20131105Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472 W, WASHINGTON
BOISE, IDAHO 83702-5918
Attomey for the Commission Staff
IN THE MATTER OF rDAHO POWER )
COMPANY'S 2013 INTEGRATED RESOURCE )
PLAN.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC.E.13.15
COMMENTS OF THE
COMMISSION STAFF
)
)
)
)
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's 2013 Integrated Resource Plan ("[U"';.
BACKGROUND
On June 28,2013,ldaho Power Company filed its 2013 IRP. The IRP explains how the
Company intends to adequately and reliably serve its electric customers at the lowest system cost
over the next 20 years. The Company files an IRP every two years as required by the
Commission. See Order No. 22299.
The 2013 IRP addresses available supply-side and demand-side resource options,
planning period load forecasts, potential resource portfolios, a risk analysis, and includes an
action plan that details how the Company intends to implement the IRP. The IRP filing consists
of four documents: (l) the 2013 IRP; (2) Appendix A - Sales and Load Forecast; (3) Appendix B
- Demand-Side Management 2012 Annual Report; and (a) Appendix C - Technical Appendix.
The Company says it incorporated stakeholder and public input into its IRP by working
with the Integrated Resource Plan Advisory Council ("IRPAC"). The IRPAC meetings were
STAFF COMMENTS NOVEMBER 5,2013
open to the public, and the Company says the IRPAC and members of the public significantly
contributed to the IRP.
STAFF ANALYSIS
Staff actively participated in the IRPAC and believes the current IRP reflects the
Company's continued improvement in incorporating the group's feedback. Idaho Power held 11
IRPAC meetings while preparing the IRP. Many of these were well-attended by non-IRPAC
members. Both IRPAC members and non-members were involved in the discussions, several of
which were categorized as "spirited." The Company's acceptance of input is evidenced by the
IRP's inclusion of a resource portfolio proposed by the Idaho Conservation League and Boise
State University that centers on early retirement of the Company's coal-fired facilities. While
not all recommendations were incorporated, nor all of the conclusions universally supported, the
Company's willingness to discuss sensitive issues represents progress toward developing a
robust IRP.
Unlike the past two IRPs, in this IRP the Company analyzed the 20-year planning period
in one segment as opposed to two, 10-year segments. Idaho Power previously stated that
bifurcating the 20-year planning period prevented resource decisions for the first 10 years from
being influenced by more speculative and unproven resource decisions from the second 1O-years.
2009 IRP, p. 3. Staff has acknowledged the benefits and risks associated with modeling each
period separately, and supports the Company's retum to a single, 2}-year planning period for this
IRP. The IRPAC also endorsed the return to the 2}-year planning period, and it is appropriate
given Idaho Power's changing circumstances. The Company revisited the 20-year period for this
IRP to account for long lead times for new resources and the IRP's role in PUPRA rate setting.
2013 IRP, p. 2. Also, it was unnecessary to divide the 20-year period because lower growth
projections, the recent addition of Langley Gulch, and the presumed on-line date of the
Boardman to Hemingway ("B2H") transmission line significantly reduce the Company's need
for more supply-side resources in the near and long term.
The 2013 IRP's primary goals are to: (1) identify sufficient resources to reliably serve
growing energy demands over the 2}-year planning period; (2) ensure the selected resource
portfolio balances cost, risk, and environmental concerns; (3) give equal and balanced treatment
to supply-side resource and demand-side measures; and (a) involve the public in the planning
process. 2013 IRP, p. 1. Despite specific issues addressed in these comments, Staff believes the
STAFF COMMENTS NOVEMBER 5,2013
Company has effectively accomplished these goals while meeting Commission requirements set
forth in Order No.22299.
Load and Resource Balance
This IRP system peak and load forecasts are lower than those in the 2011 IRP. The
Company cites several reasons for the declines. Notably, 133 average megawatts (aMW) of load
from Hoku Materials and a proposed server farm (denoted as a "Special" customer) have been
removed from the prior forecast. Lingering effects of the recession have shown that the 2011
IRP's recovery projections were overly optimistic. Finally, the 2013 IRP projects declining use
per customer for the residential class. The result is a more conservative expectation of load
growth in the Company's service territory. The Company continues to use 70th percentile water
conditions and 70th percentile average load for energy planning, and 90th percentile water
conditions and 95'h percentile peak-hour load for capacity planning.
The Company expects the population in its service territory will continue to grow, mainly
due to net migration from other states. Id at p. 48. The IRP projects that the Company will serve
170,000 more customers over the 20-year planning horizon. Customer growth is partially offset
by forecasts of declining residential use per customer over the timeframe, prior to any
incremental energy efficiency savings. The Company says recent changes in lighting standards
and customer response to higher retail prices drive the lower per-customer use for the residential
class. The IRP also projects robust sales among the commercial and industrial sectors, and
relatively flat load for the irrigation class. In total, average system load is projected to increase
by 21 aMW (1.1%) each year through 2032. Peak demand is expected to grow at a compounded
rate of 1.4%o ayear.
The following table reflects the average annual compound growth rates and selected peak
loads for the last four IRPs. While the differences between growth rates appear relatively minor,
the impact for peak-planning purposes is significant. Between the 2011 and 2013 IRPs, the
Company's peak load expectations for 2018 declined by over 400 MW, nearly as much as the
Danskin and Bennett Mountain gas peaking units combined. Staff believes the Company's
forecasting methods and data are sound. The table illustrates the inherent uncertainty of electric
load forecasting, even within the near-term.
STAFF COMMENTS NOVEMBER 5,2013
Idaho Power Energy and Peak Forecasts By IRP
IRP Growth Rate (%l Peak Load (MWl
2006
2009
20L7
20L3
Energv Peak
1.9 2.L
o.7 1.5
7.4 1.8
t.t L,4
2018 2025
4,051 4,689
4,003 4,34L
4,056 4,529
3,651 4,033
The Company's use of the 70o/o planning criteria for energy and90l95% for peak is
consistent with IRPs since 2002. In that time, Staff has generally supported Idaho Power's
conservative planning approach. Staff continues to support the 70th percentile load and water
conditions for evaluating future energy needs. But Staff recommends that the Company
investigate whether it should adjust its peak load planning criteria before the next IRP.
The change in planning criteria arose from the energy crisis of the early 2000's and
relying on market transactions to meet peak deficits. Severe spikes in Mid-C prices were a
function of a regionally under-built transmission system and market manipulation. In response,
entities throughout the Pacific Northwest have taken steps to ensure customers are not exposed to
such volatile energy costs. Over 75,000 miles of transmission build-out from 2001 to 2012t, and
enhanced protocols, have increased the grids connectivity and reliability within the Western
Electricity Coordinating Council's ("WECC") footprint. From 2003 to 2012, over 11,500 MW
of net generationz capacity has been added in the Pacific Northwest, primarily consisting of
natural gas-fired facilities and wind. The Company's B2H transmission project will improve its
access to low cost energy resources in the Northwest via the Mid-C market. As detailed below,
the B2H project remains the preferred resource alternative under all the risk scenarios, implying
that reliance on the market is less risky in today's environment.
Idaho Power relies less on hydroelectric generation now than in 2002because it has
added more gas-fired generation. While water conditions remain important in meeting customer
demand, they are not the resource balance drivers they once were. Intuitively, moving to a less
I Source: WECC State of Interconnection 2012 Report.
2 Net generation takes into consideration plant retirements. Source: Northwest Power and Conservation Council.
STAFF COMMENTS NOVEMBER 5,2013
restrictive peak planning criteria would result in smaller deficits, and may potentially delay the
building of a resource designed to meet a low-probability event. Less restrictive, yet still
conservative planning criteria may include a specific planning reserve margin or more
probabilistic water and load conditions (80% load and water for peak planning, as an example).
Staff believes the Company's current resource position provides an opportunity for the Company
to reassess its planning criteria for the upcoming IRP cycle without unduly jeopardizing its
obligation to meet customer demands.
The Company has updated its facilities' operating characteristics to reflect additional
constraints going forward. Streamflow and management practice trends in the Snake River
Basin have been incorporated into the hydrologic modeling, resulting in a more realistic view of
hydro availability throughout the planning horizon. The Company also considered the potential
generation loss arising from the installation of pollution-control equipment on its coal-fired
facilities. In Case No. IPC-E-13-16, Staff addressed the investment decisions regarding coal
retrofits. For this IRP, Staff believes the Company has been consistent with the findings from its
Coal Unit Environmental Investment Analysis, and that its coal generation is properly reflected
in the resource balance for baseline purposes.
The results of the load and resource balance show that the Company has no energy-
related deficits throughout the planning period. The IRP shows a capacity deficit beginning in
2016, which steadily increases through the planning horizon. Without more resources, the peak-
hour capacity shortfall grows from 126 MW in 2016 to 1,095 MW in2032. Peak-hour deficits
occur exclusively in the summer months when irrigation load coincides with residential and
commercial air conditioning load.
Natural Gas and Coal Adder Forecasts
Prior IRPs used a weighted composite natural gas forecast based on several public and
private sources. The 2013 IRP relies on the US Energy Information Administration ("EIA")
forecast published in the Annual Energy Outlook 2012 from June 2012. The EIA forecast was
used for the Company's coal replacement study, and is the Commission-approved source for gas
prices when updating the avoided-cost rates for PURPA projects. Staff supports the consistent
use of the EIA forecast for planning purposes, though Staff recommends that the Company use
the EIA nominal forecast instead of applying its own escalation factor to the 2010 constant dollar
forecast. Staff uses EIA's nominal price forecast to calculate published avoided cost rates for
STAFF COMMENTS NOVEMBER 5,2013
PURPA projects, and supports it in Case No. IPC-E-13-16 as a more transparent use of EIA's
data. It is unclear if the Company applies its escalation factor to capture the effect of lower
purchasing power in the future, or some belief that the forecast produces prices that are
inherently lower than what can be expected in the future. Either way, Staff believes the EIA
nominal forecast more transparently provides a fuel price that indicates what the fundamental
forecast predicts prices will be at a given point in time. The difference between the EIA nominal
forecast and the Company's escalated values can be as large as 30Yo or more, meaning the
Company may be overstating the fuel cost associated with natural gas facilities. Staff continues
to believe it is reasonable for Idaho Power to apply a standard 3%o escalation rate to capital and
general O&M expenses.
The Company applies a carbon adder to the generation from CO2-emiting resources, as it
has since the mid-90s. The base case scenario of $14.64 per ton beginning in 2018 and escalated
at3o/o comports with the value used in the Company's coal investment study. The IRPAC vetted
and generally supported this carbon adder. Staffbelieves the range ofcarbon scenarios (a low of
$0 per ton to $3 5 per ton in 20 I 8 escalat ed at 9Yo) is reasonable given the uncertainty
surrounding future carbon regulations.
Demand-Side Management
Before analyzingthe load and resource balance, the Company adjusts the balance by
including demand-side management ("DSM") resources. The Company relies on a Conservation
Potential Study or Assessment ("CPA") by a third party consultant to set achievable savings for
the IRP planning period. Energy savings from potential programs effectively reduce the resource
deficit and alleviate the obligation to add additional supply-side resources.
Cons ervation P otential Study
Idaho Power commissioned EnerNOC to complete a2}-year CPA to forecast technical,
economic and achievable energy efficiency savings. The CPA analyzed the Residential,
Commercial, Industrial and Inigation sectors to ascertain criteria like electric use, market
characterization and potential savings. The Company previously completed a CPA in 2009.
EnerNOC forecasted 234 aMW of total achievable savings by 2032. The Commercial sector
provides the largest achievable potential savings through 2027. The Industrial sector provides
the second largest source of savings until2015, when Residential sector savings become the
STAFF COMMENTS NOVEMBER 5,2013
second largest source. The Irrigation sector provides the least amount of potential savings.
Lighting in the Residential (59% of total residential savings) and Commercial (46%) sectors is
forecast to provide the largest potential achievable savings by end use in 2017. Most of the
Industrial savings are from motors (52%). The study forecasts scientific irrigation practices will
comprise most of the Irrigation sector's savings (38%).
The CPA illuminates the large disparity between achievable and economic potential
savings in Idaho Power's service territory, which is largely a symptom of program participation
rates. While achievable savings over the 20-year period are estimated at234 aMW, the
forecasted economic potential is 438 aMW. Staff recommends that the Company increase its
efforts to improve customer participation rates to bridge the disparity between achievable and
economic potential savings.
Staff believes the CPA is an appropriate venue to forecast future potential savings. As
stated earlier, the Company will use the CPA's forecast and may refine the savings potential that
is then incorporated into its IRP load and resource balance. Staff notes the CPA was not
included in the IRP filing, and that the IRP failed to address how the Company will acquire the
future savings.
Future Savings
The Company refined the CPA's 2}-year energy potential savings from234 aMW to26l
aMW. In the short term (2013 -2017), the Company projects 69 aMW of achievable energy
savings. The Company applies its forecasted future savings to the Load and Resource Balance
section of the IRP. Staff has two concerns about the Company's treatment of DSM savings in
the IRP. First, the load and resource balance calculation excludes new Residential energy
efficiency savings in 2013 and2014 with no explanation. Second, there is inadequate discussion
of the Company's future energy efficiency acquisition plans. The Company includes forecasted
energy savings in its load and resource balance, but fails to adequately describe how the savings
are to be acquired. Considering that the DSM alternate costs for energy efficiency have
decreased by almost 50% from the 2011 IRP, and the Company's total energy savings have
decreased over the past two years, it is not clear in the IRP how the Company plans to acquire
forecasted energy efficiency savings. Preliminary cost-effectiveness analysis from the
September 18, 2013 Energy Efficiency Advisory Group ("EEAG") indicates that over half of the
Residential energy efficiency programs are not cost-effective due to the 2013 alternate cost used
STAFF COMMENTS NOVEMBER 5,2013
in the cost-effectiveness calculation. The IRP Action Plan does not describe current problems or
how they might be resolved to acquire the energy efficiency resources in the future.
Staff acknowledges that the EEAG is the Company's forum to discuss future DSM
acquisition. But the IRP is the centralized document that matches future need with resources.
As such, the IRP should discuss future energy efficiency acquisition. Staff recommends the
Company provide greater detail of future energy efficiency acquisition in the IRP's'Action Plan
section.
Dynamic Pricing Programs
The Company does not consider expanded dynamic pricing programs in its IRP.
Dynamic pricing can take many forms, including time of use and critical peak pricing. Though
dynamic pricing is not DSM in the traditional sense, Staff believes that large scale dynamic
pricing programs can significantly impact the Company's peak loads. Idaho Power currently has
mandatory time of use rates for large industrial customers (Schedule l9). But it has not
conducted an impact evaluation of the rate design since 2007 (the rate design went into effect in
2004). The Company also has a voluntary time of use program for residential customers that has
provided inconclusive results regarding peak load shaving capability. Staff recommends that the
Company investigate dynamic pricing options, enrollment strategies, and potential savings for
inclusion in its the next IRP. The findings would inform the Company and IRPAC as to whether
pricing structures can potentially reduce future peak loads.
Resource Alternatives Analysis
In response to comments from the IRPAC, the Company analyzed initial resource
alternatives before developing its portfolio. The goal of this approach was to isolate the impacts
of a particular resource addition rather than the combination of resources developed in the
Company's portfolios. Eight resources were chosen for the analysis, and scaled to meet 200
MW of on-peak capacity at a90%o exceedance value (200 MW 9 times out of l0). The eight
resources and the associated costs are included as Attachment A to Staff s comments. Aside
from the upfront capital cost, particular resources, such as solar, compare unfavorably due to the
additional nameplate capacity needed to achieve the 200 MW evaluation criteria.
As the Company points out, the treatment of distributed solar Photovoltaics ("PV") was a
divisive point of discussion throughout the IRP planning process. For both utility scale and
STAFF COMMENTS NOVEMBER 5,2013
distributed PV, the Company relied on cost and operating characteristics from the February 2012
Cost and Performance Data for Power Generation Report published by the National Renewable
Energy Laboratory ("NREL"). The NREL report served as the foundation for all supply-side
resource inputs. Unlike other generation resources, solar was modeled with a slight decrease in
capital cost over the planning period. Solar costs have been on a downward trend for a number
ofyears, and it is thought that technological breakthroughs and increased production could halve
the price of installations in the next 15 years.3 The Company's price assumptions are more
modest, and may not account for potential efficiency gains from new PV technologies.
The IRP includes the full cost of distributed PV, including customer costs. Several
IRPAC members argued that as a utility planning document, the IRP should only concern itself
with utility costs, thereby representing distributed PV as virtually costless. Staff concurs that the
IRP should analyze only utility costs. That said, arguments that customer-owned PV should be
modeled as costless ignore all entry barriers, and result in spurious conclusions.o Euen with the
cost of distributed PV installations becoming more competitive, Staff believes distributed PV
cannot be considered a plausible resource alternative until some consensus can be reached on
appropriate pricing assumptions that balance the Company and customers' perspectives. Staff
recommends that the Company investigate whether incentive programs could realistically
generate enough interest in expanding distributed PV installations in sufficient capacity (10 MW
and above) to warrant including distributed PV as an alternative resource. The analysis would
provide a good foundation for discussion in the next IRP cycle, and would result in a
representative price in alternative analysis.
The Company conducted further risk analysis on the eight resources to test for
sensitivities to changes in natural gas prices, carbon adders and water conditions. The rank order
of the resources did not change under any of the risk scenarios. After reviewing the table in
Attachment A, it is not surprising that the ranking remained unchanged under the various risk
scenarios. The primary driver in total cost differences between the resources is the capital, or
fixed costs, which would be unchanged under the different risk scenarios. The change in total
cost is attributed to changes in variable cost, which are calculated for the existing resources plus
' Source: Distributed Generation System Characteristics and Costs in the Buildings Sector, EIA, August 2013.o By that logic, the Company should spend no resources and acquire all distributed solar it can. It currently does so
through the net metering tariff, which accounts for approximately 3 MW of generation.
STAFF COMMENTS NOVEMBER 5,2013
the additional resource being analyzed. The magnitude of the change in system variable cost for
each resource alternative is not significant enough to overcome the disparity in fixed costs.
Portfolio Design and Selection
The results of the alternative resource analysis served as the basis for designing resource
portfolios to meet the Company's forecasted deficits over the next 20 years. Nine resource
portfolios were analyzed, and generally fell into three main categories:
l. B2H resource portfolios (2), designed around an on-line date of 2018;
2. Alternative to B2H portfolios (3), which exclude B2H as a resource; and
3. Coal alternative portfolios (4), which explore the partial or full retirement of
the Company's coal-fired facilities.
Each portfolio was designed to meet the Company's peak-hour needs accounting for existing and
committed resources and energy efficiency. The net present value ("NPV") of each portfolio
was used as a preliminary ranking method. The results are included as Attachment B to Staff s
comments. The Company then performed a stochastic analysis to test the robustness of each
portfolio under varying load, gas, carbon and hydrologic scenarios.
Generally speaking, the portfolios that contain B2H and ongoing coal-fired operations
performed better than portfolios without B2H or retired coal facilities. The two lowest cost
portfolios, both with B2H and one with demand response (Portfolio 2) and one with demand
response and a Simple Cycle Combustion Turbine ("SCCT") addition in2029 (Portfolio l),
significantly outperformed the alternatives from a least cost and least risk standpoint. The NPVs
for these two portfolios are nearly identical; Portfolio 2 is less than lYo cheaper than Portfolio 1
under planning conditions. The primary difference between the two is the fixed cost, which
tempers Staff s concern regarding the Company's adjustment to the EIA natural gas price
forecast. Staff also notes that these portfolios are identical until2029, confirming that the
demand response/B2H combination is the preferred near- and mid-term option.
Though the portfolios that assess early retirement of coal plants perform poorly in terms
of NPV, Staff believes it is beneficial to include them in this analysis. The use of carbon adders
is an appropriate method for capturing the additional cost of environmental regulations. But it
does not effectively convey the impact that stringent regulation may have if the plants are forced
to shut down entirely. The analysis shows that early retirement of coal-fired facilities could
expose ratepayers to increase s 35oh greater than the preferred altemative over the next 20 years.
STAFF COMMENTS l0 NOVEMBER 5,2013
Staff expects the Company to continue to include a similar type of analysis in future IRPs as
emissions costs and regulations evolve in the coming years.
Staff noted in its previous IRP comments that the Company's analysis fails to quantify
the risk associated with transmission siting and escalating capital cost. IPC-E-11-11, Staff
Comments, p. 13. Staff is concerned that all portfolios containing B2H assumed a specific in-
service date, and no analysis was conducted to address the potential delay in the projected
completion. The conclusion of the environmental review and routing process are mostly beyond
the Company's control. The Company's demand response programs may be able to meet peak
deficiencies for 2018 and 2019. But after that, deficits grow in duration beyond what current
demand response programs can handle. Staff recommends the Company provide an alternative
action plan that would result from a 2 to 5 year delay in the construction of B2H as part of its
next IRP update.
Preferred Resource Portfolio and Action Plan
Based on the Company's analysis, the preferred portfolio comprised of demand response
and B2H in 201 8 (Portfolio 2) performed best in terms of least-cost and least-risk. Under
virtually all scenarios, Portfolio 2 proved to be less costly than altematives that did not include
B2H. Staff believes this result is well-supported, with the reservation that the B2H timeline is
not certain. Additionally, Staff notes that none of the analysis made any assumptions about the
completion or impact of the Gateway transmission expansion of which the Company is a part.
Staff recommends that the Company include a broader discussion and analysis of the Gateway
transmission project in its IRP update.
The Company's Action Plan is shown below. The specified actions are representative of
the IRP analysis and, besides the lack of detail on additional energy efficiency acquisition,
provide an adequate blueprint given the information at this time. Although the IRP Action Plan
is not intended to bind Company decisions, Staff expects the Company to keep the Commission
well-informed on the progress made toward achieving the identified goals.
ilSTAFF COMMENTS NOVEMBER 5, 2OI3
Table 10.1 Fortfolio 2 action plan
Year Resource
2013-2018
2013-
2013
2013
2016-2017
2018
2U1s
2019
2020
2020
2024-2432
Boardman to Hemingway
Gateway West
North Valmy Unit 'l
Jrm Bndger Units 3 and 4
Demand respons€
Boardman io Hemingway
Shoshone Falls
Jim Bridger Unit 2
Jim Bridger Unit 1
Boardman
Demand response
Ongoing permitting, planning studies, and regulatory filings.
Ongoing permitting, planning studies, and regulatory filings.
Commrt to the installatiorr of dry sortent injectron
emission-control technology.
Commit to the installation of selective catalytic reduction
emission-control technology.
Have demand response capacity available to satisfo deficiencies
up to approximately 150 f\,4\ry.
Transmission line complete and in service.
Shoshone Fafls upgrade complele and in service.
Comrnit to the installation of selective catalytic reduction
emission-control technology.
Commit to the installation of selective catalytic reduction
emission-control technology.
Coal-fired operations at the Eoardman plant are scheduled to
end by year-end 2020.
Have demand response capacity available to satisfy defrciencies
in 50-MW increments up to approximately 370 MW in 2031.
STAFF RECOMMENDATIONS
After reviewing Idaho Power Company's 2013 IRP, Staff believes that the Company
performed extensive analyses, gave reasonably equal consideration of supply- and demand-side
resources, and provided acceptable opportunities for public input, resulting in an IRP that
satisfies the requirements set forth in Commission Order Nos. 25260 and22299. Staff, therefore,
recommends that the Commission acknowledge the Company's 2013 IRP.
Respectfully submitted this day of November 2013.
/// 1 ,//
Karl T. Klein
Deputy Attorney General
Technical Staff: Bryan Lanspery
Nikki Karpavich
i:umisc/comments/ipcel3. I 5kkbl comments
STAFF COMMENTS
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Case No. IPC-E-13-15
Staff Comments
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Case No. IPC-E-13-15
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 5TH DAY oF NoVEMBER 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-I3.Is, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
LISA D NORDSTROM
JENNIFER REINHARDT
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
EMAIL: [e-mail]
j reinhardt@idahopower. com
[e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 8370I
EMAIL: [e-mail]
PETER J RICHARDSON
RICHARDSON ADAMS
5I5 N 27TH ST
BOISE ID 83616
EMAIL: oeter(Erichardsonadams.com
THOMAS H NELSON
ATTORNEY AT LAW
PO BOX 1211
WELCHES OR 97068
Email: [e-mail]
GREGORY W SAID
TIMOTHY E TATUM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
EMAIL: [e-mail]
ttatum@ idahopower. com
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH ST
BOISE ID 83702
EMAIL : [e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: [e-mail]
NANCY ESTEB PhD
PO BOX 490
CARLSBORG WA 98324
Email: [e-mail]
SECRETAR
CERTIFICATE OF SERVICE