20170906Comments.pdf

CAMILLE CHzuSTEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 10177
Street Address for Express Mail
472W. WASHINGTON
BOISE, IDAHO 837 02-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
5 fii l: 33
IN THE MATTER OF'THE APPLICATION OF
IDAHO POWER COMPANY FOR APPROVAL
OF THE CAPACITY DEFICIENCY TO BE
UTILIZED FOR AVOIDED COST
CALCULATIONS.
CASE NO. IPC.E-I7-12
COMMENTS OF THE
COMMISSION STAFF
)
)
)
)
)
)
)
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attorney of record, Camille Christen, Deputy Attorney General, and in response to the Notice of
Notice of Application and Modified Procedure issued in Order No. 33838 on August 16,2017,in
Case No. IPC-E-I7-12, submits the following comments.
BACKGROUND
On July 26,2017,Idaho Power Company applied to the Commission for an Order
approving the capacity deficiency period to be used for the Company's avoided cost calculations
under the Public Utility Regulatory Policies Act (PURPA).
Under PURPA, electric utilities must purchase electric energy from qualifying facilities
(QFs) at rates approved by the applicable state agency-in Idaho, this Commission. l6 U.S.C.
$ 824a-3; Idaho Power Co. v. Idaho PUC,155 Idaho 780,780,316 P.3d 1,278,1287 (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
ISTAFF COMMENTS SEPTEMBER 6,20I7
itself or purchase from another source." Order No. 32697 at 7 , citing Rosebud Enterprises v.
Idaho PUC,128 Idaho 624,917 P.2d78l (1996);18 C.F.R. 5 292.101(b)(6) (defining "avoided
cost").
The Commission has established two methods of calculating avoided cost, depending on
the size of the QF project: (l) the surrogate avoided resource (SAR) methodology, and (2) the
integrated resource plan (IRP) methodology. See Order No. 32697 at7-8. The Commission uses
the SAR methodology to establish what are commonly referred to as "published" avoided cost
rates. Id. Published rates are available for wind and solar QFslwith a design capacity of up to
100 kilowatts (kW), and for QFs of 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. at2; 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 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 [used for calculating published avoided cost rates]." Id. at23. The Commission
also stated "utilities must update fuel price forecasts and load forecasts annually-between IRP
filings. . . . We find it reasonable that all other variables and assumptions utilized within the IRP
Methodology remain fixed between IRP filings (every two years)." Id. at22.
I See Order No. 33785 (regarding battery storage facilities).
STAFF COMMENTS 2 SEPTEMBER 6,2017
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 updated SAR-based rates. Order No. 33377.
Idaho Power states that its 2017 IRP, which it filed with the Commission on June 30,
2017 (Case No. IPC-E-17-ll), identifies a first peak-hour deficit in July 2026. Application at 2.
Idaho Power describes that peak-hour load deficits are determined using 90th percentile water
and 95th percentile peak-load conditions. Id. at2-3.
The Company indicates 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 requests that the first capacity deficit date of July 2026 be used for avoided
cost calculations for both the SAR and IRP methodologies. /d
STAFF ANALYSIS
SAR Method Deficiency Date
Staff recommends that the Commission authorize JuJy 2026 as the first capacity
deficiency date for valuing contracts that use the SAR methodology. This change will push back
the deficit date two years from the currently authorized deficit date of July 2024. The 2017 IRP
indicates that a first capacity deficiency of approximately 34 megawatts will occur in Jdy 2026
under the preferred portfolio.
Staff compared the 201 5 Peak-Hour Load and Resource Balance, used to determine the
currently authorized July 2024 first capacity deficiency date, and the 2017 Peak-Hour Load and
Resource Balance to identiff reasons causing the two-year shift. By comparing average loads
and average amounts of capacity from supply resources between 2024 and2026, Staff was able
to determine that the over-riding cause for the two-year shift was a l03Yo 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 I in2019;
and (2) an additional 80 MW of incremental transmission capacity through the Company's
Idaho/Montana transmission pathway. The Company identified these increases through a re-
evaluation of Idaho Power's transmission system conducted as part of a case assessing the early
closure of the Valmy Plant (Case No. IPC-E-16-24) and throughthe20lT IRP (Case No.
rPC-E-17-r l).
3STAFF COMMENTS SEPTEMBER 6,2017
Other contributing factors assumed in the 201 5 IRP as compared to the 2017 IRP include
(l) a decrease in peak-hour load forecast of about 125 MW (average of years 2024,2025, and
2026) due to a reduction in the annual growth rate assumption from 1.5o/o to 1.4%; (2) an
increase in the amount of existing energy efficiency of about 40 MW (average of years 2024,
2025, and2026); and (3) a slight increase in hydro generation and firm purchase power
agreements of about 8 MW. Staff believes the changes in IRP assumptions causing a two-year
shift in the first capacity deficiency date are reasonable. Staff updated the SAR model based on
the new deficiency year and calculated new avoided cost rates included as an attachment to these
comments.
IRP Method Deficiency Date
Staff also recommends that the Commission authorize and lock in the same July 2026
deficiency date as requested in the Company's Application for use in the IRP method for valuing
capacity payments. For reasons stated above, Staff finds the first capacity deficiency date
reasonable for purposes of negotiating capacity-related avoided costs in IRP-based PURPA
contracts.
Although the Commission approved the use of the same first capacity deficiency date
based on the most recent submitted IRP to be used in both the SAR and IRP methods (See Case
No. GNR-E-l l-03; Order Nos. 32697,32802), Staff notes that the application of the deficiency
date in determining the value of capacity payments is different between the SAR and IRP
methods. For SAR-based contracts, 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. However, 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. This methodology has been approved
by the Commission in several IRP-based PURPA contracts since Case No. GNR-E-I1-03.2
With the exception of fuel price forecasts and load forecasts needing to be updated
annually, Staff maintains that "all other variables and assumptions utilized within the IRP
methodology remain fixed between IRP filings (every two years)." Id. at22. The table below
shows how frequently variables are updated in the IRP methodology.
2 See, e.g., Grand View Solar (IPC-E-14-19), Boise City Solar (lPC-E-14-20), Mountain Home Solar ([PC-E-I4-26),
Pocatello Solar I (IPC-E-14-27), and others.
4STAFF COMMENTS SEPTEMBER 6,2017
Variables in IRP Methodology Update Frequency
First capacity deficiency date Every two years with IRP publication
Fuel price forecasts and load forecasts Annually
All other variables and assumptions Every two years with IRP publication
PURPA Projects in the queue As changes occur
In order to efficiently process routine cases, Staff recommends combining the annual fuel
price and load forecast filings with the biennial capacity deficiency date filings for both SAR and
IRP pricing methodologies when they occur in the same year. There is significant overlap in the
information Staff has to examine for the two cases. This would reduce administrative burden for
Staff, the utilities and other interested parties.
Currently, all three Idaho electric utilities file separate cases to establish a new capacity
deficiency date and to update their fuel and load forecasts. In Order No.32697, the Commission
stated, "when a utility submits its Integrated Resource Plan to the Commission, a case shall be
initiated to determine the capacity deficiency to be utilized in the SAR Methodology." Order
No. 32697 at 23. Staff notes that PacifiCorp files its IRP on about April 1, Idaho Power on about
July l, and Avista on about September 1. However, the Commission did not establish distinct
deadlines for each utility to update its capacity deficiency date and consequently, the utilities file
their deficiency date cases with various amounts of delay from the time they file their IRP.
The Commission ordered fuel and load forecasts to be updated every year on October 15.
This was established through a collaborative recommendation from all three utilities. See Order
No. 32802 at 3. With Commission approval, Staff will work with the utilities to establish a date
for combined filings. Once agreement is reached, the parties will submit the proposed filing date
to the Commission for approval.
STAFF RE,COMMENDATION
Staff has updated the SAR model and the avoided cost rates and recommends that the
Commission approve the new rates to reflect the first deficiency date of July 2026. Staff also
recommends the same first deficiency date to be used as a starting point in the IRP methodology.
5STAFF COMMENTS SEPTEMBER 6,2017
Staff also recommends 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.
Respectfully submitted this
t1/('day of September 2017 .
Camille Christen
Deputy Attorney General
Technical Staffi Yao Yin
Stacey Donohue
i :umisc/comments/ipce I 7. I 2ccsdlycomments
6STAFF COMMENTS SEPTEMBER 6,2017
IDAHO POWER COMPANY
AVOIDED COST RATES FOR WIND PROJECTS
xxxx,2017
$/MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates is limited to projects 100 kW or smaller
LEVELIZED NON-LEVELIZED
CONTRACT
LENGTH
(YEARS)
ON-LINE YEAR
2017 2018 2019 2020 2021 2022
CONTRACT
YEAR
NON-LEVELIZED
RATES
.l
2
3
4
5
b
7
8I
10
11
12
13
14
15
16
17
18
'19
20
28.61
29.99
31.35
32.37
33.12
33.56
33.95
34.40
35.01
35.90
36.70
37.42
38.09
38.69
39.23
39.73
40.1 I
40.62
41.04
41.44
31.48
32.89
33.83
34.48
s4.80
35.1 1
35.52
36.1 3
37.07
37.91
38.67
39.36
39,98
40.53
41.04
41.51
41.96
42.38
42.79
43.19
34.42
35.1 5
35.65
35.81
36.03
36.40
37.03
38.05
38.95
39.75
40.48
41.12
41.69
42.22
42.70
43.15
43.59
44.01
44.42
44.81
35.95
36.35
36.35
36.52
36.90
37.60
38.75
39.74
40.61
41.39
42.07
42.66
43.21
43.71
44.18
44.64
45.08
45.50
45.90
46.29
36.78
36.57
36.74
37.18
38.01
39.37
40.48
41.42
42.27
42.98
43.61
44.18
44.70
45.1 I
45.67
46.12
46.56
46.98
47.38
47.78
36.36
36.71
37.34
38.39
40.02
41 .28
42.32
43.23
43.99
44.64
45.23
45.77
46.27
46.76
47.22
47.68
48.11
48.53
48.94
49.32
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
28.61
31.48
34.42
35.95
36.78
36.35
37.10
38.76
42.05
47.99
49.35
50.58
52.04
52.76
53.50
54.64
55.49
56.72
58.16
59.63
61 .27
62.44
63.98
65.87
67.01
69.03
Note: These rates will be turther adjusted with the applicable integration charge.
Note: The rates shown in this table have been computed using the U.S. Energy lnformation Administration (ElA)'s Annual Energy
Outlook 2017, released January 2017 . See Annual Energy Outlook 201 7, Table 3.8 Energy Prices by Sector-Mountain at
https ://www.eia. gov/oullooks/aeoltables_ref .clm
IDAHO POWER COMPANY Page 1
Attachment A
Case No. IPC-E-I7-12
StaffComments
09106117 Page I 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 proiects 100 kW or smaller
LEVELIZED NON-LEVELIZED
CONTRACT
LENGTH
(YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES20172018201 I 2020 2021 2022
1
2
J
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
'19
20
28.61
29.99
31.35
32.37
33.12
33.56
33.9s
34.40
35.01
38.05
40.62
42.83
44.76
46.44
47.93
49.26
50.46
51.55
52.55
53.48
31.48
32.89
33.83
34.48
34.80
35..1.1
AE EO
36.1 3
39.57
42.42
44.83
46.92
48.72
50.30
51.70
52.95
54.09
55.1 4
56.11
57.01
34,42
35,1 5
35.65
35.81
36.03
36.40
37.03
40.99
44.1 I
46.84
49.1 0
51.03
52.70
54.1 I
55.49
56.68
57.76
58.77
59.70
60.56
35.95
36.35
36.35
36.52
36.90
37.60
42.26
45.90
48.84
51.31
s3.38
55..15
56.70
58.07
s9.30
60.43
6't.47
62.43
63.32
64.15
36.78
36.57
36.74
37.18
38.01
43.63
47.82
51 .10
53.79
56.00
57.86
59.48
60.90
62.17
63.32
64.38
6s.37
66.27
67.12
67.92
36.36
36.71
37.34
38.39
45.36
50.23
53.87
56.77
59.10
61 .03
62.59
64.13
65.41
55.58
67.65
68.64
59.55
70.40
71 .20
71 .95
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
28.61
31 .48
34.42
35.95
36.78
36.36
37.10
38.76
42.05
79.43
81.25
82.94
84.88
86.08
87.30
88.94
90.29
92.03
93.99
95.98
98.16
99.87
101 .96
104.40.106.1 1
108.71
Note: These rates will be further adjusted with the applicable integration charge.
Note: The rates shown in this table have been computed using the U.S. Energy lnlormation Administration (ElA)'s Annual Energy
Outlook 201 7, released January 2017 . See Annual Energy Outlook 201 7, Table 3.8 Energy Prices by Sector-Mountain at
https ://www. eia. gov/outlooks/aeoltables_ref . cf m
IDAHO POWER COMPANY Page 2
Attachment A
Case No. IPC-E-I7-12
Staff Comments
09/06/17 Page 2 of 5
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON.SEASONAL HYDRO PROJECTS
xxxx,2o17
$iluwh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility tor these rates is limited to projects smaller than 10 aMW.
LEVELIZED NON.LEVELIZED
LENGTH
ON.LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
'I
2
3
4
E
6
7
8I't0
11
12
13
14
15
16
17
'18
19
20
28.61
29.99
31 .35
J1.C I
33.12
33.56
33.95
34.40
35.01
37.84
40.24
42.30
44.11
45.69
47.08
48.33
49.46
50.49
51.43
52.31
31.48
32.89
33.83
34.48
34.80
35.1 1
35.52
36.1 3
39.33
41.99
44.24
46.1 9
47.87
49.35
50.66
51.84
52.9i
53.90
54.81
55.67
34.42
35.1 5
35.65
35.81
36.03
36.40
37.03
40.70
43.68
46.15
48.27
50.07
51 .63
53.02
il.25
55.36
56.39
57.33
58.22
59.03
35.95
36.35
36.35
36.52
36.90
37.60
41.92
45.30
48.04
50.35
52.28
53.94
55.39
s6.68
57.84
58.90
59.88
60.79
61.63
62.41
36.78
36.57
36.74
37.18
38.01
43.22
47.11
50.15
52.67
54.74
56.48
58.00
59.33
60.52
61.51
62.61
63.54
64.40
65.20
65.96
36.36
36.71
37.34
38.39
44.84
49.36
52.75
55.45
57.63
59.44
61.00
62.35
63.55
64.65
65.66
66.60
67.47
68.27
69.04
69.75
2017
201 I
201 9
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
28.61
31.48
34.42
35.9s
36.78
36.36
37.10
38.76
42.05
76.38
78.15
79.80
81 .69
82.85
84.02
85.61
86.91
88.61
90.52
92.45
94.58
96.24
98.28
100.66
102.32
104.85
Note: The rates shown in this table have been computed using the U.S. Energy lnlormation Administration (ElA)'s Annual Energy
Outlook 201 7, released January 2017 . See Annual Energy Outlook 201 7, Table 3.8 Energy Prices by Sector-Mountain al
https ://www. eia. gov/outlooks/aeoltables_ref .cf m
IDAHO POWER COMPANY Page 3
Attachment A
Case No. IPC-E-I7-12
StaffComments
09106117 Page 3 of 5
Note: These rates will be further adjusted with the applicable integration charge.
IDAHO POWER COMPANY
AVOIOED COST RATES FOR SEASONAL HYDRO PROJECTS
xxxx,2017
$/MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates is limited to projects smaller than 10 aMW.
LEVELIZED NON.LEVELIZED
LENGTH
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
4
5
o
7
8I'10
11
12
13
14
15
16
17
18
.19
20
28.61
29.99
31.35
32.37
33.12
33.56
33.95
34.40
35.01
39.30
42.91
45.98
48.65
50.97
53.00
54.82
56.44
57.92
59.27
60.51
31.48
32.89
33.83
34.48
34.80
35.1 1
35.52
36.1 3
41.03
45.05
48.43
51 .33
53.82
55.99
57.91
59.63
61.17
62.58
53.87
65.07
34.42
35.1 5
35.65
35.81
36.03
36.40
37.03
42.70
47.24
50.98
54.14
56.82
59.12
61 .15
62.95
64.56
66.03
67.37
68.61
69.75
35.95
36.35
36.35
36.52
36.90
37.60
44.30
49.49
53.65
57.10
59.98
62.43
64.57
66.45
68.1 2
69.64
71.03
72.31
73.48
74.56
36.78
36.57
36,74
37.18
38.01
46.12
52.11
56.75
60.51
63.59
66.1 7
68.40
70.34
72.07
73.62
75.04
76.3;,4
77.53
78.63
tv.h I
36.36
36.71
37.34
38.39
48.47
55.44
60.61
64.67
67.91
70.59
72.87
74.84
76.58
78.14
79.56
80.86
82.05
83.16
84.1 I
85.15
2017
201 8
201 9
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
28.61
31.48
34.42
35.95
36.78
36.36
37.10
38.76
42.05
97.77
99.85
101 .82
104.03
105.52
107.02
108.95
1 10.59
112.63
1 14.89
117.19
1 19.68
121.71
124.12
126.88
128.92
131 .85
Note: A "seasonal hydro project" is defined as a generation lacility which produces at least 55% of its annual generation during the
months ol June, July, and August. Order 32802.
Note: These rates will be further adjusted with the applicable integration charge.
Note: The rates shown in this table have been computed using the U.S. Energy lnlormation Administration (ElA)'s Annual Energy
Outlook 201 7, released January 201 7. See Annual Energy Outlook 201 7, Table 3.8 Energy Prices by Sector-Mountain at
https ://www.eia. gov/outlooks/aeo/tables ref .cf m
IDAHO POWER COMPANY Page 4
Attachment A
Case No. IPC-E-I7-12
Staff Comments
09106117 Page 4 of 5
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
xxxx,2017
$/MWh
New Contracls and Replacement Contracts without Full Capacity Payments
Eligibility for lhese rates as limited to projects smaller than 10 aMW.
LEVELlZED NON-LEVELIZED
LENGTH
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES20172018201 9 2020 2021 2022
1
2
3
4
5
6
7
8
o
10
11
12
IJ
14
'15
16
17
18
19
20
28.61
29.99
3.1.35
32.37
33.1 2
33.56
33.95
34.40
35.01
37.27
39.21
40.88
42.36
43.65
44.79
45.82
46.75
47.61
48.40
49.14
31.48
32.89
33.83
34.48
34.80
35.1 1
35.52
36.1 3
38.67
40.80
42.61
44.20
45.57
46.78
47.86
48.83
49.72
50.54
51.31
52.02
34,42
35.15
35.65
35.81
36.03
36.40
37.03
39.93
42.30
44.28
45.99
47.46
48.73
49.86
50.88
51 .80
52.65
53.45
54.19
54.88
35.95
36.35
36.35
36.52
36.90
37.60
41 .00
43.68
45.87
47.73
49.30
50.65
51 .84
52.89
53.85
54.74
55.56
56.33
57.04
57.71
36.78
36.57
36.74
37.18
38.01
42.09
45.1 8
47.61
49.63
51.31
52.72
53.97
55.06
56.05
56.96
57.80
58.59
59.32
60.00
60.66
36.36
36.71
37.34
38.39
43.43
47.00
49.71
51 .89
53.65
55.12
56.40
57.51
58.51
59.43
60.28
51 .08
61 .82
62.51
63.1 7
53.79
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
28.61
31.48
34.42
35.95
36.78
36.36
37.10
38.76
42.05
68.09
69.75
71.28
73.04
74.07
75.11
76.57
77.75
79.30
81.07
82.88
84.86
86.38
88.27
90.51
92.01
94.40
Note: "Otherprojects"referstoprojectsotherthanwind,solar,non-seasonalhydro,andseasonalhydroprojects, These"Other
projects" may include (but are not limited to): cogeneration, biomass, biogas, landf ill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy lnlormation Administration (ElA)'s Annual Energy
Outlook 201 7, released January 201 7. See Annual Energy Outlook 201 7, Table 3.8 Energy Prices by SectorMountain at
https ://www. eia. gov/outlooks/aeo/tables_rel.clm
IDAHO POWER COMPANY Page 5
Attachment A
Case No. IPC-E 17-12
Staff Comments
OglO6ltT Page 5 of 5
CBRTIFICATE OF SBRVICB
I HEREBY CERTIFY THAT I HAVE THIS 6TH DAY oF SEPTEMBER 2077,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-17.72, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
DONOVAN E WALKER
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-mail: [e-mail]
dockets@idahopower. com
C. TOM ARKOOSH
ARKOOSH LAW OFFICES
802 W BANNOCK STREET STE 9OO
PO BOX 2900
BOISE ID 83701
E-mail : [e-mail]
erin. [e-mail]
MICHAEL DARRINGTON
ENERGY CONTRACTS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-mail: [e-mail]
ener gvcontracts@ idahopower. com
Jr,42,.,.--
SECRETAR /
CERTIFICATE OF SERVICE