20170601Application.pdf

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,1";11:l\/'":i,rt.,L-iJL"1r'An IDACORP Company
DONOVAN E. WALKER
Lead Counsel
dwalker@i dahopower.com
May 24,2017
VIA HAND DELIVERY
Diane M. Hanian, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, ldaho 83702
Re: caseNo. e N R' E - l7-OL
Update to Published Avoided Cost Rates to Reflect an Updated Natural
Gas Price Forecast of the U.S. Energy lnformation Administration (ElA)
ldaho Power Company's Response and Objection
Dear Ms. Hanian
Enclosed for filing in the above matter please find an original and seven (7)
copies of the Response and Objection of ldaho Power Company.
Very truly yours,
E. Walker
DEW:csb
Enclosures
1221 W. ldaho St. (83702)
P.O. Box 70
Boise, lD 83707
(o o
DONOVAN E. WALKER (lSB No. 5921)
ldaho Power Company
1221West ldaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker@ ida hopower. com
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UT!LITIES COMMISSION
itr/1I"lr/i"!'li-r!*i !-l!rl'.r '
!'ti^.,!@':*I u;"-
:rill .iiji': - | iii{ l[:: I U
IN THE MATTER OF THE ANNUAL
UPDATE TO PUBLISHED AVOIDED
COST RATES TO REFLECT AN
UPDATED NATURAL GAS PRICE
FORECAST OF THE U.S. ENERGY
TNFORMATTON ADMTNISTRATTON (EtA)
CASE NO
RESPONSE AND OBJECTION OF
IDAHO POWER COMPANY
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ldaho Power Company ("!daho Power" or "Company"), pursuant to ldaho Public
Utilities Commission Staffs ("Staff') May 16, 2017, letter with attached gas price
forecast and proposed rate tables, hereby respectfully submits the following response
and objection to the subset of Energy lnformation Administration's ("ElA") natural gas
forecast selected by Staff, and the resulting published avoided cost rates proposed
thereby.
I. INTRODUCTION AND BACKGROUND
Prior to the ldaho Public Utilities Commission's ("Commission") Order No. 32697
(December 18, 2012), the surrogate avoided resource ('SAR') avoided cost
methodology utilized the natural gas forecast published by the Northwest Power and
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 1
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Conservation Council ("NPCC"). However, because updates to NPCC's forecast were
relatively infrequent in a volatile natural gas price market, the Commission, with Order
No. 32697, moved to annual natural gas forecast updates using the EIA natural gas
forecast. The Commission directed, 'lT lS FURTHER ORDERED that natural gas
prices utilized in the SAR Methodology be updated annually, on June 1 of each year,
with the most recent natural gas forecasts provided by EIA's Annual Energy Outlook."
Order No. 32697 , p.52', See a/so, Order No. 32697, pp.7-11, 16.
EIA's Annual Energy Outlook contains several subsets of natural gas forecasts.
Subsequent to Order No. 32697, Staff has utilized the EIA forecast as an input to the
SAR methodology, and specifically applied the Mountain Region natural gas forecast
under the table titled, Electric Prices: Energy Prices by Sector and Source. Staff has
similarly proposed use of EIA's Electric Prices: Energy Prices by Sector and Source,
Mountain Region subset for the naturat gas forecast update in this case. However, for
ldaho Power's lntegrated Resource Plan ("lRP") process as well as for avoided cost
rates based upon the lncremental Cost IRP ("lClRP") methodology, ldaho Power utilizes
EIA's Annual Energy Outlook from a different EIA subset: the Henry Hub: High Oil and
Gas Resource and Technology (nom $/MMBtu) forecast, adjusted for pricing at Sumas
and ldaho City Gate.
Use of the Mountain Region EIA forecast proposed by Staff results in published
avoided cost rates that are over $8/megawatt-hour ("MWh") higher than use of the
adjusted Henry Hub EIA forecast used by Idaho Power in its IRP and the ICIRP
methodology. ldaho Power hereby objects to the use of the proposed Mountain Region
EIA natural gas forecast for this annual update to avoided cost rates, which will be
locked in for 2}-year term, published rate contracts. ldaho Power proposes the use of
the adjusted Henry Hub EIA natural gas forecast.
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY.2
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II. COMMENTS
Order No. 32697 generically requires the use of the EIA's Annual Energy Outlook
natural gas forecast as an input to the SAR methodology, but that order and subsequent
errata orders do not specify the data series, or subset, within EIA's Annual Energy
Outlook that is to be applied to the SAR methodology. The continued use of the
Mountain Region forecast is not a representative forecast for natural gas prices for
ldaho Power as it represents pricing in a higher priced supply basin than where ldaho
Power holds firm pipeline capacity and performs natural gas transactions, does not
represent or track with actual natural gas trading prices from the lntercontinental
Exchange ("lCE"), and is higher than prices occurring in the market. lts continued use
unreasonably inflates the avoided cost prices calculated under the SAR methodology.
ln accordance with Commission orders, the ICIRP methodology used for larger
projects subject to negotiated rates and contracts, utilizes the natural gas price forecast
that ldaho Power uses in its IRP process. The Company's IRP model and process use
the EIA natural gas price forecast from EIA's Annual Energy Outlook for Henry Hub,
adjusted for pricing at Sumas and ldaho City Gate, where ldaho Power holds firm
pipeline capacity and actually performs natural gas transactions. Specifically, in the
development of the 2017 lRP, ldaho Power is using EIA's Natural Gas Spot Price at
Henry Hub: High Oil and Gas Resource and Technology (nom $/MMBtu) forecast.
ldaho Power has presented this forecast at the IRP Advisory Council ("|RPAC')
meetings, and believes the forecast consists of a more accurate expectation of long-
term natural gas prices that are accessible to ldaho Power.
The ElA Annual Energy Outlook is published every year with multiple gas price
scenarios. ln the past, the Company has used the reference case forecast for its IRP;
however, for the 2017 lRP, the Company compared the reference case forecast with
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 3
o
actual future trading prices from lCE. Through that analysis, it was determined that the
reference case natural gas prices were higher than what was occurring in the market.
The Company looked at the other EIA scenarios and chose the High Oil and Gas
Resource and Technology, which tracks much closer to actual future trading prices from
lCE. The Company uses the Henry Hub index from the High Oil and Gas Resource and
Technology and adjusts the Henry Hub price to geographically deliver the natural gas to
its service territory. This adjustment reflects the price that the Company will pay for
natural gas delivered to its production plants.
As presented at the January 12, 2017, IRPAC meeting, and included below,
analysis of this forecast demonstrates it follows recent history and is in close alignment
with ICE settled transactions, which are based on actual willing buyer/willing seller
transactions.
Henry Hub NaturalGas Prices (Nominal$/mmbtu)
o
-l
ldaho Power recommends that pursuant to the required annual avoided cost
update to the SAR methodology in accordance with Order No. 32697, the Natural Gas
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 4
o o
Spot Price at Henry Hub: High Oil and Gas Resource and Technology (nom $/MMBtu)
forecast from EIA's Annual Energy Outlook be utilized, adjusted for pricing at Sumas
and ldaho City Gate. This forecast is relevant and applicable to prices that are based
on real and expected natural gas prices for actual transactions utilized by ldaho Power.
Using this forecast will result in the determination of a far more accurate approximation
of and appropriate published avoided cost pricing. The following table includes the
recommended forecast:
Year
EA Henry Hub Forccast
Annurl Energy Outlmk
(Nominrl S/mmBtu)
2017 Sumas Basis
Otiominal $/mmBtu)
2017 Transport Cmt
(Nominal S/mmBtu)
U@ted Ihliwred NG Cost
(Idaho City Gate Price)
Nominal $/mmBtu)
(a)(b)(c)(d)
++
Notes:
l. HenryHubForecastisfromEIA's20lTAnnualEnergyOutlook,HighOilandCasResourceandTechnologyCase,Table13,
Natural Cas Supply, Disposition and Prices, published January 5,2017.
2. SunasBasisisMarketQuotedBasisthrough2023perthelCEerchangeandthenheldstaticfrom2024-2041.
3. Transportation Costs include Pipeline Fuel Rateal l.28Vo nultiplied by the conrrndity price, Pipeline conrrndity charge of $.0313,
and Pipeline reservation charges of$.410 through 2017,$.3V24 through October 201 8, and $.3903 for November 201 8 through 2019 per
cunent Tarrifi, then escalated at l%operyeal2020-2M1.
$2.85
$2.63
$2.82
$3. l0
$3.56
$3.79
$3.70
$3.75
$3.88
$4.t2
$4.32
$4.56
$4.82
$5. 16
$5.29
$5.24
$5.1 1
$5. l2
$5. 19
$5.30
$5.38
$5.45
$s.52
$s.6s
$5.79
$5.83
$s.83
s6.03
$6. 14
$6.25
s6.33
s2.620
$2.419
$2.827
s3.240
$3.7s0
$3.860
$3.617
$3.s56
$3.714
$3.%5
$4.138
$4.375
$4.630
$4.958
$5.080
$5.028
$4.895
$4.900
$4.%5
$5.065
$5.149
$5.2r3
$s.271
$5.396
$5.53 I
$5.565
s5.561
$5.752
s5.861
$5.957
s6.039
($0.243)
($0.263)
($0.480)
($0.6m)
($o.6so)
($0.533)
($0.3001
($0.28s)
($0.3 l5)
($0.3 l5)
($0.3 ls)
($0.3 l5)
($0.3 ls)
($0.3 ls)
($0.3 l5)
($0.3 ls)
($0.31s)
($0.315)
($0.3 l 5)
($o.3 r s)
($0.3ts)
($0.3 r5)
($0.315)
($0.3 l5)
($0.3 rs)
($0.3 l5)
($0.3 ls)
($0.3 l5)
($0.315)
($0.3 l5)
($0.3 l5)
$0.473
$0.473
$0.471
$0.457
$0.461
$0.468
$0.471
$0.47s
$0.48t
$0.488
$0.495
$0.502
$0.509
$0.518
$0.523
$0.527
$0.530
$0.534
$0.539
s0.545
$0.551
$0.556
$0.562
$0.568
$0.574
$0.580
$0.584
$0.s92
$0.598
$0.604
$0.6t0
2015
20t6
20t7
2018
2019
2020
202t
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2W
2Mt
20/.2
2M1
2044
2M5
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 5
O o
As stated above, this forecast is currently utilized in both ldaho Power's 2017 IRP
process, as well as in avoided cost pricing based upon the ICIRP methodology.
Additionally, this same forecast (and table above) is utilized in the present annual
update to standard avoided cost pricing (Oregon's equivalent of published rate, SAR-
based avoided costs) for Public Utility Regulatory Policies Act of 1978 ('PURPA")
qualifying facilities ("QF') in the Company's Oregon jurisdiction. Public Utility
Commission of Oregon Docket No. UM 1730.
ldaho Power has applied the adjusted 2017 Natural Gas Spot Price at Henry Hub
forecast to the SAR model and compared the resulting avoided cost prices to the prices
determined by Staff and contained in Staff's May 16, 2017, letter. Please see
Attachment 1 for the Avoided Cost Pricing Tables utilizing the EIA Henry Hub forecast
adjusted for Sumas and ldaho City Gate. When the Natural Gas Spot Price at Henry
Hub forecast is applied as the basis in the SAR methodology, the approximate decrease
in 20-year, levelized avoided cost prices across all resource types, assuming an on-line
year of 2017, is about $8.36/MWh.
Customers are harmed by an avoided cost methodology that results in inflated
prices based on natural gas forecasts that are not applicable to the utility. ldaho Power
has experienced continued development of new QF projects that are eligible for
published avoided cost rates which are locked-in for 2}-year terms. Several projects
have recently entered into replacement Energy Sales Agreements ("ESAs") for existing
projects, and several more have or are expected to request replacement ESAs this year
and over the next several years. Since Order No. 32697 was issued on December 18,
2012, ldaho Power has entered into eight new ESAs and seven replacement ESAs
containing published avoided cost prices that are based on the EIA Mountain Region
forecast. !t is anticipated that in 2018, five projects that are eligible for published
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 6
o a
avoided cost prices will request to implement replacement ESAs for existing projects. ln
2019, that number grows to 10, and in 2020 it is expected that 16 QF projects will
request replacement ESAs. The continued use of the Mountain Region natural gas
forecast, that does not represent prices that are utilized by ldaho Power, results in an
artificially high price that customers should not be required to pay.
The mandatory purchase requirement of PURPA already works to undermine the
required integrated resource planning of the Company in several ways. Use of EIA's
Mountain Region forecast further detaches avoided costs from the Company's
integrated resource planning, which is used to plan for the future acquisition of
generation resources. The SAR model is set up to recognize different model inputs and
variables for each utility, such as capacity rate calculations, seasonalization factors, and
load and resource data; therefore, the application of the proper natural gas forecast
should be consistent with other utility specific inputs.
ilt. coNcLUStoN
ldaho Power proposes that the annual update to published avoided cost rates
utilize the 2017 EIA Annual Energy Outlook, Natural Gas Spot Price at Henry Hub: High
Oil and Gas Resource and Technology (nom $/MMBtu) forecast, adjusted for Sumas
and ldaho City Gate. This would align SAR published rates with the current natural gas
forecast utilized by the IC|RP avoided cost methodology, the Company's 2017 lRP, and
the Company's annual standard avoided cost rates in Oregon. Unlike the use of EIA's
Mountain Region forecast, the use of EIA's Henry Hub forecast, adjusted for Sumas and
ldaho City Gate, represents pricing in the supply basin in which ldaho Power holds firm
pipeline capacity and actually performs natural gas transactions. Use of EIA's Henry
Hub forecast would result in a closer approximation of the Company's avoided cost
pricing, which for published rates is locked in for 20-year term contracts, and results in a
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 7
o Or
substantia! cost savings to ldaho Power customers in the mandatory PURPA purchase
requirements of potentially hundreds of millions of dollars. As such, ldaho Power
respectfully requests that the Commission direct the use of EIA's Henry Hub forecast,
adjusted for Sumas and ldaho City Gate, in the 2017 annual update to published
avoided cost rates for ldaho Power, which results in the published avoided cost rates
reflected in Attachment t hereto.
Respectfully submitted this 24th day of May 2017
DONOVAN E. WALKER
Attorney for ldaho Power Company
RESPONSE AND OBJECTION OF IDAHO POWER COMPANY - 8
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 24th day of May 2017 I served a true and correct
copy of the within and foregoing RESPONSE AND OBJECTION OF IDAHO POWER
COMPANY upon the following named parties by the method indicated below, and
addressed to the following:
o
Commission Staff
Daphne J. Huang
Deputy Attorney General
ldaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, ldaho 83720-0074
Avista Corporation
MichaelAndrea
Avista Utilities
1411 East Mission
P.O. Box 3727
Spokane, Washington 99220-3727
Clint Kalich
Avista Utilities
1411 East Mission
P.O. Box 3727
Spokane, Wash ingt on 99220-37 27
Rocky Mountain Power
Yvonne Hogle
Ted Weston
PacifiCorp dlbla Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Daniel MacNeil
PacifiCorp dlbla Rocky Mountain Power
825 NE Multnomah Street
Portland, Oregon 97232
o
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RESPONSE AND OBJECTION OF IDAHO POWER COMPANY.9
rry, Legal nt
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-07
IDAHO POWER COMPANY
ATTAGHMENT 1
(o (.
IDAHO POWER COMPANY
AVO]OED COST RATES FORWND PROJECTS
June 01, 2017
$/MWh
New Contracts and Replacement Contracts without Full Caoacitv Pavments
Eligibility for these rates is limited to projects 100 kW or smaller
LEVELIZED NON.LEVELIZED
CONTRACT
LENGTH
ryEARS)
ON.LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
3
4
5
6
7
8I
10
11
12
13
'14
15
16
17
18
19
20
22.13
23.10
24.45
25.50
26.01
26.41
26.80
27.57
28.28
28.96
29.64
30.32
30.94
31.46
31.87
32.22
32.55
32.86
33.16
33.43
24.15
25.75
26.81
27.19
27.49
27.82
28.62
29.35
30.07
30.77
31.48
32.12
32.65
33.06
33.42
33.75
34.06
34.35
34.62
34.87
27.49
28.30
28.38
28.50
28.74
29.59
30.36
31 .10
31.83
32.58
33.25
33.79
u.20
34.55
34.88
35.1 9
35.48
35.75
36.00
36.24
29. t9
28.88
28.90
29.13
30.12
30.99
31.80
32.60
33.41
u.12
34.68
35.1 0
35.46
35.79
36.10
36.39
36 66
36.92
37.17
37.41
28.55
28.73
29.1 0
30.40
31.44
32.37
33.2s
34.14
34.91
35.50
35.93
36.30
36.6s
36.9s
37.24
37.52
37.78
38.03
38.28
38 50
28.94
29.41
31 .13
32.31
33.33
u.28
35.23
36.03
36.62
37.04
37.39
37.71
38.02
38.31
38.58
38.83
39.08
39.33
39.55
39.76
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
22.13
24.15
27.49
29.1 I
28.55
28.94
29.93
34.98
36.50
38.33
40.29
42.78
43.79
43.55
42.73
42.91
43.53
44.39
45.14
.45.75
46.32
47.38
48.50
48.90
49.04
50.58
Note: These rates will be further ad.iusted with the applicable integration charge.
Note: The rates shor/n in this table have been computed using the U.S.lnformation Administration Annual Energy
Outlook released 2017. See Annual Energy Outlook 2017
IDAHO POWER COMPANY Page 1
oo
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SOLAR PROJECTS
June 01, 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
NEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES2017201420192020202'l 2022
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
'16
17
18
19
20
22.13
23.10
24.45
25.50
26.01
26.41
26.80
30.42
33.36
35.86
38.02
39.95
41.64
43.08
44.29
45.36
46.32
47.20
48.00
48.73
24.15
25.75
26.81
27.19
27.49
27.82
32.02
35.33
38.07
40.40
42.47
44.25
45.75
47.01
48.1 0
49.09
49.98
50.79
51.53
52.21
27.49
28.30
28.38
28.50
28.74
33.73
37.50
40.51
43.03
45.22
47.09
48.65
49.93
51.(N
52.03
52.93
53.75
54.49
55.17
55.81
29.1 I
28.88
28.90
29.13
35.31
39.67
43.03
45.75
48.09
50.04
51.64
52.93
54.05
55.04
55.94
56.75
57.49
58.1 6
58.79
59.39
28.55
28.73
29.1 0
37.'t6
42.31
46.O4
48.95
51.40
53.40
55.01
56.29
57.38
58.34
59.21
60.00
60.72
61.38
61.99
62.57
63.1 I
28.94
29.41
40.52
46.48
50.44
53.39
55.81
57.76
59.28
60.46
61,46
62.33
63.1 3
63.86
64.52
65 13
65.70
66.25
66.75
67.21
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
22.13
24.15
27.49
29.19
28 5s
28.94
29.93
65.52
87.48
69.76
72.14
75.',t4
76.63
76.87
76.54
77.22
78.33
79.70
80.97
82.11
43.21
84.81
86.49
87.44
88.14
90.26
Note: These rates will be further ad,iusted with the applicable integration charge.
Note: The rates shown in this table have been computed using the U.S.I nformation Administration Annual Energy
Outlook 2017 released 2017. See Annual Energy Outlook 2017
IDAHO POWER COMPANY Page 2
at (o
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NONSEASONAL HYDRO PROJECTS
June 01,2017
$/MWh
New Contracts and Replacement Contracts without Full Capacity Payments
Eligibility for these rates is limited to projects smaller than l0 aMW.
LEVELIZED NON-LEVELIZED
LENGTH
ON-LINE YEAR
CONTRACT
YEAR
NON-LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
3
4
5
6
7
8I
10
11
12
13
14
15
16
17
18
19
20
22.13
23.',t0
24.45
25.50
26.01
26.41
26.80
30.1 4
32.87
35.1 I
37.20
39.02
40.60
41.95
43.08
44.09
44.98
45.81
46.56
47.24
24.15
25.75
26.81
27.19
27.49
27.82
31.69
u.75
37.29
39_47
41.40
43.08
44.48
45.65
46.68
47.60
48.43
49.20
49.89
50.53
27.49
28.30
28.38
28.50
28.74
33.33
36.80
39.60
41.94
44.00
45.75
47.20
48.40
49.44
50.37
51.21
51.97
52.67
53.31
53_91
29.1 9
28.88
28.90
29.13
34.80
38.83
41.94
44.47
46.66
48.49
49.99
51.20
52.25
53.17
54.01
54.77
55.47
56.1 0
56.69
57.25
28.55
28.73
29.10
36.51
41.26
44.71
47.43
49.72
51.61
53.'11
54.31
55.33
56.24
57.05
57.80
58.47
59.09
59.67
60.21
60.72
28.94
29.41
39.60
45.1 1
48.74
51.53
53.81
55.65
57.08
58.1 I
59.12
59.94
60.70
61.38
62.00
62.58'63.12
63.64
64.11
64.54
2017
201 8
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
203',|
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
22.13
24.15
27.49
29.19
28.55
28.94
29.93
62.55
64.47
66.71
69.09
72.OO
73.44
73.84
73.26
73.89
74.95
76.28
77.49
78.58
79.63
a1.17
82.80
83.70
84.34
86.40
Note: The rates shor/n in this table have been computed using the U.S.I nforrnation Administration Annual Energy
Outlook 2017 released 2017- See Annual Energy Outlook 2017
IDAHO POWER COMPANY Page 3
o o
Note: A "seasonal hydro project" is defined as a generation facility which produces at least 55% of its annual generation during the
months of June, July, and August. Order 32802.
Note: The rates shown in this table have been computed using the U.S.I nformation Administration Annual Energy
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
June 01,2017
$/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
CONTRACT
LENGTH
ffEARS)
ON-LINE YEAR
2017 2018 2019 2020 2021
CONTRACT
YEAR
NON.LEVELIZED
RATES
1
2
3
4
5
6
7
8
9
10
1'l
12
13
14
15
't6
17
18
19
20
22.13
23.10
24.45
25.50
26.O1
26.41
26.80
32.08
36.33
39.88
42.91
45.57
47.88
49.85
51.54
53.02
54.35
55.56
56.65
57.65
24.15
25.75
26.81
27.19
27.49
27.82
34.01
38.82
42.74
46.03
48.88
51.33
53.40
55.14
56.67
58.03
59.27
60.38
61.40
62.33
27.49
28.30
28.38
28.50
28.74
36.15
41.66
46.00
49.56
52.60
55.17
57.3'l
59.1 0
60.66
62.O4
63.28
u_40
65,43
66.36
67.22
29.1 9
28.88
28.90
29.13
38.33
44.74
49.57
53.42
56.65
59.33
61.53
63.34
8t.90
66.27
67.51
68.62
69.63
70.56
71.41
72.21
28.55
28.73
29.10
41.10
48.65
54.01
58.1 1
61.46
64.1 9
66.39
68.1 6
69.68
71.O1
72.20
73.28
74.26
75.15
75.97
76.75
77.46
28.94
29.41
45.99
54.75
60.41
64.53
67.82
70.43
72.49
74.12
75.49
76.70
77.78
78.76
79.66
80.47
81.23
81.95
82.62
83.22
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
22.13
24.15
27.49
29.19
28.55
28.94
29.93
83.33
8s.55
88.10
90.79
94.02
95.78
96.31
96.26
97.22
98.63
100.30
101.87
103.32
104.73
1 06.64
1 08.64
109.92
1 10.95
1',13.40
Outlook 2017, released January 2017. See Annual Energy Outlook 2017
IDAHO POWER COMPANY Page 4
o o
I
Note: "Other projects" refers to projects other than wind, solar, non-seasonal hydro, and seasonal hydro prqects- These "Other
projects" may include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shovvn in this table have been computed using the U.S. Energy lnformation Adminlstration (ElA)'s Annual Energy
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
June 01, 2017
$/MWh
New Contracts and Reolacement Contracts without Full Caoacitv Pavments
Eligibility for these rates is limited to projects smaller than 10 aMW.
LEVELIZED NON-LEVELIZED
CONTRACT
LENGTH
ryEARS)
ON-LINE YEAR
CONTRACT
YEAR
NON.LEVELIZED
RATES2017 2018 2019 2020 2021 2022
1
2
3
4
5
6
7II
10
11
12
13
14
15
16
't7
18
'19
20
22.13
23.10
24.45
25.50
28.01
26.41
26.80
29.39
31.53
33.37
35.00
36.48
37.78
38,89
39.81
40.62
41.36
42.03
42.65
43.21
24.15
25.75
26.81
27.19
27.49
27.82
30.79
33.1 8
35.1 8
36.93
38.51
39.88
41.03
41.98
42.81
43.56
44.24
44.86
45.43
45.96
27.49
28.30
28.38
28.50
24.74
32.24
u.92
37.12
38.99
40.67
42.10
43.29
44.26
45.1 0
45.85
49 s3
47.16
47.73
48.26
48.75
29.1 I
28.88
28.90
29.13
33.U
36.54
38.98
41.0',1
42.79
44.30
45.52
46.50
47.35
48.10
48.78
49.41
49.98
50.50
51.00
51.46
28.55
28.73
29.10
34.72
38.39
41.11
43.29
45.1 I
46.74
47.98
48.95
49.78
50.51
51.19
51.80
52.36
52.87
53.3s
53.81
54.24
28.94
29.41
37.13
41.37
44.27
46.50
48.39
49.52
51.11
52.02
52.78
53.46
54.08
54.65
55.17
55 65
56.1 0
56.54
56.95
57.31
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
22.13
24.15
27.49
29.19
28.55
28.94
29.93
54.51
56.31
58.43
50.68
63.47
u.79
64.86
64.35
64.85
65.78
65.97
68.05
69.00
69.91
71.31
72.79
73.55
74.04
75.95
Ouuook 201 7. released 2017. SeeAnnual Energy Outlook 2017
IDAHO POWER COMPANY Page 5