20171205Comments.pdf

DAPHNE HUANG
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 8370
IN THE MATTER OF AVISTA )
CORPORATION'S COMPLIANCE FILING TO )
UPDATE LOAD AND GAS FORECASTS IN THE )
INTEGRATED RESOURCE PLAN AVOIDED )
COST MODEL AND TO ESTABLISH ITS )
CAPACITY DEFICIENCY PERIOD FOR USE IN )
AVOIDED COST CALCULATIONS.
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Street Address for Express Mail
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. AVU.E-17.I0
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Daphne Huang, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 33926, submits the following
comments.
BACKGROUND
On October 72,2017, Avista Corporation, dba Avista Utilities, filed its annual update to
certain components of its avoided cost rate calculation for qualifying facilities (QF) under the
Public Utility Regulatory Policies Act of 1978 (PURPA). Specifically, Avista updated the load
forecast, natural gas forecast, and contract information components of the incremental cost
Integrated Resource Plan avoided cost methodology. Application at 1. The Company also seeks
1STAFF COMMENTS DECEMBER 5,20I7
approval ofthe updated capacity dehciency period, updated load forecasts, updated natural gas
forecasts, and updated contract information to be used for avoided cost calculations.
Under PURPA, electric utilities must purchase electric energy from 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 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 at7, citing Rosebud Enterprises v. Idaho PUC,l28 Idaho 624,917
P.2d781 (1996); 18 C.F.R, S292.101(bx6xdefining "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 is commonly referred to as "published" avoided cost rates.
1d Published rates are available for wind and solar QFsr 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 l0 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
methodolo gyl." Id. at 2; Order No. 3 2 1 7 6 . The IRP methodology "takes into account many
different variables and produces a[n avoided cost] result based on each individual utility's need for
energy." Order No. 32697 at 17.
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. Wirh respect to the IRP methodology, the Commission similarly stated
In 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.
I See Order No. 33785 (regarding battery storage facilities).
STAFF COMMENTS 2 DECEMBER 5, 20I7
Id. at2l.
The Commission directed that "when a utility submits its [RP] 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 further 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. The Commission directed that the update
to fuel price forecasts and load forecasts should occur on October 15 of each year. Order No.
32802 at 3. The Commission also found it appropriate to consider long-term contract
commitments, as well as PURPA contracts that have terminated or expired, in the utility's load
and resource balance. OrderNo. 32697 at22.
Avista explains that it has combined the capacity deficiency date filing with the annual
update to the load and fuel price forecast due to the timing of its filing of its 2017 Electric IRP,
which occurred on August 31,2017 . Application at 2. Avista indicates that it consulted with Staff
prior to combining these filings. /d
STAFF ANALYSIS
Staff recommends that the Commission authorize 2026 as the first capacity deficit year for
valuing contracts that use the SAR methodology. Staff also recommends the approval of the
updated load forecast, natural gas forecast, and long-term PURPA contracts to be used in the IRP
methodology.
Capacity Deficit Review
Data Source
Staff notes that the Company did not use the load and resource balance in the 2017 IRP to
calculate the capacity deficit in this filing; instead, it used an updated load and resource balance.
The difference between the two sets of load and resource balances range from 1 1 megawatts in
early years to 2 megawatts in later years. Despite the insignificant gap, Staff believes the
Company should use the load and resource balance in the 2017 IRP, unless a major change has
occurred since the preparation of the IRP. For example, in Case No. IPC-E-15-20,141 MW of
solar projects were terminated after Idaho Power's 2015 IRP analysis was completed.
Commission Order No. 32697 stated that:
aJSTAFF COMMENTS DECEMBER 5, 2017
...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. 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.
Although the deficit date does not change in the Company's proposal, Staff believes the
Company should use the load and resource balance in the 2017 IRP in accordance with the
Commission Order. This is consistent with Idaho Power's and PacifiCorp's practices.
A new commission order was issued on October 24,2017 to change the filing timeline of
capacity deficiency cases. Commission Order No. 33917 required that:
...each Idaho electric utility shall submit its updated capacity deficiency filing after
the Commission has acknowledged its IRP report, rather than upon its IttP filing,
thus amending Order No. 32697.
As a result, the Company is expected to file its future capacity deficiency cases after the
acknowledgement of its IRP reports.
Freq of Filine
Staff notes that the Company did not file the capacity deficiency case after it filed its IRP
in 2015. In accordance with Commission Order No. 33917, a capacity deficiency case should
have been initiated when Avista submitted its IRP to the Commission.
However, this oversight did not cause any negative impacts because there have not been
any new SAR-based PURPA contracts filed since 2015.
Capacit), Deficienc),
Staff compared the peak hour load and resource balance between the 2017 IRP and the
2013 capacity deficiency filing of Case No. AVU-E-13-10 to identify reasons for the shift in the
first deficit years. By comparing average loads and average capacity of supply resources between
2020 and2026, Staff was able to determine that the overriding causes of the shift included a 103
MW reduction in load and a 66 MW addition in hydro resources as a result of a contract extension
of Douglas County PUD and Chelan County PUD hydro projects. Staff believes the changes in
the 2017 IRP which caused the shift in the first deficit date are reasonable. Staff updated the SAR
4STAFF COMMENTS DECEMBER 5,2017
Filine Timeline
model based on the new deficiency date and calculated new avoided cost rates included as
Attachment A to these comments.
Updated Load and Natural Gas Forecast Review
Avista provided an updated load and fuel (natural gas) price forecast for years 2018
through 2040. For the load forecast, Avista provided the forecasted energy (average megawatt)
and one-hour peak (megawatt) for each year. Avista explains that the energy forecast escalates at
an annual average growth rate of 0.43 percent, and that the peak forecast growth rate is 0.38%.
Regarding its updated natural gas price forecast, Avista states that the forecast was
developed using a blend of a consultant's national price forecast and forward market prices as of
September 28,2017. Avista provides forecasted prices at Henry Hub and Stanfield Hub as inputs
into its IRP method model.
Updated Load Forecasts Review
Staff compared Avista's proposed energy and 1-hour peak load forecast from 201 8 through
2040 to last year's filing in Case No. AVU-E-I6-07. The comparison showed very little change.
Since there has not been a significant change in population, economic characteristics, or other
factors that would affect usage-per-customer in Avista's service territory. Staff believes the new
forecast is reasonable and acceptable.
Updated Natural Gas ForecastsBcvlel
Staff compared Avista's proposed natural gas price forecast from 2018 through 2040 to the
natural gas forecast in last year's filing in Case No. AVU-E-16-07 for both Henry Hub and
Stanfield Hub. The 2017 natural gas forecast has decreased by 12.3% at Henry Hub and by 17.8%
at Stanfield from the 2016 natural gas forecast for the same time period. Because this is consistent
with reductions in EIA Henry Hub Reference forecasts from 2016 to 2077, Staff believes the
proposed natural gas forecast is reasonable and acceptable,
Contract Additions and Terminations
Regarding contract additions and terminations, Avista explains that it has signed three new
long-term PURPA contracts since the last annual update and no new Power Purchase Agreements.
One of the contracts is a two-year agreement with Stimson Lumber in Idaho. The other two are
5STAFF COMMENTS DECEMBER 5,2077
Washington agreements with Deep Creek Energy and are extensions of a prior agreement. New
contracts and terminated or expired contracts are all updated in the IRP model used for contract
pricing on a continuous basis.
STAFF RECOMMENDATION
Staff recommends that the Commission authorize 2026 as the first capacity deficit year for
valuing contracts that use the SAR methodology. Staff also recommends the approval of the
updated load forecast, natural gas forecast, and long-term PURPA contracts to be used in the IRP
methodology. Per Order No. 33917, Staff recommends that Avista file its next Application to
update load and gas forecasts and establish capacity deficiency period after the Commission has
acknowledged Avista's 2019 IRP.
Respectfully submitted this
Technical Staff: Yao Yin
i :umisc:commentsiavue I 7. I 0djhyykkrf comments
{rb day of December 2ot7 .
Deputy Attorney
6STAFF COMMENTS DECEMBER 5,2077
AVISTA
AVOIDED COST RATES FOR WIND PROJECTS
xxxx xx, 20't 7
$/wWh
New Contracts and Replacement Contracls without Full Capacity Paymenls
Eligibility lor these rates is limited to proiects 100 kW or smaller.
LEVELIZED NON.LEVELIZED
CONTRACT
LENGTH
(YEARS)
ON-tINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
3
4
5
6
7
8
9
10
11
12
IJ
14
15
16
17
18
19
20
28.61
29.99
31 .36
32.38
33.13
33.57
33.97
34.42
35.03
35.92
30.tz
37.45
38.12
38.72
39.27
39.77
40.24
40.68
41 .10
41 .50
.31.48
32.89
33.84
34.49
34.81
35,12
35.53
36.1 5
37.09
37.92
38.68
39.38
40.00
40.55
41 .07
41.54
41.99
42.42
42.84
43.24
34.42
35.1 6
35.65
35.81
36.03
36.40
37.04
38.06
38.95
eo 7E
40.48
41 .12
41 .69
42.?3
42.71
43.17
43.61
44.04
44.46
44.85
35.95
36,35
36.35
36,52
36.90
37,60
38.75
39,74
40.60
41.38
42.06
42.65
43.21
43.71
44.19
44.65
45,09
45.52
45.93
46,32
36.78
36.57
36.74
37,1 9
38.02
39.36
40.46
41.40
42.25
42.56
43.59
44.17
44.69
45.1 8
45.66
46.12
46.56
46.99
47.40
47.80
36.36
35.71
37.35
38.39
40.00
qt.zo
42.29
43.20
43.95
44.60
45.20
45.73
46.24
46.73
47.20
47.66
48.'l 0
48.52
48.94
49.33
2017
2018
201 I
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
37.1 0
38.76
42.05
47.84
49,20
50.42
51 .88
52.60
53.33
54.48
55.32
56.55
E7 00
59.45
61 .10
oz.zo
63.80
65.68
66.82
68.84
Note: These rates will be lurther 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 2017,Table 3.8 Energy Prices by Sector-Mountain at
https ://www.eia. gov/outlooks/aeo/tables_ref .cf m
AVISTA Page 1
Attachment A
Case No. AVU-E-I7-10
Audit Request
12/05/17 pase I of 5
AVTSTA
AVOIDED COST RATES FOR SOLAR PROJECTS
xxxx xx, 201 7
$/MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility lor these rates is limited to projects 100 kW or smaller.
LEVELIZED NON-LEVELIZED
CONTRACT
LENGTH
(YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES20172018201 I 2020 2021 2022
1
J
4(
o
7
II
10
11
12
13
14
'15
'16
17
'18
19
20
28.61
29.99
31.36
32.38
33.'13
33.57
33.97
34.42
35.03
35.92
36.72
37.45
38.12
38.72
39.27
39.77
40.24
40.68
41 .10
41 .50
31.48
32.89
33.84
34.49
34.81
35.1 2
35.53
36.1 5
37.09
37.92
38.68
39.38
40.00
40.55
41 .07
41 .54
41.99
42.42
42.84
43.24
34,42
35.1 6
35.65
35.81
36.03
36.40
37.04
38.06
38.95
39.75
40.48
41.'12
41.69
42.23
42.71
43.17
43.61
44.04
44.46
44.85
EE OE
36,35
Jb,JJ
36,52
36,90
37.60
38.75
39.74
40.60
41 .38
42.06
42.65
43.21
43.71
44.19
44,65
45.09
45.52
45.93
46.32
36.78
36.57
36.74
37.1 I
38.02
39.36
40.46
41.40
42.25
42.56
43.59
44.17
44.69
45.1 8
45.66
46.12
46.56
46.99
47.40
47.80
Jb. Jb
36.71
37.35
ea ao
40.00
+t.zo
42.29
43.20
43.95
44.60
45.20
45.73
46.24
46,73
47.20
47.66
48.10
48.52
48.94
49.33
2017
2018
201 I
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
Jb.Jb
37.1 0
38.76
42.05
47.84
49.20
50.42
51.88
52.60
53.33
54.48
55.32
56.55
57.99
59.45
61 .10
oz.zo
63.80
65.68
66.82
68.84
Note: These rates will be lurther adjusted with the applicable inlegration charge.
Note: The rates shown in this table have been computed usrng the U.S. Energy lnformation Administration (ElA)'s Annual Energy
Outlook 201 7, released January 2017 . See Annual Energy Outlook 2017 , T able 3.8 Energy Prices by Sector-Mountajn at
https ;//www.eia. gov/outlooks/aeo/tables_ref .cf m
AVISTA Page 2
Attachment A
Case No. AVU-E-17-10
Audit Request
12105117 Page 2 of 5
AVISTA
AVOIDED COST RATES FOR NON.SEASONAL HYDRO PROJECTS
xxxx xx,2o17
$/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
CONTRACT
TENGTH
(YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES2017 2018 2019 2020 2021
1
3
4
5
6
7I
o
10
11
12
'13
14
15
16
17
18
19
20
28.61
29.99
31.36
32.38
33.1 3
33.57
33.97
34.42
35.03
35.92
36.72
37.45
38.12
38.72
39.27
39.77
40.24
40.68
41 .10
41.50
31.48
32.89
33.84
34.49
34.81
5J.tl
35.53
36.15
37.09a7 0c
38.68
39.38
40.00
40.55
41 .07
41.54
41.99
42.42
42.84
43.24
34.42
J3.tb
35.65
35.81
36.03
36.40
37.04
38.06
38.95
39.75
40.48
41.12
41 .69
42.23
42.71
43.17
43.61
44.04
44.46
44.85
35.95
36.35
36.35
36.52
36.90
37.60
38.75
39,74
40.60
41 ,38
42.06
42.65
43,21
43.71
44,19
44.65
45.09
45.52
45.93
46.32
36.78
36.57
36.74
37.1 I
38.02
39.36
40.46
41 .40
42.25
42.96
43.59
44.17
44.69
45.1 I
45.66
46.12
46.56
46.99
47.40
47.80
36.35
36,71
37.35
38.39
40.00
41.26
42.25
43.20
43.95
44.60
45.20
45.73
46.24
46.73
47.20
47.66
48.10
48.52
48.94
49.33
2017
201 8
201 I
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
37.1 0
38.76
42.05
47.84
49.20
50.42
51.88
52.60
53.33
54.48
55.32
56.55
57.99
59.45
6l .10
62.26
63.80
65.68
66.82
68.84
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 lnformation Administration (ElA)'s Annual Energy
Outlook 2017, released Januaty 2017. See Annual Energy Outlook 2017, Table 3.8 Energy Prices by Sector-lvlountain at
https ://www.eia. gov/outlooks/aeo/tables_rel.cf m
AVISTA Page 3
Attachment A
Case No. AVU-E-17-10
Audit Request
12105117 Page 3 of 5
AVISTA
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
xxxx xx, 201 7
$/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
CONTRACT
LENGTH
{YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
J
4
5
b
7
n
o
10
11
12
13
14't5
16
17
18
19
20
28.61
29.99
31 .36
s2.38
33.13
33.57
33.97
34.42
35.03
35.92
36.72
37.45
38.12
38.72
39.27
39.77
40.24
40.68
41 .10
41 .50
31.48
32.89
33.84
34.49
34.81
35.1 2
35.53
5b.tJ
37.09
37.92
38.68
39.38
40.00
40.55
41.07
41.54
41.99
42.42
42.84
43.24
34.42
35.1 6
35.65
35.81
36.03
36.40
37.04
38.06
38.95
39.75
40.48
41.12
41.69
42.23
42.71
43.17
43.61
44.04
44.46
44.85
35.95
36.35
s6.35
36.52
36.90
37.60
38.75
39.74
40.60
41 .38
42.06
42,65
43.21
43.71
44,19
44,65
45.09
45.52
45.93
46.32
36.78
36.57
36.74
37.1 9
38.02
39.36
40.46
41 .40
42.25
42.96
43.59
44,17
44.69
45.1 8
45.66
46.'l?
46.56
46.99
47.40
47.80
36.36
36.71
37.35
38.39
40.00
41.26
42.29
43.20
43.95
44.60
45.20
45.73
46.24
46.73
47.20
47.66
48.10
48.52
48.94
49.33
2017
201 8
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
Jb.50
37.1 0
Jd./b
42,05
47.84
49.20
50.42
51.88
52.60
53,33
54.48
55.32
56.55
57.99
59.45
61 .10
62.26
63.80
65.68
ob.dz
68.84
Note: A "seasonal hydro prolect" is delined as a generation facility which produces at least 55% of its annual generation during the
months of 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 lnformation 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/aeo/tables_ref .cf m
AVISTA Page 4
Attachment A
Case No. AVU-E-17-10
Audit Request
12105117 Page 4 of 5
AVISTA
AVOIDED COST RATES FOR OTHER PROJECTS
xxxx xx, 201 7
$/MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility lor these rates is limited to projects smaller than 10 aMW,
LEVELIZED NON.LEVELIZED
CONTRACT
LENGTH
{YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES20172018201 I 2020 2021 2022
1
2
4
q
6
7I
9
10
11
tt
'13
14
15
16
17
'18
19
20
28.61
29.99
31.36
32.38
33.1 3
33.57
33.97
34.42
35.03
35.92
36.72
37.45
38.12
38,72
39.27
39.77
40.24
40.68
41 .10
41 .50
31.48
32.89
33.84
34.49
34.81
35.1 2
35.53
36.1 5
37.09
37.52
38.68
39.38
40.00
40.55
41 .07
41 ,54
41.99
42.42
42.84
43.24
34.42
35.1 6
35.65
35.81
36.03
36.40
37.04
38.06
38.95
39.75
40.48
41.12
41.69
42.23
42.71
43.17
43.61
44.04
44.46
44.85
AE OE
36,35
36,35
36.52
36.90
37.60
38.75
39.74
40.60
41.38
42.06
42,65
43,21
43.71
44.19
44.65
45,09
45.52
45.93
46.32
36.78
36.57
36.74
37.1 9
38.02
39.36
40.46
41,40
42.25
42.96
43.59
44.17
44.69
45.18
45.66
46.12
46.56
46.99
47,40
47.80
Jb.Jb
36.71
J /.J3
38.39
40.00
+t.zo
42.29
43.20
43.95
44.60
45.20
45.73
46.24
46.73
47.20
47.66
48.1 0
48.52
48.94
49.33
2017
2018
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
47.84
49.20
50.42
51 .88
52.60
JJ.JJ
54.48
55.32
56.55
57.99
59.45
61 .10
62.26
63.80
65.68
66.82
68.84
Notet "Other projects" refers to projects other than wind, solar, non-seasonal hydro, and seasonal hydro projects. These "Other
projects" may include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal prolects.
Note: The rates shown in this table have been computed using the U.S. Energy lnformation Administration (ElA)'s Annual Energy
Outlook 2017, released Januaty 2017. See Annual Energy Outlook 2U7,fabb 3.8 Energy Prices by Seclor-Mountain at
https ://www.eia. gov/outlooks/aeo/tables_ref .cf m
AVISTA Page 5
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