20191021Pengilly Direct.pdf

RECEIVED
1319 OCT 2l P!'l lr: 26
ON
BEEORE THE IDAHO PUBLIC UTILlTIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ]DAHO POWER COMPANY EOR
AUTHORITY TO EUND ]TS CONTINUED
PARTIC]PATION IN THE NORTHWEST
ENERGY EEEIC]ENCY ALL]ANCE
THROUGH THE ENERGY EEFICIENCY
RrDER FOR 2020-2024.
CASE NO. I PC_E- 19_ 34
]DAHO POWER COMPANY
DIRECT TESTIMONY
OF
PETER PENGILLY
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O PIease state your name, business address, and
present position
"Company" ) .
A. My
address is l22l
with Idaho Power Company ("Idaho Power" or
name j-s Peter Pengi11y.My business
Idaho 83702.
Research &
West Idaho Street, Boi se,I
am employed by Idaho Power as a
Analysis Leader j-n its Customer
Customer
Operations & Bus ine s s
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Devel-opment Department.
0. Please describe your work experience with
Idaho Power.
A. I began my employment with Idaho Power in
December 1999 as a Senior Pricing Anafyst in the Prj-cing
and Regulatory Services Department. My duties as a Senior
Pricj-ng Analyst incl-uded the development of afternative
pricing structures, management of pricing programs, the
analysis of the impact on customers of rate design changes,
and the administration of the Company's tariffs. In that
position, I helped develop several demand response
programs, a time-of-use pilot program, and a critical peak
pr j-cing program.
In 2006, I was promoted to my current position as
Customer Research & Analysis Leader in the Customer
Operations & Business Development Department. In this
position I am responsible for the research, ana.Iysis,
forecasting, and reporting associated with Idaho Power's
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PENGILLY, D]
Idaho Power Company
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energy efficiency and demand response programs. Part of my
current respons ibi 1it ies include participation in Northwest
Energy Efficiency AlLiance (*NEEA") activities: the
Regional Portfofio Advisory Conmittee and the Cost-
Effectiveness Advisory Conunittee.
O. What is the purpose of your testimony in this
case?
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A.
the amount
standards,
Idaho Power
The purpose of my testimony is to discuss (1)
of NEEA savings attributed to codes and
(2) allocation methodology of NEEA savings to
customers, and (3) cost-e f fect ivenes s impacts
Demand-Sj-de Management (*DSM") a.Iternate
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I. NEEA REPORTED ENERGY SAVINGS COST-EFEECTIVENESS
CAICIII,ATIONS
L6 O. What types of
L1 customers receive from the
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energy savings do ldaho Power's
Company' s participation in NEEA?
Idaho Power' s customers receive ene.rgy savlngs
which in
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19 through NEEA's mar:ket transformatlon efforts,
part, is an effort to permanently change the existing
market for energy efficiency goods and services by engaging
and influencing large nati-ona1 companies to manufacture or
supply more energy-efficient equipment. As descrlbed j-n
more detail in Mr. Richins' testimony, from 1997 through
2018, Idaho Power's customers were a.I.Iocated NEEA savings
of 371,527 megawatt-hours.
PENGILLY, DI
Idaho Power Company
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PENGlLLY. D]
Idaho Power Company
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1 Q. As part of preparation for the 2020-2024
2 cycle, has Idaho Power performed an analysis to validate
3 NEEA-reported energy savings and determine the cost-
4 effectiveness of those savings?
5 A, Yes, as part on the due dj-ligence leading up
6 to Idaho Power's funding of the 2020-2024 cycle, I analyzed
7 NEEA claimed energy savings wi-th respect to (1) the amount
8 of NEEA savings attrlbuted to codes and standards, (2')
9 allocation methodology of NEEA savings to Idaho Power
10 customers, and (3) cost-effectiveness impacts of declining
l1 avoided costs. The analysis also evaluated if claimed
72 savings from NEEA's 2018 initiatives would be cost-
13 effectlve using fdaho Power's standard cost-effective
L4 analysis that is conducted for programs 1t administers
15 directly.
16 O. Can you describe how NEEA develops and reports
71 Idaho Power's savings ?
18 A. In the spring of each year, NEEA sends Idaho
19 Power an annua.I savings report for the prior year. NEEA
20 reports savlngs in five ways:
27 o Total R€gional Sawings - estimated savings
22 associated wj-th af1 market changes in the
23 Northlrest
24 . Baseline Savings - estimated savi-ngs from
25 nalurally occurring market change without
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utilit.y, NEEA, Bonneville Power Administration
("BPA"), or Energy Trust of Oregon ("ETO")
intervention
Loca]. Prograo saviags - savings reported from
participating utilities, BPA, and ETO
I o Co-Creeted Savings - sum of Net Market Effect
Savj-ngs and Local Program Savings
The relatlonship between the types of savings is
reflected in Figure 1: Al-f iance Energy Savings (average
megawatt-hours ) , included below and on sl-ide 133 of the
NEEA 2020-2024 Strategic and Business Plan included as
Attachment 2 to the Application.
figurc 1: Alliarce Energy Savings (aMW)
TOTAI
I{ARKET
tlet MaEk€t Effects - calculated by
Base.Iine Savings and Local Program
Total Regional Savings
Net Marlet
Etrects
s ubt ract i ng
Savings from
ADOPTIOII
TIARKET
BASELINE rOTAL
REGIONAL
SAVINGS
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CURRET{I
MARKET
PENGlLLY. DI
Idaho Power Company
TIME
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ult
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=
Local Prcqrams
CGCREATEO
SAVINGS
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A. NEEA Savings Proportion fron Codes and Standards
Idaho Power were reported as deriving from codes and
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standards?
A.
Net Market
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attributed
What percent of the 2018 savings allocated to
In
]n 2018 NEEA reported that 83 percent of its
Effects savings were from codes and standards,
How has the percentage of Net Market Effects
to codes and standards changed over time?
A. The percentage of savings attributed to codes
standards have increased over time. Erom 2OA2 Lo 241310 and
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the percentage of savings averaged I percent, in 2013 it
increased to 1"9 percent and has gone up steadily since.
2015, 201,6, and 2017, the NEEA savings from codes and
standards were 68, 83, and B6 percent, respectively.
How does NEEA quant i fy
co-developed
1ts.influence and
16 determine its share of codes and standards ?
l7 A. Eor standards, NEEA accounts for the savings
18 by hj-ring a third-party evaluator to determine the
19 appropriate savings .Ieve1. NEEA's third-party evaluator
20 estimates the overal-l- regional savings using regional
2l assumptions and data where availabl-e. NEEA's evafuator
22 estimates the share of the savings that ls baseline and
23 calculates NEEA's share of savings based on how much
24 influence NEEA and its energy efficlency partners had on
25 the adoption of a standard. The thj-rd party considers the
PENGILLY, DI
Idaho Power Company
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number of meetings NEEA staff attends. comments they write
(or help write), and other activities to calculate the
percent of the overa.Il- inf l-uence on adoption of a standard.
The contractor compares the NEEA activities and influence
to NEEA's Standard's Logic Model: (program design or
outline) to see how successfully NEEA staff and other
energy efficiency organizations compl-eted each
stage /act j-vity. The contractor then applles that percentage
to the overa]]- estimated regional savings less the
basel-ine.
For codes, NEEA reports 100 percent of the savj-ngs
from code-to-code changes as Co-Created and Net Market
Effects savings. NEEA' s practice is to report the savings
for 10 years afte.r constructj-on starts under the new code.
NEEA, for example, provides technica.I expertise and data to
support the adoption of more stringent energy codes and
funds education and training efforts regionalJ-y. NEEA and
its contractors actively support above-code building
practices that help facil-ltate code advancement,
O. Who are the other energy effj-ciency
organizations NEEA partners with to facifitate code and
standards advancement?
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Logic model developed by the BPA
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ldaho Power Company
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L The modeling approach folfovrs a
and the NWPCC.
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A. It can vary depending on the standard NEEA is
work.ing to advance, but they often include: Natural
Resources Defense Councif ,' Appliance Standards Awa.reness
Project; California Investor Owned Utilitiesi and the
American Council for an Energy Efficient Economy.
B, NEEA Codes and Standards Cost-Effectiveness
O. How does NEEA cafcufate
energy efficiency savings attributed
promote codes and standards?
A. NEEA does not perform a
effectiveness anaJ-ysis on its work on
rather they anafyze if the initiative
Standards Logic Model (program design
O. Hov, does NEEA calculate
cost-ef fectiveness f or
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to NEEA' s efforts to
formaf cost-
codes and standards;
is f of l-owing NEEA's
or outline) .
cost-e f fectlvenes s for
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16 A. NEEA calculates cost-effectiveness on Total
l1 Regional Savj.ngs using the Total- Resource Cost (*TRC")
18 test. NEEA aligns its cost -effect ivenes s methodology with
l-9 the methods and inputs from the Northwest Power and
?0 Conservation Counci.I (*NWPCC"). They use the Procost model,
2l and inputs from the NWPCC most current power p1an,
'?The Procost model was developed to characterize the costs and
benefits of conservation measures and programs so that they can be
compared on an equal footing to other energy resource options includingqeneraiion and other dernand-sicie resources. NEEA uses the most recent
version of Procost localed on the Regional Technical Forum's ("RTF")
website: https: //rtf, nlicouncil. org /work-product s / suppo rt i!g-
docume !Lts/proclqq
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Idaho Power Company
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current.l-y the
These inputs
vaIue, winter
analyses
incfuded
7th Power Pfan,published Eebruary 25, 20\6.3
costs, line .Iosses, ca.rbonincfude avoided
peak value, and in some cases savings and
costs from the NWPCC or the RTE. NEEA' s TRC tests are
calcufated assuming 20 years of market development. The
impact of the 2O-year horizon will depend on forecasted
future assumptions incJ"udlng market penetration, unit
counts and costs. NEEA performs forma.l cost -e ffectivenes s
on initiatives in market development which in 2018
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low wattage l-amp
O. rs
heat pumps, heat pump water heaters, and
repLacement j-nitiat ives .
NEEA cost-effective under thi-s modef?
A. Yes, market development initiative's cost-
effectiveness benefits outweigh costs of total NEEA
spending making the portfolio cost-effective under NEEA's
methodol-ogy. Under NEEA's cost -effect ivenes s model and
current inputs, NEEA shows a portfolio cost-effectiveness
TRC ratio of 1.4 for 2018.
II. IDAEO POIIER' S SEARE OF NEEA SAVIIIGS
ductless
How does NEEA calcul-ate ldaho Power's savings?
NEEA determines Idaho Power's savings by
that year's Net Market Effect savings by the
Idaho Power percentage of total annual- funding
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Idaho Power Company
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multiplying
same year' s
r ht t s : //www. nwcouncil. orglenergy/f th-northwest-polrer-pIan/about-
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for NEEA. In 2018, Idaho Power's share of funding was 8.01
percent.
O. Does ldaho Power be.Lleve this resuft
represents savings Idaho Power customers receive?
A. While the Company cannot be certain that
allocatj-ng savings based on funding proportion accurately
reflects actuaf savings occurring for Idaho Power's
customers, the Company believes it is a reasonable method
given the difficulty in allocating regional ef fo.rts to
specific uEifiLy service areas.
III. COSI-EFFECTI\IENESS IMPACTS OE DECIINING AITERNATE
COSTS A}ID IDASO PO}'ER' S A}iIAIYS I S Or' NEEA COST-EEEECTIVENESS
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L4 effectivenessmodel-
15 A. Yes,
16 cost-effectiveness
Can you briefly describe Idaho Power's cost-
and inputs?
for the TRC test, Idaho Power uses a
model common for util,ities. The Company
l1 conducts cost-effectiveness analysis using first year
18 measure or program costs divided by the present value of
19 the benefits stream over the measure Iife of the measure or
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program.
benef .i-ts,
benefits,
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analysis
The benefi-ts include DSM alternate costs, capacity
avoided Transmisslon and Distlibution ('T&D")
and non-e.l-ectric impacts.
that
Please describe the cost -effect iveness
Idaho Power conducted Ieading up to the
NEEA contract for the 2020-2024 cycle.
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Idaho Power Company
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A. Idaho Power conducted a cost -ef f ect.ivenes s
analysis using inputs provided by NEEA for 2018 and the
Company' s standard cost-effectiveness analysj-s modeJ-
applied to its directLy administered programs. Idaho Power
received the following inputs from NEEA staff for the 2018
report for the three initiatives in the market devel-opment
. Weighted unit counts for total region
. Total- Regional, Co-Created, and Net Market Effects
savings
. RTE and/or NEEA savings vafues
. Present value of non-energy impacts over the life of
the measure
o Measure ll fe
. Totaf initiative spending
o Additionaf program costs from the region
L1 Idaho Power's inputs included:
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. DSM alternate costs
. Avoided T&D benefits
. Line ]os ses
. Load shapes
22 ldaho Power's DSM alternate costs and financial assumptions
23 were sourced from Idaho Power's most
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recentl-y
the Idaho
acknowledged
Publ icIntegrated
Utilities
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Resource Plan
Commi-ssion,
How did
the
("rRP") by
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21 effectiveness
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Idaho Power's ca]culated NEEA cost-
compare to NEEA reported cost -effect ivenes s
using these inputs ?
a Case No. IPC-E-17-11, Order No. 33983.
PENGILLY, DI 10
Idaho Power Company
I A. OnIy one of the NEEA inj-tj-atives in market
2 development was shown to be cost-effective under ldaho
3 Power's methodology. Usinq Idaho Power's methodology,
4 NEEA' s 2018 portfolio TRC ratio for Total Regional Savings
5 was 0.54 compared to NEEA's reported vafue of 1.4.
6 Q. Can you explain the difference between the
7 Idaho Power calculated and NEEA reported cost-effectiveness
8 ratios?
9 A. There are three primary differences between
L0 the Idaho Power calcu]-ated cost-effectiveness and NEEA's
11 analysis. Eirst, NEEA's benefit values in its cost-
12 effectiveness analysis align with the NWPCC ?th Power PIan.
13 Not only are the benefits used for the 7th Power Pl-an
1,4 considerably higher than the Idaho Power 2017 IRP benefit
15 vafues across all categories, NEEA also includes a val,ue
L6 for carbon reduction in its avoided costs, whereas Idaho
71 Power does not.
18 Iife considering
Second, NEEA assumes a 20-year program
the average measure Iife cont.inued over 20
cost-effectiveness wifl be impacted byt9
20
years.
forecast
longer
to the
Therefore
uni t. count s.
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efficient technology or
NEEA uses is much Lower
incremental costs, and savings over a
Power uses first-year costs compared
from a third-party source, of an
system. Finally, the discount .rate
than the discount rate Idaho Power
perlod.
present
Idaho
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value of the benefits over the average
23 measure obt a r ned
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uses, 4 percent versus
discounting of savings
calcufation,
O. When Idaho
NEEA cost -e ffectivenes s,
(avoided) costs did the
most cl-osely aJ-ign with?
A. The NWPCC
most cl-osely w j-th Idaho
6.74 percent, which affects the
and benefits/costs in the NEEA
Power completed its analysis of
which Idaho Power DSM alternate
NWPCC 7!h Power PIan avoided costs
7th Power PIan avoided costs aligned
Power's 2013 IRP DSM alternate
10 costs for energy.
Vihat has been the trend of Idaho Power's DSM
costs in i-ts 2015 and 2017 fRPs?
Idaho Power's DSM alternate costs have
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L2 alternate
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14 steadily decl,ined for the 2015 and 2017 IRP. There was an
15 approximate 36 percent decline from the 2013 IRP to the
16 2015 IRP, and a 13 percent decline from the 2015 IRP to the
L7 2017 IRP. The cumulative change from the 2013 IRP to the
l-8 2017 IRP was a 44 percent decfine in DSM alternate costs.
19 Exhibit No. 2 to my testimony graphs the Company's
20 declining DSM alternate costs in the 201-l through 20L'1
2L IRPs.
22 O. How does the recent trend of Idaho Power's
23 declining DSM afternate costs compare to other utiLities in
24 the region?
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PENGILLY, D] 1.2
Idaho Power Company
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a.L so experiencing
Portland Genera.I
Other utilities.in the Northwest region are
costs. In oregon,declining avoided
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are blended to determine avoided costs for ETO, which cited
declj-ning avoided costs ranging between 5 and 21 percent by
measure for the 2014 planning year as noted on page 2 of
Exhibj-t No. 3 to my testimony, and declining between 6 and
18 percent by measure for the 2018 planning year.i
Avista Util-ities in the state of Washington has also
experience reduced avoided costs, Standard Power Rates for
Qualified Eacility output under j-ts Schedufe 62 ate
j-nformed by avoided costs, and the fJ-rst year of delivery
rate has decreased by approximatel-y 47 percent for first'
year delivery rates effective January 2013 compared to
first year deJ-ivery rates effective November 20L7. Please
see Exhibit No. 4 to my testj-mony for a comparison of
Avista Schedule 52 Standard Power Rates from January 2013
to November 2011 in the state of Washington.
O. What j-s the anti-cipated timing of the next
update for inputs used in NEEA cost-e f fect ivenes s ?
: Energy Trust Electri-c and cas Avoided Cost Update for Oregon for
2018 Measure and Proqram Planning, p. 5.
E.Iectric and Pacific Power avoided costs
/tt
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htt s: //www. e nerqyt rus t content / u
018 .df
l oaCs /20 18 / 01 /Energy- Trus t -
Avoided-Cost-U da t e- f or-Oregon-2
PENGILLY, DI
Idaho Power Company
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A The NWPCC 2021 Power PIan will be the basis
for NEEA' s next
be published in
v.the Company concerned the next NWPCC Po$/er
P.Ian's avoided costs might decrease similar to Idaho
Power's change in alternate cost from 2071-207'7 ?
A. That is hard to say. Normally I would say yes
because a decrease in avoided costs is occurring for most
utifities. However, the NWPCC is revising its overall
methodology for determining the val-ue of energy efficiency,
so the outcome is currently uncertain. If avoided costs
avoided cost update, which is scheduled to
early 2021 .
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72 for NWPCC Power Plan decrease in a slmilar manner as Idaho
l-3 Power's, they may have a negative impact on the future
1-4 cost-effectiveness of NEEA.
l-5 O. How is Idaho Power addressing the risk that
16 NEEA' s savings may no longer be cost-effective during the
77 2020-2024 cycfe ?
18 A. The Agreement negotiated with NEEA includes
19 provisions allowing the Company to exit the agreement for
20 variety of reasons including fack of regulatory approval,
2L and for convenience with 365 days' notice.
22 IV. STNGEOI.,DER ENGAGEMENT
23 O. Did Idaho Power consult the Energy Efficiency
Advisory Group ("EEAG") regarding the Company's plan to
pursue funding NEEA in the 2020-2024 cycle?
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PENGILLY, DI 1.4
Idaho Power Company
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A. Yes, on September 3, 20L9, the Company held a
calf with EEAG to share the resu.l-ts of the cost-
effectiveness evaluation and to discuss its plan to fund
l}:e 2020-2024 cycle. Several EEAG members asked clarifylng
questions regarding differences in methodology between NEEA
and Idaho Power's energy efficiency cost-effectivenes s
calculations, how NEEA allocates energy savings to Idaho
Power, and how infl-uence on codes and standards j-s
quantified.
o.Was EEAG supportive of the Company's plans to
l.L pursue funding the 2020-2024 cyc).e?
12 A. Yes.
13 V. CONCLUSION
14 0. With consideration of these potential issues
15 for NEEA reported savings and future cost-effect ivenes s,
16 does the Company support funding the 2020-2024 cycle?
l1 A. Yes, with the inclusion of contract provisions
18 allowing the Company to terminate the agreement if
19 circumstances suggest that participation is no longer
20 reasonable, I believe it is appropriate for the Company to
2l continue supporting NEEA.
22 O. Does this conc.Iude your testimony?
23 A. Yes, it does,
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PENGILLY, DI 15
Idaho Power Company
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ATTESTATION OF TESTTMONY
STATE OF I DAHO
County of Ada
I, Peter Pengilly, having been duly sr,rorn to testify
truthful-ly, and based upon my persona.I knowledge, state the
followi-ng:
l am employed by Idaho Powe.r Company as Customer
Research & Analysis Leader in the Customer Operations &
Business Development Department and am competent to be a
witness in Lhis proceeding.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-fiIed testimony
and exhibits are true and correct to the best of my
information and belief .
DATED this 21st day of October 2019.
e ter Pengilly
SUBSCRIBED AND SWORN to before me th.is 21st day of
23 October 2019.
o uJ-!.,(
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No ary P ic for ldaho
Re s idi ng at Bo ise Idaho
My commission expires:72/2A /202A
PENGILLY, DI 1.6
Idaho Power Company
KIMEEHLY K. TOWELL
coMMrssroN #16958
NOTARY PUBLIC
STATE OF IDAHO
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. !PC-E-19-34
IDAHO POWER GOMPANY
PENGILLY, DI
TESTIMONY
EXHIBIT NO. 2
AloUOrlpggtEl
ldaho Power DSM Alternate Cost by IRP Cycle
so.2oo
-2011tRPs0.180
-2013
tRP (Similar to NWPCC)
2015 tRP
$0.160
2017 rRP
E3
o(J
o
(,c
{,
a
E
o
s0.140
So.12o
$o.roo
s0.080
So.o50
So.o40
so.o20
So.ooo
2018 2019 2020 20212022 2023 2024 2025 2026 202t 2028 2029 2030 2031 2032
7 Exhibit No. 2
Case No. IPC-E-19-34
P. Pengilly, IPC
Page I of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. !PC-E-19-34
IDAHO POWER COMPANY
PENGILLY, DI
TEST!MONY
EXHIBIT NO. 3
\1.
EnergyTiust
ot Oregon
Energy Trust Electric Avoided Costs
January 30, 2014
Energy Trust's electric avoided costs are critical assumptions used to evaluate the value of
energy savings of measures and programs through the total resource and utility cost tests of our
cost effectiveness models. While updating them for 2014 operations and planning purposes,
Energy Trust, OPUC staff, PGE and Pacificorp staff collectively anived at a new approach.
The existing calculation used some dated regional assumptions for important cost adders and
old market price forecasts. Therefore the overall goal of the new approach was to align key
assumptions with cunent utility planning processes and markel conditions in a way that would
be easy to replicatG every two years as markets change.
The agreed upon methodology consists of four key components- Those components are 1)
base foruard prices, and what the adders to the base prices should be; 2) avoided T&D
assumptions, 3) generation deferral value and 4) 10% conservation credit compared to the risk
avoidance value.
1) Base forward prices
Two options were discussed for use as base foruard prices; filed QF avoided costs or a blend of
fonarard market prices and production model prices with base case carbon regulation
assumptions. The group agreed to start with the weighted average biend (based on utility
revenue contributions, 41% PAC and 59olo PGE) of forward markel and production cost model
prices produced by each utility for their system. Going forward, when updating avoided costs
every other year, the most recent version of fonvard prices that available from each utility will be
used.
2) Avoided T&D value
The first adder to the base fonrard prices is a value for the deferr€d or avoided T&D capital
investments due to less need to transmit energy than planned. Energy Trust had been using the
NW Power Council's regional estimate for this system benefit; $20/kW year for avoided
distributions and $3/kw year for avoided transmission level investment but each utility has since
been valuing this benefit specific to their systems.
ln PacifiCorp's 2013|RP, they estimate the value to be $54/kw year. PGE estimated
$6.03/MWh as the avorded cost for a savings shape that follows the system load which
translates to 529.21lkw y6ar. The weighted average result of these syslem specific values is
now used in Energy Trust's calculation. Each savings shape provides different daily and
seasonal variation in contribution to capacity savings which is reflected in translating $/kW year
into $/MWh for avoided cost calculations for each measure.
3) Generation resource capacaty deferral benefit
Both utilities calculate this value within their IRP models by running lheir resource selection
models after removing 100 MW of DSM resources and comparing the fixed portfolio costs to
those of the base portfolio resources. The timing and value of this benefit varies by utility
system. PacifiCorp's thermal resource deficiency period of their 20-1 3 IRP begins in 2024 but the
value of DSM in their base portfolio shifts their value of $29.20lMWh levelized ahead four years
Exhibit No. 3
Case No. IPC-E-19-34
P. Pengilly, IPC
Page 1 of 3
to 2020. PGE first assigns value to generation capacity deferral to 2018 at $19.51/MWh
levelized. Removing DSM from their base portfolio shifted their deficiency period fonivard 3 three
years from 2021. Prior to 20'18, Energy Trust's avoided cost calculation does not include any
value for generation resource capacity defenal benefit. From 2018 foruvard, a blended rate is
applied.
4) Risk avoidance value and 100/o NW Conservation Credit
In addition to avoided T&D and generation capacity investments, both utilities have quantified
the value of fuel price risk avoidance. PacifiCorp's IRP refers to it as stochaslic risk reduction
with an average value across efficiency savings shapes of $2.12lMWh levelized. PGE's risk
reduction value is similar at $2.41lMWh levelized.
The Northwest Power Act directs the Council and Bonneville to give conservation a 10 percent
cost advantage over sources of electric generation. The Council does this by calculating the Act
credit as 10 percent of the value of energy saved at wholesale market prices, plus ten percent of
the value of savings from deferring electric transmission and distribution system expansion.
Energy Trust has followed suit and currently adds 10% to the avoided cost value, before
generation defenal or risk reduction benefits are included. ln defining the new approach to
calculating avoided costs, the question of whether the risk reduction values are represented
within the 10% credit was discussed and if it's duplicative to include both in the calculation. The
group agreed to continue to include both values.
New Avoided Cost Results and Comparison
Utilities supplied all necessary information to Energy Trust to create new avoided costs.
Compared to the current avoided costs, the new avoided costs are lower but not by a consistent
amount across measure savings shapes and lifetimes. For example, avoided costs for heat
pumps with an 18 yr. measure life declined just 5% while the avoided cost for commercial
lighting with a 15 year measure life declined 20o/o. 'lhe difference illustrates the importance of
load shape and measure life in determining value, and how much lhat has changed with the
new approach.
Table 1. Levelized Cost Per First Yea. kwh
load Profile
Life
(vr.)
New
Values
otd
Values
o/o
Change
lndoor Lighting
Electric Water Heater
New Commercial Light
F LAT
Air-Source Heat Pump, 21
Existing Weatherization
Residential Space Heat
NEW
7
t2
15
15
18
45
70
s0.07
50.08
s0.07
so.07
So.10
so.10
50.11
So.o8
s0.09
s0.09
s0.09
s0.11
5o.rr
So.12
-L8o/o
-L4o/o
-20o/o
-21%
-5o/o
-8o/o
-5%
Next staps
Energy Trust will request updated values for each of the key assumptions from electric utilities
every two years. The n6xt update will be Q'1 2016.
Exhibit No. 3
Case No. IPC-E-19-34
P. Pengilly. IPC
Page 2 of 3
Exhibit No. 3
Case No. IPC-E-I9-34
P. Pengilly, IPC
Page 3 of 3
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CASE NO. IPG-E-19-34
IDAHO POWER COMPANY
PENGILLY, DI
TESTIMONY
EXHIBIT NO. 4
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Case No. IPC-E-19-34
P. Pengilly, IPC
Page '1 of 1
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