20130325Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6618
7r?ftR25 F1 2:0.8
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
AVOIDED COST RATES.
CASE NO. GNR-E-11-03
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to Order No.
32737, submits the following comments.
BACKGROUND
On February 5, 2013 the Commission issued Order No. 32737 in Case No. GNR-E-1 1-03.
In part, that Order granted the Petitions for Clarification of Renewable Energy Coalition and
Idaho Power regarding the definition of "canal drop hydro" and the determination of resource-
specific capacity factors as they relate to "canal drop hydro" and "other" projects under the SAR
methodology. Because the issues surrounding the definition of canal drop hydro and resource-
specific capacity factors were not fully explored at hearing, the Commission directed the parties
to file comments on these issues.
STAFF COMMENTS 1 MARCH 25, 2013
A proper definition of "canal drop hydro" is important because under the Surrogate
Avoided Resource ("SAR") methodology "hydro" and "canal drop hydro" are distinguishable,
each with its own set of published avoided cost rates. "Canal drop hydro" has a higher set of
avoided cost rates because irrigation-related projects provide capacity when the utility most needs
it - during the peak hours of the peak days of the year (i.e., during the summer season). The
definition of "canal drop hydro" will dictate which hydro projects are entitled to the higher
published avoided cost rates.
Resource-specific capacity factors are used in the SAR model for two different purposes.
First, the on-peak capacity factors of each resource type are used in determining the value of the
capacity provided by each resource towards helping to meet the utility's summer and winter peak.
For example, resources that can provide capacity during a utility's peak load hours have much
greater value to the utility than resources that do not generate on-peak. Higher peak capacity
factors in the SAR model generate higher rates.
Second, annual capacity factors are used in the SAR model for the purpose of spreading
capacity value over the kilowatt-hours of generation produced by the project. In actuality,
capacity value is dependent only on the peak hour timing of a project's generation, not on the
volume of its energy generation over the course of the year. However, because avoided cost
payments are made only as a per kilowatt-hour payment (energy), capacity payments (capacity)
must be spread over an estimated number of kilowatt hours in order for the project to be fully
reimbursed for its capacity value. Higher annual capacity factors in the SAR model generate
lower rates.
The "other" category of published rates is intended for all project types other than hydro,
"canal drop hydro," wind, and solar. This would typically encompass project types such as
biomass (wood or agricultural waste), biogas (municipal wastewater treatment, animal waste),
landfill gas, and geothermal. These project types operate more like baseload facilities, and have
similar capacity factors.
ANALYSIS
Definition of seasonal hydro project
Instead of using the term "canal drop hydro," Staff proposes using the term "seasonal
hydro." What is important, Staff believes, is not whether a hydro project is located on a canal or
whether it is somehow associated with irrigation, but instead whether it reliably generates during
STAFF COMMENTS 2 MARCH 25, 2013
the season of the year when capacity is most valuable to the utility, i.e., summer for Idaho Power
and PacifiCorp.
Staff proposes to define a seasonal hydro project as one that, over the last ten years,
generated at least 90 percent of its average annual generation during the months of April through
October. There currently are 26 hydro projects on Idaho Power's system that meet this definition
and 33 hydro projects which do not meet this definition. Ninety-percent was chosen as the cut-off
point because there appeared to be a natural break in the data at this point.
This definition would apply to any new hydro project seeking a contract and to any
existing projects seeking to replace an expiring contract. For new contracts, Staff proposes that
projects be required to demonstrate compliance with this definition in the first year of operation,
with retroactive adjustment of rates if the project fails to comply.
Because Staff proposes to use capacity factor as a means of defining seasonal and non-
seasonal hydro projects, each resulting category will by definition exhibit its own characteristics
for both annual and peak hourly capacity factor. Adding or removing projects from one category
to the other will unavoidably impact the overall capacity factor characteristics of the other
category. Consequently, it will be necessary for Staff to propose annual and peak capacity factors
for each category, even though Order No. 32737 seeks comments only on "capacity factors as
they relate to 'canal drop hydro' and 'other' projects under the SAR methodology."
Annual capacity factors
Using monthly generation data provided by Idaho Power, Staff calculated an average
annual capacity factor for two groups of projects: seasonal hydro projects and non-seasonal
hydro projects. These, along with the peak capacity factors, are shown in the table below.
Annual Peak hour capacity factors
capacity
factor Summer peak Winter peak
Seasonal hydro projects 32% 79% 0%
Non-seasonal hydro projects 50% 67% 25%
"Other" projects 89% 93% 93%
STAFF COMMENTS 3 MARCH 25, 2013
Peak hour capacity factors
In the direct testimony of Mark Stokes, Idaho Power outlined its methodology for
determining peak capacity factors. To summarize, Idaho Power examined the output of four
different hydro projects during the hours of 3 p.m. through 7 p.m. in July. For each of these
hours, Idaho Power calculated a capacity factor by summing the actual output from these projects
and then dividing this by the sum of the nameplate capacity of the same projects. This resulted in
a capacity factor for each peak hour of each year.
Idaho Power used these hourly capacity factors to compute an annual capacity factor for
each year. Idaho Power defined the annual capacity factor as the hourly capacity factor that
would be exceeded 90 percent of the time. Idaho Power calls this the 90th percentile capacity
factor. Idaho Power averaged this annual 901h percentile capacity factor over all the years with
data to arrive at the summertime peak capacity factor. Attachment 1 illustrates Idaho Power's
approach.
Staff made several changes to Idaho Power's approach as listed below:
1.Staff defined summer peak hours as the hours between 3 p.m. and 8 p.m. from June 23
through July 31. Staff defined winter peak hours as 8 a.m. and 9 a.m. from December 1
through February 28/29.
2.Staff used MV90 hourly generation data instead of P1 data.'
3.Staff applied a correction factor to the sample of projects that had hourly data available in
order to make this sample more representative of the total population of projects.
It should be noted that Staff agrees with Idaho Power that the q0 th percentile capacity factor is
appropriate to use. It is consistent with Idaho Power's IRP as Idaho Power uses 90th percentile
water conditions for peak hour capacity planning in their IRP. Using a lower percentile capacity
factor increases the probability that planned-on capacity will not be available when needed. Staff
believes that the 90th percentile capacity factor minimizes this risk. If, instead, a 50th percentile
capacity factor (the median) was used, then half of the time, planned-on capacity would not
actually be available during peak hours.
Idaho Power provided two different types of hourly generation data: MV90 data (measured in kilowatts) and P1
data (measured in megawatts).
STAFF COMMENTS 4 MARCH 25, 2013
Staff determination of peak hours
Staff used 20 years of data from Idaho Power's annual FERC Form 1 filings to identify
the day and hour of Idaho Power's summer and winter peak for those 20 years. The years
included are 1991-1997 and 1999-2011. Staff does not have a copy of the 1998 filing and the
2012 filing has not yet been made.
Attachment 2 graphically shows the time of day and date that the summer peak occurred
for this time period. As can be seen, the summer peak occurred between the hours of 3 p.m.
through 8 p.m. from June 23rd through July 29th1• Thus, Staff defined peak hours as those hours
between 3 p.m. and 8 p.m. between June 23 and July 31st• In comparison to Idaho Power's
definition of peak hours, Staff's definition of peak hours includes an additional 8 days (June 23'
through June 30th) and an additional hour (8 p.m.).
Attachment 3 graphically shows the time of day and date that the winter peak occurred for
this time period. The winter peak occurred anywhere from the first part of December to the last
part of February. While there was variation in the month of the winter peak, there was little
variation in the hour of the winter peak. The winter peak occurred at either 8 a.m. or 9 a.m. for all
years except one in which it occurred at 7 p.m. Staff views the 7 p.m. peak as an anomaly and,
therefore, defined winter peak hours as 8 a.m. and 9 a.m. during the months of December,
January, and February.
Data sources
Idaho Power provided two different types of hourly generation data in response to Staff's
Fourth Production Request, Request No. 22: MV90 data (measured in kilowatts) and P1 data
(measured in megawatts). Hourly generation data was available from 2006 through 2012. In
2012, Idaho Power had 59 hydro projects in the state of Idaho. Out of these 59 projects, nine
projects had MV90 data and four had PT data.
Staff found several inconsistencies in the PT data provided by Idaho Power. Furthermore,
as noted by Idaho Power in their response to Staff's Request No. 22, the PT data is inherently less
precise than the MV90 data because the P1 data is measured at the MW level while the MV90
STAFF COMMENTS 5 MARCH 25, 2013
data is measured at the kW level.2 Due to the inconsistencies and lack of precision in the PT data,
Staff decided to only use the MV90 data in its peak capacity calculations.
This approach differs from Idaho Power's approach. Idaho Power used PT data for four
canal drop hydro projects to calculate its peak capacity factor. In addition, Idaho Power
calculated its peak capacity factors using four years of data (2008 through 2011) while Staff used
six years of data (2007-2012).
Representativeness of sample
As noted above, Staff defined the population of seasonal hydro projects as those hydro
projects which had 90 percent of their generation occur during the months of April through
October. Using the monthly generation data provided by Idaho Power, Staff found that 26 hydro
projects met that definition. These 26 hydro projects comprise the population of seasonal hydro
projects. Of the nine hydro projects with hourly MV90 data, seven are seasonal hydro projects.
Those seven comprise the sample of seasonal hydro projects.
Staff had concerns that the sample of projects did not accurately represent the population
of projects. Staff examined this issue by comparing the July monthly capacity factor for projects
in the sample with the population of projects. Staff found that the July capacity factor was lower
for projects included in the sample (71 percent) than for the population as a whole (78 percent).
Therefore, a capacity factor calculated using only this sample would most likely be biased by
underestimating the actual peak capacity contribution of the population. Furthermore, as the
composition of projects included in the sample changed over time, this bias was likely worse for
the early years of data.
In order to correct this potential bias, Staff took two steps. First, Staff used linear
regression techniques to estimate the annual 901h percentile capacity factor for each project as if it
had been operational throughout the entire time period. In other words, Staff estimated capacity
factors for each year from 2007 through 2012 for each project in the sample. This step should
account for changing sample composition during the time period. Second, Staff compared the
average monthly July capacity factor of this sample to the average monthly July capacity factor of
the population for the 2007-2012 time period (both averages were weighted by project nameplate
capacity). Staff calculated the percentage difference between these two factors and called this the
2 Hourly P1 data is less precise than hourly MV90 data because Pt data is used for scheduling purposes where less
accuracy is required, whereas MV90 data is used for billing purposes where great accuracy is required.
STAFF COMMENTS 6 MARCH 25, 2013
sample correction factor. Staff then applied this sample correction factor to the average annual
90th percentile capacity factor calculated using the regression results. This resulted in a
summertime peak capacity factor for seasonal hydro projects of 79 percent. Staff did a similar
analysis for non-seasonal hydro projects and calculated a summertime peak capacity factor of 67
percent.
Bias could also exist in the calculation of the wintertime peak capacity factor. In order to
examine the issue of bias in the wintertime, Staff repeated the same analysis except using winter
months in its calculation and comparing the results to the average of the December, January, and
February monthly capacity factors. Staff used the wintertime peak capacity hours to define the
peak period as described above. Staff calculated a wintertime peak capacity factor of 0 percent
for seasonal hydro projects and 25 percent for non-seasonal hydro projects.
Capacity factors for "other" project types
As mentioned earlier, "other" project types include biomass (wood or agricultural waste),
biogas (municipal wastewater treatment, animal waste), landfill gas, and geothermal. These
project types operate more like baseload facilities, and have similar capacity factors.
Staff proposes that the Northwest Power and Conservation Council's Sixth Power Plan be
used as the basis for capacity factors for projects in the "other" category. Appendix I of the Sixth
Power Plan contains discussion of the generation characteristics and planning assumptions for a
wide variety of generation resources, including each of those likely to fall in the "other" project
category.
Attachment 4 is a summary of the Council's planning assumptions for Equivalent Forced
Outage Rates and for Equivalent Annual Availabilities for relevant project types. Equivalent
Forced Outage Rate (EFOR) is the hours of unit failure (unplanned outage hours and equivalent
unplanned derated hours) given as a percentage of the total hours of the availability of that unit
(unplanned outage, unplanned derated, and service hours). Equivalent Annual Availability
(EAA) represents the amount of time that a plant is able to produce electricity in a year, divided
by the amount of the time in the year. Occasions where only partial capacity is available are
deducted. In other words, EFOR represents the percentage of time forced outages occur, while
EAA represents the percentage of time the plant is available taking into consideration both forced
and unforced outages.
STAFF COMMENTS 7 MARCH 25, 2013
Staff proposes an annual capacity factor of 89 percent for "other" project types based on
the average EAA for the project types shown on Attachment 4. Staff believes it is more
appropriate to base the annual capacity factor on EAA because it represents the percentage of
time a project would be expected to operate during the year, accounting for both forced and
unforced outages.
Staff proposes that a peak capacity factor of 93 percent be used for "other" project types
based on the average EFOR for the project types shown on Attachment 4•3 Because the
generation from "other" project types generally does not vary substantially by season, Staff
proposes that the same capacity factor be used for both summer and winter. Staff believes it is
more appropriate to base the peak capacity factor on the EFOR because it only accounts for the
periods of time when forced outages occur. Because projects can control when unforced outages
occur, it is unlikely a project would choose to have an outage during the utility's peak load period.
Staff proposes a rounded number be used for simplicity and in recognition that the numbers upon
which it is based are not precise.
Avoided cost rates using Staffs proposed capacity factors
Using Staffs proposed capacity factors in the SAR model, Staff computed the resulting
avoided cost rates for seasonal hydro, non-seasonal hydro and other project types. The resulting
rates are shown in Attachment 5 for each utility. Compared to the rates currently in effect, the
rates for seasonal hydro are almost equivalent to the rates for "canal drop hydro." This is due to
the fact that the increase in rates due to changing the annual capacity factor almost completely
offset the decrease in rates due to changing the peak summer capacity factor.4 Specifically, the
proposed rates for a 20-year seasonal hydro project online in 2013 are roughly a half percent
lower than the current rates for a canal drop hydro project for all three utilities.
Compared to the current rates, the proposed rates for a 20-year non-seasonal hydro project
online in 2013 are approximately 23 percent higher for Idaho Power and 24 percent higher for
PacifiCorp. These large increases are driven by the increase in the summer peak capacity factor.
The current summer peak capacity factor is 25 percent while the proposed summer peak capacity
factor is 67 percent. The increase for Avista is 6 percent. This is due to the fact that Avista
To be more precise, Staffs proposal is based on (1 - EFOR), which represents the percentage of time the project
would be operational, rather than the time it would not be operational due to forced outages.
' The annual capacity factor decreased by 20% (40% to 32%) leading to an increase in rates. The peak summer
capacity factor decreased by 21% (100% to 79%) leading to a decrease in rates.
STAFF COMMENTS 8 MARCH 25, 2013
switches from needing capacity in the summer to needing capacity in the winter and, while the
summer peak capacity factor increased from the current factor, the winter peak capacity factor
decreased from the current factor (50 percent to 25 percent). Finally, the proposed rates for a 20-
year "other" project type online in 2013 is 2 to 4 percent lower than the current rates for all the
utilities.
RECOMMENDATIONS
First, Staff recommends that the terminology "seasonal hydro project" be used in the
future instead of "canal hydro" to refer to hydro projects whose generation is primarily produced
in the summer months. Staff recommends that a seasonal hydro project be defined as one that
generates at least 90 percent of its annual generation during the months of April through October.
Seasonal hydro projects should qualify for higher published avoided cost rates than non-seasonal
projects.
Second, Staff recommends that the following annual and peak capacity factors be used for
seasonal hydro, non-seasonal hydro, and "other" project types:
Annual Peak hour capacity factors
capacity
factor Summer peak Winter peak
Seasonal hydro projects 32% 79% 0%
Non-seasonal hydro projects 50% 67% 25%
"Other" projects 1 89% 1 93% 93%
Dated at Boise, Idaho, this 5iay of March 2013.
4QA
s me A. Sasser
Deputy Attorney General
Technical Staff: Cathleen McHugh
Rick Sterling
i:umisc:comments/gnrel I .3ksrps capacity factor comments.doc
STAFF COMMENTS 9 MARCH 25, 2013
Attachment 1: Illustration of Idaho Power's methodology in calculating summer peak capacity factors
Note: All of the numbers used are for illustration purposes only. They do not reflect any actual project
on Idaho Power's system.
1.Calculate total nameplate capacity of all the projects
Project Project Project Project Total nameplate
A B C D capacity
(a) (b) (c) (d) (e)=(a)+(b)+(c)+(d)
Nameplate capacity (kW) 100 500 50 150 800
2.Calculate the capacity factor across all projects for each hour
Project Project Project Project
A B C D Total output Capacity Factor
Year 1 (f) (g) (h) (i) (j)(f)+(g)+(h)+(i) (k)=(j)/(e)
July 1 - 3 p.m. 96 380 22 107 605 75.6%
July 1 -4 p.m. 93 366 27 110 596 74.5%
July 1 - 5 p.m. 93 440 27 107 667 83.4%
July 1 - 6 p.m. 93 371 20 101 585 73.1%
July 1 - 7 p.m. 95 382 21 95 593 74.1%
July 2 - 3 p.m. 98 383 20 103 604 75.5%
July 2-4p.m. 99 392 20 100 611 76.4%
July 2 - 5 p.m. 94 365 22 102 583 72.9%
July 2 - 6 p.m. 91 363 23 92 569 71.1%
July 2-7p.m. 92 360 24 116 592 74.0%
July 3 - 3 p.m. 95 375 24 98 592 74.0%
Year 2
July 1 - 3 p.m. 95 377 22 99 593 74.1%
July 1 -4 p.m. 92 382 28 110 612 76.5%
July 1 - 5 p.m. 96 384 22 110 612 76.5%
July 1 - 6 p.m. 98 428 23 103 652 81.5%
July l-7p.m. 94 426 24 114 658 82.3%
July 2 - 3 p.m. 98 438 23 103 662 82.8%
July 2-4p.m. 96 449 21 92 658 82.3%
July 2 - 5 p.m. 94 417 26 120 657 82.1%
July 2 - 6 p.m. 100 433 20 112 665 83.1%
July 2 -7 p.m. 94 359 22 95 570 71.3%
July 3 - 3 p.m. 93 400 24 98 615 76.9%
Attachment No. 1
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 1 of 2
3. Calculate the 90th percentile capacity factor.
a.Sort the capacity factors for each year in order of largest to smallest.
Year Year
July 1 - 5 P.M. 83.4% July 2 - 6 p.m. 83.1%
July 2 -4 p.m. 76.4% July 2 - 3 p.m. 82.8%
July 1 - 3 p.m. 75.6% July 1 - 7 p.m. 82.3%
July 2 - 3 p.m. 75.5% July 2 -4 p.m. 82.3%
July 1 -4 p.m. 74.5% July 2 - 5 p.m. 82.1%
July 1 - 7 p.m. 74.1% July 1 - 6 p.m. 81.5%
July 2 -7 p.m. 74.0% July 3 - 3 p.m. 76.9%
July 3 - 3 p.m. 74.0% July 1 -4 p.m. 76.5%
July 1 - 6 p.m. 73.1% July 1 - 5 P.M. 76.5%
July 2 - 5 p.m. 72.9% July 1 - 3 p.m. 74.1%
July 2 - 6 p.m. 71.1% - July 2 -7 p.m. 71.3%
b.For each year, identify the capacity factor that is exceeded 90% of the time.
Year Year
July 1 - 5 p.m. 83.4% July 2 - 6 p.m. 83.1%
July 2 -4 p.m. 76.4% July 2 - 3 p.m. 82.8%
July 1 - 3 p.m. 75.6% July 1 -7 p.m. 82.3%
July 2 - 3 p.m. 75.5% July 2 -4 p.m. 82.3%
July 1 -4 p.m. 74.5% July 2 - 5 p.m. 82.1%
July 1 -7 p.m. 74.1% July 1 - 6 p.m. 81.5%
July 2 - 7 p.m. 74.0% July 3 - 3 p.m. 76.9%
July 3 - 3 p.m. 74.0% July 1 -4 p.m. 76.5%
July 1 - 6 p.m. 73J.% July 1 - 5 p.m.
July 2-5p.m.Z2.99 ) Julyl-3p.m. (74.1..
July 2 - 6 p.m. 71.1% - July 2 - 7 p.m. 71.3%
c.Average the 90th percentile capacity factor across the two years.
90th percentile peak capacity factor = (72.9+74.1)/2 = 73.5%
Attachment No. 1
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 2of2
Attachment 2: Timing of Idaho Power's Summer Peak
Attachment No. 2
Case No. GNR-E-1 1-03
Staff Comments
3/25/13
Attachment 3: Timing of Idaho Power's Winter Peak
Timing of Idaho Power's WinterPeak 19912011
(Excluding 199$)
Attachment No. 3
Case No. GNR-E-1 1-03
Staff Comments
3/25/13
Attachment 4: Planning assumptions of Northwest Power and Conservation Council's Sixth Power Plan
Northwest Power and Conservation Council
Sixth Power Plan
Appendix I
Resource Type
Landfill Gas to Energy
Animal Manure Energy Recovery
Waste Water Treatment Energy Recovery
Woody Residue Power Plants
Geothermal
Average
Equivalent Forced
Outage Rate
8.0%
8.0%
4.7%
7.0%
6.4%
6.8%
Equivalent
Annual
Availability
88%
88%
93%
86%
90%
89%
Equivalent Forced Outage Rate (EFOR) is the hours of unit failure (unplanned outage hours and
equivalent unplanned derated hours) given as a percentage of the total hours of the availability of that
unit (unplanned outage, unplanned derated, and service hours).
Equivalent annual availability represents the amount of time that a plant is able to produce electricity
in a year, divided by the amount of the time in the year. Occasions where only partial capacity is
available are deducted.
Attachment No. 4
Case No. GNR-E-1 1-03
Staff Comments
3/25/13
Rates based on Staff's proposed capacity factors
AVISTA
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH _____________________________ CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 43.60 2015 33.34
5 31.60 32.53 33.80 35.49 41.44 48.26 2016 34.38
6 32.12 33.10 34.43 39.80 45.45 51.90 2017 35.49
7 32.64 33.70 38.08 43.26 48.74 54.83 2018 36.81
8 33.18 36.81 41.13 46.22 51.49 57.24 2019 38.48
9 35.87 39.51 43.81 48.75 53.79 59.25 2020 67.52
10 38.24 41.92 46.15 50.91 55.75 61.02 2021 71.24
11 40.41 44.05 48.17 52.78 57.49 62.66 2022 75.33
12 42.35 45.93 49.95 54.45 59.11 64.16 2023 78.56
13 44.08 47.59 51.55 56.01 60.58 65.51 2024 80.88
14 45.62 49.10 53.04 57.44 61.92 66.78 2025 82.93
15 47.04 50.52 54.41 58.74 63.17 67.98 2026 85.62
16 48.36 51.82 55.67 59.96 64.35 69.11 2027 89.17
17 49.59 53.02 56.85 61.11 65.47 70.18 2028 91.95
18 50.72 54.14 57.96 62.19 66.53 71.24 2029 94.38
19 51.79 55.20 59.01 63.22 67.57 72.29 2030 97.45
20 52.79 56.21 60.00 64.22 68.59 73.27 2031 100.68
2032 103.98
2033 107.23
2034 112.11
2035 117.22
2036 119.85
2037 124.06
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case" at http:/Iwww.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 1 of 9
Rates based on Staffs proposed capacity factors
AVISTA
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 48.79 2015 33.34
5 31.60 32.53 33.80 35.49 45.42 56.61 2016 34.38
6 32.12 33.10 34.43 42.97 52.11 62.39 2017 35.49
7 32.64 33.70 40.68 48.72 57.34 66.89 2018 36.81
8 33.18 38.99 45.70 53.41 61.57 70.48 2019 38.48
9 37.71 43.38 49.92 57.31 65.03 73.44 2020 91.11
10 41.58 47.17 53.50 60.58 67.94 75.99 2021 95.18
11 44.96 50.43 56.56 63.36 70.48 78.28 2022 99.61
12 47.93 53.26 59.20 65.81 72.76 80.33 2023 103.20
13 50.53 55.73 61.54 68.03 74.81 82.17 2024 105.88
14 52.82 57.94 63.67 70.03 76.65 83.86 2025 108.29
15 54.89 59.96 65.60 71.84 78.35 85.43 2026 111.35
16 56.79 61.80 67.35 73.50 79.92 86.89 2027 115.28
17 58.53 63.48 68.97 75.05 81.39 88.27 2028 118.44
18 60.12 65.03 70.47 76.49 82.77 89.60 2029 121.26
19 61.59 66.47 71.88 77.84 84.10 90.90 2030 124.73
20 62.96 67.82 73.19 79.14 85.38 92.11 2031 128.35
2032 132.06
2033 135.72
2034 141.02
2035 146.55
2036 149.61
2037 154.26
Note: Staff proposes that seasonal hydro projects be defined as those hydra projects that, over the last ten years, generated at least
90 percent of its average annual generation during the months of April through October.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case at http:/Iwww.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No, GNR-E- 11-03
Staff Comments
3/25/13 Page 2 of 9
Rates based on Staff's proposed capacity factors
AVISTA
AVOIDED COST RATES FOR OTHER PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH ______________________________________ CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 30.25 33.34 34.38 35.49 2012 30.53
2 30.45 30.30 31.73 33.84 34.91 36.12 2013 30.35
3 30.39 31.24 32.54 34.34 35.49 36.84 2014 30.25
4 31.04 31.93 33.19 34.89 36.15 42.24 2015 33.34
5 31.60 32.53 33.80 35.49 40.40 46.07 2016 34.38
6 32.12 33.10 34.43 38.97 43.70 49.15 2017 35.49
7 32.64 33.70 37.40 41.84 46.49 51.68 2018 36.81
8 33.18 36.24 39.94 44.34 48.85 53.77 2019 38.48
9 35.38 38.49 42.21 46.51 50.85 55.54 2020 61.36
10 37.37 40.54 44.22 48.38 52.56 57.11 2021 64.99
11 39.22 42.39 45.98 50.01 54.09 58.58 2022 68.98
12 40.90 44.02 47.53 51.49 55.54 59.93 2023 72.12
13 42.40 45.47 48.94 52.87 56.86 61.16 2024 74.35
14 43.74 46.79 50.26 54.15 58.07 62.32 2025 76.30
15 44.98 48.05 51.49 55.32 59.21 63.41 2026 78.89
16 46.16 49.21 52.62 56.42 60.29 64.46 2027 82.34
17 47.25 50.29 53.68 57.46 61.31 65.46 2028 85.02
18 48.27 51.30 54.69 58.46 62.28 66.45 2029 87.35
19 49.23 52.26 55.64 59.40 63.25 67.43 2030 90.32
20 50.14 53.17 56.55 60.32 64.20 68.34 2031 93.45
2032 96.65
2033 99.78
2034 104.56
- 2035 109.55
2036 112.07
2037 116.17
Note: 'Other projects' refers to projects other than wind, solar, hydro, and canal drop hydro projects. These 'Other projects' may
include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case' at http://www.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 3of9
Rates based on Staff's proposed capacity factors
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 34.03 59.05 60.46 61.94 2012 30.53
2 30.44 32.12 46.05 59.72 61.17 62.76 2013 30.35
3 31.55 40.40 50.48 60.41 61.93 63.67 2014 34.03
4 37.63 44.84 53.02 61.13 62.77 64.44 2015 59.05
5 41.51 47.75 54.82 61.91 63.52 65.54 2016 60.46
6 44.28 49.90 56.30 62.62 64.51 66.81 2017 61.94
7 46.44 51.67 57.51 63.54 65.68 68.08 2018 63.65
8 48.24 53.11 58.76 64.60 66.84 69.24 2019 65.72
9 49.75 54.52 60.05 65.68 67.93 70.30 2020 67.16
10 51.19 55.92 61.29 66.70 68.93 71.32 2021 70.87
11 52.61 57.25 62.43 67.64 69.90 72.36 2022 74.95
12 53.94 58.46 63.48 68.56 70.88 73.35 2023 78.18
13 55.16 59.57 64.48 69.48 71.83 74.30 2024 80.49
14 56.28 60.61 65.47 70.38 72.73 75.23 2025 82.53
15 57.33 61.63 66.41 71.24 73.62 76.14 2026 85.22
16 58.35 62.60 67.31 72.08 74.48 77.03 2027 88.76
17 59.32 63.52 68.18 72.90 75.33 77.90 2028 91.53
18 60.22 64.40 69.02 73.70 76.15 78.78 2029 93.96
19 61.10 65.25 69.83 74.49 76.99 79.68 2030 97.03
20 61.93 66.07 70.63 75.28 77.85 80.53 2031 100.25
2032 103.55
2033 106.79
2034 111.67
2035 116.77
2036 119.39
2037 123.60
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case" at http://www.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 4of9
Rates based on Staff's proposed capacity factors
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
March 25,2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
--I
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 36.16 80.70 82.42 84.23 2012 30.53
2 30.44 33.14 57.55 81.53 83.29 85.21 2013 30.35
3 32.20 47.77 65.20 82.36 84.21 86.27 2014 36.16
4 42.94 55.44 69.41 83.22 85.19 87.19 2015 80.70
5 49.64 60.33 72.28 84.15 86.08 88.43 2016 82.42
6 54.34 63.85 74.50 85.00 87.22 89.85 2017 84.23
7 57.90 66.61 76.28 86.06 88.53 91.26 2018 86.26
8 60.77 68.84 77.98 87.26 89.83 92.56 2019 88.66
9 63.13 70.88 79.64 88.47 91.05 93.75 2020 90.43
10 65.27 72.80 81.20 89.61 92.18 94.91 2021 94.49
11 67.27 74.56 82.63 90.68 93.28 96.08 2022 98.91
12 69.11 76.16 83.93 91.72 94.39 97.20 2023 102.49
13 70.77 77.60 85.16 92.77 95.46 98.27 2024 105.16 14 72.27 78.95 86.35 93.78 96.48 99.32 2025 107.56
15 73.66 80.24 87.49 94.75 97.47 100.34 2026 110.62
16 74.99 81.46 88.56 95.70 98.45 101.35 2027 114.53
17 76.23 82.59 89.60 96.63 99.41 102.33 2028 117.68
18 77.39 83.68 90.59 97.54 100.34 103.32 2029 120.49
19 78.50 84.72 91.55 98.42 101.28 104.32 2030 123.95
20 79.55 85.72 92.48 99.32 102.24 105.28 2031 127.56
2032 131.26
2033 134.91
2034 140.20
2035 145.71
2036 148.76
2037 153.40
Note: Staff proposes that seasonal hydro projects be defined as those hydro projects that, over the last ten years, generated at least
90 percent of its average annual generation during the months of April through October.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case' at http://www.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 5of9
Rates based on Staffs proposed capacity factors
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
___
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 32.38 53.39 54.72 56.12 2012 30.53
2 30.44 31.33 42.47 54.03 55.39 56.90 2013 30.35
3 31.04 38.11 46.23 54.67 56.11 57.77 2014 32.38
4 35.99 41.78 48.42 55.35 56.91 58.50 2015 53.39
5 39.17 44.22 50.00 56.09 57.62 59.55 2016 54.72
6 41.47 46.05 51.32 56.77 58.58 60.79 2017 56.12
7 43.28 47.58 52.41 57.65 59.70 62.02 2018 57.74
8 44.82 48.84 53.56 58.68 60.84 63.14 2019 59.72
9 46.11 50.10 54.76 59.73 61.89 64.16 2020 61.07
10 47.38 51.37 55.93 60.71 62.85 65.15 2021 64.70
11 48.65 52.59 57.01 61.62 63.79 66.15 2022 68.68
12 49.86 53.71 58.00 62.50 64.74 67.12 2023 71.82
13 50.97 54.73 58.94 63.40 65.66 68.04 2024 74.05
14 51.99 55.70 59.88 64.27 66.53 68.93 2025 75.99
15 52.95 56.66 60.78 65.09 67.38 69.81 2026 78.58
16 53.90 57.57 61.64 65.90 68.22 70.67 2027 82.03
17 54.80 58.43 62.46 66.69 69.03 71.51 2028 84.70
18 55.64 59.26 63.27 67.47 69.83 72.37 2029 87.02
19 56.46 60.06 64.05 68.23 70.65 73.24 2030 89.99
20 57.24 60.83 64.81 69.00 71.47 74.06 2031 93.11
2032 96.31
2033 99.44
2034 104.21
2035 109.20
2036 111.71
2037 115.81
Note: "Other projects" refers to projects other than wind, solar, hydro, and canal drop hydro projects. These 'Other projects' may
include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case' at http:/Iwww.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 6of9
Rates based on Staff's proposed capacity factors
PACIFICORP
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
March 25, 2013
$/MWh
- New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH ____ CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 55.03 58.49 59.89 61.37 2012 30.53
2 30.44 42.22 56.70 59.16 60.60 62.19 2013 30.35
3 38.02 47.23 57.68 59.84 61.36 63.09 2014 55.03
4 42.56 50.04 58.50 60.56 6220 63.86 2015 58.49
5 45.52 51.97 59.28 61.34 62.94 64.95 2016 59.89
6 47.68 53.49 60.08 62.05 63.94 66.23 2017 61.37
7 49.41 54.79 60.80 62.97 65.11 67.50 2018 63.07
8 50.89 55.90 61.69 64.04 66.28 68.67 2019 65.13
9 52.14 57.05 62.71 65.12 67.37 69.73 2020 66.56
10 53.39 58.25 63.73 66.14 68.37 70.75 2021 70.26
11 54.65 59.41 64.70 67.09 69.34 71.80 2022 74.33
12 55.86 60.49 65.61 68.01 70.33 72.80 2023 77.56
13 56.98 61.48 66.49 68.95 71.29 73.76 2024 79.86
14 58.01 62.44 67.39 69.85 72.20 74.69 2025 81.89
15 58.99 63.38 68.25 70.72 73.09 75.61 2026 84.57
16 59.95 64.29 69.08 71.56 73.96 76.51 2027 88.10
17 60.87 65.15 69.89 72.40 74.82 77.38 2028 90.87
18 61.74 65.99 70.68 73.21 75.66 78.28 2029 93.28
19 62.57 66.80 71.46 74.00 76.51 79.19 2030 96.34
20 63.38 67.59 72.22 74.81 77.38 80.06 2031 99.55
2032 102.84
2033 106.07
2034 110.94
2035 116.03
2036 118.64
2037 122.84
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)'s Annual Energy
Outlook 2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case' at http:/Iwww.eia.gov/oiaf/aeo/tablebnDwser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 7of9
Rates based on Staff's proposed capacity factors
PACIFICORP
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
--
LENGTH ____ CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 75.91 79.67 81.38 83.18 2012 30.53
2 30.44 52.26 77.72 80.49 82.24 84.15 2013 30.35
3 44.45 60.70 78.85 81.32 83.15 85.20 2014 75.91
4 52.27 65.29 79.81 82.18 84.14 86.12 2015 79.67
5 57.24 68.34 80.73 83.10 85.02 87.36 2016 81.38
6 60.77 70.64 81.66 83.95 86.16 88.78 2017 83.18
7 63.51 72.54 82.52 85.01 87.46 90.19 2018 85.19
8 65.78 74.12 83.54 86.21 88.77 91.49 2019 87.58
9 67.66 75.66 84.68 87.42 89.99 92.68 2020 89.33
10 69.44 77.19 85.83 88.57 91.12 93.84 2021 93.37
11 71.14 78.64 86.93 89.64 92.22 95.01 2022 97.78
12 72.74 79.98 87.95 90.68 93.34 96.14 2023 101.34
13 74.19 81.21 88.95 91.74 94.41 97.22 2024 104.00
14 75.53 82.38 89.96 92.76 95.44 98.27 2025 106.38
15 76.78 83.52 90.94 93.74 96.44 99.30 2026 109.42
16 77.98 84.61 91.87 94.69 97.43 100.32 2027 113.32
17 79.12 85.64 92.79 95.63 98.40 101.30 2028 116.45
18 80.20 86.63 93.68 96.55 99.34 102.31 2029 119.24
19 81.22 87.59 94.56 97.44 100.29 103.32 2030 122.68
20 82.21 88.51 95.42 98.35 101.26 104.29 2031 126.28
2032 129.96
2033 133.59
2034 138.86
2035 144.36
2036 147.39
2037 152.01
Note: Staff proposes that seasonal hydro projects be defined as those hydro projects that, over the last ten years, generated at least
90 percent of its average annual generation during the months of April through October.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (EIA)s Annual Energy
Outlook 2012 released June 25, 2012. See 'Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case" at http:/Iwww.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-E-1 1-03
Staff Comments
3/25/13 Page 8of9
Rates based on Staff's proposed capacity factors
PACIFICORP
AVOIDED COST RATES FOR OTHER PROJECTS
March 25, 2013
$/MWh
New Contract
Eligibility for these rates is limited to wind and solar projects 100 kW or smaller, and to non-wind and non-
solar projects smaller than 10 aMW.
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS) 2012 2013 2014 2015 2016 2017 YEAR RATES
1 30.53 30.35 49.58 52.95 54.27 55.67 2012 30.53
2 30.44 39.60 51.20 53.59 54.95 56.45 2013 30.35
3 36.34 43.71 52.15 54.23 55.67 57.32 2014 49.58
4 40.03 46.06 52.93 54.91 56.47 58.05 2015 52.95
5 42.46 47.70 53.67 55.65 57.17 59.10 2016 54.27
6 44.26 49.00 54.43 56.33 58.13 60.34 2017 55.67
7 45.72 50.15 55.13 57.21 59.26 61.57 2018 57.29
8 46.99 51.14 55.98 58.25 60.40 62.70 2019 59.26
9 48.08 52.19 56.96 59.30 61.45 63.73 2020 60.60
10 49.20 53.29 57.96 60.28 62.42 64.72 2021 64.22
11 50.34 54.38 58.89 61.20 63.36 65.73 2022 68.20
12 51.45 55.39 59.77 62.09 64.32 66.70 2023 71.34
13 52.48 56.33 60.62 62.99 65.25 67.62 2024 73.55
14 53.43 57.23 61.49 63.87 66.12 68.53 2025 75.49
15 54.34 58.12 62.32 64.70 66.99 69.41 2026 78.07
16 55.24 58.98 63.12 65.52 67.83 70.28 2027 81.51
17 56.10 59.80 63.90 66.32 68.66 71.13 2028 84.18
18 56.91 60.59 64.67 67.11 69.47 72.00 2029 86.50
19 57.70 61.37 65.42 67.88. 70.29 72.89 2030 89.46
20 58.46 62.12 66.15 68.66 71.13 73.72 2031 92.57
2032 95.76
2033 98.88
2034 103.64
2035 108.62
2036 111.13
2037 115.22
Note: "Other projects" refers to projects other than wind, solar, hydro, and canal drop hydro projects. These "Other projects" may
include (but are not limited to): cogeneration, biomass, biogas, landfill gas, or geothermal projects.
Note: The rates shown in this table have been computed using the U.S. Energy Information Administration (ElA)'s Annual Energy
Outlook 2012 released June 25, 2012. See "Annual Energy Outlook 2012, All Tables, Energy Prices by Sector and Source, Mountain,
Reference case' at http:/Iwww.eia.gov/oiaf/aeo/tablebrowser/.
Attachment No. 5
Case No. GNR-.E-1 1-03
Staff Comments
3/25/13 Page 9of9
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 25TH DAY OF MARCH 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. GNR-E- 11-03, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
DONOVAN E WALKER
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
E-mail: [e-mail]
MICHAEL G ANDREA
AVISTA CORPORATION
1411 E MISSION AVE
SPOKANE WA 99202
E-mail: [e-mail]
ROBERT D KAHN
NW & INTERMOUNTAIN POWER
PRODUCERS COALITION
1117 MINOR AVE STE 300
SEATTLE WA 98101
E-mail: [e-mail]
ROBERT A PAUL
GRAND VIEW SOLAR II
15690 VISTA CIRCLE
DESERT HOT SPRINGS CA 92241
E-mail: robertapaul08gmail.com
ELECTRONIC SERVICE ONLY:
DR. DON READING
E-mail: dread [e-mail]
MARV LEWALLEN
CLEAR WATER PAPER CORP
601 W RIVERSIDE AVE STE 1100
SPOKANE WA 99201
E-mail: [e-mail]
DANIEL E SOLANDER
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
E-mail: [e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
E-mail: [e-mail]
gregrichardsonandolearv.com
DON STURTEVANT
ENERGY DIRECTOR
J R SIMPLOT COMPANY
P0 BOX 27
BOISE ID 83707-0027
E-mail: [e-mail]
JAMES CARKULIS
EXERGY DEVELOPMENT GROUP OF
IDAHO LLC
802 W BANNOCK ST STE 1200
BOISE ID 83702
E-mail: [e-mail]
BILL BROWN CHAIR
BOARD OF COMMISSIONERS
OF ADAMS COUNTY ID
P0 BOX 48
COUNCIL ID 83612
E-mail: [e-mail]
TED S SORENSON P B
BIRCH POWER COMPANY
5203 SOUTH 11TH EAST
IDAHO FALLS ID 83404
E-mail: [e-mail]
R GREG FERNEY BILL PISKE MGR
CERTIFICATE OF SERVICE
MIMURA LAW OFFICES PLLC INTERCONNECT SOLAR DEVELOPMENT LLC
2176 E FRANKLIN RD STE 120 1303 E CARTER
MERIDIAN ID 83642 BOISE ID 83706
E-mail: [e-mail] E-mail: [e-mail]
RONALD L WILLIAMS WADE THOMAS
WILLIAMS BRADBURY DYNAMIS ENERGY LLC
1015 W HAYS ST 776 E RIVERSIDE DR STE 15
BOISE ID 83702 EAGLE ID 83616
E-mail: [e-mail] E-mail: [e-mail]
JOHN R LOWE LIZ WOODRUFF
RENEWABLE ENERGY COALITION KEN MILLER
12050 SW TREMONT ST SNAKE RIVER ALLIANCE
PORTLAND OR 97225 BOX 1731
E-mail: jravenesanmarcosCiyahoo.com BOISE ID 83701
E-mail: [e-mail]
kmiller(isnakeriveralliance.org
C THOMAS ARKOOSH ELECTRONIC SERVICE ONLY:
ARKOOSH LAW OFFICES
802 W BANNOCK, 9TH FL BRIAN OLMSTEAD
P0 BOX 2900 GENERAL MANAGER
BOISE ID 83701 E-mail: olmstead(tfcanal.eom
E-mail: [e-mail]
[e-mail] TED DIEHL
GENERAL MANAGER
E-mail: [e-mail]
DON SCHOENBECK
RCS
E-mail: [e-mail]
M J HUMPHRIES MEGAN WALSETH DECKER
BLUE RIBBON ENERGY LLC SR STAFF COUNSEL
3470 RICH LANE RENEWABLE NW PROJECT
AMMON ID 83406 421 SW 6TH AVE STE 1125
E-mail: [e-mail] PORTLAND OR 97204
E-mail: inegan(mp.org
DEAN J MILLER
CHAS McDEVITT THOMAS H NELSON
MeDEVITI' & MILLER LLP RENEWABLE ENERGY
P0 BOX 2564 COALITION
BOISE ID 83701 P0 BOX 1211
E-mail: [e-mail] WELCHES OR 97067
[e-mail]
CERTIFICATE OF SERVICE
GLENN IKEMOTO
MARGARET RUEGER
IDAHO WINDFARMS LLC
672 BLAIR AVE
PIEDMONT CA 94611
E-mail: g1enni(envisionwind.com
margaret(envisionwind.com
TAUTNA CHRISTENSEN
ENERGY INTEGRITY PROJECT
769N I 100
SHELLEY ID 83274
E-mail: [e-mail]
BENJAMIN J OTTO
IDAHO CONSERVATION LEAGUE
P0 BOX 844
BOISE ID 83702
E-mail: [e-mail]
DEBORAH E NELSON
KELSEY J NUNEZ
GIVENS PURSLEY
601 W BANNOCK ST (83702)
P0 BOX 2720
BOISE ID 83701-2720
E-mail: [e-mail]
[e-mail]
1L
SECRETARY
CERTIFICATE OF SERVICE