20111114Staff Comments.pdf

WELDON STUTZMAN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 3283
RECE ç:ì... i.,:l
2m I ~mv I i, Pt.1 2: 35
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S 2011 INTEGRATED RESOURCE )PLAN (lRP) )
)
)
)
CASE NO. IPC-E-11-11
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilties Commission (Commission), by
and through its attorney of record, Weldon Stutzman, Deputy Attorney General, and in response
to the Notice of Filng and Notice of Modified Procedure issued in Order No. 32356 on
September 14,2011 in Case No. IPC-E-ll-ll, submits the following comments.
BACKGROUND
On June 30, 2011, Idaho Power Company (Idaho Power; Company) fied its 2011 electric
Integrated Resource Plan (IRP) with the Commission. As required by Commission Order No.
22299 (Case No. U-1500-165), Idaho Power's filing is a biennial planning document that sets
forth how the Company intends to serve the electric requirements of its customers.
The complete 2011 IRP consists of four separate documents: (1) the 2011 Integrated
Resource Plan; (2) Appendix A - Sales and Load Forecast; (3) Appendix B - Demand-Side
Management 2010 Annual Report; and (4) Appendix C - Technical Appendix.
STAFF COMMENTS 1 NOVEMBER 14,2011
STAFF REVIEW
Overview
The main purpose of Idaho Power's IRP process is to develop a resource plan that will
economically meet future electricity load in the service area it is obligated to serve while
considering important risk factors. The four main goals that Idaho Power used to develop its
plan were to: (a) "identify suffcient resources to reliably serve the growing demand for energy
within Idaho Power's service area thoughout the 20-year planing period; (b) ensure the
selected resource portfolio balances cost, risk, and environmental concerns; (c) give equal and
balanced treatment to both supply-side resources and demand-side measures; and (d) involve the
public in the planing process in a meaningful way" (Idaho Power Co., 2011 IRP, p. 1).
Idaho Power evaluated nine different resource portfolios for the 2011 through 2020 time
period and 10 different resource portfolios from 2021 through 2030. Utilzing an advisory
council of outside stakeholders to provide input and feedback throughout the process, the
Company selected portfolio 1-3 Boardman to Hemingway (B2H) as the preferred portfolio and
portfolio
1-4 SSCT as the alternative near-term (2011-2020) resource portfolio. The Company also
selected 2-6 Balanced 1 and 2-8 PNW Transmission as the preferred and alternate long-term
(2021-2030) portfolios, respectively. An explanation of the Company's selections and the
method and rationale used are explained in greater detail later in these comments.
Staff identified some areas for possible improvement related to the Company's plan.
This includes enhancements:
1. in modeling scenarios where the impacts of additional large new customers can be
quantified (see page 5);
2. in the Company's methodology to more adequately consider and evaluate new DSM
resources on par with supply-side resources (see page 11);
3. in portfolio design to address inadequate evaluation for the potential early retirement
of existing coal plants in lieu of investing in costly emission controls (see page 11);
4. to quantify transmission siting and market price risk in their analysis (see page 13);
and
5. in providing sufficient rationale for a solar demonstration project (see page 13).
STAFF COMMENTS 2 NOVEMBER 14,2011
In general, Staff believes that Idaho Power demonstrated a rigorous approach in
developing its IRP and has reasonably met goals set by the Company and requirements set forth
by the Commission.
IRP Methodology
Idaho Power duplicated the approach it used to develop the 2009 IRP by dividing the
20-year planing horizon into two 10-year periods. Using a two-step process, the Company
developed portfolios from which preferred and alternate resource plans were selected. This was
necessary to make sure that a preferred near-term (2011-2020) resource portfolio could be
selected and used as a basis for all long-term portfolios (2021-2030) that were developed and
evaluated. According to the Company, splitting the planing horizon into two 1 O-year periods
"prevents near-term resource decisions from being influenced by the availability of resources
that are dependent on technological advancements in the second 10 years." (2011 IRP, p. 3).
Staff believes there are alternative ways to accomplish this same goal using technology readiness
lead times instead of bifurcating the planning horizon. This would eliminate the potential of
selecting least-cost plans for each of the two ten-year periods that in combination may not lead to
an overall least-cost plan over the 20-year planing horizon.
To prepare for the two-step process, Idaho Power developed peak-demand and average
load forecasts across the IRP's 20-year planing horizon accounting for new customer growth in
each customer class, changes in customer class usage characteristics, changes in the service area
economy, existing energy efficiency program performance, loss factors, fuel prices, weather
variabilty, and the potential for a new electric vehicle market. These forecasts were netted
against Idaho Power's current and committed resource base to determine average energy and
peak-hour load and resource balance deficits. Curent resources include all existing DSM
programs, current levels ofPURPA development, existing PPA's, firm Pacific Northwest import
capability, and generation from all existing and committed Idaho Power resources. Committed
resources include Langley Gulch (CCCT) and the Shoshone Falls Upgrade (Hydro) available in
years 2012 and 2015, respectively.
Once load and resource balance deficits were identified, Idaho Power designed nine
resource portfolios to address deficits that occurred during the near-term time period (2011-
2020). These were developed considering the technology readiness of different types of load-
serving resources, the capital and operational cost of varous resources, the future cost of natual
STAFF COMMENTS 3 NOVEMBER 14,2011
gas, the cost of carbon and other emissions, production tax and renewable energy credits
(REC's), future national renewable energy legislation, and the cost of incremental transmission
investment. Each near-term portfolio was analyzed using cost and risk as criteria. Variable costs
were determined using AURORA modeling capabilty, and internal financial analysis modeling
tools used to evaluate capital cost. Risk was evaluated based on sensitivity to various levels of
REC prices, carbon costs, natural gas prices, generation capital cost, DSM adoption variabilty,
and load variabilty. Using this analysis, the Company selected preferred and alternate near-term
portfolios.
In the second step, the Company assumed the preferred near-term portfolio would be
fully implemented by the year 2021 with load and resource balance deficits adjusted to reflect
the additional resources. To address deficits that occur in years 2021 through 2030, the
Company designed ten additional resource portfolios. Employing the same type of analysis used
to select the near-term portfolios, Idaho Power chose preferred and alternate long-term
portfolios, again using cost and risk as criteria.
Load and Resource Balance
Average Energy Load Forecast
As in the 2009 IRP, overall uncertainty persists throughout the development of the 2011
IRP. The curent recession has not subsided, contributing to a reduction in overall electricity
consumption within Idaho Power's service area, declining 3.5% in 2009 and 1.2% in 2010.
Industrial and commercial electricity consumption has decreased, while new residential customer
growth has increased but at a much slower rate since the star of the recession. For example, the
Company has added approximately 2000 residential customers compared to 15,000 residential
customers per year prior to the recession. The decline in residential load growth can be
attributed to a collapse in the housing sector, while reduction in commercial and industrial
energy use is mostly due to a general downturn ofthe economy. As a result of continued
pessimism in the economy, the Company's 2011 IRP average load forecasts are lower than
forecasts in the 2009 IRP through year 2015. Moving forward, the Company has assumed that
by 2012, the recession wil subside and the economy will recover. In the Company's expected
case forecast, it anticipates that by 2015 new customer growth rates wil be equivalent to growth
that occured between the year 2000 and 2004. For the rest of the forecast horizon, average load
STAFF COMMENTS 4 NOVEMBER 14,2011
is higher in all remaining years compared to the 2009 IRP. This results in an overall average
system growth rate of 1.4 percent per year across the 20-year planing horizon.
Driving much of the higher average load included in the 2011 IRP as compared to the
2009 IRP load forecast is an assumption that electricity prices wil be lower, approximately 9
cents per kWh lower by the end of the 20-year planning horizon. Much of the difference is due
to carbon price assumptions. Unlike the 2009 electricity price forecast assumptions used to
develop the load forecast, the 2011 IRP did not include a cost of carbon. More importantly, the
Company used two different cost of carbon assumptions within the 2011 IRP. Although no cost
of carbon was incorporated into the load forecast, carbon cost was incorporated into the cost of
resources used to determine how the load forecast will be met.
Staff is concerned that by having no cost of carbon in the load forecast while assuming a
cost of carbon in current and future resources, the load forecast may reflect larger growth than
might occur due to underestimated electricity prices. This is especially true if recessionar
issues recede and there is a renewed push for carbon reduction legislation at the national level
over the next 20 years.
For the first time, the Company incorporated the effect of plug-in hybrid electric vehicles
on load growth. Moody's Analytics, EPRI and Oak Ridge Laboratory market adoption and end
use consumption assumptions were used to develop the forecast. Staff agrees with the Company
that there is significant uncertinty in the forecast due to a lack of empirically derived data, but
because of its relatively small impact, from 9 aMW in 2020 to 43 aMW in 2030, its effect on the
total load forecast is minimaL. However, Staff supports the Company's inclusion of electric
vehicle impact in its IRP so that it can be monitored in case this nascent market grows
appreciably in future years.
Staff has previously commented on the difficulty in forecasting new increments of load
from potential large industrial customers within the IRP. Because of the interest large customers
have recently shown in locating into Idaho Power's service territory, a "Special" contract
customer was incorporated into the load forecast in the 2011 IRP. Although no contract has been
signed, the "Special" customer was reflected in the Company's firm load forecast staring in
2011 at 2 aMW and ramping up to 54 aMW in 2016. This is in addition to the four large contract
customers already included (Micron Technology, Simplot Fertilzer, INL, and Hoku Materials).
Staff believes that this is an important consideration and a reasonable method of dealing with the
issue, however it is difficult to discern the size of the impact. Breaking out potentially large new
STAFF COMMENTS 5 NOVEMBER 14,2011
load additions as a separate planing scenario might help decision-makers understand the overall
cost impact of a new industrial customer so that it can be compared effectively with benefits
related to economic development.
Another factor included in the 2011 IRP load forecast is the impact of current DSM
energy efficiency programs. The programs are reflected in the forecast based on the savings the
Company is predicting to achieve considering changes in program design, trends in paricipation,
future changes in codes and standards, and where the program is in its life cycle. Idaho Power
assumed that current program performance remains constant after 2015 and is ramped down
staring in year 2020 until the end of the IRP planning horizon. Any new programs were added
as a resource equivalent to a curent or committed resource. Staff notes that the amount of
savings per customer and per unit of load steadily increases, but levels off and begins to decrease
during the last five years of the 20-year planing horizon Idaho Power Company (2011 IRP:
Appendix C - Technical Appendix, Table DSM-5, DSM-lO; Appendix A - Sales and Load
Forecast, Appendix AI). Staff believes that as electricity prices increase as shown by the
Company's own forecast (2011 IRP: Appendix A - Sales and Load Forecast, Fig. 1), the amount
of energy effciency per unit of load would increase, not decrease due to favorable economics.
According to the Company, the focus was on program performance and its effect on average
energy use during the first five years of the IRP planing horizon (2011 IRP, p. 38). Because
this trend happens at the end of the planing horizon, the Company will have several IRP cycles
to re-evaluate this trend.
Weather is the last major effect the average load forecast takes into consideration. In
addition to a median expected case weather scenario (50th percentile), Idaho Power prepared two
alternative scenaros, a 70th percentile and a 90th percentile case. The Company used the 70th
percentile weather scenario as a basis to forecast its monthly average load for all of its IRP
planing. According to the Company, this provides a 10% monthly planing margin for the
preferred resource portfolio when compared to demand using the expected case. Given the
amount of hydro resources the Company utilzes and the drivers that create peak-load conditions
for the system, Staff believes this is a reasonable planing assumption.
Peak Demand Load Forecast
Idaho Power forecasts system peak-hour loads by summing the coincident peak-demand
periods across all customer classes and uses the 70th percentile average monthly load forecast as
STAFF COMMENTS 6 NOVEMBER 14,2011
a basis for the peak-hour load forecast. Winter peak demand is mostly driven by cold weather
space heating, while summer peaks are caused by hot weather air-conditioning and agricultural
irrigation needs. Summer peak-hour loads are consistently larger than winter peak-hour loads
making Idaho Power a summer peaking utilty. For example, the largest system peak-hour load
event recorded by the utilty was 3214 MW occurring on June 30, 2008 at 3 p.m. while the
largest winter peak was 2528 MW occuring on December 10, 2009 at 8:00 a.m.
Other major factors include average peak-day temperature and precipitation assumptions
due to the number of customers and intensity of energy use by customer classes with significant
air-conditioning and irrgation needs. In most cases, these types of loads increase considerably
with hotter temperatures which also happen coincidently with the growing season, while a lack
of precipitation can increase irrigation electricity use.
Staff supports the Company's use of conservative 95th percentile average peak-day
temperature and 90th percentile precipitation assumptions to forecast peak-hour load. Using
these assumptions, the IRP peak-hour load forecast is projected to grow to 4901 MW in year
2030 from the highest recorded peak of3214 MW recorded in June 2008.
Current and Committed Resources
The 2011 IRP nets the peak-hour and average energy load forecasts against curent and
committed resources to determine deficits that future resource portfolios wil need to address.
These resources total 4,926 MW of total nameplate capacity and include all existing and
committed Idaho Power owned resources, curent levels of PURP A contracts, existing power
purchase agreements, firm Pacific Northwest import capabilty, as well as all demand response
DSM programs.
The 2011 IRP included the 49 MW Shoshone Falls upgrade in 2015 along with 300 MW
of capacity from Langley Gulch in 2012 as a committed resource. There is also a reduction in
coal-fired capacity reflected in the 2011 IRP due to the projected shutdown of the Boardman
Plant in 2020. Portland General Electric, the majority owner and operator, has agreed to close
the plant as a result of legal proceedings in Oregon.
According to the Company, demand response is included as a resource to help meet peak-
hour loads on par with supply-side resources. Staff notes that beyond year 2015, demand
response is assumed to be flat, held at 351 MW throughout the rest of the 20-year planing
horizon. Given that peak-hour load and the number of customers are projected to grow, this
STAFF COMMENTS 7 NOVEMBER 14,2011
effectively means the Company is projecting demand response to shrink on a per customer and
per unit of demand basis. However, if electricity prices and avoided costs are projected to
increase, it is expected that cost effectiveness thresholds would become easier to meet and
demand response would grow.
Staff also notes that the 2011 IRP changed the strategic role demand response plays in
resource acquisition by modifying the criteria used in the 2009 IRP to value demand response.
The value of demand response and how it compares to avoided supply side resources was a
significant issue in Case No. IPC-E-I0-46. Staff believes there should be additional dialogue
and deliberation in the futue to understand demand response valuation and how it wil be
consistently applied in future IRPs.
Load Resource Balance Deficits
Based on the Company's loàd resource balance analysis, average monthly deficits begin
occurring in July 2017 using 70th percentile precipitation and 70th percentile average load
scenarios. The size of the deficit is 12 aMW increasing to 1232 aMW by the end of the 20-year
planing horizon. Similarly, using 95th percentile peak-hour load conditions and 90th percentile
water conditions, deficits begin occurring as early as July 2011 growing to a maximum of 1232
MW in June of2030.
The Company's resource portfolios were designed to eliminate peak-hour deficits. When
these resources were modeled, average load balance deficits were also eliminated.
Resource Portfolios
The Company developed nine near-term resource portfolios for the first 10-year period
and ten long-term portfolios for the second 1 O-year period. All portfolios were designed to meet
resource deficits as well as a federal renewable energy standard as minimum requirements.
Senate bil S.3813 by Senator Jeff Bingaman was used as the standard which has a three percent
renewable requirement by the year 2012 and 15 percent by 2021. The nine near-term resource
portfolios considered by the Company are shown below.
STAFF COMMENTS 8 NOVEMBER 14,2011
Near-Term Resource Portfolios (2011-2020)
Year 1-1 Sun & Steam 1-2 Solar 1-3 B2H 1-4 SCCT 1-5 CCT
2011
2012 Solar PV-i
2013 Solar PV-5
2014 CHP-75 Solar PV-5
2015 Solar PV-30 Solar PT-lOO Eastside Purchase SCCTFrame CCCT
2016 CHP-IOO Solar PTlOO B2H-450
2017 Geothermal-52 Solar PT-125 SCCTFrame
2018 Solar PT-125 Solar PV-50
2019 Solar PV-30 Solar PT-IOO SCCT S Aero-94 SCCTFrame
2020 Solar PT-75 Solar PV-50
MW 493 530 450 434 470
Year 1-6CHP 1-7 Balanced 1-8 Pumped Storae:e 1-9 Distributed Gen.
2011
2012 Dist Gen-IO
2013
2014
2015 CHP-lOO CHP-lOO Pump St-80 SCCTFrame
2016 SCCTFrame SCCTFrame SCCTFrame
2017 SolarPV-IO SCCTFrame
2018 CHP-50 Solar PT-IOO Pump St-80
2019 CHP-50 Geothermal-26 SCCT S Aero-47 SCCT S Aero-94
2020 SCCT S Aero-94 SCCT S Aero-47 Pump ST-80
MW 464 453 457 444
When designing different portfolios, the Company analyzed transmission capacity
constraints based on assumptions about the location of different generation resources and off-
system purchases. The cost of transmission investment was included in the net present value and
incremental revenue requirements; however, assumptions for including transmission investment
were different between the first and last 10-year planing periods. In the first 10-year planing
period, incremental in-service-area transmission capacity was only included if additional
capacity was needed to deliver power from a new resource to the Treasure Valley. The only
incremental interstate transmission line was the addition of Boardman to Hemingway in portfolio
1-3 B2H.
Portfolios analyzed for the second ten years of the planing period are shown in the table
below.
STAFF COMMENTS 9 NOVEMBER 14,2011
Long-Term Resource Portfolios (2021-2030)
Year 2-1 Nuclear 2-2IGCC 2-3 SCCTlWind 2-4 CCTlWind 2-5 Hvdro/CHP
2021 Solar PT-lOO Geothermal-52 SCCT S Aero-141 CCCT Hydro Sm-60
2022 Pump St-50 SCCTFrame Wind-lOO Wind-l 50 CHP-75
2023 Solar PT-lOO SCCT S Aero- 141 Pump St-80
2024 Nuclear CHP-50 Wind-l 00 CHP-IOO
2025 Solar PT-75 SCCT S Aero-94 Hydr0-0
2026 IGCC w/CS Wind-lOO CCCT Pump St-80
2027 SCCT S Aero- i 4 i Hydro Sm- i 00
2028 Nuclear Solar PT-75 SCCT S Aero- i 4 i Wind-l 50 SCCT S Aero- i 4 i
2029 Pump St-50 SCCT S Aero-94 SCCTFrame Hydro Sm-80
2030 Hvdro Sm-60
MW 800 802 1052 1070 816
Year 2-6 Balanced 1 2-7 Balanced 2 2-8 PNW Transmission 2-9 E/S Transmission 2-10 Renewable
2021 Geothermal-52 Geothermal-52 Geothermal-52 Geothermal-52 CHP-75
2022 SCCTFrame CHP-75 PNW Purchase E/S Purchase Pump St-80
2023 SCCTFrame Solar PT-150
2024 Solar PT-50
2025 CCCT Geothermal-52 CHP-75
2026 CHP-75 Solar PT-150
2027 Hydro Sm-60 Solar PV-20 Solar PV-20 Solar PV - i 50
2028 Hydro Sm-60 CCCT Geothermal-52 Geothermal-52 Geothermal-52
2029 SCCTFrame SCCTFrame SCCTFrame Hydro Sm- i 00
2030 Solar PV -200
MW 802 784 794 794 1032
During this period Boardman to Hemingway was assumed to be built because it was
selected as the preferred portfolio in the near term and its cost was included in all long-term
portfolios. However, all additional transmission investment needed to enable market purchases
and required to take new generation to load were included, not just transmission investment into
the Treasure Valley. This includes the cost of interstate transmission lines needed for market
purchases from the Pacific Northwest in portfolio 2-8 PNW Transmission and from the East by
including the cost of Gateway West in portfolio 2-9 E/S Transmission (both with 2022
completion dates). The cost of Gateway West was also included in all long-term resource
portfolios that required it to deliver any amount of new generation to load. Because of its large
up-front cost, the proportion of Gateway West capacity used by a given portfolio is an importnt
factor that Staff believes should be identified separately in the IRP. Staff also believes the
transmission line's utilzation be used to fine tune its resource portfolios and recommends the
Company consider this assessment in future IRPs. Staff agrees with Idaho Power that there is
significant uncertainty in the location of new generation sources and it is prudent for the
Company to continually evaluate new transmission lines (2011 IRP, p. 6) so that the Company
STAFF COMMENTS 10 NOVEMBER 14,2011
can make decisions in the best interests of the public with sufficient lead time that allows for
timely construction.
As the Company has shown over time, improvements have occured with each IRP.
Although Staffhas reservations related to method feasibilty, it believes by only including
assumed levels of DSM in the load and curent/committed resource base, and not including new
DSM programs/levels as par of a resource portfolio, the Company is not able to comparatively
evaluate DSM as an alternative to supply-side resources to meet future load deficits. Doing so
might provide a relative comparison of demand-side alternatives to supply-side options as they
affect the electricity system which is difficult to achieve in a simple benefit-to-cost analysis test.
Staff agrees with the Company's inclusion of varing DSM levels as a risk factor in their
analysis of resource portfolios. It provides information as to the potential range in cost each
portfolio can exhibit, given base level performance of assumed DSM programs.
Because of the recent decision to retire the Boardman plant early and potentially large
future investments required for emission controls at other coal-fired plants, Staff believes that in
future IRPs, additional portfolios could be considered that adequately address early retirement of
coal-fired thermal resources. All portfolios are currently modeled as additions to curent and
committed resources, which includes Idaho Power's ownership interests in existing coal plants.
Although the Company has incorporated emission adders (C02, NOx, mercury, and S02) to the
cost of incremental fossil fuel based resources and increased the cost of emission upgrades to
meet curent emission permit levels at the Jim Bridger plant, Staff believes that not all costs and
benefit can be fully captured until plant closure alternatives are considered. Examples of cost
include decommissioning and accelerated depreciation. Examples of benefits include foregone
investments in emission controls and worth derived from use of alternative resources.
Preferred and Alternate Portfolios
Based on its analysis, Idaho Power selected 1-3 Boardman to Hemingway (B2H) as the
preferred near-term portfolio because it had the lowest total cost and showed the third lowest
sensitivity to risk factors. Staff used the amount of cost variability reflected in the Company's
stochastic analysis results to ran the amount of risk for each portfolio. The preferred portfolio
is characterized by completion of the Boardman to Hemingway transmission line in year 2016
which wil allow the Company to purchase up to 450 MW of power from the Pacific Northwest.
Idaho Power also selected 1-4 SSCT as an alternative portfolio in case the Boardman to
STAFF COMMENTS 11 NOVEMBER 14,2011
Hemingway transmission line is delayed or cancelled. It was selected because it had the second
lowest total cost and the second lowest sensitivity to risk. The portfolio is characterized by the
addition of three simple-cycle gas-fired combustion turbines in 2015,2017, and 2019. Both
short-term portfolio action plans are shown below.
Short-term Portfolio Action Plans (2011-2020)
Preferred Resource Portfolio Alternative Resource Portfolio
1-3 Boardman to Hemine:wav 1-4 Simple Cycle Combustion Turbine
201 I
2012
2013 Solar Demonstration Project (500kW-IMW)Solar Demonstration Project (500kW-IMW)
2014
2015 Eastside PPA (83MW)SCCT (170 MW)
2016 Boardman to Hemingway (450MW)
2017 SCCT (170 MW)
2018
2019 SCCT(94 MW)
2020
The Company selected 2-6 Balanced 1 and 2-8 P NW Transmission as the preferred and
alternate long-term portfolios, respectively (see table below). The Balanced 1 portfolio is
characterized by a diverse mix of different types of renewable and natural gas generation
resources. The PNW Transmission portfolio consists mainly of incremental market purchases
from the Pacific Northwest requiring construction of additional transmission capacity in the
Idaho-Northwest and Brownlee East transmission paths. Although the preferred long-term
portfolio did not have the lowest total cost (3rd lowest) or sensitivity to risk (4th lowest), the
Company justified its selection because the two portfolios that performed better against
quantitative measures relied heavily on market purchases of power as well as construction of
new transmission lines, both of which car substantial risk. The Company did select the best
performing of the two highest scoring portfolios, 2-8 PNW Transmission, as the alternate
portfolio, but with caveats to reassess in the future.
STAFF COMMENTS 12 NOVEMBER 14,2011
Long-term Portfolio Action Plans (2021-2030)
Preferred Resource Portfolio Alternative Resource Portfolio
2-6 Balanced 1 2-7 Pacific Northwest Transmission
2021 Geothermal (52 MW)Geothermal (52 MW)
2022 SCCT (170 MW)Pacific Northwest Purchase (500 MW)
2023
2024 Solar Power Tower (50 MW)Solar Power Tower (50 MW)
2025 CCCT (300 MW)CCCT (300 MW)
2026
2027 Solar PV (20 MW)
2028 Small Hydro (60 MW)Geothermal (52 MW)
2029 SCCT (170 MW)SCCT (170 MW)
2030
Staff cautions the Company in using resource diversity as justification when selecting
portfolios that have a higher cost or placing too much weight on market price risk. This is
especially true when least cost portfolios use market purchase as its primar resource which
provides access to significant resource diversity by default. Additionally, Staff notes that a
potentially large portion of market price risk was quantified in the Company's analysis by
including risk variables (natural gas price, capital cost, cost of carbon, load variabilty, etc.) that
serve as determinants of market price (in the Aurora model) used to calculate the cost of resource
portfolios.
Staff suggests there may be ways to quantify risk related to transmission siting in the next
IRP. Risk associated with siting a transmission line could be captured if the definition of capital
cost risk was expanded to include the capital cost and siting cost of a transmission line. This
would not address the time aspect of risk associated with transmission siting, but it would
account for its cost.
Solar Demonstration Project
Idaho Power included a solar demonstration project in its 2011 IRP to be implemented
sometime in 2012 with an estimated cost between $2 and $4 milion. The proposal is for a 0.5 to
1 MW solar photovoltaic (PV) resource. The Company believes that the facility would "provide
useful data and give the company experience owning and operating this type of resource....and
better evaluate the advantages and disadvantages of utilty-scale solar PV projects and distributed
rooftop programs" (2011 IRP, p. 11).
STAFF COMMENTS 13 NOVEMBER 14,2011
Staff believes that although the project may have merit, the Company must justify why
the same information could not be obtained from other existing solar facilties not owned by
Idaho Power (Interconnect Solar, Grand View Solar, or other proposed projects). If Idaho Power
chooses to pursue a new Company-owned project, Staff believes the project should incorporate
unique features or data collection capability that wil provide valuable information that canot
likely be obtained from other facilties.
STAFF RECOMMENDATION
After review ofIdaho Power Company's 2011 IRP, Staff believes that the Company
performed extensive analyses, gave reasonably equal consideration of supply- and demand-side
resources, and provided acceptable opportunities for public input, resulting in an integrated
resource plan that satisfies the requirements set forth in Commission Order Nos. 25260 and
22299. Staff, therefore, recommends that the Commission acknowledge the Company's 2011
IRP.
Respectfully submitted this 14Jt day of November 2011.
~~Wc
Deputy Attorney General
Technical Staff: Mike Louis
i:umisc:commentsipce i 1.1 i wsml comments
STAFF COMMENTS 14 NOVEMBER 14,2011
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF NOVEMBER 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-11-11, BY E-MAILING AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
DONOV AN E. WALKER
JASON B. WILLIAMS
LEGAL DEPARTMENT
IDAHO POWER COMPANY
P.O. BOX 70
BOISE IDAHO 83707
E-MAIL: dwalkercmidahopower.com
jwiliamscmidahopower.com
GREGORY W. SAID
TIMOTHY E. TATUM
IDAHO POWER COMPANY
P.O. BOX 70
BOISE IDAHO 83707
E-MAIL: gsaidcmidahopower.com
ttatumcmidahopower.com
,.b~_SECRETARY
CERTIFICATE OF SERVICE