20170928Comments.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 THE APPLICATION OF
PACIFICORP DBA ROCKY MOUNTAIN
POWER COMPANY TO APPROVE ITS
CAPACITY DEFICIENCY PERIOD FOR
AVOIDED COST CALCULATIONS
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. PAC.E.17-09
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. 33869, submits the following
comments.
BACKGROUND
On August 18,2017, PacifiCorp dba Rocky Mountain Power Company filed an
Application asking the Commission to approve its updated capacity deficiency period for use in its
avoided cost calculations under the Public Utility Regulatory Policies Act (PURPA), using the
Surrogate Avoided Resource (SAR) methodology.
Under PURPA, electric utilities must purchase electric energy from qualifying facilities
(QFs) at rates approved by the applicable state regulatory agency - in Idaho, this Commission. l6
U.S.C. g 824a-3; Idaho Power Co. v. Idaho PUC,l55 Idaho 780,789,316 P.3d 1278,1287
'.,/T IJ
(riain,-;f'
STAFF COMMENTS SEPTEMBER28,2017I
(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.2d78l (1996); l8 C.F.R. 5292.101(bX6)
(defining "avoided cost").
The Commission has established two methods of calculating avoided cost, depending on
the size of the QF project: (1) the surrogate avoided resource (SAR) methodology, and (2) the
integrated resource plan (IRP) methodology. See Order No. 32697 at7-8. At issue in this case is
the SAR methodology, which the Commission uses to establish "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). 1d.
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." Id. at 16. As to the
capacity calculation, 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. The Commission
elaborated:
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 capactty 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." 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. at
22.
STAFF COMMENTS SEPTEMBER28,2OI72
Rocky Mountain's Application states it filed its2017IRP (Case No. PAC-E-17-03) with
the Commission on April 4, 2017 . The Company's 2017 IRP includes the results of its capacity
balance, which is "calculated for summer peak loads only." Application at 3. Also, the 2017 IRP
"shows that the Company first becomes capacity deficient in2028." Id.
Rocky Mountain identifies two factors affecting the capacity deficit period reflected in its
2017 IRP: (l) power purchase agreements with QFs signed since preparation of the 2017 IRP;
and (2) termination of a power purchase agreement originally included in the 2017 IRP. Id. at 4.
After accounting for these factors, Rocky Mountain states that its "capacity deficit still first occurs
in the summer of 2028." Id.
Rocky Mountain's Application includes Table 2, which shows "updated system capacity
loads and resources." Id. Table 2 reflects the inclusion of 460 megawatts (MW) of nameplate
capacity from nine additional QF contracts, as well as the removal of one QF contract, thus
eliminating five MW of nameplate capacity. Id. at 4-5. The Company asks the Commission to
approve a capacity deficiency period, for calculating SAR based avoided cost rates, of summer
2028.
STAFF ANALYSIS
Authorization of First Capacity Deficiency Date
Staff recommends that the Commission authorize July 2028 as the first capacity deficiency
date for valuing contracts that use the SAR methodology. According to the Company's filing, a
first capacity deficiency of 270 megawatts will occur in July 2028. This change will push back
the deficit date three years from the currently authorized date of July 2025.
Staff compared the 201 7 Summer Load and Existing Resource Balance to the 2015
Summer Load and Existing Resource Balance which was used to determine the currently
authorized luly 2025 first capacity deficiency date. By comparing average annual loads and
average annual resource capacity between 2025 and2028, Staff identified a 1393 MW annual
average reduction in demand and a 473 MW decrease in supply resources for a net reduction in
demand that delays the need for new capacity for an additional three years.
There were two factors decreasing demand: an829 MW average annual increase in Class 2
demand side management resources (DSM) and a 379 MW reduction in the load forecast. The
increase in Class 2 DSM is the result of including all cost-effective Class 2 DSM from the
Company's DSM potential study that was included in its preferred portfolio to resolve deficits in
3STAFF COMMENTS SEPTEMBER28,2OI7
the load resource balance. Although this is a change in PacifiCorp's methodology from its 2015
IRP, it is effectively the same method Idaho Power uses to establish the first deficit capacity year
by netting all cost-effective DSM from its load forecast. Staff believes that this change is
reasonable because the Company is expected to pursue all cost- effective DSM selected in its
preferred portfolio prior to the first deficit date occurring. This will effectively push out the deficit
date to the time period when new PURPA projects not yet in the queue will contribute to capacity
deficiency.
PacifiCorp also decreased its load forecast in the 2017 IRP, primarily due to reduction in
industrial and residential class customer loads. According to the Company, industrial class loads
are projected to be smaller due to lower industrial commodity prices. The Company also assumed
increased penetration of distributed generation and changes in building codes which caused
average use per customer decreases for residential customers. Staff believes these assumptions are
reasonable.
As to the amount of available resources, PacifiCorp has seen a 473 MW decrease in its
2017 load and resource balance as compared to the Company's 2015 load and resource balance.
This usually results in an earlier deficit date but is not large enough to offset the reduction in
demand discussed above. The Company has assumed that thermal generation capacity will be
reduced by 7 55 MW from the early shutdown of the Cholla 4, Craig I , and Naughton 3 coal plants
that was not assumed in the 2015 IRP. However, capacity from qualifying facilities has increased
by 380 MW moderating the effects of the thermal generation reductions.
Staff believes the changes in the 201 7 IRP causing the three-year shift in the first deficit
date are reasonable. Staff updated the SAR model based on the new deficiency date and
calculated new avoided cost rates, included as an attachment to these comments.
Timing of First Capacify Deficiency Date Filing
While Order No. 32697 directs all three electric utilities to file their first capacity
deficiency case after submitting their IRP report to the Commission, Staff respectfully suggests
that cases seeking first capacity deficiency date authorizations for all three utilities be filed after
Commission IRP acknowledgement.
Staff has found that the scope of review to determine the reasonableness of the proposed
deficiency date must sometimes consider a large subset of factors that are typically reviewed for
IRP acknowledgement. However, Staffls review and Commission acknowledgment of the IRP
4STAFF COMMENTS SEPTEMBER28,2Ol7
can occur several months after the first capacity deficiency date cases are settled. Staff believes it
would be more efficient and appropriate to delay capacity deficiency filings until after
Commission IRP acknowledgment. This would eliminate duplication of effort between the two
types ofcases and ensure that all factors that could affect the first capacity deficiency date are
covered through the comprehensive nature of the IRP acknowledgement review.
STAFF RECOMMENDATION
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 2028. Staff also
recommends that cases seeking first capacity deficiency date authorizations for all three utilities
should be filed after Commission IRP acknowledgement starting with the 2019 IRPs.
Respecttully submitted this L day of September 2017 .
Deputy Attorney General
Technical Staff: Yao Yin
i : umisc:comments/pace I T.9djhyybe comments
5STAFF COMMENTS SEPTEMBER28,2Ol7
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 28TH DAY OF SEPTEMBER 2017,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-17-09, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
YVONNE R HOGLE
ROCKY MOUNTAIN POWER
I4O7 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 84116
E-MAIL : ted.weston@pacifi corp.com
vvonne.ho gle@pacifi corp. com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datarequest@nacifi corp. com
RON SCHEIRER
PACIFICORP
825 NE MULTNOMAH STE 600
PORTLAND OR 97232
E-MAIL: ron.scheirer@pacifi corp.com
SECRET
CERTIFICATE OF SERVICE
PACIFICORP
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
CONTRACT
YEAR
NON-LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
3
4
5
6
7
8I
10
11
1a
13
14
'15
16
17
18
19
20
28.61
29.99
3 t.35
32.37
33.1 2
JJ.5 /
33.96
34.41
35.03
35.69
36.30
37.05
37.74
38.36
38.92
39.43
39.91
40.36
40.78
41.20
31 .48
32.89
33.83
34.49
34.81
35.1 2
35.53
36.1 4
36.82
37.44
38.23
38.95
39.59
40.17
40.70
41.18
41.64
42.08
42.50
42.91
34.42
35.1 5
35.65
35.81
36.03
36.40
37.04
37.75
38.40
39.24
40.00
40.67
41 .26
41.81
42.79
43.24
43.68
44.10
44.50
35.95
36.35
Jb.Jf,
36.52
36.90
37.60
JO,JO
QO nO
40.01
40.83
41.54
42.17
42.75
43.27
43.76
44.24
44.69
45.13
45.55
45.95
36.78
36.57
36.74
37.19
38.02
38.91
39.69
40.71
41 .61
42.38
43.04
43.65
44.20
44.71
45.21
45.68
46.'14
46.57
46.99
47.40
36.36
36.71
37.35
38.39
39.45
40.33
41.47
42.45
43.27
43.98
44.61
45.1 8
46.23
46.72
47.20
47.65
48.08
48.51
48.91
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
s5.95
36.78
JO.JO
37.10
38.76
42,05
44.58
45.89
50.51
51.96
52.69
53.42
54.56
55.41
5b.b4
58.08
59.54
61 .19
62.35
63.89
65.78
66.92
68.93
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 2017 , Table 3.8 Energy Prices by Sector-Mountain at
https ://www.eia.gov/outlooks/aeo/tables_rel.clm
PACIFICORP Page 1
PACIFICORP
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 projects 100 kW or smaller
LEVELIZED NON.LEVELIZED
LENGTH
ON-LINE YEAR
CONTRACT
YEAB
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
J
4
5
6
7
6
I
10
1l
13
141(
16
17
18
19
20
28.61
29.99
31.35
JZ.5I
33.1 2
33.57
33.96
34.41
35.03
35.69
36.30
38.72
40.83
42.67
44.29
45.74
47.03
48.22
49.30
50.31
31.48
32.89
33.83
34.49
34.81
35.1 2
35.53
36.1 4
36.82
37.44
40.1 3
42.45
44.45
46.1 I
47.74
49.1 1
50.36
51.51
52.56
53.54
34.42
OE < E
35.65
35.81
36.03
36.40
37.04
37.75
38.40
41 .42
43.99
46.17
48.05
49.70
51.17
52.49
53.70
54.81
55.84
56.78
3s.95
36.35
36.35
36.52
36.90
37.60
38.38
39.09
42.54
45.41
47.81
49.85
51.64
53.20
54.60
55.88
57.04
58.1 2
59.11
60.02
36.78
36.57
36.74
37.1 I
38.02
38.91
39.69
43.69
46.93
49.58
51.80
53.72
55.38
56.86
58.20
59.42
60.54
61.57
62.53
63.42
36.36
36.71
37.35
38.39
39.45
40.33
45.02
48.69
51.63
54.04
56.09
57.85
59.40
60.80
62.06
63.23
64.29
65.27
66.20
67.05
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
37.1 0
38.76
42.05
44.58
45.89
82.17
84.09
85.29
86.50
88.1 3
89.47
91 .19
93.1 4
95.12
97.29
98.99
101 .06
103.49
1 05.1 I
107.77
Note: These rates will be lurther adjusted with the applicable integration charge.
Note: The rales 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 .clm
PACIFICORP Page 2
TYFAFIS\
PACIFICORP
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
xxxx, 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
2
3
4
5
o
7
I
'10
11
12
13
14
15
16
17
18
19
28.61,o oo
31.35
32.37
33.1 2
33.57
33.96
34.41
35.03
35.69
36.30
38.56
40.53
42.25
43.77
45.12
46.34
47.45
48.48
49.42
31 .48
32.89
33.83
34.49
34.81
35.1 2
35.53
36.1 4
36.82
37.44
39.95
42.11
43.98
45.60
47.05
48.34
49.52
50.59
51.59
52.51
34.42
35.1 5
35.65
35.81
36.03
36.40
37.04
37.75
38.40
41.21
43.60
45.63
47.39
48.94
50.31
51.55
52.68
53.73
54.70
55.59
35.95
36.35
36.35
36.52
36.90
37.60
38.38
39.09
42.30
44.97
47.20
49.1 1
50.77
52.24
53.55
54.75
55.84
56.86
57.79
58.66
36.78
Jb.J/
JO./4
37.1 I
38.02
38.91
39.69
43.40
46.41
48.88
50.95
52.74
54.30
55.68
56.94
58.09
59.1 5
60.1 2
61.02
61.87
JO.JO
36.71
37.35
38.39
39.45
40.33
44.67
48.09
50.82
53.06
54.97
56.62
58.07
59.38
60.57
6l .67
62.67
63.60
64.48
65.29
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
35.95
36.78
36.36
37.10
38.76
42.05
44.58
45.89
79.10
80.97
82.12
83.29
84.87
86.1 6
87.84
89.74
91.67
93.78
95.43
97.45
99.83
101.47
104.00
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 lntormation Administration (ElA)'s Annual Energy
Outlook2017,releasedJanuary2017. SeeAnnualEnergyOutlook20lT,Table3.SEnergyPricesbySector-Mountainat
hft ps://www.eia. gov/outlooks/aeo/tables-ref .cf m
PACIFICORP Page 3
PACIFICORP
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
xxxx, 201 7
$/lvwh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates is limiled 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
2
2
4(
6
7II
10
11
12
13
14
15
16
17
18
19
20
28.61
29.99
31.35
32.37
33.12
33.57
33,96
34.41
35.03
35.69
36.30
39.69
42.64
45.19
47.42
49.41
51.19
52.80
54.27
55.62
31.48
32.89
33.83
34.49
34.81
35.12
35.53
36.14
36.82
37.44
41.25
44.50
47.28
49.70
51.84
53.74
55.45
57.01
58.43
59.74
34.42
35.1 5
35.65
35.81
36.03
36.40
37.04
37.75
38.40
42.70
45.32
49.38
52.00
54.31
56.34
58.15
59.80
61.30
62.68
63.94
35.95
36.35
36.35
36.52
36.90
37.60
38.38
39.09
44.02
48.09
51.47
54.33
56.82
58.99
60.92
62.66
64.24
65.69
67.01
68.23
36.78
36.57
36.74
37.1 9
38.02
38.91
39.69
45.43
50.03
53.78
56.91
59.59
61 .90
63.95
65.78
67.44
68.95
70.32
71.59
72.77
36.36
36.71
J /.J3
38.39
39.45
40.33
47.09
a, ea
56.50
59.91
62.78
65.24
67.38
69.30
71 .01
72.58
73.99
75.30
76.51
tt.b3
2017
201 I
201 I
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
ZVJJ
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
44.58
45.89
100.64
102.84
104.31
105.79
107.70
109.33
111.35
1 13.60
115.87
1 18.35
120.35
122.74
125.49
127.51
130.42
Note: A "seasonal hydro project" is defined as a generation lacility 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 lntormation Administration (ElA)'s Annual Energy
Outlook 20'17, released January 2017. See Annual Energy Outlook 2017, Table 3.8 Energy Prices by Sector-lvlountain at
https ://www.eia.gov/outlooks/aeo/tables_ref.cf m
PACIFICORP Page 4
PACIFICORP
AVOIDED COST RATES FOR OTHER PROJECTS
xxxx,2017
$/MWh
New Contracts and Replacement Contracts without Full Capacitv Pavments
Ellgibility for these rates is limited to projects smaller than 10 aMW
LEVELIZED NON.LEVELIZED
CONTFACT
LENGTH
(YEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
e
4
5
6
7
8
o
10
11
12
13
14
15
16
17
18
19
20
28.61
29.99
31.35
32.37
33.12
33.57
33.96
34.41
35.03
35.69
36.30
38.12
39.72
41.12
42.35
43.46
44.47
45.38
46.23
47.02
31.48
32.89
33.83
34.49
34.81
35.12
35.53
36.1 4
36.82
37.44
39.45
41.19
42.70
44.02
45.20
46.25
47.22
48.1 1
48.94
49.71
34.42
35.1 5
35.65
35.81
36.03
36.40
37.04
37.75
38.40
40.63
42.55
44.19
45.60
46.86
47.98
48.99
49.93
50.80
51.60
52.Jf,
35.95
36.35
36.35
36.52
36.90
37.60
38.38
39.09
41 .63
43.76
/.( (q
47.08
48.43
49.62
50.69
51 .68
52.59
53.44
54.22
54.95
36.78
36.57
36.74
37.19
38.02
38.91
39.69
42.62
45.01
46.98
48.64
50.09
51.35
52.48
53.52
54.47
55.35
56.1 6
56.93
57.65
36.36
36.71
37.35
38.39
39.45
40.33
43.74
46.44
48.62
50.41
51.95
53.28
54.47
55.54
56.53
57.45
58.29
59.07
59.82
60.51
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
35.78
36.36
37.1 0
38.76
42.05
44.58
45.89
70.76
72.51
73.53
74.57
76.02
77.19
7A.74
80.50
82.29
84.27
85.78
87.66
89.89
91.39
93.77
Note: "Other projects" relers 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, landtill gas, or geothermal projects.
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 .clm
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