20151223final_order_no_33441.pdf

Office of the Secretary
Service Date
December 23,2015
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER Of IDAHO POWER )CASE NO.IPC-E-15-19
COMPANY’S 2015 INTEGRATED )
RESOURCE PLAN )ORDER NO.33441
_____________________________________________________________________________________________
)
On June 30,2015,Idaho Power Company filed its 2015 Integrated Resource Plan
(IRP)to explain how it expects to meet its customers’energy needs for the next 20 years.After
the Company filed its IRP,the Commission invited interested persons to submit comments in the
case.See Order No.33346.The Commission Staff,Idaho Conservation League (ICL),Sierra
Club,Snake River Alliance (SRA),and numerous individuals filed comments,and the Company
filed a reply.’Having reviewed this record,we find that the Company’s 2015 WP discusses the
subjects required by the Commission’s prior Orders.We thus acknowledge that the 2015 JRP
has been filed.Our decision is further explained below.
THE IRP PROCESS
An WP is a status report on the utility’s ongoing,changing plans to adequately and
reliably serve its customers at the lowest system cost and least risk over the next 20 years.The
report informs the Commission and the public about the utility’s plans,and is similar to an
accounting balance sheet;i.e.,it is a “freeze frame”look at the utility’s fluid,resource planning
process.See Order No.22299.The WP is meant to demonstrate to the public that the Company
has prepared for,and considered,many scenarios through a reasonable planning process.The
Commission thus expects a utility to have vigorously tested the RP’s assumptions to ensure the
IRP accurately reflects changing markets and customer demand.
The Company must update its WP every two years and allow the public to participate
in the development of the IRP.See id.and Order No.25260.The final IRP must include the
subjects required by the Commission’s prior Orders,including Order Nos.22299 and 25260.In
summary,the final IRP should explain the Company’s present load/resource position,expected
responses to possible future events,and the role of conservation in those responses.It also
On October 21,2015,the Company filed a letter and replaced page 9 of its reply comments to clarify it had not
changed its policy to pursue all cost-effective energy efficiency.The Company explained it “will continue to pursue
all cost-effective energy efficiency.Idaho Power does not and has not viewed the achievable potential as a ‘ceiling’
for the pursuit of cost-effective energy savings and will continue to pursue energy efficiency beyond the achievable
potential when possible.”
ORDER NO.33441 1
should discuss “any flexibilities and analyses considered during comprehensive resource
planning,such as:(1)examination of load forecast uncertainties;(2)effects of known or
potential changes to existing resources;(3)consideration of demand-and supply-side resource
options;and (4)contingencies for upgrading,optioning and acquiring resources at optimum
times (considering cost,availability,lead time,reliability,risk,etc.)as future events unfold.”
See Order No.22299.The IRP should separately address:
•“Existing resource stack,”by identifying all existing power supply
resources:
•“Load forecast,”by discussing expected 20-year load growth scenarios for
retail markets and for the federal wholesale market including
“requirements”customers,firm sales,and economy (spot)sales.This
section should be a short synopsis of the utility’s present load condition,
expectations,and level of confidence;and
•“Additional resource menu,”by describing the utility’s plan for meeting
all potential jurisdictional load over the 20-year planning period,with
references to expected costs,reliability,and risks inherent in the range of
credible future scenarios.
Id
If the Commission finds the IRP discusses these required subjects,then it will enter
an Order acknowledging that the Company filed the IRP.By acknowledging the IRP,the
Commission is acknowledging the Company’s ongoing planning process,not the conclusions or
results reached through that process.
THE 2015 IRP
A.Overview
Idaho Power’s 2015 IRP addresses available supply-side and demand-side resource
options,planning period load forecasts,potential resource portfolios,a risk analysis,and an
action plan that details how the Company intends to implement the IRP.The IRP filing consists
of four documents:(1)the 2015 IRP;(2)Appendix A —Sales and Load Forecast;(3)Appendix B
—Demand-Side Management 2014 Annual Report;and (4)Appendix C —Technical Appendix.
In developing the IRP,the Company obtained public input by working with an
Integrated Resource Plan Advisory Council (IRPAC)consisting of various stakeholders.The
Company held 12 IRPAC meetings,and also public working group meetings to discuss energy
ORDER NO.33441 2
efficiency,solar resources,and coal resources.The Company presented the IRP to the public at
different community meetings,to civic groups,and through seminars as requested.
B.IRP Goals and Assumptions
With the 2015 IRP,the Company attempted to:(1)identify sufficient resources to
reliably serve growing energy demands over the next 20 years;(2)ensure the Company’s
preferred portfolio of resources balances cost,risk,and environmental concerns;(3)treat supply-
side resources and demand-side measures equally;and (4)involve the public in the planning
process.The Company noted that the 2015 IRP makes many assumptions about what will occur
over the next 20 years,including that:(1)the Company will continue to be responsible for
acquiring sufficient resources to serve its customers and operate as a vertically-integrated utility;
and (2)the Company will add about 196,000 customers and increase its load by 1.2%per year
for average energy demand and 1.5%per year for peak-hour demand.The Company plans to
meet this increased demand by combining demand-side measures with additional Company-
owned resources.
C.Preferred Resource Porfolio
With the 2015 IRP,the Company selected a preferred resource portfolio that assumes
the Boardman to Hemingway (B2H)transmission line will be completed and the North Valmy
power plant will be closed in 2025,and that the Company will add 60 megawatts (MW)of
demand response and 20 MW of ice-based thermal energy storage in 2030,and a 300 MW
combined-cycle combustion turbine in 2031.The Company stated it needs no more resources
before North Valmy closes in 2025,and that the Company’s ability to serve customers with
existing resources before shields the preferred resource portfolio from risks of uncertainty
surrounding:(1)planned,but yet-to-be-built,solar generation under the Public Utility
Regulatory Policies Act of 1978 (PURPA);(2)the impact of the federal Environmental
Protection Agency’s (EPA’s)proposed regulations under Section 111(d)of the Clean Air Act
(CAA);(3)the B2H line’s completion date;and (4)retirement planning for North Valmy.The
Company notes,however,that even with this uncertainty it is prudent to complete B2H and retire
North Valmy early.The Company stated it can still adjust the timing of those actions as
warranted.
ORDER NO.33441 3
D.Action Plan
The Company’s short-term action plan for 2015 to 201$addresses preferred resource
portfolio items like B2H permitting and planning,and collaborating with North Valmy’s co
owner,NV Energy,on planning for North Valmy’s closure.The action plan also discusses:
permitting and planning for the Gateway West transmission line;evaluating how EPA’s
regulations may impact fossil fuel plants;pursuing cost-effective energy efficiency;amending a
Federal Energy Regulatory Commission license to adjust for the 50 MW Shoshone F ails project
expansion,and completing up to a 4 MW upgrade by 2019;completing selective catalytic
reduction (SCR)retrofits for Jim Bridger Units 3 and 4;and evaluating the economics of 5CR
retrofits for Jim Bridger Units 1 and 2.
E.Response to Order No.32980
In the Company’s 2013 IRP case,the Commission ordered the Company to ensure its
future IRPs account for national developments that could impact resource planning.See Order
No.32980.Consistent with that Order,the Company’s 2015 IRP accounts for the federal EPA’s
regulations implementing Section 111(d)of the CAA.
The Commission also ordered the Company to collaborate with stakeholders about
using energy efficiency as a resource.In response,the Company notes that it relies on its Energy
Efficiency Advisory Group for stakeholder input on energy efficiency and demand response
matters.The Company stated that it held two Energy Efficiency Working Group meetings for
stakeholders and that these meetings led the Company to continue investigating energy
efficiency-related transmission and distribution benefits.The Company also noted that it
updated the IRPAC on its efforts,and will evaluate whether energy efficiency programs and
measures can defer growth-related transmission and distribution investments.
The Commission also directed the Company to be actively involved with North
Valmy and promptly advise the Commission of developments that could impact the Company’s
reliance on that resource.Consistent with this aspect of the Order,the Company explained that it
and NV Energy have been discussing North Valmy’s future.The Company noted that balancing
the potential impact of EPA’s carbon regulations with the economic impact to customers and
their service needs is an important part of the Valmy discussions.
ORDER NO.33441 4
THE COMMENTS
Commission Staff,ICL,Sierra Club,SRA,and 42 individual customers commented
on the 2015 IRP.Commenters observed that the 2015 IRP is an improvement over prior IRPs.
Nevertheless,some concerns persist,and commenters thus offered suggestions for improving
future IRPs.The Company filed a reply that addressed some of these issues.The comments and
the reply are summarized below.
A.Customer C’omme;tts
Customers commented on a variety of subjects.For example,some customers
applauded the Company’s efforts to lessen reliance on coal by proposing to retire both North
Valmy coal plants by 2025.Others,however,urged the Company to close North Valmy Unit 1
even sooner,by 2019,to better protect the environment and potentially save customers $75
million over the next 20 years.Some customers also suggested that the Company should
decommission the Jim Bridger coal plant instead of retrofitting it with expensive pollution
controls.
One customer questioned the Company’s plan to upgrade the Shoshone Falls hydro
facility in 2019 when the Company needs no more resources until 2025.The customer suggested
that the Company’s next IRP should forecast both solar PV and battery storage in conjunction
with the natural gas forecast,evaluate more types of battery storage,better account for future
growth in the use of electric vehicles,and consider a residential DSM program with meters that
display real-time data on energy use,cost,and C02.
Some customers expressed concern about the limitation on PURPA power contracts
set forth in Case No.IPC-E-15-01.2 One customer recommended establishing a competitive
renewable energy procurement mechanism,like California’s Renewable Auction Mechanism,to
meet future load.Another customer expressed concern that the Company’s IRP and potential
reliance on an Energy Imbalance Market (ElM)3 to meet load could subject Idaho to brown-outs,
2 In IPC-E-15-01,the Commission reduced the length of certain PURPA contracts from 20 years to two years.The
Commission found the utilities do not need additional generating capacity,that PURPA and non-PURPA generation
exceeds Idaho Power’s and Rocky Mountain’s minimum average loads,and that given the undisputed evidence that
avoided costs are decreasing,retaining fixed rates for 20 years would violate PURPA’s Section 2 10(b)mandate that
avoided costs rates shall not exceed a utility’s avoided costs.See Order Nos.33357 and 33419.The Commission’s
Orders were not appealed.
An ElM is a means of supplying and dispatching electricity to balance generation and load fluctuations by
aggregating the variability of generation and load over multiple balancing authority areas.See Order No.32980 at
14.
ORDER NO.33441 5
significant primary utility voltage loss,and enable the Company and other utilities to artificially
inflate demand by restricting power supply available to the market.
One customer believes the Company inflated the expense of portfolios containing
pumped-storage hydropower projects.The customer criticized the Company for assuming those
projects would cost $5,000 per kW instead of the more realistic,$2,000-$2,500 per kW used by
other utilities.The customer suggested that using the lesser costs would ensure the Company’s
future IRPs more fairly consider portfolios that have pumped-storage projects.
Another customer claimed the Company overestimated the cost of solar photovoltaic
(PV)resources.The customer noted that the IRP’s lowest cost for solar PV is $105 per MWh
over 30 years when far less expensive solar PV exists in Idaho.In particular,the customer
observed that the Company buys solar power from first Wind and Grand View at prices ranging
from $63-$74 per MWh over 20 years.In reply to this and similar comments (for example,from
the Sierra Club),the Company explained that solar cost estimates rely on a third-party report on
resource costs.The Company noted that the costs of solar PV resources,as well as other
resources,was extensively discussed with the IRPAC and public participants and will continue to
receive considerable attention during the development of the 2017 IRP to properly reflect
changes in the PV solar market.
B.Staff Comments
Staff stated that the 2015 IRP complies with the Commission’s Orders and is an
improvement over the 2013 IRP.Staff thus recommended that the Commission acknowledge the
Company’s 2015 IRP.Staff particularly supported the Company’s development and modeling of
a variety of portfolios that include many resource retirement and replacement scenarios,
alternatives to B2H,and expanded energy efficiency and demand response resources.Staff also
supported the Company’s proposed pilot projects including ice-based thermal energy storage,
community solar,and solar PV to address distribution feeder loss.Staff noted that the Company
also modeled CAA Section 111(d)compliance possibilities,stochastic risk,and at the request of
stakeholders provided a year-to-year price variability risk assessment for each portfolio,as well
as a tipping point analysis to evaluate how declining capital costs for utility-scale solar PV and
pumped hydro generation affect total portfolio costs.Staff opined that the Company performed
extensive analyses,gave reasonably equal consideration to supply and demand-side resources,
and provided acceptable opportunities for public input.
ORDER NO.33441 6
While Staff recommended that the Commission acknowledge the IRP,Staff also
suggested that the Company consider the following four issues when developing future IRPs.
1.Screen Cost Effectiveness with the Utility Cost Test.Staff reiterated its
recommendation from prior cases that the Company should use the Utility Cost Test (UCT)and
not the Total Resource Cost test (TRC)to screen energy efficiency potential for cost-
effectiveness.4 In reply,the Company noted that the Commission has never precluded it from
using the TRC,and has stated that “the Company may (but need not exclusively)emphasize the
UCT”(see Order No.33365 at 9-10).Further,using the TRC is consistent with the
Memorandum of Understanding that Staff and Idaho’s lOUs signed in 2010,and with the orders
of the Oregon PUC.See OPUC Order No.94-590,requiring program administrators to use the
TRC.
2.Simultaneously Model Demand-Side and Supply-Side Resources.Staff stated the
Company could better incorporate energy efficiency into the RP by modeling demand-side
resources simultaneously with supply-side resources,as do PacifiCorp,Avista,the Northwest
Power and Conservation Council,and Puget Sound Energy.In reply,the Company explained
that it commits all achievable energy efficiency potential to every portfolio regardless of need,
and thus gives preferential treatment to energy efficiency over supply-side resources.In fact,the
Company does not identify whether it needs additional supply-side resources until after it applies
all cost-effective energy efficiency to the load and resource balance.The Company stated that,
despite what other utilities may do,the Company’s method is consistent with Idaho policy and
Commission Orders requiring utilities to pursue all cost-effective energy efficiency.
3.Design Portfolios to Mitigate Risk.Staff observed that the Company designed
resource portfolios based on stakeholder preferences.Staff recommended that the Company’s
future IRPs design resource portfolios by forecasting specific scenarios and then strategically
selecting resource portfolios to mitigate the most significant risks of those scenarios.
4.Preferred Portfolio Selection.Staff (along with the ICL,SRA,and individual
customers as noted above)expressed concern that the Company may have ignored its own
The TRC and UCT test a DSM program’s cost-effectiveness from different perspectives.In summary,the TRC
compares program administrator costs and customer costs to utility resource savings,and assesses whether the total
cost of energy in a utility’s service territory will decrease.The UCT,on the other hand,compares program
administrator costs to supply-side resource costs,and assesses whether utility bills will increase.Under both tests,a
program or measure is deemed cost-effective if it has a benefit/cost ratio above 1.0.
ORDER NO.33441 7
quantitative analysis when choosing the preferred portfolio.In particular,Staff noted that the
Company’s preferred portfolio,which contemplates closing North Valmy Unit 1 in 2025,is more
costly and risky than portfolios that would close North Valmy Unit 1 in 2019.In reply,the
Company explained that closing North Valmy Unit 1 in 2019 would increase annual depreciation
expense by $6 million more than the expense would be if North Valmy Unit 1 were to close in
2025.Moreover,customer rate increases due to capital additions to keep North Valmy Unit 1
operating would accelerate if the plant were to close in 2019 instead of 2025.When added to the
uncertainty in the assumptions used for the different portfolios,this need for immediate
additional cost recovery from customers led the Company to determine it would be imprudent
and unreasonable to close North Valmy Unit 1 by 2019.The Company believes its preferred
portfolio is lower risk than a portfolio with a 2019 closure,and that it promotes near-term rate
stability and is a reasonable glide path to reducing coal generation on the Company’s system.
C.ICL Comments
ICL noted the 2015 IRP contains a “robust consideration of future coal plant
operations,uses better data for future supply-side options,and considers a range of compliance
options for the [CAA]111(d)rule....“ICL also commended the Company for working
“collaboratively with stakeholders and thinking creatively about analytical inputs and methods.”
With regard to coal unit analysis,ICL stated that the Company developed a “methodology to
consider this issue that should be a best practice for utilities around the country.”And,for the
performance and cost of solar power,ICL noted that the Company “worked with stakeholders to
develop a robust method for assigning a peak capacity contribution for solar.”ICL
recommended,however,that the Company take additional actions on the following subjects:
1.Solar Performance.ICL suggested the Company reconsider its use of a 90%
exceedance factor when correlating five-minute generation profiles with specific high-load hours
for purposes of assigning a peak capacity contribution for solar.While ICL acknowledged that a
90%exceedance factor aligns with other peak-hour forecasts,it questions whether “planning to
be wrong 90%of the time is an appropriate metric as opposed to a 70%factor used for energy
planning.”
2.CAA 111(d)Compliance Options.ICL maintained that the Company should
update its analysis of CAA 111(d)compliance options to reflect that the EPA has issued a final
rule.The Company also should explore how to account for the full cost of carbon pollution
ORDER NO.33441 8
beyond the cost of pollution controls,including impacts to the hydroelectric system and energy
demands due to changes in rainfall and temperature patterns,the public health due to hotter drier
weather,and the potential for wildfires that could threaten remote generation or transmission
lines.See also SRA Comments (requesting the Commission direct the Company to address the
social cost of carbon in the 2017 IRP).
3.Energy Efficiency Potential.While ICL agreed with the Company’s using of a
third-party efficiency study to forecast technical,cost-effective,and achievable energy efficiency
potential,ICL disagreed with the level of achievable potential that the Company used to set the
load-and-resource balance.ICL noted that the level of achievable potential is less than the cost-
effective potential because achievable potential is calculated based on assumptions on market
maturity,customer preferences,and expected program participation.ICL stated that the
Company may be able to influence these assumptions and exceed achievable potential by
improving program design,marketing,and customer engagement.For the 2017 IRP,ICL urged
the Company to identify and strive to acquire an optimal amount of efficiency between the
achievable and cost-effective levels.ICL suggested that if the selected portfolio includes
additional efficiency beyond the achievable level,then the Company can work with the EEAG to
identify the hurdles assumed to limit uptake and devise strategies to acquire the resource.
In reply,the Company noted that not all cost-effective energy efficiency is
achievable,and that the achievable potential as determined by its third-party consultant is the
upper limit for cost-effective energy efficiency savings.The Company subsequently clarified,
however,that despite this comment,the Company has not changed is policies and “will continue
to pursue all cost-effective energy efficiency.”The Company “does not and has not viewed the
achievable potential as a ‘ceiling’for the pursuit of cost-effective savings and will continue to
pursue energy efficiency beyond the achievable potential when possible.”See Company letter
filed October 21,2015.The Company also stated that it strives to continuously improve its
program design and operation while keeping costs in check.Lastly,the Company believes that
creating a separate multi-year implementation plan,as suggested by ICL,is unnecessary and
would create an additional administrative burden.The Company explained that its current
planning and reporting on DSM activities is comprehensive and adequate and involves regular
updates to the EEAG and the filing of any annual DSM report.
ORDER NO.33441 9
D.Sierra Ctzth Comments
The Sierra Club stated that the 2015 WP is the “latest step along a path of continuous
improvement in the Company’s recent resource planning activities,”and “is the best IRP yet.”
Sierra Club Comments at 1-2.However,Sierra Club believes changes are needed in how the
TRP treats transmission and distribution (T&D)costs.Sierra Club expects that distributed
generation (both solar PV and natural gas-fired reciprocating generators)and enhanced
information system enabled demand-management opportunities can reduce T&D expenditures;
however,the Company’s AURORA cost model does not identify these potential T&D cost
savings.Sierra Club believes that updating the IRP analysis to include T&D costs can reveal
even more cost-effective resource alternatives than the IRP currently considers.Sierra Club thus
asked the Commission to direct the Company to improve the 2017 IRP by:(a)expanding the
scope of future cost analyses to consider all relevant T&D expenditures,not just generation
costs;and (b)making a concerted effort to ensure in the 2017 RP solar PV costs are more fairly
estimated.
E.SRA Comments
The SRA commended the Company for its WPAC planning process being
“increasingly transparent and accessible to the public,”and recommended the Commission
accept the 2015 IRP.However,SRA noted that the Company has more than enough supply-side
resources,which has unfortunately led the Company to curtail its demand response programs.
SRA expressed concern that emphasizing thermal power production resources while interrupting
demand response resources sends the wrong message to customers and raises questions about the
Company’s commitment to reducing its greenhouse gas emissions.
SRA specifically requested that the Company take action on the following subjects:
1.IRPAC Process.SRA would like the Company to broaden public participation by
more visibly publicizing IRPAC meetings and exploring other methods to engage with
stakeholders,such as periodically holding evening meetings so customers and others can have
input at various stages of the WP’s development.
2.Pilot Projects.SRA appreciates that the IRP proposes three pilot projects:solar PV
to address distribution feeder voltage loss;ice-based thermal energy storage;and community
solar.The Company has promised,and SRA asked the Commission to ensure,that the
Company’s 2017 IRP will report on the Company’s early experiences with solar PV to address
ORDER NO.33441 10
distribution feeder voltage loss.SRA also urged the Commission to support the Company’s
proposed ice-based thermal energy storage pilot project.Lastly,SRA asked the Commission to
hold the Company accountable for implementing its community solar pilot projects so all
customers are assured the Company is committed to pursuing solar power as part of its supply-
side portfolio.
3.B2H Transmission Project.SRA does not oppose the Company including B2H in
its preferred portfolio,and commended the Company for sharing information on the B2H
process.But given the gravity that a B2H delay could have on the balance of the Company’s
preferred portfolio and the potential for increased C02 emissions,such as with new natural gas
projects,SRA urged the Commission to require the Company to submit quarterly public reports
on the status of B2H project.
4.Solar Power.SRA disagreed with the Company’s and Commission’s positions on
utility-scale solar power and the Commission’s Order No.33357 in Case No.WC-E-15-01.SRA
believes the Commission should direct the Company to ensure the levels of solar power
production called for in the Idaho Energy Plan.SRA noted that Idaho has some of the most
favorable solar potential in the nation,but Idaho is not contributing even a MW of solar power to
the western grid.SRA asked the Commission to reiterate that the 2012 Idaho Energy Plan
envisions robust development of solar energy,and that utilities should plan for and encourage
solar power development in their service territories.Or,if the Commission disagrees,then it
should provide guidance to the Legislature in preparing to update the Energy Plan.
5.Electric Vehicle Projections.SRA believes the Company inaccurately estimates
the number of licensed electric vehicles in its territory.SRA thus suggested that the Commission
direct the Company to frequently update its electric vehicle projections and the implication for
the Company’s load forecasts.
6.ElM Participation.SRA would like the Company to supply additional information
on its plans for possibly participating in a western ElM.In reply,the Company noted that in
September 2015 it announced its withdrawal from Northwest Power Pool’s effort to establish an
ElM,and its corresponding plans to study the costs and benefits of participating in the Cal-ISO
ElM.The Company stated that it expects to finalize its decision about the Cal-ISO ElM in 2016.
However,the Company believes a detailed analysis of ElM participation is outside the scope of
ORDERNO.33441 11
the WP,which addresses the adequacy of system resources,although a limited reporting of high-
level ElM developments would be appropriate for the 2017 RP.
FINDINGS AND DISCUSSION
Idaho Power is an electrical corporation and public utility.See Idaho Code §61-
118,-119,and -129.The Commission has jurisdiction over the Company and the issues in this
case under Title 61 of the Idaho Code,including Idaho Code §61-501.Having reviewed the
record in this case,we find that the Company’s 2015 IRP satisfies the requirements set forth in
the Commission’s prior Orders.We thus acknowledge that the Company has filed the 2015 IRP.
In doing so,we reiterate that an RP is a working document that incorporates many assumptions
and projections at a specific point in time.It is a plan,not a blueprint,and by issuing this Order
we merely acknowledge the Company’s ongoing planning process,not the conclusions or results
reached through that process.With this Order,the Commission is not approving the IRP or any
resource acquisitions referenced in it,endorsing any particular element in it,or opining on the
prudency of the Company’s decision to select its preferred resource portfolio.The appropriate
place to determine the prudence of the IRP or the Company’s decision to follow or not follow it,
and the validation of predicted performance under the IRP,will be a general rate case or another
proceeding in which the issue is noticed.
The Commission appreciates the Company’s collaboration with stakeholders in
developing the 2015 IRP,and the numerous well-written comments received in this case.We
encourage the Company to continue to increase stakeholder involvement in the IRP process.
Stakeholders offered many laudatory comments about the 2015 IRP.And as the Company
develops the 2017 IRP,we believe it is appropriate for the Company to continue to use the
IRPAC meetings and other outreach opportunities to further explore issues raised in this case.
For example,in the interest of transparency,we encourage the Company to more clearly explain
to stakeholders why the Company chose Portfolio 6(b)and its 2025 closure of North Valmy Unit
1 as the preferred portfolio,and why the Company believes it is imprudent to select Portfolio 9
or another portfolio that would close Unit 1 in 2019.We also believe it would be proper for the
Company to further explore whether its IRP could more effectively incorporate energy efficiency
by using a model that is similar to those used by PacifiCorp,Avista,the Northwest Power and
Conservation Council,or Puget Sound Energy.It would also be appropriate for the Company to
update stakeholders about the status of B2H,participation in an ElM,solar PV cost estimates,
ORDER NO.33441 12
and the penetration of electric vehicles and their impact on the Company’s load as the 2017 WP
is being developed.
ORDER
IT IS HEREBY ORDERED that the filing of the Company’s 2015 RP is
acknowledged.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order.Within seven (7)
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §6 1-626.
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this Z3
day of December 2015.
PAUL KJELLAND PRESIDENT
MARSHA H.SMITH,COMMISSIONER
KRI NE RAPER,CO MISSIONER
ATTEST:
D.Jewell (JCmissionSectetary
O:IPC-E-15-19_kk3
ORDER NO.33441 13