20171005final_order_no_33898.pdf

Office of the Secretary
Service Date
October 5,2017
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )CASE NO.IPCE4742
APPROVAL OF THE CAPACITY )
DEFICIENCY TO BE UTILIZED FOR )ORDER NO.33898
AVOIDED COST CALCULATIONS )
On July 26,2017,Idaho Power Company applied to the Commission for an Order
approving the capacity deficiency period for the Company’s avoided cost calculations under the
Public Utility Regulatory Policies Act (PURPA).The Company asked that the Application be
processed under Modified Procedure.The Commission issued a Notice of Application and
Notice of Modified Procedure setting comment and reply deadlines.Order No.33838.The
Commission also granted intervention to the Idaho Hydroelectric Power Producers Trust,d/b/a
IdaHydro.Order No.33856.Commission Staff timely submitted comments.After the
comment deadline,IdaHydro submitted comments styled as a “Response to Comments of the
Commission Staff”Idaho Power timely submitted reply comments.No other comments were
received.
Having reviewed the record,the Commission enters this Order approving the
Company’s Application and requested capacity deficiency period of July 2026 for the
Company’s avoided cost calculations.We also approve the updated published avoided cost rates
attached to this Order.The Commission’s decision is set out more fully below.
BACKGROUND
Under PURPA,electric utilities must purchase electric energy from qualifying
facilities (QFs)at rates approved by the applicable state agencyin Idaho,this Commission.16
U.S.C.§824a-3;Idaho Power Co.v.Idaho PUC,155 Idaho 780,780,316 P.3d 1278,1287
(2013).The purchase or “avoided cost”rate shall not exceed the “incremental cost’to the
purchasing utility of power which,but for the purchase of power from the QF,such utility would
either generate itself or purchase from another source.”Order No.32697 at 7,citing Rosebud
Enterprises v.Idaho PUC,128 Idaho 624,917 P.2d 781 (1996);18 C.F.R.§292.101(b)(6)
(defining “avoided cost”).
The Commission has established two methods of calculating avoided cost,depending
on the size and resource of the QF project:(1)the surrogate avoided resource (SAR)
ORDER NO.33898 1
methodology,and (2)the integrated resource plan (IRP)methodology.See Order No.32697 at
7-8.The SAR methodology is used to establish what are commonly called “published”avoided
cost rates.Id.Published rates are available for wind and solar QFs’with a design capacity of up
to 100 kilowatts (kW),and for QFs of all other resource types with a design capacity of up to 10
average megawatts (aMW).For QFs with a design capacity above the published rate eligibility
caps,avoided cost rates are “individually negotiated by the QF and the utility using the [IRP
methodology].”Id.at 2;Order No.32176.
In calculating avoided cost.the Commission found it “reasonable,appropriate and in
the public interest to compensate QFs separately based on a calculation of not only the energy
they produce,but the capacity that they can provide to the purchasing utility.”Order No.32697
at 16.As to the capacity calculation for the SAR methodology,the Commission found it
appropriate “to identify each utility’s capacity deficiency based on load and resource balances
found in each utility’s IRP.”Id.With respect to the IRP methodology,the Commission
similarly stated
[i]n calculating a QF’s ability to contribute to a utility’s need for capacity,we
find it reasonable for the utilities to only begin payments for capacity at such
time that the utility becomes capacity deficient.If a utility is capacity surplus,
then capacity is not being avoided by the purchase of QF power.By including
a capacity payment only when the utility becomes capacity deficient,the
utilities are paying rates that are a more accurate reflection of a true avoided
cost for the QF power.
Id.at2l.
The Commission found that “the IRP process determines when the utility will
experience a need for new capacity.”Id.at 23.The Commission acknowledged this
determination has “an impact on calculations under the SAR and IRP methodologies.”Id.
Because the utility’s TRP is reviewed by this Commission,but not “approved,”the Commission
found it “reasonable and fair to subject each utility’s determination of capacity deficiency to
further scrutiny.”Id.The Commission directed that when a utility submits its IRP to the
Commission,“a case shall be initiated to determine the capacity deficiency to be utilized in the
SAR Methodology.The capacity deficiency determined through the IRP planning process will
be the starting point,and will be presumed to be correct subject to the outcome of the
proceeding.”Id.Likewise,the Commission has considered updates to Idaho Power’s capacity
See Order No.33785 (regarding battery storage facilities).
ORDER NO.33898 2
deficiency date for the IRP methodology in cases filed separately from the IRP.See Case Nos.
IPC-E-14-22;IPC-E-15-20.
In 2015,the Commission confirmed July 2024 as Idaho Power’s capacity deficiency
period for the incremental cost IRP methodology and approved the updated SAR model based on
that deficiency period and the updated SAR-based rates.Order No.33377.
THE APPLICATION
Idaho Power stated that its 2017 IRP,which it filed with the Commission on June 30,
2017 (Case No,IPC-E-17-11),identifies a first peak-hour deficit in July 2026.Application at 2.
Idaho Power described that peak-hour load deficits are determined using 90’percentile water
and 95th percentile peak-load conditions.Id.at 2-3.The Company indicated that under the
IRP’s preferred portfolio,a first capacity deficiency of approximately 34 MW occurs in July
2026 and a first energy deficit of 143 MW occurs in July 2029.Id.at 3.The Company
requested that the first capacity deficit date of July 2026 be used for avoided cost calculations for
both the SAR and IRP methodologies.Id.
THE COMMENTS
A.Commission Staff
Staff reviewed the Application and supporting documentation and believed that the
capacity deficit date of July 2026,as identified in the IRP,is reasonable.Staff Comments at 3-4.
Specifically,Staff stated that it compared the 2015 Peak-Hour Load and Resource Balance
(which was used to determine the current July 2024 capacity deficiency date)with the 2017
Peak-Hour Load and Resource Balance.Id.at 3.By comparing the two,Staff determined that
the primary cause of the two-year shift in the capacity deficiency date (from July 2024 to July
2026)was
a 103%increase in market purchase availability.The increase comes from
two sources:(1)an additional 130 MW of import transmission capacity into
the south side of its system by closing Valmy Unit 1 in 2019;and (2)an
additional 80 MW of incremental transmission capacity through the
Company’s Idaho/Montana transmission pathway.
Id.Staff also identified other contributing factors to the two-year shift—assumptions that
changed from the 2015 IRP to the 2017 IRP.Id.at 4.These assumptions include a decrease in
the peak-hour load forecast,an increase in existing energy efficiency,and a slight increase in
ORDER NO.33898 3
hydro generation and firm purchase power agreements.Id.Staff believed the changes in
assumptions are reasonable.Id.
Thus,Staff supported the Company’s request to use the July 2026 capacity deficiency
date for avoided cost calculations for the SAR methodology.Id.Staff updated the SAR model
accordingly and calculated new avoided cost rates,which were attached to Staff’s comments.Id.
Regarding the IRP methodology,Staff supported the use of the July 2026 date as a
starting point for avoided cost calculations.Id.Staff asserted that the capacity deficiency date is
applied differently under the IRP methodology than it is under the SAR methodology.Id.Under
the SAR methodology,“once the deficiency date is authorized,all new contracts signed within
the two-year period are effectively valued (through published rates)using the same deficiency
date.”Id.In contrast,Staff asserted,“for IRP-based contracts,the deficiency date is allowed to
float around the authorized deficiency date depending on the capacity contribution of projects
within the PURPA queue until a new deficiency date is authorized.”Id.Staff also discussed the
filing schedule for the capacity deficiency date updates and other updates relevant to the
calculation of avoided costs under PURPA.Specifically,Staff explained that utilities file their
capacity deficiency date updates every two years,after filing their IRPs.In contrast,the
Commission directed the utilities to file their annual fuel price and load forecast updates on or by
October 15 of each year.Staff suggested that combining the fuel price and load forecast update
with the capacity deficiency date update,in the years in which both occur,could reduce
administrative burden for Staff,utilities,and interested parties.As a result,Staff requested that
the Commission direct Staff to work with the utilities to establish a single filing date for the
updates to fuel price and load forecasts and capacity deficiency dates.
B.IdaHydro Response
IdaHydro disputes Staff’s and Idaho Power’s assertion and reasoning that the
Company will be capacity deficient in July 2026,instead of July 2024,because it will have more
transmission capacity than assumed in the previous IRP,and thus more market access.IdaHydro
Comments at 1.IdaHydro asserted this position is “factually contrary to the text of the IRP”and
“conceptually contrary to [PURPA].”Id.
IdaHydro quoted the Company’s IRP as stating that the Idaho/Montana pathway is
“capacity-limited during the summer months.”Id.at 2 (quoting Idaho Power IRP,Case No.
IPC-E-17-11,at 59).Regarding transmission associated with Valmy Unit 1,IdaHydro stated that
ORDER NO.33898 4
“it also appears that the Valmy plant currently occupies all the transmission capacity from the
south of the system.”Id.According to IdaHydro,the closure of that unit “opens only space that
is currently occupied and does not clear additional transmission capacity.”Id.To support this
assertion,IdaHydro included an excerpt from the Idaho Power IRP,which indicated,in part,that
while Nevada is not considered a viable source for abundant wholesale
energy,it may have potential to source seldom-needed capacity during peak
loading periods....For this reason,Idaho Power is assuming for the 2017
IRP that the retirement of North Valmy generating capacity can be adequately
replaced with infrequent wholesale capacity imports across the Idaho-Nevada
transmission path.
Idaho Power recognizes the uncertainty of assuming wholesale capacity
imports from Nevada can replace North Valmy generating capacity.The
viability of the Idaho-Nevada path can be evaluated as the company continues
to transition away from coal in a measured and responsible manner [and as
Idaho Power commences participation in the western Energy Imbalance
Market beginning in Spring 2018]....As it continues its evaluation,Idaho
Power recognizes the assumption that wholesale capacity imports from
Nevada can replace North Valmy generating capacity may prove unfounded,
and future IRPs may need to reflect such a change.
Id.at 2-3 (quoting Idaho Power IRP,Case No.IPC-E-17-l 1,at 68-69).IdaHydro thus asserted
that “the IRP appears to trend toward less ‘capacity’from future market and transmission trends,
not more.”Id.at3.
IdaHydro also asserted that using the availability of transmission capacity for market
purchases to extend the capacity deficiency date is “conceptually contrary to [PURPA].”Id.at 1.
IdaHydro submitted that “market purchase availability’does not supplant the capacity that
PURPA anticipates [QFs]bring to a utilities [sic]system when ratemaking.”Id.at 3.IdaHydro
suggested that if no investment in base load resources is required because QFs “supplant such
capacity,and the current Idaho Power base load balances intermittent ‘must take’QF energy
without additional investment,then Idaho Power’s new capacity costs are being avoided by QF
capacity”and new QFs should have a capacity payment.Id.
IdaHydro argued that if “market purchase availability”can count as utility capacity
for determining the capacity deficiency date,then “QFs may never receive capacity
compensation as contemplated by PURPA even though QFs displace new base load investment
and capacity.”Id.In brief,IdaHydro argued that QFs should receive capacity payments when
ORDER NO.33898 5
“QF energy displaces Idaho Power capacity without the need for new investment by the utility to
balance intermittent ‘must take’QF energy.”Id.at 3-4,
IdaHydro concluded by asking the Commission to stay this proceeding pending the
outcome of the IRP proceeding,Case No.IPC-E-17-ll,because “this docket depends entirely
upon the outcome”in that docket.Id.
C.Idaho Power Reply
In its reply,Idaho Power acknowledged Staff’s acceptance of its justification for a
July 2026 capacity deficiency date.Idaho Power Reply at 2.According to the Company,
IdaHydro’s position—that allowing transmission capacity and market access to meet capacity
deficits is “factually contrary to the text of the IRP”and “conceptually contrary to”PURPA—is
incorrect.Id.
Idaho Power explained that including “transmission capacity,or as [sic]sometimes
referred to as import capability,in Idaho Power’s load and resource balance is not contrary to the
IRP.”Id.Rather,it is included in this capacity deficiency case because it is included in the IRP.
Id.Idaho Power explained that in the past,it has included import capability for the Idaho-
Northwest transmission path,but that in the current load and resource balance,it has also
included import capability from the Idaho-Nevada path and the Idaho-Montana path.Id.at 4.
Idaho Power attached responses to production requests supporting its approach and explained
that
the import capability on the Idaho-Nevada path is a result of the analysis for
closure of the Valmy coal plant,that—in essence—swaps out coal generation
for import capability on that path.The 77 megawatts (“MW”)of import
capability on the Idaho-Montana path was not previously included in the 2015
IRP,but in Idaho Power’s assessment of the regional transmission
interconnections for the 2017 IRP and in conjunction with the closure of
Valmy,the Company determined that an additional 77 MW of transmission
capacity on the Idaho-Montana path could be assumed for peak-hour market
purchases in July 2024-2026.
Id.
Idaho Power further asserted,citing and quoting Order No.33425,that this
Commission previously determined that a utility’s import capability and its ability to purchase
short-term using its transmission capacity should be treated the same as available generation
ORDER NO.33898 6
resources,such as a signed QF contract or generation from its own plant,for purposes of setting
the utility’s capacity deficiency date for calculation of avoided cost prices.Id.at 2-3.
The Company concluded that it has “properly included its import capability in the
capacity deficiency determination as authorized,and required,by the Commission.”Id.at 5.
The Company reiterated its request that the Commission issue an Order approving a first
capacity deficit date of July 2026 to be used in the Company’s avoided cost determinations under
the SAR and IRP methodologies.Id.at 6.
COMMISSION FINDINGS
The Commission has jurisdiction over this matter under Idaho Code §S 61-502 and
61-503.The Commission has the express statutory authority to investigate rates,charges,rules,
regulations,practices,and contracts of public utilities and to determine whether they are just,
reasonable,preferential,discriminatory,or in violation of any provision of law,and may fix the
same by Order.Idaho Code §61-502 and 61-503.In addition,the Commission has authority
under PURPA and FERC’s implementing regulations to set avoided costs,to order electric
utilities to enter into fixed-term obligations for the purchase of energy from qualified facilities
and to implement FERC rules.The Commission may enter any final Order consistent with its
authority under Title 61 and PURPA.
We have reviewed the record,including the Application and comments.We find
Idaho Power’s proposed capacity deficiency date of July 2026 to be reasonable and appropriate.
The July 2026 date reflects an increase in market purchase availability based primarily on an
increase in transmission capacity resulting from the closure of Valmy Unit 1 in 2019 and an
increase in transmission capacity on the Company’s Idaho/Montana transmission pathway.
We note that IdaHydro’s comments,while filed as a response to Staff,were submitted
out-of-time.See Order No.33838.Regardless,we find that IdaHydro’s points are not
persuasive nor are they supported by the record.IdaHydro asserted that the IRP does not support
an increase in market purchase availability due to the closure of Valmy Unit 1 and on the
Idaho/Montana path.IdaHydro Comments at 1.We find that the record,and in particular the
Company’s IRP analysis,supports the assumption that such capacity is available and contributed
to the July 2026 date.
IdaHydro also asserted that inclusion of transmission capacity available for market
purchases is contrary to the requirements of PURPA.We disagree.We previously have found,
ORDER NO.33898 7
in Case No.PAC-E-15-12 involving Rocky Mountain Power,that a utility’s import capability
(its ability to purchase short-term using its transmission capacity)should be treated the same as
available generation resources such as a signed QF contract or generation from its own plant for
purposes of determining the capacity deficiency date.Order No.33425 at 6-7.There,the
Company used existing plant generation,QF contracts,and available transmission capacity to
balance its capacity needs.Id.at 7.We determined that “[i]mport capability constitutes
capacity,”and explained that when a utility has import capability available,it would use that to
meet its capacity needs—it would not build a new resource.Id.Thus,if a utility has available
transmission capacity,it is capacity surplus.Id.
We found that including the Company’s
import capability in the capacity deficit determination comport[edj with the
“incremental cost”mandate in PURPA.By including import capability,
avoided cost rates appropriately recognize the Company’s mix of available
resources.And importantly,including import capability ensures that avoided
cost rates do not favor QFs at the expense of Rocky Mountain’s ratepayers,
who ultimately bear the costs.
Id.(citing Order No.33419 at 6).As a result,the Commission approved the Company’s capacity
deficit determination,which included consideration of the transmission capacity it had available
for market purchases.
Similarly,here Idaho Power proposed to use available transmission capacity to
import market purchases to meet its capacity needs.Consistent with our previous analysis,we
find that when the utility has import capability available,it is reasonable to use that to meet
capacity needs,rather than building a new resource.It is therefore appropriate to consider the
utility’s import capability when setting its capacity deficiency date.Doing so ensures that
avoided cost payments to QFs include payments for capacity when the utility forecasts it will
need capacity—not earlier—and thus protects ratepayers.
Staffs interpretation of capacity deficiency determinations under the IRP
methodology—that July 2026 is a starting point and the actual deficiency date will “float
around”depending on the capacity contributions of QFs in the queue—is a divergence from our
prior Orders and from the Company’s request in this Application.See,e.g.,Order No.32697 at
23 (acknowledging that the IRP process determines when the utility will experience a need for
new capacity);Order No.33159 at 9 and Order No.33377 at 3 (each approving new deficiency
ORDER NO.33898 8
dates based on changes to the information from the last IRP);Application at 4 (requesting
approval of a deficiency date of July 2026 for the SAR and IRP methodologies).We find that
such a divergence,without a more thorough analysis of reasoning and potential impacts,would
not be just or reasonable.Thus,we find the proposed July 2026 capacity deficiency date to be
reasonable and we approve it for use in the SAR and IRP methodologies.We further find that
Staffs updated SAR model,using the July 2026 date,and the resulting published avoided cost
rates are just and reasonable,and we approve the rates.
We also find it reasonable and appropriate for Staff,utilities,and other interested
parties to explore whether to combine future PURPA fuel price and load forecast updates with
the capacity deficiency date updates every other year when all updates occur.Combined filings
could reduce the administrative burden on parties and result in more efficient use of time and
resources.
ORDER
IT IS HEREBY ORDERED that Idaho Power’s Application for approval of the
capacity deficiency to be utilized for avoided cost calculations is approved.We confirm that the
Company’s capacity deficiency period for the avoided cost SAR and IRP methodologies is July
2026.
IT IS FURTHER ORDERED that the updated SAR model and the SAR-based
published avoided cost prices,attached hereto,are also approved.
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 with regard to any
matter decided in this Order.Within seven (7)days after any person has petitioned for
reconsideration,any other person may cross-petition for reconsideration.See Idaho Code §61-
626.
ORDER NO.33898 9
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of October 2017
ATTEST:
PAUL KJELLAND ,PRESIDENT
J;;tz;4t
KRI E RAPER,COMMISSIONER
Diane M.Hanian
Commission Secretary
I:Legal\LORDERS\IPCEI 71 2cc2.doc
ERIC ANDERSON,COMMISSIONER
ORDER NO.33898 10
IDAHO POWER COMPANY
AVOIDED COST RATES FOR WIND PROJECTS
XXXX,2017
$/MWh
New Contracts and Replacement Contracts without Full capac Paents
Eligibility for these rates is limited to projects 100 kW or smaller.
LEVELIZED 4*öNLEELJZEÔ
CONTRACT ON-LINE YEAR
LENGTH .CONTRACT NON-LEVELIZED
J1L 2017 2018 2019 2020 2021 2022 YEAR RATES
I 28.61 31.48 34.42 3595 36.78 36.36 2017 28.61
2 29.99 32.89 35.15 36.35 36.57 36.71 2018 31.48
3 31.35 33.83 35.65 36.35 36.74 37,34 2019 34.42
4 32.37 34.48 35.81 36.52 37.18 38.39 2020 35.95
5 33 12 34.80 36.03 36.90 38.01 40.02 2021 36.78
6 3356 35.11 36.40 37.60 39,37 41.28 2022 36.36
7 33,g5 3552 37,03 38.75 40.48 42.32 2023 37.10
8 34.40 36.13 38.05 39.74 41.42 43.23 2024 38.76
9 35.01 37,07 38.95 40.61 42.27 43.99 2025 42.06
10 35.90 37.91 3975 41.39 42.98 44.64 2026 47.99
11 36.70 38.67 40,48 42.07 43.61 45.23 2027 49.35
12 37.42 39.36 41,12 42.66 44.18 45.77 2028 50.58
13 38.09 39.98 41.69 43.21 44.70 46.27 2029 52.04
14 38.69 40.53 42.22 43.71 45.19 46.76 2030 52.76
15 39.23 41.04 4270 44.18 45.67 47.22 2031 53.50
16 39.73 41.51 4.3.15 44.64 46.12 47.68 2032 54.64
17 4019 41.96 43.59 45.08 46.56 48.11 2033 55.49
18 40.62 42.38 44.01 45.50 46.98 48.53 2034 56.72
19 41.04 42.79 44.42 45.90 47.38 48.94 2035 .58.16
20 41 44 43 19 44.81 46.29 47.78 49.32 2036 59.63
2037 61.27
2038 62.44
2039 63.98
2040 85.87
2041 67.01
2042 69.03
Nc.te These rates wil be turther adlusted with InC appcab(e rntegraron charge.
Note The rates shcwn n trus table have been conrp’Jted uwng the U S Energy Incrmalon Adms’ssrrabon (EIAys Annuat Eregy
Outicok 2017,released January 2017.See Annua Energy Outtock 2017,Table 3.8 Energy Pnces by Sector-Moun1an at
https://weri.wa.gov’outtooksIaec/1abtes ref.cfm IDAHO POWER COMPANY Page 1
ATTACHMENT
CASE NO.IPC-E-1742
ORDER NO.33898
(PAGE 1 OF 5)
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SOLAR PROJECTS
XXXX,2017
$!MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates Is limited to profects 100kW or smaller.
LEVELIZED NONLEVELIZED
CONTRACT!ON4JNE YEAR
LENGTH CONTRACT NON-LEVELIZED
IYEARS)2017 2018 2019 2020 2021 2022 YEAR RATES
1 2861 3148 3442 3595 3678 3636 2017 2861
2 2999 3289 3515 3635 3657 3671 2018 3148
3 31 35 3383 3565 3635 3674 3734 2019 3442
4 3237 3448 3581 3652 3718 3839 2020 3595
5 3312 3480 3603 3690 3801 4536 2021 3678
6 3356 3511 3640 3760 4363 5023 2022 3636
7 3395 3552 3703 4226 4782 5387 2023 3710
8 3440 3613 4099 4590 51 10 5677 2024 3876
9 3501 3957 4419 4884 5379 5910 2025 4205
10 3805 4242 4684 5131 5600 6103 2026 7943
11 4062 4483 4910 6338 5786 6269 2027 8125
12 4283 4692 5103 5515 5948 6413 2028 8294
13 4476 4872 5270 5670 6090 6541 2029 8488
14 4644 5030 5418 5807 8217 6658 2030 8608
15 4793 5170 5549 5930 6332 6765 2031 8730
16 4926 5295 5868 6043 6438 6864 2032 8894
17 5046 5409 5776 6147 6537 6955 2033 9029
18 5155 5514 5877 6243 6627 7040 2034 9203
19 5255 56 11 5970 6332 87 12 71 20 2035 9399
20 5348 5701 6056 6415 6792 7195 2036 9598
2037 98 16
2038 9987
2039 10196
2040 10440
2041 10611
J 2Q42 10871
Note:These rares will be further Øusted With the appllcabte integrafon charge.
Note The rates shown in this laNe have been cornpsited using Ire U S Energy Irfomatior Admnistraton IEIA)S Annual Energy
Outlook 2017,reteased January 2017 See Annual Energy Outlook 2017,Table 38 Energy PrIces by Sector-Mountain at
https://wwweia gov/outlooks/aeoftables ref cfrn IDAHO POWER COMPANY Page 2
ATTACH ME NT
CASE NO.IPC-E-17-12
ORDER NO.33898
(PAGE 2 OF 5)
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
XXXX,2017
$/MWH
New Contracts and Replacement Contracts without Fufl Capacity Payments
Eligibility for these rates is limited to prolects smaller than 10 aMW.
LEVEL.IZED NON-tEVELIZED
CONTRACT ONLINE YEAR
LENGTH CONTRACT NON-LEVEUZEC
(YEARS)2017 2018 2019 2020 2021 2022 YEAR RATES
1 28.61 3148 34.42 35.95 36.78 36.36 2017 28.61
2 29.99 3289 35.15 36.35 36.57 36.71 2018 31.48
3 31.35 33.83 35.65 36.35 36.74 37,34 2019 34.42
4 32.37 34.48 35.81 3652 37.18 38.39 2020 35.95
5 33.12 34.80 36.03 36.90 38.01 44.84 2021 36.78
6 3356 35,11 36.40 37.60 43.22 49.36 2022 36.36
7 33.95 35.52 37.03 41.92 47.11 52.75 2023 37.10
6 3440 36.13 40,70 45.30 50.16 55.45 2024 38.76
9 35.01 39.33 43.68 48.04 5267 57.63 2025 42.05
10 37,84 41.99 46.15 50.35 54.74 59.44 2026 76.38
11 40.24 44.24 48.27 5228 56.48 61,00 2027 78.15
12 42.30 46.19 50.01 53,94 58.00 62.35 2028 79.80
13 44.11 47.87 51.63 55.39 5933 63.55 2029 81.69
14 45.69 49.35 53.02 56.68 60.52 64.65 2030 82.85
15 47.08 50.66 54.25 57.84 61.61 65.63 2031 84.02
16 48.33 51,84 55.36 58.90 62,61 66.60 2032 85.61
17 4946 52.91 5639 59.68 6354 67.47 2033 8691
18 50.49 53.90 57.33 60.79 64.40 68.27 2034 88.61
19 51.43 54.81 58.22 61.63 65.20 69.04 2035 90.52
20 5231 5567 59.03 6241 6596 69.75 2036 92.45
2037 94.58
2038 96.24
2039 9828
2040 100.66
2041 102.32
2042 104.85
Note These rates wOt be turther adjusted with the appilcable ntegration charge.
Note The rates shown in this tabte have been computed usrng the U.S.Energy tntormation Adminwtration (EIA)s Anmat Enesgy
Outiok 2017,released January 2017.See Annual Energy Outlook 2017,Table 3.8 Energy Prices by Sec1orMounian at
https.//www.eia.gov’cutlooksJaeoitabtes ref,cfm IDAHO POWER COMPANY Page 3
ATTACHMENT
CASE NO.IPC-E-17-12
ORDER NO.33898
(PAGE 3 OF 5)
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SEASONAL HYORO PROJECTS
XXXX,2017
SfWp
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates is limited to projects smaller than 10 aMW.
LEVEUZEO NOWLEVWZEO
CONTRACT ON LINE YEAR
LENGTH CONTRACT NOt4-LEVELIZED
JL 2017 2018 2019 2020 2021 2022 YEAR —RATES
1 2861 3148 3442 3595 3678 3636 2017 2861
2 2999 3289 3515 3635 3657 3671 2018 3148
3 3135 3383 3565 3635 3874 3734 2019 3442
4 3237 3448 3581 3652 3718 3839 2020 3595
5 3312 3480 3603 3690 3801 4847 2021 3678
6 3356 3511 3640 3760 4612 5544 2022 3636
7 3395 3552 3703 4430 5211 6061 2023 3710
8 3440 3613 4270 4949 5675 6467 2024 3876
9 3501 4103 4724 5365 6051 6791 2025 4205
10 3930 4505 5098 5710 6359 7059 2026 9777
11 4291 4843 5414 5998 6617 7287 2027 9985
12 4598 5133 5682 6243 6840 7484 2028 10182
13 4865 5382 59 12 6457 7034 7658 2029 10403
14 5097 5599 6115 6645 7207 7814 2030 10552
15 5300 5791 6295 6812 7362 7956 2031 10702
16 5482 5963 6456 6964 7504 8086 2032 10895
17 5644 61 17 6603 7103 7634 8205 2033 11059
18 5792 6258 6737 7231 7753 8316 2034 11263
19 5927 6387 6861 7348 7863 8419 2035 11489
20 6051 6507 6975 7456 7967 8515 2036 11719
2037 11968
2038 121 71
2039 12412
2040 12688
2041 12892
2042 131 85
Note A seasonat hydra proecrt is defined as a generation facidy which produces at least 55%of 4s annual generation during the
montris of June.July,and August Order 32802
Note:These rates wit be further adlusled with the applicable integrahon chargeS
Note:The rates shown tn tnis taofa have been computed uang the US Energy tntormauon Administration IE1A)s Annual Energy
Outlook 2017,reteased January 2017.See Annual Energy Outlook 2017,Tabte 3.8 Energy Prces by SectorMauntain at
https://awweia.gov/outlooksfaeo!tables retcfm IDAHO POWER COMPANY Page 4
ATTACHMENT
CASE NO.IPC-E-17-12
ORDER NO.33898
(PAGE 4 OF 5)
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
XXXX,2017
$IMWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates Is limited to projects smaller than 10 aMW,
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2017 2018 2019 2020 2021 2022 YEAR RATES
1 2861 31.48 3442 35.95 3678 3636 2017 2861
2 29.99 3289 3515 36.35 3657 3671 2018 31.48
3 3135 3383 35.65 3635 3674 37.34 2019 34.42
4 3237 34.48 35.81 3652 37.18 38.39 2020 35.95
5 33.12 34,80 36.03 36.90 38.01 43.43 2021 36.78
6 33.56 35.11 36.40 37.60 42.09 47.00 2022 38.36
7 33.95 35.52 37.03 41.00 45.18 49.71 2023 37.10
8 3440 36.13 39,93 43.68 47.61 51,89 2024 38.76
9 35.01 38.67 42.30 45.87 49.63 53.65 2025 4205
10 37.27 40.80 44.28 47.73 51.31 55,12 2026 6809
11 39.21 42,61 45.99 49,30 52.72 56.40 2027 69.75
12 40.88 44.20 47.46 50.65 53.97 57.51 2028 71.28
13 4236 4557 48.73 5184 55.06 58.51 2029 73.04
14 43.65 46,78 49.86 5289 5605 59.43 2030 74.07
15 4479 47.86 50.88 53.85 56.96 6028 2031 75.11
16 45.82 48.63 51.80 54.74 57.80 61.08 2032 76.57
17 4675 49.72 52.85 55.56 58.59 81,82 2033 77.75
18 .47,61 5054 53.45 56.33 59.32 8251 2034 79.30
19 48.40 51.31 54.19 57.04 60.00 63.17 2035 81.07
20 49.14 5202 54.88 57.71 6066 6379 2036 82.88
2037 64.86
2038 86.38
2039 88.27
2040 90.51
2041 92.01
2042 94.40
Note.Oiher projects refers to projects other than wind,solar,nesyOnaI hydro.and seasonal rrydro pecects.These Other
projects may include (but are not ümjted to):cogeneration.bromass,biogas,andNi gas.or geothermal pro)ects,
Note The rates shown in this tabie have been computed using the U S.Energy Information Adminstratrn )EIA)’s Annual Energy
Outlook 2017.released January 2017,See Annual Energy Ouflook 2017,Table 38 Energy Prices by Sector-Mountain at
https:/lwww eia.gov/outiooksiaeo/tables ref,cfm IOAKO POWER COMPANY Page 5
ATTACHMENT
CASE NO.IPC-E-17-12
ORDER NO.33898
(PAGE 5 OF 5)