonable resolution of all issues between the Parties identified herein.
IPC-E-14-18 I
Joint Settlement and Motion
Therefore,the Parties hereby respectfully move the Commission,in accordance with
RP 56 and RP 274-76,for an Order approving the Settlement Stipulation executed
between the Parties and all of its terms and conditions without material change or
condition.
N.BACKGROUND
2.On July 1,2014,Idaho Power filed an Application with the Commission
requesting Commission approval of Idaho Power’s proposed implementation of solar
integration rates and charges as set forth in the proposed Schedule 87,Variable
Generation Integration Charges,as indicated by the 2014 Solar Integration Study
Report (“Solar Study”)filed with the Application.On July 23,2014,the Commission
issued a Notice of Application and Notice of Intervention Deadline.Order No.33079.
ICL,the Sierra Club,and SRA petitioned for intervention which was granted.Order No.
33090;Order No.33097.
3.On September 24,2014,the Commission issued a Notice of Scheduling
and Notice of Technical Hearing,Order No.33137,selling forth deadlines for testimony
and setting the Technical Hearing for November 13,2014.On November 6,2014,the
Commission approved the Parties’request to suspend the procedural schedule by
striking the rebuttal testimony filing deadline and Technical Hearing.The Parties
agreed to meet for settlement discussions and that if settlement discussions were
unsuccessful to re-establish mutually agreeable dates for the submission of rebuttal
testimony and a Technical Hearing.Order No.331 73.
4.The Parties met on November 17,2014,for settlement discussions and
reached agreement resolving the issues in this case and between the Parties.Based
upon the settlement discussions,as a compromise of the respective positions of the
IPC-E-14-18 2
Joint Settlement and Motion
parties,and for other consideration as set forth below,the Parties agree to the following
terms:
III.TERMS OF THE SETTLEMENT STIPULATION
5.Implementation of Schedule 87,Variable Generation Integration Charges -
The Parties agree to Commission approval and implementation of Schedule 87,
Variable Generation Integration Charges,including the rates and charges as proposed
and filed by Idaho Power in this proceeding to implement solar integration charges.
6.Initiation of a Second Solar Integration Study —The Parties acknowledge
that there are disagreements with respect to the methodology used in the 2014 Solar
Study.The Parties agree that Idaho Power will initiate a second solar integration study
in January 2015.This second solar integration study should be completed as
expeditiously as possible with the goal of not exceeding 12 months.Upon completion of
the second solar integration study Idaho Power will file the same with the Commission
seeking to update Schedule 87 with the results of said study.
7.Conduct of the Second Solar Integration Study -The Parties agree that
the second solar integration study should utilize a Technical Review Committee (“TRC”)
that generally adheres to the Principles for Technical Review Committee Involvement in
Studies of Wind Integration into Electric Power Systems authored by the National
Renewable Energy Laboratory and the Utility Wind Integration Group.The TRC should
include members with expertise in solar generation,variable energy integration,and
electrical grid operations.The Parties also anticipate participation in the second solar
integration study from the Idaho Public Utilities Commission Staff,the Public Utility
Commission of Oregon Staff,the appropriate personnel from Idaho Power,and a
technical expert designated by each of the Parties herein.The Parties agree that the
IPC-E-14-18 3
Joint Settlement and Motion
TRC will assist in developing the scope of the second solar integration study and
provide advice on the best available methods to analyze solar integration needs,
strategies,and costs on Idaho Power’s system.The Parties agree and acknowledge
that Idaho Power is ultimately responsible for determining how the study is conducted,
the content of the study,and any results therefrom.If Idaho Power declines TRC
member suggestions for the conduct of the study,Idaho Power shall provide
explanation and basis for the same in writing as part of the study process.
8.Consideration of Issues in the Second Solar lnteqration Study -The
Parties agree that Idaho Power,together with the TRC,will consider whether the
second solar integration study should include the following —and if so,what would be
the appropriate methodology to be used in connection with the following:
•Alternative water-year types (e.g.,low-type and high-type),range of water
years or normalized water year
•Intra-hour trading opportunities
•Shortening the hour-ahead forecast lead time from 45 minutes to 30
minutes
•Clustered solar build-out scenarios
•Other solar plant technologies (e.g.,tracking systems or varied fixed-panel
orientation)
•Correlation between solar,wind,and load variability,uncertainty,and
forecasting error.
•Improved forecasting methods
•Energy imbalance markets,or other market structures
•Voltage/frequency regulation
•Increased transmission capacity,changes in operation of hydroelectric
facilities,addition of demand-side technologies
IPC-E-14-18 4
Joint Settlement and Motion
•Gas price forecast(s)
•Modeling of sub-hourly scheduling of load and generation
•Identification of the existence of low occurrence events that contribute to
proportionately higher integration costs and possible remedies,including
operational or contractual solutions to mitigate these events and reduce
integration costs and charges.
9.The Parties submit this Settlement Stipulation to the Commission and
recommend approval in its entirety pursuant to RP 274-76.The Parties shall support
this Settlement Stipulation before the Commission and shall not appeal a Commission
order approving the Settlement Stipulation or an issue resolved by the Settlement
Stipulation.If this Settlement Stipulation is challenged by anyone who is not a Party,
then each Party reserves the right to file testimony,cross-examine witnesses,and put
on such case as they deem appropriate to respond fully to the issues presented,
including the right to raise issues that are incorporated in the settlements embodied in
this Settlement Stipulation.Notwithstanding this reservation of rights,the Parties agree
that they will continue to support the Commission’s adoption of the terms of this
Settlement Stipulation.
10.If the Commission or any reviewing body on appeal rejects any part or all
of this Settlement Stipulation or imposes any additional material conditions on approval
of this Settlement Stipulation,then each Party reserves the right,upon written notice to
the Commission and the other Party to this proceeding within fourteen (14)days of the
date of such action by the Commission,to withdraw from this Settlement Stipulation.In
such case,no Party shall be bound or prejudiced by the terms of this Settlement
Stipulation and each Party shall be entitled to seek reconsideration of the Commission’s
IPC-E-14-18 5
Joint Settlement and Motion
order,file testimony as it chooses,cross-examine witnesses,and do all other things
necessary to put on such case as it deems appropriate.In such case,the Parties
immediately will request the prompt reconvening of a prehearing conference for
purposes of establishing a procedural schedule for the completion of IPUC Case No.
IPC-E-13-25,and the Parties agree to cooperate in development of a schedule that
concludes the proceeding on the earliest possible date,taking into account the needs of
the Parties in participating in hearings and preparing briefs.
11.The Parties agree that this Settlement Stipulation is in the public interest
and that all of its terms and conditions are fair,just,and reasonable.
12.No Party shall be bound,benefited,or prejudiced by any position asserted
in the negotiation of this Sefflement Stipulation,except to the extent expressly stated
herein,nor shall this Settlement Stipulation be construed as a waiver of rights unless
such rights are expressly waived herein.Except as otherwise expressly provided for
herein,execution of this Settlement Stipulation shall not be deemed to constitute an
acknowledgment by any Party of the validity or invalidity of any particular method,
theory,or principle of regulation or cost recovery,including the methodology employed
for the 2014 solar integration study upon which the rates and charges contained in
Schedule 87 are based.No Party shall be deemed to have agreed that any method,
theory,or principle of regulation or cost recovery employed in arriving at this Sefflement
Stipulation is appropriate for resolving any issues in any other proceeding in the future.
No findings of fact or conclusions of law other than those stated herein shall be deemed
to be implicit in this Settlement Stipulation.This Settlement Stipulation sets forth the
complete understanding of the Parties,and this Settlement Stipulation includes no other
promises,understandings,representations,arrangements or agreements pertaining to
IPC-E-14-18 6
Joint Settlement and Motion
the subject matter of this Settlement Stipulation,or any other subject matter,not
expressly contained herein.
13.The obligations of the Parties are subject to the Commission’s approval of
this Settlement Stipulation in accordance with its terms and conditions and upon such
approval being upheld on appeal,if any,by a court of competent jurisdiction.All terms
and conditions of this Settlement Stipulation are subject to approval by the Commission,
and only after such approval,without material change or modification,has been
received shall the Settlement Stipulation be valid.
14.This Settlement Stipulation may be executed in counterparts and each
signed counterpart shall constitute an original document.
IV.PROCEDURE
15.Pursuant to RP 274,the Commission has discretion to determine the
manner with which it considers a proposed settlement.In this matter,the Parties have
reached agreement on a final resolution to this case.This Settlement Stipulation is
reasonable and in the public interest.The Parties request that the Commission approve
the Settlement Stipulation without further proceedings.
16.In the alternative,should the Commission determine that further
proceedings are required to consider the Settlement Stipulation,pursuant to RP 201,
the Parties believe the public interest does not require a hearing to consider the issues
presented by this Motion and request it be processed as expeditiously as possible by
Modified Procedure,without waiving the right to a hearing on the previously disputed
matters in this proceeding should the Commission reject the settlement.
IPC-E-14-18 7
Joint Settlement and Motion
V.REQUESTED RELIEF
NOW,THEREFORE,the Parties respectfully request that the Commission enter its
Order approving the Settlement Stipulation without material change or condition,and
without further proceedings.
DATED this /day of 2015.
Idaho Power Company Commission Staff
_____________
By 1A
Donovan E.Walker Kristine A.Sasser
Attorney for Idaho Power Company.Attorney for IPUC Staff
Sierra Club Idaho Conservation League
By_________________By_________________
Dean J.Miller Benjamin J.Otto
Attorney for Sierra Club Attorney for Idaho Conservation League
Snake River Alliance
By
_____________________________
Kelsey Jae Nunez
Attorney for Snake River Alliance
IPC-E-14-18 8
Joint Settlement and Motion
V.REQUESTED RELIEF
NOW,THEREFORE,the Parties respectfully request that the Commission enter its
Order approving the Settlement Stipulation without material change or condition,and
without further proceedings.
DATEDth1s \daoW\2015.
Idaho Power Company Commission Staff
By_____________________________By_____________________________
Donovan E.Walker Kristine A.Sasser
Attorney for Idaho Power Company.Attorney for IPUC Staff
Sierra Club Idaho Conservation League
llU By___________
Dean J.Miller Benjamin J.Otto
Attorney for Sierra Club Attorney for Idaho Conservation League
Snake River Alliance
By
______________________________
Kelsey Jae Nunez
Attorney for Snake River Alliance
IPC-E-14-18 8
Joint Settlement and Motion
V.REQUESTED RELIEF
NOW,THEREFORE,the Parties respectfully request that the Commission enter its
Order approving the Settlement Stipulation without material change or condition,and
without further proceedings.
DATED this /day of________2015.
Idaho Power Company Commission Staff
By____________________________By____________________________
Donovan E.Walker Kristine A.Sasser
Attorney for Idaho Power Company.Attorney for IPUC Staff
Sierra Club Idaho Conservation League
By
___________________________
By
Dean J.Miller Benjamin J.Otto
Attorhey for Sierra Club Attorney for Idaho Conservation League
Snake River Alliance
Kelsey Jae Nyqez
Attorney for Sh)ke River Alliance
IPC-E-14-18 8
Joint Settlement and Motion
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 9th day of January 2015 I served a true and
correct copy of the SETTLEMENT STIPULATION AND MOTION TO APPROVE
SETTLEMENT STIPULATION upon the following named parties by the method
indicated below,and addressed to the following:
Commission Staff X Hand Delivered
Kristine A.Sasser
____U.S.
Mail
Deputy Attorney General
____Overnight
Mail
Idaho Public Utilities Commission
____FAX
472 West Washington (83702)X Email kris.sasser2puc.idaho.cjov
P.O.Box 83720
Boise,Idaho 83720-0074
Idaho Conservation League
____Hand
Delivered
Benjamin J.Otto X U.S.Mail
Idaho Conservation League
____Overnight
Mail
710 North Sixth Street (83702)
____FAX
P.O.Box 844 X Email bottocidahoconservation.orq
Boise,Idaho 83701
Snake River Alliance
____Hand
Delivered
Kelsey Jae Nunez X U.S.Mail
Snake River Alliance
____Overnight
Mail
P.O.Box1731
___FAX
Boise,Idaho 83701 X Email knunez(snakeriveralliance.orq
Ken Miller
____Hand
Delivered
Snake River Alliance X U.S.Mail
P.O.Box 1731
____Overnight
Mail
Boise,Idaho 83701
____FAX
X Email [e-mail]
Sierra Club
____Hand
Delivered
Dean J.Miller X U.S.Mail
McDEVITT &MILLER LLP
____Overnight
Mail
420 West Bannock Street (83702)
____FAX
P.O.Box 2564 X Email ioe(mcdevitt-miller.com
Boise,Idaho 83701 heather(ämcdeviff-miller.com
IPC-E-14-18 9
Joint Settlement and Motion
Mall Vespa
____Hand
Delivered
Sierra Club X U.S.Mail
85 Second Street,Second Floor
____Overnight
Mail
San Francisco,California 94105
____FAX
X Email matt.vespa(sierraclub.orq
(%x .&CLQtwTr..
CFista Bearry,Legal Assistan 7
IPC-E-14-18 10
Joint Settlement and Motion
Solar Integration Study Report Idaho Power Company
Page 44
TECHNICAL REVIEW COMMITTEE STUDY PLAN
The following document was shared as a draft with the TRC after receiving their input on
prioritization of issues for this solar integration study.

“Second” Idaho Power Solar Integration Study

Technical Review Committee Study Plan

Sponsored by:

Idaho Power Company

May 28 , 2015

Study Plan - “Second” Idaho Power Solar Integration Study

Page 2

Table of Contents
1. Objective ......................................................................................................... 3
2. Project Background ......................................................................................... 3
2.1 2014 Solar Integration Study ................................................................................ 3
3. Technical Review Committee (TRC) ................................................................. 4
3.1 TRC Principles ........................................................................................................ 5
4. Consideration of Issues ................................................................................... 6
4.1 Discussion ............................................................................................................. 7
4.2 Conclusion ............................................................................................................. 7
5. Study Approach ............................................................................................. 10
5.1 Solar Data ...................................................................................................... 10
Table 6: Solar Integration Study #2 Schedule ....................................................................... 11
Appendix A: Invitation/Introduction Letter .......................................................... 12
Appendix B: Settlement Stipulation Issues ........................................................... 13

Study Plan - “Second” Idaho Power Solar Integration Study

Page 3

1. Objective
Study the integration of Solar onto the Idaho Power System.
2. Project Background
On July 1, 2014, Idaho Power filed an Application with the Idaho Public Utilities Commission
requesting Commission approval of Idaho Power’s proposed implementation of solar
integration rates and charges as set forth in the proposed Schedule 87, Variable Generation
Integration Charges, as indicated by the 2014 Solar Integration Study Report (“Solar Study”)
filed with the Application. On July 23, 2014, the Commission issued a Notice of Application and
Notice of Intervention Deadline. Order No. 33079. The Idaho Conservation League (“ICL”), the
Sierra Club, and the Snake River Alliance (“SRA”) petitioned for intervention which was granted.
Order No. 33090; Order No. 33097.
The Parties met on November 17, 2014, for settlement discussions and reached agreement
resolving the issues in this case and between the Parties. On January 9, 2015, pursuant to Rules
of Procedure 56 and 274 through 276, the parties filed a Joint Motion for Approval of a
Settlement Stipulation. The Stipulation, in Order No. 33227, calls for the formation of a
Technical Review Committee (“TRC”), see section 3.
The parties agree that the second solar integration study should utilize a Technical Review
Committee (TRC) that generally adheres to the Principles for Technical Review Committee
Involvement in Studies of Wind Integration into Electric Power System authored by the National
Renewable Energy Laboratory and the Utility Wind Integration Group. The TRC will advise Idaho
Power of the scope and methods use in the analysis, however, Idaho Power is ultimately
responsible for determining how the study is conducted, the content of the study, and any
results therefrom.
This Study plan will guide the development of a second Solar Integration Study to be filed with
the Idaho Commission by the first-quarter 2016.
2.1 2014 Solar Integration Study
The 2014 study performing an integration analysis of four solar penetration levels (100 MW,
300 MW, 500 MW, and 700MW). The analysis took each penetration level and completed two
production cost simulations, one with the solar forecast assumed to be perfect and the other
including the same level of energy but also holding capacity available in the Idaho Power
system to accommodate a predicted level of uncertainty for any given hour. By using the
difference method, the value of the energy produced due to the production uncertainties does
not get incorporated into the integration cost result.
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Idaho Power integration studies use a production cost model developed internally by Idaho
Power to closely simulate operation of the Hells Canyon Complex (Brownlee, Oxbow and Hells
Canyon hydro plants), the Idaho Power gas and coal thermal generation, and the Idaho Power
transmission interconnections. The simulation model represents the three generation facilities
in the Hells Canyon Complex in a cascaded fashion where water flows from Brownlee, through
Oxbow, and then through the Hells Canyon dam, recognizing that many hydro constraints
placed on the complex including flood control and environmental fish mitigation measures. The
cascaded simulation means that each dam has separate dispatch considerations yet the
dispatch decisions of the upstream plants constrain the dispatch decisions of the downstream
plants.
3. Technical Review Committee (TRC)
The following members have agreed to participate in the TRC:
Cameron Yourkowski
Senior Policy Manager
Renewable Northwest
421 SW 6th Ave, Suite 1125
Portland, OR 97204
503-223-4544
971-634-0143
[e-mail]
Michael Milligan, Ph.D.
Transmission and Grid Integration
National Renewable Energy Laboratory
15013 Denver West Parkway
Golden, CO 80401
303-384-6927
[e-mail]
Clint Kalich
Manager, Resource Planning and Power
Supply Analyses
Avista Corporation
[e-mail]
509.495.4532 work phone
509.777.6061 work fax
Kurt Myers
Project Manager, Idaho National Laboratory
[e-mail]
208-526-5002
Brian Johnson, Ph. D
University of Idaho
[e-mail]
208-885-6902
Rick Sterling
Idaho Public Utilities Commission
[e-mail]
208-334-0351
John Crider
Oregon Public Utilities Commission
[e-mail]
503-373-1536

3.1 TRC Principles
Based on the “Principles for Technical Review Committee (TRC) Involvement in Studies of
Variable Generation Integration into Electric Power Systems” Paper:
What will the TRC Provide?
A properly constituted TRC will assist the project sponsors in ensuring that the quality of the
technical work and the accuracy of results will be as high as possible. TRC participation will
also enhance the credibility and acceptance of the study results throughout the affected
stakeholder communities. And TRC members will be qualified to carry the key messages of
the study to their respective sectors.
What is a Properly Constituted TRC?
TRC membership should include individuals that collectively provide expertise in all of the
technical disciplines relevant to the study. A TRC facilitator should be selected from among
the TRC membership. Sponsorship and facilitation of the TRC should be independent from,
but closely coordinated with, the project sponsors and the team conducting the work.
Observers from relevant government agencies and other interested parties may attend TRC
meetings and be included in TRC communication at the discretion of the project sponsors.
Alternatively, a separate stakeholder group can be considered in order to update interested
parties on study progress and key results.
What are the TRC’s Functions & Requirements?
The TRC will:
 Review study objectives and approach, and offer suggestions when appropriate to
strengthen the study.
 Help ensure that the study:
o Builds upon prior peer-reviewed variable generation integration studies and
related technical work;
o Receives the benefit of findings from recent and current variable generation
integration study work;
o Incorporates broadly supported best practices for variable generation
integration studies;
o Is developed with broad stakeholder input.
 Engage actively in the project throughout its duration. In general, project review
meetings should be held nominally on a regular basis.
 Engender collegial discussions of methods and results among TRC members, the study
team, project sponsors and other interested parties. The aim of these discussions is to
improve accuracy, clarity and understanding of the work, and reach consensus
resolution on issues that arise.
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 Avoid public disclosure of meeting discussions and preliminary results. In general,
findings should not be released until accepted and generally agreed upon by project
sponsors, the study team and the TRC. When advisable, possible and agreed to by all
project participants, interim progress reports can be provided to a broader stakeholder
group.
 Ensure that findings are based entirely on facts and accurate engineering and science.
Project sponsors need to embrace this aim so that the results and findings are
objectively developed and not skewed to support any desired outcome.
 Document results of TRC meetings and distribute meeting presentations and minutes.
To carry out these functions, the TRC requires
 Access to all relevant information needed to properly evaluate the work and the results.
When required, TRC members will enter into confidentiality agreements to protect this
information. In no case can certain information needed by the TRC be declared “off-
limits.”
 Assurance that the study results will be made public through published documentation
or other suitable means, with the understanding that business-sensitive information will
not be made public.
4. Consideration of Issues
Parties agree that Idaho Power, together with the TRC, will consider whether the second solar
integration study should include the following – and if so, what would be the appropriate
methodology to be used in connection with the following:
 Alternative water-year types (e.g., low-type and high-type), range of water years or
normalized water year
 Intra-hour trading opportunities
 Shortening the hour-ahead forecast lead time from 45 minutes to 30 minutes
 Clustered solar build-out scenarios
 Other solar plant technologies (e.g., tracking systems or carried fixed-panel orientation)
 Correlation between solar, wind, and load variability, uncertainty, and forecasting error
 Improved forecasting methods
 Energy imbalance markets, or other market structures
 Voltage/frequency regulation
 Increased transmission capacity, changes in operation of hydroelectric facilities, addition
of demand-side technologies
 Gas price forecast(s)
 Modeling of sub-hourly scheduling of load and generation
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 Identification of the existence of low occurrence events that contribute to
proportionately higher integration costs and possible remedies, including operational or
contractual solutions to mitigate there events and reduce integration costs and charges.
4.1 Discussion
As with the prior study, there continue to be challenges in studying the effects and associated
costs of integrating variable generating resources, such as solar, onto a vertically integrated
power system. Unfortunately Idaho Power and the TRC do not time to achieve resolution of all
issues. Idaho Power and the TRC addressed the study scope and the issues in the stipulation
that can be addressed given desire to complete the study by the end of 2015. Idaho Power and
the TRC jointly agreed to limit the scope of the solar integration study.
4.2 Conclusion
Following a discussion and input from the TRC, Idaho Power and the TRC agreed to address the
following issues in the second integration study:
 Correlation between solar, wind, and load variability, uncertainty, and forecasting error.
Idaho Power will update the integration study method to replace plus or minus three
percent load variability with time varying data. Idaho Power will study the correlation
between solar, wind, and load variability, uncertainty, and forecasting error. In
particular, Idaho Power will study the effects that different solar penetration levels will
have on Idaho Power’s system variability considering the existing load and wind on the
Idaho Power system.
 Clustered solar build-out scenarios
Idaho Power will review build-out scenarios to align the scenarios to the expected solar
development. Additional solar data will be acquired by Idaho Power. Idaho Power will
perform a separate set of sensitivity cases at the 800 MW penetration level.
 Higher Penetration Levels
With 320 MW under contract and many 100s more in study. Requests have surpassed
the 2014 study levels. Idaho Power will analyze the integration costs at the 400 MW,
800 MW, 1200 MW and 1600 MW quantities to address a wide range of futures.
 Alternative water-year types (e.g., low-type and high-type), range of water years or
normalized water year
Idaho Power will use the water year data for 2011, 2012 and 2013 coincident with other
wind and market data for those periods.
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 Frequency and effect of low occurrence events
Idaho Power will perform the analysis on higher penetration levels where the events
may significantly exceed the reserve capacity held for such events.
The following issues that are more difficult to assess, or are of lower priority, these will be
addressed by:
Rather than performing detail studies, using west wide system models for example,
sensitivity cases at 800MW will be performed by adjusting the regulation requirement by an
appropriate percentage. These sensitivities will provide some indication of the relative
effect the issue has on the integration costs.
 Issues that require an interconnection-wide view of the system are costly and time
consuming:
o Intra-hour trading opportunities
o Energy imbalance markets (EIM) or other market structures
o Modeling of sub-hourly scheduling of load and generation
Idaho Power applied the Plexos interconnection-wide model in the 2013 wind
integration study, the study cost was high (over $100,000) and failed to produce reliable
and rational results. There is no current active intra-hour market in the Pacific
Northwest and any study involves numerous assumptions including how to represent
current operations and whether the modeling package closely simulates an assumed
intra-hour trading market.
Idaho Power participated in the development of a joint initiative project with over
fifteen other utilities called ITAP or Intra-hour Transaction Accelerator Platform. ITAP is
an internet based tool designed to facilitate expedited energy trading. The ITAP tool has
not been successfully deployed by the participating utilities.
Sub-hourly dispatch affects the real-time market value. Resource capacity is still
necessary to follow the uncertain output. Contemplated energy imbalance markets in
the west are not expected to trade capacity products or perform unit commitment
decisions. Capacity and unit commitment decisions are the focus of integration studies
including the Idaho Power integration studies.
 Reducing the hour-ahead forecast lead time from 40 minutes to 30 minutes
Power purchases and sales must be acquired and tagged by 20 minutes before the top
of the hour. A 30 minute lead-time leaves 10-minutes to acquire and tag a transaction.
The 10-minute interval is possible in some hours, but in high transaction volume hours,
a ten-minute interval is problematic.
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The following are of a lower priority that will not be addressed in this integration study:
 Improved forecasting methods
As described in section 2, Idaho Power in the 2014 Solar Study did an excellent near-
term forecast of the variability of expected solar production. Idaho Power does not see
much opportunity for improvement.
 Voltage/Frequency regulation
From a voltage perspective, Voltage and frequency issues may be considerations in
some geographic locations, but voltage and frequency regulation is beyond the scope of
this integration study. Idaho Power is performing other studies considering regulation
issues.
Solar production technology is displacing more typical resources that have governors
making the generation resource responsive to large changes in frequency due to the loss
of generation. As greater penetrations of solar are achieved in the western
interconnection, system reliability may necessitate requiring inverters with frequency
response. Voltage and frequency regulation is beyond the scope of this integration
study.
 Gas Price Forecast(s)
Different gas price forecasts can be considered, however, current data (2010-2013) is
time synchronized. Changing Gas data will affect market prices and the dispatch of most
resources. The selected simulation years contain a range of actual natural gas prices.
 Other solar plant technologies (e.g., tracking systems or varied fixed-panel orientation)
Integration costs would not be generally affected because most solar uncertainty is a
result of atmospheric conditions. Different solar plant technologies would likely affect
energy value of the solar generation project.
 Increased transmission capacity, changes in operation of hydroelectric facilities, and
addition of demand-side technologies
The Idaho Power transmission system capacity is fully subscribed and no new
construction is planned until Boardman to Hemingway. Idaho Power anticipates
updating the solar integration study as conditions change.
Restrictions at Hells Canyon would likely reduce the capability of the Idaho Power
system to integrate variable generation resources.
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Demand-side technologies reduce load and affect Reg Up capacity where intermittent
generation output is below forecast. Present demand-side technologies are less useful
when the intermittent generation exceeds the forecast.
 Energy storage with energy scheduling method to eliminate integration cost
Battery storage of two hours of intermittent generation nameplate output may reduce
integration costs. No integration study is required, but designing scheduling protocols
would be necessary. Large-scale battery storage is not anticipated in the 2015 Idaho
Power Integrated Resource Plan.
5. Study Approach
As with prior integration studies, the assessment will be made from the difference between
two production cost cases:
1. one with capacity reserved for uncertainty,
2. and the other case assuming output follows a perfect forecast.
5.1 Solar Data
Solar data will be developed for 400 MW, 800 MW, 1200 MW and 1600 MW penetration levels.
These data will be developed using information and patterns seen in signed and unsigned
contracts. Idaho Power will acquire additional solar data to assist in the development of the
generation profiles. Idaho Power will use the uncertainty forecasting method developed in the
2014solar integration study to establish the uncertainty capacity requirements at the solar
generation levels at 400 MW, 800 MW, 1200 MW and 1600 MW of solar generation. Schedule
The following table presents a schedule for conducting this Solar Study starting in January 2015
and completing the study less than 12-months later in December 2015.
Activity Period
TRC Formation Jan 26 – Feb 15
TRC Kick Off Call March 6
Develop Study Scope & Study Plan March 6 - 31
Data Analysis March 1 – May 31
TRC Meeting May 5
TRC Call June
Integration Study Analysis July 1 – August 31
TRC In-Person Meeting July
TRC Call August
Draft Report Sept 1 – Nov 15
TRC Call September
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TRC Call October
TRC Review Draft Report Nov 15 – Dec 1
Study Workshop November
File Study at Idaho Commission December 15
Table 1: Solar Integration Study #2 Schedule
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Appendix A: Invitation/Introduction Letter
February 19, 2015
Subject: Second Solar Study Technical Review Committee
To: Potential Technical Review Committee Members
As part of a settlement stipulation approved by the Idaho Public Utilities Commission in Case No. IPC-E-
14-18, Idaho Power has agreed to perform a second solar integration study. I have been asked lead this
study for Idaho Power. The study is expected to be complete by December 2015 as outlined in the
attached stipulation agreement. I am contacting you and others, as shown in the attached proposed
Technical Review Committee (“TRC”) membership list. Your willingness to participate as a member of
the TRC is much appreciated.
I anticipate the committee will meet via conference call or face to face once a month on average
through the completion of the study. Initially the committee will meet to discuss the study issues, the
study focus/scope, and the plan to accomplish the study. Later meetings will be used to discuss study
progress and finally to review a draft study report in late fall. Idaho Power will strive to document the
discussion of the issues and rational for any decisions made that impact the study. As the stipulation
states, Idaho Power is ultimately responsible for the study.
As with the prior study, there continue to be challenges in studying the impacts and associated costs of
integrating variable generating resources, such as solar, onto a vertically integrated power system. One
significant challenge the TRC will have to address is the study scope and how many of the issues in the
stipulation can be addressed given the compressed schedule. Unfortunately we do not have unlimited
resources, the capability, or the time to achieve resolution of all these issues. To that end, we have
attached a matrix list of the issues in the stipulation. I would like the TRC members to rank each issue
with their view of the priority and complexity (High, Medium, Low rankings). For example, to address
some issues it will be very complex and time consuming yet yield results of lesser value than other issues
that are less complex and of higher value. Another question is whether there are other issues of high
value that should be added to this list.
We understand that your time is valuable, and we will strive to minimize your time commitment. We
will be using the doodle website to schedule the first kick-off conference call for everyone that is
capable of web conferencing. If you have a preference for a face-to-face meeting, that can be arranged.
We are extremely grateful for your participation as a member of the TRC. If you have additional
questions, please don’t hesitate to contact me.
Best Regards,
Ronald Schellberg
Transmission Policy and Development
Idaho Power Company
Phone [phone]

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Appendix B: Settlement Stipulation Issues