20070122Comments.pdf

CECELIA A. GASSNER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6977
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Street Address for Express Mail:
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BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
CO MP ANY'2006 INTEG RATED
RESOURCE PLAN.
CASE NO. IPC-06-
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of record
Cecelia A. Gassner, Deputy Attorney General, in response to the Notice of Filing and Notice of
Comment Deadline in Order No. 30185 issued on November 21 2006, submits the following
comments.
BACKGROUND
On September 24, 2006, Idaho Power Company ("Idaho Power" or "Company ) filed its 2006
Integrated Resource Plan (IRP). On October 18 , 2006, the Company filed a revised plan that corrected
certain typographical errors and revised certain exhibits. The Company s filing is pursuant to a
biennial requirement established in Commission Order No. 22299, Case No. U-1500-165. The IRP
describes the Company s growing customer base, load growth, supply-side resources, demand-side
management and risk analyses. Additionally, the 160-page IRP document and related appendices
contain information regarding available resource options, planning period forecasts, potential resource
portfolios, a twenty-year resource plan, and a near-term action plan.
STAFF COMMENTS JANUARY 22, 2007
THE INTEGRATED RESOURCE PLAN
The IRP filing consists of five documents: the IRP, a Sales and Load Forecast, the Company
2005 Demand-Side Management Annual Report, an Economic Forecast, and a Technical Appendix.
Idaho Power has worked with stakeholders over the last 12 months to develop the subject IRP.
The Integrated Resource Plan Advisory Council (IRP AC) consisted of members of the environmental
community, major industrial customers, agricultural interests, an Idaho state legislator, Commission
Staff, a representative from the Idaho Governor s Office, and others. The Company also conducted
presentations open to the general public from November 13-2006 in Boise, Pocatello, and Twin
Falls, Idaho, and Ontario, Oregon.
According to the Plan Summary, the Company anticipates that its customer base will increase
from approximately 455 000 to over 680 000 by the end of the planning period of2025 , an increase of
000 to 12 000 new customers each year. The Company states that it used a conservative resource
plan based upon a worse-than-median hydro conditions. It used 70th percentile water conditions and
70th percentile average load for energy planning. In addition, for peak-hour capability planning, it used
90th percentile water conditions and 95th percentile peak-hour load.
The IRP states that it includes 1 300 MW (nameplate) of supply-side resource additions and
demand side management (DSM) programs designed to reduce peak load by 187 MW and average
load by 88 aMW. The Company s average load and summertime peak load are expected to increase by
40 aMW and 80 MW, respectively, per year through 2025.
The Company states that the 2006 IRP provides the Company s estimate of future loads and
sets forth how the Company intends to serve the electrical requirements of its native load customers
over the next 20 years. While the proposed resource portfolio represents current resource acquisition
targets, the Company notes that the actual resource portfolio may differ from the quantities and types
of resources outlined in the IRP depending on responses to the Company s Requests for Proposals, the
business plans of any ownership partners, and the changing needs of Idaho Power s system.
Idaho Power conducted an analysis of possible transmission path upgrades, and the following
were selected as the most viable transmission alternatives:
McNary (Columbia River) to the Locust Substation (Boise) via Brownlee;
Lolo (Lewiston area) to Oxbow;
. Bridger, Wyoming to the Boise Bench Substation via the Midpoint Substation;
Garrison or Townsend, Montana to the Boise Bench Substation via the
Midpoint Substation; and
. White Pine, Nevada to the Boise Bench Substation via the Midpoint Substation.
STAFF COMMENTS JANUARY 22, 2007
The IRP's preferred portfolio includes a 250 MW coal-fired resource addition in 2013
identified as "Wyoming Pulverized Coal." The Company does not know specifically where this
addition will be located, but states that one of the Company s best near-term alternatives for expansion
at an existing coal-fired resource is the addition of a fifth unit at the Jim Bridger plant.
STAFF ANALYSIS
General Comments
Idaho Power continues to make strides in producing a quality resource plan. The 2006 IRP has
built upon the well-received 2004 IRP by adding additional analyses to the portfolio selection process
and incorporating recommendations made by the Commission in the previous filing. Staff believes
that through the interaction with the IRP AC, increased rigor in the scrutiny of portfolios, extended
planning horizon, and inclusion of regional transmission capacity projects, the 2006 IRP is superior to
prior filings.
There have been numerous events that have happened since the 2004 IRP that have influenced
the 2006 analysis; most of these have been accounted for in the planning process. The 2006 IRP
assumes the approval of the 170 MW addition to the Danskin facility. Also assumed in the analysis is
the net upgrade of 49 MW to the Shoshone Falls Hydroelectric Project first identified in the 2002 IRP
and scheduled for completion in 2010.
The Company continues to use a more conservative water, load, and peaking capacity planning
criteria in this IRP process as it did in the 2004 IRP. While wholesale market prices for electricity
have shown less volatility than in prior years, some risk remains for excessive reliance on regional
markets to meet the Company s summer peaking needs. This risk is somewhat mitigated through the
use of conservative planning criteria and the Company s risk management process.
The 2006 IRP includes 250 MW of additional wind resources, including a 100 MW project
currently in the latter stages of the RFP process. There is also a 50 MW geothermal project in the
latter stages of the RFP process included in the chosen portfolio. The Company s Plan appears to take
a reasoned approach to developing a diversified portfolio that includes fossil fuel-based resources
more renewable resources, and increased DSM in its future resource mix.
Staff believes that the Company is justified in extending the planning horizon from ten years to
twenty years in order to incorporate more capital intensive resources that require a longer lead time
than the recently acquired simple cycle combustion turbines. The extended horizon also facilitates the
analysis of transmission planning, which requires sufficient lead time for permitting and construction
ST AFF COMMENTS JANUARY 22, 2007
as well. The longer planning horizon does result in a somewhat speculative assessment of unproven or
uncertain resources. For example, inclusion of an integrated gasification combine-cycle (IGCC) coal
plant seems speculative given the Company s caveats about the immaturity of the technology, and the
250 MW power purchase agreement with Idaho National Laboratory (INL), scheduled for 2023, for
nuclear power is highly uncertain.
However, the IRP is not intended to be a binding plan for the future expansion of the Company,
and time and changing conditions will ultimately dictate the actions of the Company. The additional
sensitivity analysis, discussed in more detail below, is an appropriate enhancement of the planning
process to account for factors beyond the Company s control. Continued cooperative development of
future IRPs with the IRP AC and the general public, along with advances in the Aurora modeling
software, will enhance Idaho Power s ability to identify and evaluate uncertainty associated with the
various resource portfolios.
Load Growth Forecasts
Idaho Power continues to plan for a high level of growth in load over the planning horizon.
The expected growth rate of 1.9% is lower than the 2002 and 2004 IRPs, but still signifies a robust
upward trend. When compared to the 2004 IRP, this change in the growth rate results in a reduction of
expected load by 71 aMW in 2013. Of the four main customer classes, the residential sector appears to
be the catalyst for growing load. The growth rate for residential customers is predicted to be about 2%
annually, resulting in a net increase of nearly 190 000 customers by 2025 for that class. This
contributes to both energy and capacity needs, with emphasis on the latter due to the growing
penetration of air conditioning within the service territory. Summer peak load growth is projected at
80 MW a year over the planning horizon, with residential and irrigation accounting for approximately
60% of summer peak demand. Staff notes, and details below, that Idaho Power has implemented and
expanded cost-effective DSM programs to these customer classes with the intent of mitigating peak
load growth.
Fuel Price Forecasts
The results from the Company s analysis are based on assumptions made and inputs used in the
modeling runs. None may be as important, given recent events, as the natural gas price forecast. In
the past five years the Company has relied primarily on the addition of gas-fired combustion turbines
to meet increased peaking needs. Other electric utility providers have acted similarly, and nationally
STAFF COMMENTS JANUARY 22 2007
this trend has increased total gas consumption for electric generation by 45% over the past decade. In
that period the nation has also seen unprecedented volatility in gas prices (which was not predicted by
the majority of well-established sources), which the Company relies on to derive the price schedule
used in its analysis. The 2006 IRP includes a high natural gas price scenario in its portfolio analysis
and annual average prices of $8.23/MMBTU, which is in the lower range of prices witnessed in 2005
or 2006. The graph comparing natural gas price forecasts from the 2000 to 2006 IRPs included on
page 49 of the Technical Appendix illustrates the inability to accurately predict fuel prices. In each
case the prior forecast was well below the preceding forecast, demonstrating the volatile and somewhat
unpredictable rise in natural gas prices recently. As an example, the 2004 IRP uses an expected
(Sumas) natural gas price of $4. 85/MMBTU and a high scenario of$6.27/MMBTU. The 2006 IRP
portfolio analysis uses prices of$8.23/MMBTU for the expected scenario and $11.16/MMBTU for the
high gas price, an increase of70% and 78% respectively in two years.
Even though there are no new gas-fired plants included in the selected portfolio, there are
ramifications to using optimistic gas forecasts, namely that alternative resources can be shown to be
less competitive. Combustion turbines fired by natural gas have historically enjoyed an economic
advantage in the decision making process due to the low relative initial capital cost and stream of
variable fuel costs based on relatively low fuel price forecasts. Gas price forecasts are critical in
determining which resources are included in the portfolio. This is especially true when high capital
costs/low fuel cost resources are compared to resources with high fuel costs and low capital cost.
Although the Company has included a significant amount of renewable resources in its selected
portfolio, it has also indicated that a failure to acquire cost effective geothermal resources and other
renewables, combined with favorable gas price forecasts, could result in a need to add additional
natural gas-fired facilities in the short term.
Beyond the accuracy of gas price forecasts is the nature of the forecast represented in the IRP.
The IRP appears to present and utilize an annual average gas price. Because the majority of gas is
purchased to fire turbines in the summer peaking months, it would seem more appropriate to use a
summer pricing schedule that reflects the timing of the Company s fuel purchases. To the extent the
summer gas prices for use in summer peak facilities are lower than annual average prices (that include
the higher winter prices), then the risk of an artificially low annual average forecast is somewhat
mitigated. To the extent the Company used weighted summer prices in its IRP, it should describe the
methodology used in the calculation.
STAFF COMMENTS JANUARY 22 2007
The Company s forecast of coal prices continues to exhibit the same upward trend in forecasts
from the previous IRPs. IRP, Technical App. D at 50. Coal prices do become a major factor in
assessing potential portfolios, as the Company appears committed to adding coal-fired resources to the
mix. The steep upward trend in coal prices predicted to begin around 2012 supports the Company
position to split its coal acquisition into two segments, including 250 MW ofIGCC in 2017. A major
driver in coal prices is transportation costs, namely rail transport, which can be critical in the siting of
the plant. Idaho Power does not identify the location of their proposed coal facility in 2013, though it
mentions expanding the Jim Bridger facility in Wyoming as a potential addition. The Company is also
in discussions with Avista for possible joint acquisition of a coal-fired resource.
Transmission
At the behest of the Commission, Idaho Power included transmission alternatives in its
resource planning. Results from the Company s analysis show peak hour transmission deficiencies as
early as 2007, and significant long-term deficiencies beginning in 2009. Though the Company has
transmission interconnections to the Southwest markets, the bulk of the analysis focuses on the Pacific
Northwest markets. Given the Company s needs, availability of economical resources, and the
maturity of the Pacific Northwest markets, it appears the emphasis on transmission upgrade is properly
focused. The 2006 IRP does a far better job of incorporating transmission constraints in the portfolio
selection analysis than previous IRPs.
FERC's Standards of Conduct prohibit potentially beneficial discussion between the
Company s planning and transmission groups. In order to incorporate transmission alternatives into
the IRP, Idaho Power contacted an outside consultant to provide the technical evaluation of several
alternatives. It appears that the resulting selections of possible transmission upgrades are reasonable
though more detail regarding the findings of the consulting group would have been beneficial. The
Company has included in its selected portfolio 285 MW of transmission upgrades that provide access
to the Mid-C market in the Pacific Northwest. Given the nature of electric usage profiles of utilities in
Washington, Oregon, and Northern California, Idaho Power may have significant opportunities to
utilize additional transmission capacity for off-system purchases during summer months and periods of
low water.
The Borah-West transmission upgrade, detailed in the 2004 IRP, will serve to support the
growing number of wind and geothermal projects to the east of Boise, but as noted by the Company,
additional upgrades will be necessary should the Company site a coal-fired plant in Wyoming. The
STAFF COMMENTS JANUARY 22, 2007
IRP states that since a site has not been identified, generic transmission upgrade costs have been
included in the IRP analysis. Although there is uncertainty associated with current transmission
upgrade costs, it is likely that the Company will provide a more thorough transmission cost estimate
when a more fully developed plan to acquire resources east of Boise is presented.
Supply Side Resource Options
The selected portfolio is a modified version of the preferred portfolio from the 2004 IRP. The
modifications took into account the recommendations of the Commission in Order No. 29762 and
incorporated a more current assessment of the Company s needs. The three most significant changes
are the timing of the additional coal based resources, the inclusion of transmission upgrades, and the
modification of geothermal resources. Also, the inclusion of 250 MW of nuclear power in 2023 is
worth noting. The selected portfolio consists of the following:
250 MW Wind
150 MW Geothermal
150 MW Combined Heat & Power (CHP)
250 MW Coal
250 MW IGCC Coal
285 MW Transmission
250 MW Nuclear
187 MW DSM (Peak reduction)
Idaho Power has committed to adding more wind generation to its portfolio. The preferred
portfolio contains 250 MW of new wind acquisitions over the next ten years, down from the preferred
portfolio in 2004 (350 MW). A major factor toward the reduction in new wind acquisitions is the
amount of PURP A wind projects the Company has added since the preparation of the 2004 IRP, when
it had only 2.61 MW of wind-related contracts. The Company has indicated that, including the 100
MW proposal soon to be submitted for approval and its PURP A commitments, it estimates nearly 300
MW of wind resources in its resource mix by the end of 2007. Excluding any unforeseen additional
PURP A contracts, this amount will move to 450 MW within six years.
The 2006 preferred portfolio increases the amount of geothermal-powered generation by 50
MW over the 2004 plan to a total of 150 MW. Currently the Company includes 10 MW of geothermal
generation in their portfolio as a result of the power purchase agreement with the Raft River
geothermal project. See Case No. IPC-05-1. As previously noted, the Company is in the latter
stages of the RFP evaluation process for a 50 MW geothermal project expected to be online in 2009.
STAFF COMMENTS JANUARY 22, 2007
What had been considered a 100 MW geothermal acquisition online in 2008 in the 2004 IRP has been
altered to three separate 50 MW acquisitions in the 2006 plan including the aforementioned project.
The other two projects are projected to be online in 2021 and 2022. The Company notes that heavy
reliance on geothermal generation is risky at this time due to uncertainty in the availability of
geothermal resources, but will reassess that position in the 2008 IRP should the results of the "RFP
indicate that an abundant supply of cost-effective geothermal projects" exist in Idaho. IRP at 90.
The single 500 MW coal-fired generation resource from the 2004 preferred portfolio has been
altered in the 2006 IRP to two 250 MW acquisitions dispersed over the planning horizon. From the
previous IRP filing, the Commission ordered the Company to address new coal technologies when
examining coal-fired resources. Order No. 29762. In response, Idaho Power and Avistajointly
contracted with Cummins & Barnard, an engineering consulting firm, to assess the current state of coal
based generation technologies. IRP, Technical App. D at 99-106. The preliminary results from that
study show that IGCC technology with carbon sequestration and enhanced pulverized coal
technologies may be a viable resource in the future. Currently there are two large-scale IGCC facilities
in operation in the United States, but the large initial capital expenditure (estimated at over $2500/kW
of total investment in 2006 dollars) and unproven technology remain the primary barriers for larger
scale deployment. Future changes in carbon regulations, such as emissions taxes, along with
technological advances may make IGCC technology, especially with carbon sequestration abilities
more economically competitive in the future.
The other 250 MW of coal-fired generation is anticipated to be online in 2013. Details
regarding this acquisition are uncertain to date. The Company has provided a number of potential
scenarios for adding regional pulverized coal to its resource portfolio with the expectation that any
generating unit will be located outside of the State. By breaking up its acquisition of coal based
resources into smaller units than that proposed in the 2004 IRP, the Company notes that this reduces its
exposure to risk of equipment failure and coincides better with expected load growth. IRP at 97. Staff
observes that this reduces the immediate rate impact on the Company s customers as well. Idaho
Power has informed the Commission and Staff that it has executed a memorandum of understanding
with Avista to explore the option of jointly developing a coal-fired facility. Seasonal or shared
ownership, as well as expansion of existing generation facilities, are also options the Company is
considering. The Company may also want to consider short-term interim participation in regional coal
plants. It is anticipated that the Company will have a firmer grasp on its options early in 2007.
STAFF COMMENTS JANUARY 22, 2007
The remaining supply side resources in Idaho Power s preferred portfolio include 150 MW of
Combined Heat and Power (CHP) and a 250 MW power purchase agreement (PP A) with INL for
nuclear power. As stated earlier, the inclusion of the nuclear PP A is speculative at this time, but is not
considered in the plan to be enacted until 2023. It is assumed that this will be addressed in future IRPs
along with nuclear power in general, and is not significant in the Company s near-term plan. The CHP
addition identified in the preferred portfolio is anticipated to occur in two installments, with 50 MW
predicted to be online in 2010 and an additional 100 MW in 2020. Quantifying the costs associated
with CHP is difficult, as project costs are very site-specific. The Company has used cost figures from
the 2004 IRP escalated at 3% for its 2006 analysis. Figures 5-, 5-, and 5-3 demonstrate that CHP is
potentially an economically competitive generation resource. IRP at 46-48.
DSM Measures
The 2006 IRP sets more aggressive targets for DSM savings for the planning period than did
the 2004 IRP. Staff supports prudently managed, cost effective DSM programs and hopes that the
Company can reach at least the targets set out in the IRP.
The 2006 IRP proposes two new DSM programs and refinement and expansion of an existing
program that will potentially result in a nearly 88 aMW savings and a reduction in peak load of 187
MW in 2025, both in addition to its existing programs. The new programs target existing residential
and commercial customers with savings of29 and 18 aMW and peak reductions of 113 and 27 MW
respectively, in 2025. The refined and expanded industrial program is projected to save 40 aMWand
47 peak MW in 2025. IRP at 65.
Idaho Power s existing DSM programs, which include new homes and commercial buildings as
well as existing residential air conditioning, low-income customers and industrial and irrigation
customers, resulted in an average savings of 4.7 aMW and peak hour reductions of 47.5 MW in 2005
according to IRP Table 2-6. IRP at 25. Staff notes that the 2005 DSM report submitted as Appendix B
to the 2006 IRP lists a slightly lower 43.1 peak hour reduction, which excludes 4.5 MW attributed to
energy efficiency programs and Northwest Energy Efficiency Alliance (NEEA) market transformation.
Most of the existing programs are projected to expand for at least the first few years of the planning
period, according to the 2004 IRP.
In Case No. IPC-06-, the Commission approved modifications to the Irrigation Peak
Rewards Program that are intended to expand the program beyond the level of the 2006 Program. See
Order No. 30194. However, there is no acknowledgement of the program or assumptions of continued
STAFF COMMENTS JANUARY 22, 2007
associated savings and reductions to be found in the 2006 IRP. If included, the Company needs to be
more explicit in how it is factored into the analysis; ifnot included, the Company should explain why.
Underestimating DSM savings may lead to a heavier, unnecessary reliance upon supply side
resources. Given that DSM efforts continue to show exceptional value with benefit/cost ratios as high
as 4., the Company should continue to expand these programs and properly record energy savings.
IRP, Technical App. D at 73. Prudent DSM management results in not only acquiring DSM as cost-
effectively as practicable, but also acquiring all cost-effective DSM, and fully incorporating the
savings into the IRP.
There are several factors that may influence the level of DSM implementation. One particular
example worth noting is the implementation of a fixed cost adjustment mechanism designed to keep
the Company financially neutral to deviations in sales, such as lost sales due to DSM efforts. See Case
No. IPC-04-15. The goals of the fixed cost adjustment are to remove the inherent disincentive to
investing in demand-side measures and facilitate the Company s efforts to expand its DSM offerings.
Staff is interested in whether approval of the fixed cost adjustment mechanism would affect the
analysis conducted for the IRP, and if so, how.
A second example is the status of the Company s advanced meter reading (AMR) deployment.
In Order No. 30102, the Commission granted Idaho Power a one-year period to investigate the
technical issues that plagued the AMR deployment in the Emmett area. Through meetings with the
Staff, the Company has reported that many of the technical issues have been addressed, though new
issues have appeared. Failure to resolve these issues may have a deleterious effect on demand
response programs that utilize AMR technology. Staff and the Commission have been strong
proponents of time variant pricing and other demand response programs, and hope that the technical
issues can be resolved and full-scale deployment can be achieved as quickly as is prudent. The
Company is scheduled to submit an updated status report by May 1 , 2007.
Staff recognizes and supports the Company s effort to distribute its DSM efforts among
customer classes, between new construction and existing customers, between direct incentive programs
and NEEA's market transformation efforts, and between energy efficiency and peak load reductions.
DSM programs continue to be among the most cost effective resources available to Idaho
Power as demonstrated in Figures 5-, 5-, and 5-3 of the 2006 IRP. IRP at 46-48. However
IRP Fig. 5-7 projects Idaho Power s DSMenergy savings for 2007 and 2008 at between 65% and 75%
of its proportional share of the Northwest Power and Conservation Council's (NWPCC) estimate of
total conservation potential. IRP at 69. While the 2006 IRP demonstrates a higher commitment to
STAFF COMMENTS JANUARY 22, 2007
DSM efforts than in the past, the Company does not yet propose to pursue all cost-effective DSM
opportunities and incorporate associated energy and peak demand savings into its determination of
new supply side resource needs. Perhaps the Company s fixed cost adjustment proposal in Case No.
IPC-04-15 and its DSM incentive proposal in Case No. IPC-06-, will mitigate the Company
position stated in the IRP's Technical Appendix D that DSM programs will be selected to minimize
negative impact on shareowners. IRP, Technical App. D at 62.
Risk Analysis
Idaho Power selected four of the twelve potential portfolios for further risk analysis in
determining the preferred portfolio. Risk measures fall into either quantitative or qualitative
categories. The quantitative analysis closely follows that of the 2004 IRP with two exceptions, the
exclusion of risk analysis associated with the expiration of production tax credits for wind and the
inclusion of a sensitivity analysis to variations in the streamflows of the Snake and Columbia River
systems. Advancement in the modeling software facilitated simulating various streamflow sequences
for the hydrologic variability analysis, which each portfolio analyzed under varying assumptions of
load requirements, carbon taxes, etc. The resulting analysis was not used in the final risk adjustment
due to the magnitude of the impact of varying hydrologic conditions. Staff finds this to be reasonable
and notes that the difference in variability between the highest and lowest cost portfolios are relatively
small ($404 million versus $434 million, or less than 7% difference in variability).
The quantitative factors used in the scoring of the finalist portfolios remained the same from
the 2004 IRP (carbon taxes, natural gas price, capital and construction costs, and market risks), though
the input values have changed in most categories. As mentioned before, the natural gas price forecasts
have been updated since 2004, as well as the discount rates used in the capital risk analysis. The
subjective probabilities associated with the low, expected, and high scenarios have remained at the
2004 levels in all risk analyses with the exception of capital cost risk, which changed from 10%, 80%
and 10% respectively to 10%, 60%, and 30% respectively. As noted in Staff comments from the 2004
IRP, the Company does not provide a basis for its probability assignments, which can have significant
economic impacts on the portfolios under consideration. For example, the Company uses $ 14/ton as
an expected case scenario for the carbon adder with 50% probability. Yet given the probability
weighting assignments made by the Company, the expected value of the carbon adder is $17/ton.
I Expected value in this case is the average of possible carbon adder values weighted by their probability. Specifically,
Expected value = ($0*3)+($14*5)+($50*2) = $17/ton.
STAFF COMMENTS JANUARY 22, 2007
For the preferred portfolio, this adds an additional $200 million to power supply costs. Because the
composition of the portfolio dictates the impact of varying assumptions, these impacts are not equal
across the board. The lowest cost portfolio, in comparison, has nearly a $50 million smaller impact
due to this change.
Idaho Power has expanded its qualitative risk section in the 2006 IRP. In addition to regulatory
risks (e.g. the imposition of renewable resource portfolio standards), resource timing and commitment
risks, and operational concerns associated with its hydropower facilities, the Company acknowledges
the risks associated with technologies, fuels, and the implementation of the preferred portfolio.
Without specifically tying these qualitative measures to the individual portfolios, the Company
expresses its concerns regarding these areas in general terms. Of the qualitative risks, it appears as if
the more important risks that factor into the selection of the preferred portfolio are concerns over the
operational risk of transmission projects (and market liquidity), technology, specifically with regards to
IGCC, and potential renewable portfolio standards.
The methodology used in the analysis resulted in the selection of the preferred portfolio, an
extension of the 2004 preferred portfolio that highlights a diverse mix of new resource acquisitions.
The Company states that the diversified approach mitigates exposure to qualitative risks, and provides
flexibility in planning should actual conditions deviate from those used in the planning criteria. IRP at
91. The preferred portfolio scored well in the risk analysis, ranking second behind the 'green
portfolio . Staff would note that the preferred portfolio had the second highest cost of the finalists in
terms of average total cost, yet the lowest in terms of resource cost (capital and operating costs, with
market sales and purchases excluded). The preferred portfolio was the second lowest risk-adjusted
total cost portfolio among finalists due to its relatively higher risk ranking.
Near-term Action Plan
Since 2001 , Idaho Power has been in a period of acquiring supply-side resources after nearly
two decades of relatively few additions to its generation resource mix. The 2004 and 2006 IRPs have
presented a need to meet future deficiencies in energy as well as peak loads. Given the long lead time
associated with thermal baseload generation facilities and the projected persistent deficiencies in
energy beginning in 2012, it is imperative that the Company begin addressing these concerns. The
Company is currently investigating its options with regard to a coal-fired resource addition, as noted
earlier. The near-term action plan shows 2007 as the target date for identifying, selecting and
proceeding into the pre-construction phase of this endeavor.
STAFF COMMENTS JANUARY 22, 2007
The Borah-West transmission upgrade is scheduled for completion prior to the Company s next
IRP filing in 2008. By that time it is anticipated that the final commitments for the McNary-Boise
transmission upgrade will have been made. This addition is expected to be complete around 2012.
Besides the Borah-West proj ect, the Company is in the final stages of the wind RFP for 100 MW
scheduled to be online by the end of2007, as well as finalizing the geothermal RFP for 50 MW
scheduled for an online date in 2009. Finally, the approved 170 MW expansion of the Danskin facility
is anticipated to be online in 2008. These additions, along with changing conditions faced by Idaho
Power regarding loads, fuel prices, and market conditions will invariably affect the Company s 2008
IRP.
STAFF RECOMMENDATION
Staff recommends that the 2006 IRP be accepted and acknowledged as submitted.
Respectfully submitted this
J),
day of January 2007.
Cecelia A. G sner
Deputy Attorney General
Technical Staff: Bryan Lanspery
i :umisc :commen ts/ipceO6 .24CgilJS
ST AFF COMMENTS JANUARY 22, 2007
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 22ND DAY OF JANUARY 2007
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-06-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
LISA D. NORDSTROM
BARTON L KLINE
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
MICHAEL J. YOUNGBLOOD
PRICING & REGULATORY SERVICES
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
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SECRETARY
CERTIFICATE OF SERVICE