20041203Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, ID 83720-0074
[phone]
[phone]
Idaho State Bar No. 3366
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Street Address:
472 W. Washington St.
Boise, ID 83720
Attorney for Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE FILING OF IDAHO
POWER COMPANY'S 2004 ELECTRIC
INTEGRATED RESOURCE PLAN (IRP).
CASE NO. IPC-04-
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Donald L. Howell, II, Deputy Attorney General, and submits the following
comments in response to the Notice of Filing and Notice of Comment Deadlines issued in Order
No. 29614.
BACKGROUND
On August 27, 2004, Idaho Power Company filed its 2004 Integrated Resource Plan
(IRP) with the Commission. 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 and demand-side
management. Additionally, the 88-page IRP document and related appendices contain
information regarding available resource options, planning period forecasts, potential resource
portfolios, risk analyses, a ten-year resource plan, and a near-term action plan. The complete
ST AFF COMMENTS DECEMBER 3, 2004
2004 IRP consists of five separate documents: the IRP document, an Economic Forecast, a Sales
and Load Forecast, a Demand-Side Management Annual Report, and a Technical Appendix.
Idaho Power requests that the Commission issue an Order accepting and acknowledging the
Company s 2004 IRP and finding that the 2004 IRP meets both the procedural and substantive
requirements of Order No. 22299.
Idaho Power worked with representatives of major stakeholders for almost a year to
develop the 2004 IRP. Members of the environmental community, major industrial customers
irrigation representatives, state legislators, Commission representatives, the Governor s office
and others formed the Integrated Resource Plan Advisory Council (IRP AC) and made significant
contributions to the Plan. The Company also solicited and received presentations from anaerobic
digestion generation proj ect developers, geothermal generation proj ect developers, wind
generation project developers, and DSM advocates. To obtain public input, the Company made
live" presentations of the draft IRP throughout its Idaho and Oregon service territory, with
public meetings in Pocatello, Twin Falls, Boise and Ontario, Oregon.
The 2004 IRP places a greater emphasis on conservation and demand reduction options
than the 2002 IRP. Following a risk analysis of 12 resource portfolios, Idaho Power selected a
diversified portfolio with nearly equal amounts of renewable generation and traditional thermal
generation as the preferred resource portfolio. It contains nearly equal amounts of renewable
generation and traditional generation as well as demand response and energy efficiency
programs. The selected portfolio will increase the Company s power supply by approximately
800 aMW and increase the capacity of the system by almost 940 MW over the 10-year planning
horizon. Of this increase, 124 MW are achieved through demand-side management (DSM).
More specifically, the balanced portfolio selected for this plan is composed of the following:
76 MW Demand Response Programs (DSM)
48 MW Energy Efficiency Programs (DSM)
350 MW Wind-Powered Generation
100 MW Geothermal-Powered Generation
48 MW Combined Heat and Power at Customer Facilities
88 MW Simple-Cycle Natural Gas Fired Combustion Turbines
62 MW Combustion Turbine, Distributed Generation, or Market Purchases
500 MW Coal-Fired Generation
Idaho Power s IRP is based on an expected increase in households within its service
territory from 320 000 today to over 380 000 by the end of the planning period in 2013.
STAFF COMMENTS DECEMBER 3 2004
In light of public input and regulatory support of the 2002 IPR planning criteria, Idaho
Power continues to emphasize a resource plan based upon worse-than-median (70th percentile)
water conditions.
The 2004 IRP presented in this filing is the Company s best current estimate of future
loads and sets forth how the Company intends to serve the electrical requirements of its native
load customers over the next ten years. While the proposed resource portfolio represents current
resource acquisition targets, the actual resource portfolio may differ from the outlined quantities
and types depending on many factors, including the response Idaho Power receives from various
Requests for Proposals that it intends to issue to acquire new renewable and DSM resources.
The 2004 IRP includes a near-term action plan that sets out specific actions to be taken by Idaho
Power Company prior to the next IRP in 2006. The near-term action plan is shown below.
Preferred Portfolio - Near-Term Action Plan (Present through 2006)
Year
August 2004
Fall 2004
2005
2006
Activity
1. 2004 Integrated Resource Plan submitted to the Idaho PUC
and Oregon PUC.
1. Idaho Power Company and Utilities CommissIons
communicate regarding IRP specifics and concerns.
2. RFP issued for 200 MW wind.
3. RFP issued for 88 MW peaking resource.
4. File DSM results as a supplement to the IRP.
5. File energy efficiency tariff rider in Oregon.
1. Demand-side measures designed and funded through
Energy Efficiency Advisory Group and the Public Utilities
CommIssions.
2. RFP issued for 12 MW CHP.
3. RFP issued for 100 MW geothermal.
4. Utility partner for seasonal-ownership coal plant identified.
1. CHP design work with successful bidders.
2. 100 MW of wind generation online.
3. 150 MW Borah-West transmission upgrade complete.
4. Ongoing DSM programs.
5. RFP issued for 500 MW seasonal-ownership coal plant.
6. 2006 IRP.
In addition to the near-term action plan, the IRP also presents a ten-year resource plan
that lays out the events and timing of resource acquisitions throughout the planning period. The
ten-year resource plan is shown below.
STAFF COMMENTS DECEMBER 3, 2004
Preferred Portfolio - Ten-Year Resource Plan
Year
August 2004
Fall 2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
ST AFF COMMENTS
Activity
1. 2004 Integrated Resource Plan submitted to the Idaho PUC and
Oregon PUC.
1. Idaho Power Company and Commissions communicate regarding
IRP specifics and concerns.
2. RFP issued for 200 MW wind.
3. RFP issued for 88 MW peaking resource.
4. File DSM results as a supplement to the IRP.
5. File energy efficiency tariff rider in Oregon.
1. Demand-side measures designed in partnership with the
Energy Efficiency Advisory Group and the Commissions.
2. RFP issued for 12 MW CHP.
3. RFP issued for 100 MW geothermal.
4. Utility partner for seasonal-ownership coal plant identified.
1. CHP design work with successful bidders.
2. 100 MW of wind generation online.
3. 150 MW Borah-West transmission upgrade complete.
4. Ongoing DSM programs.
5. RFP issued for 500 MW seasonal-ownership coal-fired
generation.
6. 2006 IRP.
1. 12 MW CHP online.
2. 88 MW Danskin expansion online.
3. 100 MW wind generation online.
4. 500 MW seasonal coal begin construction.
5. RFP issued for 62 MW combined cycle gas turbine or
distributed generation.
6. Ongoing DSM programs.
1. 100 MW geothermal online.
2. 100 MW proposed Borah-West transmission upgrade
complete.
3. RFP issued for 36 MW CHP.
4. RFP issued for 150 MW wind.
5. Ongoing DSM programs.
6. 2008 IRP.
1. CHP design work with successful bidders.
2. Ongoing DSM programs.
1. 36 MW CHP online.
2. 150 MW wind online.
3. 62 MW Combustion Turbine or peaking resource online.
4. Ongoing DSM programs.
5. 2010 IRP.
1. 500 MW seasonal-ownership coal-fired generation online.
2. Ongoing SM programs.
1. Ongoing DSM programs.
2. 2012 IRP.
1. Ongoing DSM programs.
DECEMBER 3, 2004
ANALYSIS
General Comments
Staff believes that Idaho Power s 2004 IRP is an improvement over previous plans. The
plan is more complete and the supporting analysis is more thorough and more accurate. The
Company has devoted more effort to the preparation of this plan than to other recent plans.
During the preparation of this plan, Idaho Power employed a different process to solicit
the opinions of its customers and to encourage public involvement. In the past, Idaho Power
practice was to simply invite interested persons to attend and participate in a series of meetings
during the preparation phase of the plan. This often resulted in limited participation and biased
opinions because not all customer groups were represented. Staff concedes, however, that past
participation may have been limited due to the Company s lack of need to acquire new resources
in prior plans.
For the 2004 plan, Idaho Power formed an advisory committee consisting of invited
participants representing a balance of customer groups, state agencies, and advocacy groups.
Through this process, Idaho Power received valuable guidance and feedback that it used to
develop a draft plan. By employing such a process, participation was improved, more input was
received and comments were more thoughtful. In addition, participants were exposed to the
sometimes conflicting positions of other representatives, requiring collaboration, understanding
and compromise. The disadvantage to this process was that it might have excluded those who
wished to participate but were not invited.
Once a draft plan was developed, it was released for public review and comment. The
Company conducted several workshops or meetings throughout its service territory to receive
public comment. There was minimal attendance at the public meetings and few written public
comments were received on the draft plan. Staff recognizes the difficulty in getting public
participation and comment; however, we believe it is important for customers to know the types
and costs of future generation and to express their opinions during the planning process, rather
than later when plants are being constructed.
As with the previous plan, Idaho Power finds itself faced with needing to satisfy
significant deficits in both capacity and energy. Idaho Power has considered a broad array of
both supply side and demand side alternatives for meeting its forecasted load. In this plan
demand side management programs (DSM) and pricing options playa critical role, especially in
STAFF COMMENTS DECEMBER 3 2004
the near term. Staff believes this is appropriate and will specifically address DSM and pricing
options later in these comments.
Staff is also encouraged that Idaho Power now seems to be taking its IRP seriously, and
that the integrated resources planning process is consistent with the apparent business plan of the
utility. Preparation of IRPs was never intended to be a regulatory exercise, but instead was
intended to be for the benefit of the utility as well as its customers.
Because Idaho Power has an imminent need for capacity, the majority of Staffs
comments will focus on the IRP's near-term action plan. The near-term action plan calls for
immediate implementation ofDSM programs and issuance of Requests for Proposals (RFPs) for
renewables and peaking capacity. Of the top five resource portfolios considered in the IRP, four
would have very similar near-term action plans.
Demand-Side Management and Pricing Options
In 2002 Idaho Power began collecting about $2.7 million annually for new demand-side
management (DSM) programs. This funding is in addition to prior funding for its participation
in the Northwest Energy Efficiency Alliance (NEEA) and Idaho Low Income Weatherization.
The Company also participates in the Bonneville Power Administration Conservation and
Renewable Energy Discount (BPA C&RD) program. The IRP says the Company s new source
of DSM funding has been focused toward demand response, demand reduction and energy
efficiency during summer peak periods. The Company indicates in its IRP that DSM programs
reduced its summer 2003 peak load by 189 kilowatts (kW) and saved 5 912 megawatt-hours
(MWh) .
Unlike Idaho Power s 2002 IRP, the current IRP contains estimates of significant benefits
that are obtainable from various DSM programs, six of which promote energy efficiency and two
that allow the Company to directly control demand. The IRP also says that the Company will
gather data from its recently implemented seasonal rates to assess their impact on consumption.
Although not in the IRP, the Staff is also aware that Idaho Power will soon propose a trial of
more precise time-of-use rates in some of the areas where it has installed advanced meter-reading
(AMR) facilities.
The Staff acknowledges and supports Idaho Power s renewed interest in DSM. The IRP
identifies significant potential for both cost-effective DSM and cost based variable pricing that
should make customers better off than simply acquiring more supply-side resources.
ST AFF COMMENTS DECEMBER 3 , 2004
Idaho Power worked with its Energy Efficiency Advisory Committee (EEAG) and
outside consultants to identify potential cost-effective DSM programs in the four major customer
classes, i.e. residential, commercial, industrial and irrigation. The Company says it pre-screened
potential options and then used the Aurora Electric Market Model to assess DSM impacts on
power supply costs.
Idaho Power says it used cost-effectiveness as an absolute screening criterion and that
customer focus, customer class distribution, and earnings neutrality were used as guidelines for
additional screening. As a result of the screening process, the following eight programs were
determined to be cost-effective and to sufficiently satisfy the other criteria:
Over-Demand Yf.Yf.9- year year 9- year Particip.IPC Net
all Response Peak Avg.Present IPC $IPC $Cust.Net Total
DSM Programs Value IkW IkWh Payback Uti I. Rsrc.
Rank Selected IPC'/Mo.(years)B/C B/C
Costs Ratio Ratio
(mill.
Irrigation 30.4 $17.$ 4.1.4
Peak
Clipping
Air 45.2 $29.$ 5.1.3 1.7
Condi ti oning
Cycling
Efficiency
Programs
Selected
Commercial 1.0 $ 3.$10.$0.051 6. 8 Yfs.
New
Construction
Irrigation 26.$18.3 $ 6.4 $0.039 0 Yfs.
Efficiency
Industrial 10.$15.$12.$0.020 8 Yfs.
Efficiency
Residential 1.7 $ 4.$ 5.$0.036 5 Yfs.
New
Construction
I Selected Total 124.0 1 18.
I $89.
STAFF COMMENTS DECEMBER 3 2004
Over-Efficiency Yf.Yf.9- year 9- year 9- year Particip.IPC Net
all Programs Peak Avg.Present IPC $IPC $Cust.Net Total
DSM Not Value /kW /kWh Payback Util.Rsrc.
Rank Selected per IPC'/Mo.(years)B/C B/C
year Costs Ratio Ratio
(mill.)
Commercial 15.$17.$10.$0.024 8 Yfs.4.3
Existing
Constructi on
Residential 17.$23.$12.$0.034 6.4 Yfs.
Existing
Constructi on
1 Cost-
Effective Total 156.38.
I $130.
The two demand response programs were analyzed outside of the Aurora model for
technical reasons but were selected by the IRP because they were cost-effective based on their
dispatchability and peak reducing benefits. The demand response programs were estimated by
Idaho Power to have among the lowest levelized costs per kilowatt (kW) of demand per month of
all of the pre-screened DSM resources. However, the Staff notes that these two programs were
nevertheless estimated to have among the lowest Idaho Power net utility benefit/cost (B/C)
ratios.
Idaho Power s analysis showed that all six of the energy efficiency options reduced its
long-term power supply costs. Ultimately, the Company selected only the top four ranked
efficiency programs as programs to be actively pursued in addition to the two demand response
programs. The two efficiency programs that were not selected are the Commercial and
Residential Existing Constructions, which the Company estimated would have net utility B/C
ratios of 4.3 and 3., respectively. Staff notes that Idaho Power s estimated utility B/C ratios for
these two programs that were not selected are higher than those for the two demand response
programs that were selected. While Staff acknowledges that dispatchability and peak reduction
benefits are important, we are concerned that Idaho Power did not select two major DSM
programs that its modeling demonstrates are very cost-effective and will provide over 36 MW of
peak load reduction.
STAFF COMMENTS DECEMBER 3 2004
The IRP says that the two existing construction programs were not selected because 1) it
was felt that better options may be identified through the ongoing energy efficiency assessment
analysis and 2) it felt that implementing more than the six programs that it did choose would
cause too many operational challenges. Staff believes that while each of these stated reasons
may independently have merit, together they seem somewhat contradictory. Upon further
questioning of why the IRP did not select two of the cost-effective DSM programs, Company
managers have responded that they may feel more comfortable pursuing more DSM if and when
the Company is allowed a significant increase to its DSM tariff rider (currently about 0.5%); if
the issue of fixed-cost revenue losses due to DSM is favorably resolved; after DSM programs are
fine-tuned; and after DSM ramp-up is further along. Company managers also noted that new
construction DSM is more important than DSM for existing buildings because the "lost
opportunity" associated with the latter is not as significant as with the former. While Staff does
not necessarily dispute the validity of these responses, we are concerned that Idaho Power may
be neglecting effective DSM programs that could provide least-cost resources to its customers.
The Northwest Power and Conservation Council's (NWPCC) recently released draft
power plan suggests that there may be a much higher level of cost-effective DSM potential in
Idaho Power s Service territory than Idaho Power s IRP has identified. Specifically, the draft
NWPCC plan suggests that regionally there may be 700 aMW of cost-effective conservation
potential within the next five years. Idaho Power s presumed share of that potential might be
about 45 aMW compared to the IRP's estimates for 2009 of 10 aMW for programs selected and
an additional 10 aMW for the two programs not selected.
However, the NWPCC calculations, in addition to individual utility DSM programs
include efforts that are largely outside the control of Idaho Power, such as building codes
appliance standards, NEEA' s market transformation programs and naturally occurring
conservation efficiency gains. Also, Idaho Power s 20 aMW potential identified in its IRP does
not include its Low Income Weatherization, its BP A C&RD programs, nor its participation in
NEEA. Staff is aware that Idaho Power intends to file a supplement to its IRP that will identify
additional DSM potential.
Idaho Power anticipates that some of the energy efficiency and demand response
programs will be chosen through competitive bidding. It also intends to have program
evaluations done by independent evaluators chosen through competitive bidding.
STAFF COMMENTS DECEMBER 3, 2004
Staff considers Idaho Power s DSM and pricing efforts in this IRP and in other cases yet
to come before the Commission to be works-in-progress. Overall, Staff supports Idaho Power
multiple steps toward increasing the roles of energy efficiency, demand response and variable
pricing in meeting its customers' demands.
Requests for Proposals (RFPs)
Acquisition of generating resources in the IRP is expected to be accomplished by issuing
RFPs. The preferred portfolio calls for the release in late 2004 of one RFP for 200 MW of wind
power and one RFP for 88 MW of gas-fired peaking capacity. The preferred portfolio also calls
for additional future RFPs seeking to acquire an additional 150 MW of wind, 100 MW of
geothermal generation, and 12 MW of Combined Heat and Power (CHP). Because the IRP is
built upon acquisition of new resources through RFPs, the entire viability of the IRP is dependent
on the success of the RFP process.
Staff believes that the structure of the RFPs will be crucial. Staff has some concern about
whether the RFPs will be successful in attracting enough proposals to insure that desired
resources can be acquired at a location, in sufficient quantity and at a price that is acceptable to
Idaho Power. An RFP that is structured too narrowly may restrict such things as the number of
qualified bids due to the size and location of renewable resource within Idaho Power s service
territory, timing differences between when resources are needed and can be developed, and
transmission constraints that limit access to some resources. The RFPs for renewables should
accommodate on-line dates that permit projects to take advantage of the recently renewed federal
production tax credits. As it now stands, the federal production tax credit for renewables is set to
expire at the end of2005, yet the IRP calls for wind generation to come online in 2006.
Staff also has questions about how responses to the RFPs will be evaluated. For
example, how will Idaho Power decide whether bids are too expensive? What other alternatives
will renewables be compared to? How will renewables be compared to CHP? How will
different types of renewables with different generation characteristics, different locations or
different on-line dates be compared? Clearly, these questions will eventually have to be
answered, but the answers are not contained in the IRP.
If the RFPs are unsuccessful in attracting viable bids, doing nothing is not an option.
Idaho Power s load will not stop growing. The ability ofDSM and pricing options to counteract
load growth is limited. The Company is also constrained in its ability to import power during
STAFF COMMENTS DECEMBER 3 , 2004
peak demand periods. As a result, Idaho Power must have a back-up plan. Staff would like to
see greater attention paid to identifying alternate scenarios, and contingency plans developed in
the event RFPs do not produce the desired results. Otherwise, the timing of Idaho Power s need
could relegate natural gas generation as the only other realistic short-term option. Gas-fired
generation would probably be the only resource with short enough lead times and enough
certainty in its output to meet such immediate needs. As we have seen, reliance on gas-fired
generation exposes a utility and its ratepayers to volatile fuel prices. Staff is concerned that gas-
fired generation may become the resource of choice simply by default.
The preferred portfolio, and in fact all of the top-ranked portfolios, must represent
resources that are actually available. The RFP results will confirm whether these resources are
in fact, available at the costs, quantities and locations assumed in the 2004 IRP.
Renewables
Renewables, specifically wind and geothermal, are expected to satisfy a substantial
portion of Idaho Power s generation needs in the future. Because of this, Staff believes Idaho
Power should begin to independently investigate the costs and availability of these resources.
There is a danger in relying on the claims of a few developers about cost and availability of
renewables within Idaho Power s service territory. There is no guarantee that these developers
projects will prove cost effective, large enough, or competitive with other alternatives.
Similarly, modeling wind generation using only the actual data provided by one wind developer
is risky and could lead to inaccurate assumptions about wind. Staff would be interested in seeing
the Company perform a wind integration study to determine the amounts of wind generation that
could be integrated into its system and the expected costs of integration. Such a study needs to
be done before Idaho Power makes a large commitment to wind.
Staff is also concerned about project siting and the possible disparity between wind
proj ects that qualify for PURP A rates and those that do not. Current PURP A avoided cost rates
exceed the cost assumptions in the IRP for renewables. Staff sees little incentive for bidders in
the RFP to bid prices less than current PURP A rates if the wind project is a Qualifying Facility
under PURPA. Bids for other wind projects in the region are now being accepted for
significantly less than Idaho s PURP A rates. Staff suggests that it would be more appropriate for
future PURP A rates and policies to establish the ceiling for renewables cost, rather than the
floor.
STAFF COMMENTS DECEMBER 3, 2004
Transmission
Transmission constraints appear to drive many of the alternatives considered and some of
the resource choices ultimately made in the IRP. Transmission constraints from the Northwest
in particular, present the greatest problem because they restrict access to regional markets and
prohibit consideration of resources located to the west of Idaho Power s system. Moreover
transmission constraints hamper Idaho Power s ability to consider development or expansion of
jointly owned thermal projects.
Staff would be interested in a more thorough study to assess just how much of a
transmission "penalty" the Company and its ratepayers are paying and how much more severe
the penalty has to get before transmission upgrades make sense on the west side of Idaho
Power s system. The IRP does include a plan to upgrade transmission on the Borah-West path
as early as 2006 in order to provide access to expected renewable resources. The IRP is not
clear, however, as to why the Company is so quick to upgrade this path but seems to simply plan
around constraints to the Northwest that limit access to west-side resources and markets. While
Staff is not necessarily opposed to transmission upgrades or renewables, it seems somewhat
presumptuous to proceed with east side transmission upgrades before renewable RFP results are
known. Similarly, Idaho Power should continue to actively participate in the Rocky Mountain
Area Transmission Study (RMA TS) to assess whether even greater long-term transmission
additions on the east side of Idaho Power s system make sense in order to access wind and coal-
fired resources in eastern Idaho, Wyoming and Utah.
According to the IRP, each of the final candidate portfolios considered would eliminate
the transmission overloads from the Northwest that would otherwise occur. Staffbelieves the
IRP should indicate how a northwest transmission upgrade would compare to the other
portfolios, even if a transmission upgrade is more costly.
Finally, transmission upgrade costs should be taken into account and assigned fairly in
the evaluation of all potential new resources based on their location. If transmission upgrades
are necessary to gain access to renewables on the east side of Idaho Power s system, for
example, those costs should not be overlooked in considering the cost effectiveness of those
resources.
STAFF COMMENTS DECEMBER 3 2004
Baseload Thermal Generation
Idaho Power s long-term action plan calls for the release in 2006 of an RFP for a seasonal
ownership of a 500 MW coal plant to be located within the Company s service territory. The
coal plant would have an online date of20ll. A coal plant has never been included in an Idaho
Power Company IRP before, since the IRP process was initiated in 1989. Because coal plants
are new to the IRP, Staff believes the Company must carefully investigate issues surrounding
coal. The siting and permitting process for a greenfield coal plant within Idaho could be arduous
and lengthy. Given the apparent shift of other western utilities towards coal, the availability,
price and transportation of fuel must also be thoroughly investigated.
Because of the likely difficulties of siting a coal plant in Idaho, the Company should also
begin seriously studying alternatives such as additions to Bridger or Valmy, or joint ownership
of other future coal plants that may be constructed in the region along with necessary
transmission facilities. Finally, coal generation technology is rapidly advancing, and cleaner
more benign types of coal-fired plants will likely be available in the coming years. Integrated
Gasification Combined Cycle (IGCC) plants for example, are still currently more expensive than
pulverized coal plants, but they are much more environmentally friendly. Some utilities have
recently announced plans to employ this technology in new plants to be constructed in the not
too distant future. Idaho Power should closely monitor this technology as it develops.
Risk Analysis
In Staff s opinion, risk analysis is one of the most important elements of integrated
resource planning. Idaho Power has performed some risk analysis to evaluate candidate
portfolios, however, Staff believes a more thorough analysis would have been desirable. For
example, the initial twelve portfolios were analyzed and ranked under only four different
scenarios, with only one set of expected gas prices used in each scenario. In addition, the
probabilities assigned to the various scenarios in the final portfolio analyses seem arbitrary.
Staff recognizes that the Company was still developing modeling skills and tools during the
preparation of this IRP, but expects that those skills and tools should be more fully developed
before the next IRP cycle.
Nonetheless, the risk analysis that was performed confirms that over-reliance on gas-fired
generation is risky and should be avoided. Staff also believes it is noteworthy that the risk
analysis does not change ranking of the top three portfolios. Most important however, is the fact
STAFF COMMENTS DECEMBER 3 , 2004
that the risk analysis summary shows that while the preferred portfolio has the lowest power
supply cost, it is only 3.6 percent lower than the no-coal portfolio and about five percent less
than the highest cost portfolio. This result, Staff contends , demonstrates that estimated costs for
most reasonable portfolios are similar given the accuracy of cost data available today, and that
the exact composition of the portfolio that is ultimately developed may come down to issues
other than cost.
Portfolio Selections
As part of the IRP development process, the twelve initial portfolios considered in the
IRP were assembled with the assistance of the IRP Advisory Committee. Although Staff
applauds the Company for establishing the Advisory Committee and using it to assist in
developing IRP portfolios, we still believe it likely that a more systematic approach combined
with appropriate risk analysis would likely generate more optimum portfolios in terms of low
cost and risk.
The preferred portfolio consists of a balanced mix ofDSM, renewables, gas and coal-
fired resources. While Staff acknowledges that the preferred portfolio ranked highest both
before and after risk analysis, we believe it is possible that an even lower cost portfolio may exist
that is still low risk. The results of upcoming RFPs should help Idaho Power to refine its
resource cost and availability assumptions and perhaps enable it to devise an even more
attractive portfolio.
RECOMMENDATIONS
Staff recommends that Idaho Power s 2004 IRP be accepted and acknowledged.
Respectfully submitted this 3) day of December 2004.
Donald L. well, II
Deputy Attorney General
Technical Staff: Rick Sterling
Lynn Anderson
i:umisc:comments/ipceO4.18dh.rpsla
ST AFF COMMENTS DECEMBER 3 2004
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SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-04-, BY MAILING A COpy THEREOF POSTAGE PREPAID TO THE
FOLLOWING:
BARTON L KLINE
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
GREGORY W SAID
DIRECTOR REVENUE REQUIREMENT
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
SECRETARY
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