20120504McHugh Direct.pdf

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA OF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COAT RATES.
CASE NO. GNR-E-11-03
DIRECT TESTIMONY OF DR. CATHLEEN M. MCHUGH
IDAHO PUBLIC UTILITIES COMMISSION
MAY 4 v 2012
1 Q. Please state your name and business address for
2 the record.
3 A. My name is Cathleen McHugh. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q. By whom are you employed and in what capacity?
6 A. I am employed by the Idaho Public Utilities
7 Commission as a Utilities Analyst.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science degree in
11 Economics and Applied Math from the University of Idaho in
12 1995. I received a Ph.D. in Economics from Duke
13 University in 2005 with primary fields in Public Economics
14 and the Economics of Education and with secondary fields
15 in Econometrics (statistics applied to economics), Applied
16 Microeconomics, and the History of Economic Thought.
17 While at Duke University, I taught the
18 undergraduate introductory course on econometrics several
19 times and served as a teaching assistant for the graduate
20 introductory course on econometrics.
21 Between July 2005 and September 2009, I was
22 employed by the Center for Naval Analyses (CNA) as an
23 analyst. My duties there included devising and estimating
24 econometric models for use in military manpower analysis.
25 In this capacity, I co-wrote 17 different publications and
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 1
5/4/12 STAFF
and presented my work at a number of conferences. In
2 October 2009, I transitioned to a position as a CNA Field
3 Representative where I provided analytic support directly
4 to a United States Marine Corps Lieutenant General and his
5 Command. I remained at this position until joining the
6 IPUC in August 2011.
7 My current duties at the Commission include data
8 analysis, modeling, resource planning, rate design, cost
9 of service, and other duties as assigned for electric,
10 gas, and water utilities.
11 Q. What is the purpose of your testimony in this
12 proceeding?
13 A. The purpose of my testimony is to recommend
14 updates to the current Surrogate Avoided Resource (SAR)
15 model.
16 Q. Will you summarize your recommended changes to
17 the model?
18 A. I recommend:
19 a) Using a forecast of natural gas prices from
20 the Energy Information Administration's ("EIA")
21 Annual Energy Outlook report in place of a
22 forecast from the Northwest Power and
23 Conservation Council (NWPCC). I recommend this
24 change because the EIA report is updated more
25 frequently than the NWPCC report. I further
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 2
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i propose that the EIA forecast be updated in the
2 SAR model no later than July l of each year.
3 b) Taking the energy and/or capacity needs of a
4 utility into consideration in calculating
5 avoided costs. An earlier version of the SAR
6 model did this by using the "first deficit year"
7 concept.
8 c) Using resource-specific values for
9 determining capacity payments.
10 d) Allowing for avoided costs to reflect the
11 costs of transmission and loss in periods when
12 the utility is in surplus.
13 Natural gas price forecast
14 Q. What is the source for the current SAR model's
15 forecast of natural gas prices?
16 A. Pursuant to Order No. 30480, the current SAR
17 model uses the latest available Northwest Power and
18 Conservation Council's (NWPCC) 20-year forecast of natural
19 gas prices. For years beyond those included in this
20 forecast, the model predicts natural gas prices using
21 exponential growth based on the last ten years of the
22 NWPCC forecast.
23 Q. What are the main differences between this
24 forecast and the forecast of natural gas prices from the
25 EIA's Annual Energy Outlook?
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 3
5/4/12 STAFF
i A. With regards to the SAR model, there are two
2 differences between the forecasts of note - the frequency
3 of updates and the geographic focus of the updates.
4 Q. How frequently is the NWPCC forecast updated?
5 What is its geographic focus?
6 A. The NWPCC is directed to review its regional
7 power plan forecast at least every five years per the
8 Pacific Northwest Electric Power Planning and Conservation
9 Act. The 15t Power Plan was adopted in 1983. subsequent
10 plans were adopted in 1986, 1991, 1998, 2005, and, most
11 recently, 2010. Included in the development of this plan
12 is a forecast of natural gas prices.
13 The NWPCC forecast of fuel prices can be updated
14 independently of the regional plan; in fact, it was
15 revised in 2011 to reflect "a fundamental shift in
16 expectations about future natural gas supplies." However,
17 there is no set timeline for these types of updates.
18 The NWPCC forecast is a regional forecast for
19 the Pacific Northwest (Washington, Oregon, Idaho, and
20 Montana). The forecast includes prices for natural gas
21 delivered to either the west side of the region (west-side
22 delivered) or the east side of the region (east-side
23 delivered). The current SAR model uses the estimate for
24 east-side delivered.
25 Q. How frequently is the EIA forecast updated?
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 4
5/4/12 STAFF
What is its geographic focus?
2 A. The EIA forecast is updated each spring. It
3 provides forecasts of natural gas prices for all Census
4 divisions of the United States. Idaho falls in the
5 Mountain division (Montana, Idaho, Wyoming, Nevada, Utah,
6 Colorado, Arizona, and New Mexico). The specific forecast
7 I recommend using is found in the supplemental tables for
8 regional detail, Table 18: Energy Prices by Sector and
9 Source for the Mountain division/Natural Gas price for
10 Electric Power. This is the delivered fuel price. It
11 should be noted that Avista recommended using the same
12 forecast but for the Pacific division (Washington, Oregon,
13 California, Alaska, and Hawaii). The forecast I propose
14 be used is included as Exhibit No. 301.
15 I have included both the forecasted real price
16 and the forecasted nominal price. In the SAP. model, I use
17 the forecasted nominal price, which eliminates the need to
18 adjust the forecast by any inflation rate.
19 Q. Can you compare the two different forecasts?
20 A. In Exhibit No. 302, I graph four different
21 forecasts of natural gas prices. The first (denoted with
22 circles) shows the most current NWPPC East-Side Delivered
23 forecast. This forecast only extends to 2030 so I also
24 include the estimates that would be used to extend it to
25 2035. These estimates are titled IPUC Estimates based on
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 5
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NWPPC data (the line with diamonds). The next forecast is
2 the 2011 EIA forecast for the Mountain region (the line
3 with triangles). Both this forecast and the NWPCC
4 forecast were released around the same time - the EIA
5 forecast was released in the spring of 2011 while the
6 NWPCC forecast was released in summer of 2011. These two
7 forecasts are very similar especially if one excludes the
8 first two years. During the entire period, the forecasts
9 never vary by more than $0.35 and, after the first two
10 years, they never vary by more than $0.15. The IPUC
11 estimates are considerably higher than the EIA forecast -
12 they average almost $0.60 higher.
13 The final forecast shown is the EIA forecast
14 released in the spring of 2012 (the line with squares).
15 Comparing this forecast to the earlier two forecasts
16 illustrates how much can change in a single year. This
17 forecast is always lower than the NWPCC forecast - at one
18 point, it is $0.61 lower. On average, it is $0.32 lower
19 than the NWPCC forecast. In contrast, the 2011 EIA
20 forecast was, on average, $0.07 higher than the NWPCC
21 forecast.
22 In periods of price fluctuations, relying on a
23 forecast that is even a year old can dramatically change
24 the avoided cost computation. In periods of downward
25 trending prices, the computed cost would be too high if
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 6
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1 one relied on a dated forecast. Conversely, in periods of
2 upward trending prices, the computed avoided cost would be
3 too low. Therefore, Staff supports use of the EIA
4 forecast as it will reflect the most current understanding
5 of future natural gas prices.
6 Considering Need in Calculating Avoided Costs
7 Q. How did prior versions of the SAR model take
8 into consideration a utility's need for energy in setting
9 the avoided cost rates?
10 A. A prior version of the SAR model used a "first
11 deficit year" concept. This prior version of the model
12 differed from the current SAR model in that the avoided
13 costs were set equal to "surplus energy rates" for years
14 in which the utility had surplus energy (years prior to
15 the first deficit year). The surplus energy rate was
16 based on wholesale energy rates and was set by Commission
17 order. Avoided costs for years in which the utility was
18 not in surplus were calculated as they are in the present
19 SAR model.
20 Q. Why was the "first deficit year" concept
21 abandoned?
22 A. At the time this was abandoned, Staff expressed
23 concerns that determining the first deficit year was
24 problematic even though the underlying'rationale for it
25 was sound. All together, Staff identified nine areas of
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 7
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i concern regarding the determination of the first deficit
2 year. These concerns can be grouped in the following
3 categories:
4 a) There exists too much discretion on the part
5 of utilities to influence the results (Reasons
6 1, 3, 4) . As noted by Avista witness Kalich,
7 this is less true today than in 2002. All the
8 electric utilities file biennual IRPs which are
9 developed with input from the public,
10 regulators, and other interested parties. Thus,
ii irregular frequency (Reason 1), the
12 reasonableness of planning assumptions (Reason
13 3), and the possibility of inaccurate load
14 forecasts (Reason 4) can all be addressed in the
15 IRP process.
16 b) The definition of the first deficit year is
17 not clear (Reasons 2 and 5) . At the time, it
18 was not clear whether or not the first deficit
19 year should be based on energy or capacity needs
20 (Reason 2) or whether it should incorporate firm
21 market purchases (Reason 5). The proposed
22 updates take into consideration both energy and
23 capacity needs so Reason 2 is no longer valid.
24 Because it is based on the IRP, the proposed
25 update is consistent with generally accepted IRP
CASE NO. GNR-E-11-03 MCHUGH, C. (Di) 8
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1 methodology in how it treats firm market
2 purchases.
3 c) Using the concept of the first deficit year
4 really does not matter in terms of avoided rate
5 calculation (Reasons 6 and 8), and,
6 d) Market prices can be extremely volatile
7 (Reason 9). Both of these reasons had more to
8 do with the implementation of the concept rather
9 than the concept itself.
10 Q. Are you instituting the "first deficit year"
11 concept exactly as it had been instituted prior to 2002?
12 A. No. The model I recommend identifies years in
13 which a utility is deficient in energy, in capacity, or
14 both. This is based on information from each utility's
15 most recent IRP. If a utility is deficient in energy,
16 then the QF would receive an energy payment. If a utility
17 is not deficient in energy, then the QF would receive an
18 energy payment minus costs for transmission and losses.
19 The previous SAR model did not adjust for transmission and
20 losses.
21 In the recommended model, capacity payments are
22 specific to the resource used by the QF. If a utility is
23 deficient in capacity, then the recommended model examines
24 whether the utility is deficient in summer only, in winter
25 only, or in both seasons. If the utility is deficient in
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 9
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a. only one season, then the model bases a resource-specific
2 capacity payment on the ability of that resource to
3 contribute during the deficient season's peak. However,
4 if a utility is deficient in both seasons, then the model
5 bases the resource-specific capacity payment on the
6 ability of that resource to contribute during both
7 seasons' peaks. This is the same methodology suggested by
8 Avista.
9 To clarify matters, consider canal drop QFs.
10 Canal drops can contribute 100 percent of their capacity
11 during the summer peak and 0 percent of their capacity
12 during the winter peak. If a utility is only capacity
13 deficient during the summer, then a canal drop QF receives
14 the full capacity payment. However, if a utility is
15 capacity deficient in only the winter or in both the
16 summer and winter, then the canal drop receives no
17 capacity payment. Allowing capacity payments to differ by
18 resource should encourage development of QFs with
19 characteristics of value to the utilities (such as Us
20 that provide generation during peak hours).
21 Staff concurs with Avista witness Kalich on the
22 basis for capacity payments. In his direct testimony,
23 page 21, lines 5 through 9, Mr. Kalich states:
24 It is not fair to pay one resource with a
low capacity factor and an equivalently
25 high on-peak contribution the same per-MWh
payment as second base load plant
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 10
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1 operating with a relatively high capacity
factor all year round. Using the method,
2

the low capacity factor resource would
receive much lower total compensation even
3

though the resource provided the same on-
peak capacity benefit to the utility.
4
5 Q. What is the energy payment based on?
6 A. It is based on the cost of fuel and variable
7 operations and maintenance.
8 Q. Avista proposes that energy rates during surplus
9 periods be reduced to account for transmission wheeling
10 costs and losses that the utility would encounter in
11 delivering the QF's energy to a market hub. Do you
12 believe that such reductions in energy rates are
13 justified?
14 A. Yes, I do. If the energy truly is not needed by
15 the utility to meet its own obligations, then it must sell
16 that surplus energy in the market. Wheeling charges and
17 transmission losses are real costs that must be borne by
18 the utility; therefore, it seems appropriate for those
19 costs to be attributed to the QF that is supplying the
20 surplus energy.
21 I recommend that if the Commission believes it
22 is appropriate to reduce energy rates during utility
23 surplus periods then Idaho Power and PacifiCorp also be
24 directed to propose comparable amounts using an approach
25 similar to that proposed by Avista.
CASE NO. GNR-E-11--03 McHUGH, C. (Di) 11
5/4/12 STAFF
i Q. Do you have projected rates based on your
2 proposed changes to the SAR model?
3 A. Yes. These are included as Exhibit No. 303. It
4 should be noted that the results are preliminary and
5 reflect Staff's understanding of the utilities' positions
6 as of the time of filing this testimony. The calculated
7 rates could change during the course of this case due to
8 corrections, revised fuel forecasts, and changes in long-
9 term commitments.
10 For every resource, the rates for Idaho Power
11 and PacifiCorp are higher than the rates for Avista. This
12 largely reflects the fact that Idaho Power and PacifiCorp
13 are deficient in both energy and capacity earlier than
14 Avista.
15 The rates for canal drop projects are
16 considerably higher for Idaho Power and PacifiCorp
17 compared to other resources primarily because canal drop
18 projects offer capacity during peak summer hours and their
19 capacity payment is spread out over relatively few total
20 hours. This also occurs in the IRP model as discussed by
21 Staff witness Sterling. Canal drop and solar projects
22 have lower rates for Avista compared to the other two
23 utilities because Avista is generally capacity deficient
24 in the winter when neither of these resources produces
25 much energy.
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 12
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i Wind projects receive the lowest rates among the
2 different types of resources for all three utilities.
3 This reflects wind's low on-peak capacity factor.
4 Q. Have you reviewed the SAR model submitted by
5 Avista? Do you have any comments on it?
6 A. Yes, I have reviewed the model and I believe
7 there are several minor errors in the model.
8 First, the Avista model assumes an integration
9 charge of $6.50 per MWh for wind and solar projects.
10 However, pursuant to Order No. 30488, the correct
11 integration charge for Avista and Idaho Power is
12 calculated as a percentage of the levelized avoided cost
13 rate with the percent applied dependent on the amount of
14 wind/solar on the system. It cannot exceed $6.50 per MWh
15 but it can fall below that amount. Pursuant to Order No.
16 31021, the integration charge for PacifiCorp is $6.50 per
17 MWh.
18 The second minor issue is that the Avista model
19 levelizes the integration charge. The integration charge
20 should be applied annually to the levelized amount. The
21 third minor issue is that the Avista model fails to
22 properly levelize capital costs.
23 Q. Does this conclude your direct testimony in this
24 proceeding?
25 A. Yes, it does.
CASE NO. GNR-E-11-03 McHUGH, C. (Di) 13
5/4/12 STAFF
Report Annual Energy Outlook 2012 Early Release
Scenario ref201 2 Reference case
Datekey d121011b
Release Date January 2012
ref2012.021011b
18. Energy Prices by Sector and Source
(2010 dollars per million Btu, unless otherwise noted)
Mountain -08
Sector and Source
Distillate Fuel Oil
Electric Power
Residual Fuel Oil
9/
Steam Coal Natural Gas
2009 15.10 10.40 4.49 1.65
2010 18.67 11.91 5.02 1.57
2011 23.19 11.77 4.16 1.67
2012 23.36 11.33 3.98 1.69
2013 22.21 25.97 3.91 1.71
2014 23.39 27.11 3.76 1.76
2015 24.32 27.98 3.98 1.83
2016 24.69 28.24 4.01 1.85
2017 25.17 28.66 4.18 1.89
2018 25.39 28.90 4.39 1.90
2019 25.62 29.06 4.55 1.91
2020 25.83 29.21 4.67 1.92
2021 26.04 29.28 5.00 1.93
2022 26.28 29.53 5.34 1.96
2023 26.53 29.71 5.52 1.99
2024 26.67 29.82 5.60 2.03
2025 27.04 29.96 5.63 2.06
2026 27.29 30.00 5.80 2.09
2027 27.47 30.14 6.02 2.11
2028 27.65 30.34 6.10 2.13
2029 27.90 30.45 6.10 2.15
2030 28.10 30.37 6.15 2.18
2031 28.49 30.23 6.30 2.19
2032 28.72 29.88 6.48 2.21
2033 29.12 30.39 6.64 2.24
2034 29.58 30.68 6.82 2.26
2035 29.94 30.88 7.05 2.28
Exhibit No. 301
Case No. GNR-E-1 1-03
C. McHugh, Staff
5/04/12 Page 1 of 2
Prices in Nominal Dollars
Distillate Fuel Oil
Electric Power
Residual Fuel Oil
91
Steam Coal Natural Gas
2009 14.93 10.28 444 1.64
2010 18.67 11.91 5.02 1.57
2011 23.65 12.01 4.24 1.70
2012 24.05 11.67 4.09 1.74
2013 23.10 27.02 4.07 1.78
2014 24.75 28.68 3.97 1.87
2015 26.21 30.16 4.29 1.97
2016 27.14 31.04 4.41 2.04
2017 28.19 32.11 4.68 2.11
2018 28.99 33.00 5.01 2.17
2019 29.84 33.84 5.30 2.22
2020 30.70 34.71 5.55 2.28
2021 31.57 35.50 6.06 2.34
2022 32.51 36.53 6.60 2.42
2023 33.49 37.51 6.97 2.52
2024 34.36 38.42 7,22 2.61
2025 35.54 39.38 7.41 2.71
2026 36.60 40.23 7.78 2.80
2027 37.57 41.22 8.24 2.89
2028 38.56 42.31 8.51 2.97
2029 39.67 43.28 8.67 3.06
2030 40.72 44.02 8.92 3,15
2031 42.07 44.65 9.31 3.23
2032 43.21 45.10 9.74 3.32
2033 44.60 46.55 10.17 3.42
2034 46.14 47.85 10.64 3.52
2035 47.52 49.02 11.19 3.62
91 Includes electricity-only and combined heat and power plants whose primary business is to sell electricity, or electricity
and heat, to the public.
Btu = British thermal unit-
Note: Data for 2009 and 2010 are model results and may differ slightly from official EIA data reports.
Sources. 2009 and 2010 paces for motor gasoline, distillate fuel oil, and jet fuel are based on prices in the U.S. Energy
Information Administration (EIA), Petroleum Marketing Annual 2009, DOE/EIA-0487(2009) (Washington, DC, August 2010).
2009 residential and commercial natural gas delivered prices: EIA,
Natural Gas Annual 2009, DOE/EIA-0131(2009) (Washington, DC, December 2010). 2010 residential and commercial natural
gas delivered prices: EIA, Natural Gas Monthly, DOEIEIA-0130(201 1/07) (Washington, DC, July 2011).
2009 and 2010 industrial natural gas delivered prices are estimated based on EIA, Manufacturing Energy Consumption
Survey and industrial and wellhead prices from the Natural Gas Annual 2009, DOE/EIA-0131(2009)
(Washington, DC, December 2010) and the Natural Gas Monthly, DOE/EIA-0130(201 1/07) (Washington, DC, July 2011).
2009 transportation sector natural gas delivered prices are based on: EtA, Natural Gas Annual 2009, DOE/EIA-0131 (2009)
(Washington, DC, December 2010) and estimated State taxes, Federal taxes, and dispensing costs or charges
2010 transportation sector natural gas delivered prices are model results.
2009 and 2010 electric power prices based on EIA, Monthly Energy Review, DOE/EIA-0035(2010109)
(Washington, DC, September 2010). 2009 and 2010 E85 prices
2009 and 2010 electric power sector natural gas prices: EIA, Electric Power Monthly, April 2010 and April 2011, Table 42,
and EIA, State Energy Data System 2009, DOE/EIA-0214(2009) (Washington, DC, June 2011).
2009 and 2010 coal prices based on: EIA, Quarterly Coal Report, October-December 2010, DOEIEIA-0121(201014Q)
(Washington, DC, May 2011) and E1A, AE02012 National Energy Modeling System.
2009 and 2010 electricity prices: EtA. Annual Energy Review 2010, DOE/EIA-0384(2010) (Washington, DC, October 2011).
2009 and 2010 E85 prices derived from monthly prices in the Clean Cities Alternative Fuel Price Report
Projections: EIA, AE02012 National Energy Modeling System run ref20124121011b.
Exhibit No. 301
Case No. GNR-E-1 1-03
C. McHugh, Staff
5/04/12 Page 2 of 2
Forecasted Natural Gas Prices
(Real 2010 dollars per MMBTU)
$8.00
$7.50
$7.00
$6.50
$6.00
$5.50
$5.00
$4.50
$4.00
$3.50
—S—NWPPC East-Side Delivered —$—IPUC Estimates based on NWPPC data
--2011 EIA Mountain Region --2012 EIA Mountain Region
Exhibit No. 302
Case No. GNR-E-1 1-03
C. McHugh, Staff
5/04/12
Comparison of Proposed SAR Methodology Rates
Levelized Rates for 20-yr Contract Term. January 201a Online Date
$120
$100
$80
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$20
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Exhibit No. 303
Case No. GNR-E-1 1-03
C. McHugh, Staff
5/04/12
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 4TH DAY OF MAY 2012,
SERVED THE FOREGOING DIRECT TESTIMONY OF DR. CATHLEEN M.
MCHUGH, IN CASE NO. GNR-E-11-03, BY MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
DONOVAN E WALKER
JASON B WILLIAMS
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
MICHAEL G ANDREA
AVISTA CORPORATION
1411 EMISSION AVE
SPOKANE WA 99202
ROBERT D KAHN
NW & INTERMOUNTAIN POWER
PRODUCERS COALITION
1117 MINOR A VE STE 300
SEATTLE WA 98101
ROBERT A PAUL
GRAND VIEW SOLAR II
15690 VISTA CIRCLE
DESERT HOT SPRINGS CA 92241
THOMAS H NELSON
RENEWABLE ENERGY COALITION
P0 BOX 1211
WELCHES OR 97067
R GREG FERNEY
MIMURA LAW OFFICES PLLC
2176 E FRANKLIN RD
STE 120
MERIDIAN ID 83642
DANIEL E SOLANDER
TED WESTON
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
DON STURTEVANT
ENERGY DIRECTOR
J R SIMPLOT COMPANY
P0 BOX 27
BOISE ID 83707-0027
JAMES CARKULIS
EXERGY DEVELOPMENT GROUP OF
IDAHO LLC
802 W BANNOCK ST STE 1200
BOISE ID 83702
JOHN R LOWE
RENEWABLE ENERGY COALITION
12050 SW TREMONT ST
PORTLAND OR 97225
BILL PISKE MGR
INTERCONNECT SOLAR
DEVELOPMENT LLC
1303 E CARTER
BOISE ID 83706
CERTIFICATE OF SERVICE
RONALD L WILLIAMS
WILLIAMS BRADBURY
1015 W HAYS ST
BOISE ID 83702
BRAIN OLMSTEAD
GENERAL MANAGER
TWIN FALLS CANAL CO
P0 BOX 326
TWIN FALLS ID 83303
TED DIEHL
GENERAL MANAGER
NORTH SIDE CANAL CO
921 N LINCOLN ST
JEROME ID 83338
TED S SORENSON P E
BIRCH POWER COMPANY
5203 SOUTH I 1TH EAST
IDAHO FALLS ID 83404
M J HUMPHRIES
BLUE RIBBON ENERGY LLC
3470 RICH LANE
AMMON ID 83406
DEAN J MILLER
McDEVITT & MILLER LLP
P0 BOX 2564
BOISE ID 83701
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 83701
WADE THOMAS
DYNAMIS ENERGY LLC
776 E RIVERSIDE DR
STE 15
EAGLE ID 83616
MEGAN WALSETH DECKER
SR STAFF COUNSEL
RENEWABLE NW PROJECT
421 SW 6TH AVE STE 1125
PORTLAND OR 97204
BILL BROWN CHAIR
BOARD OF COMMISSIONERS
OF ADAMS COUNTY ID
P0 BOX 48
COUNCIL ID 83612
GLENN IKEMOTO
MARGARET RUEGER
IDAHO WINDFARMS LLC
672 BLAIR AVE
PIEDMONT CA 94611
ARRON F JEPSON
BLUE RIBBON ENERGY LLC
10660 SOUTH 540 EAST
SANDY UT 84070
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
P0 BOX 844
BOISE ID 83702
MARV LEWALLEN
CLEAR WATER PAPER CORP
STE 1100
601 W RIVERSIDE AVE
SPOKANE WA 99201
ENERGY INTEGRITY PROJECT
TAUNA CHRISTENSEN
769N 1100E
SHELLEY ID 83274
CERTIFICATE OF SERVICE