20111114SRA Comments.pdf

RECEI D
Comments of the Snake River Allance 20r I NOV 14 P
On Idaho Power Company's 2011 Integrated Resource Plan (lRP) M 4: 19
Submitted by
Ken Miler, Clean Energy Program Director, Snake River Allance
November 14, 2011
The Snake River Allance appreciates the opportunity to submit these comments to the Idaho
Public Utilties Commission in docket IPC-E-11-11, Idaho Power Company's 2011 Integrated
Resource Plan (IRP), on behalf of its members, many of whom are customers of Idaho Power.
The Snake River Allance (Allance) is an Idaho-based non-profit organization, established in
1979 to address Idahoans' concerns about nuclear waste and safety issues. In early 2007, the
Alliance expanded the scope of its mission by launching its Clean Energy Program. The Allance's
energy work includes advocacy for renewable energy resources in Idaho; expanded energy
efficiency, demand response and other demand-side management programs offered by Idaho's
regulated utilties and the Bonnevile Power Administration; and development of local, state,
regional, and national initiatives to advance sustainable energy policies.
The Allance appreciates Idaho Power's invitation to participate in the 20111RP Advisory
Council (IRPAC). We believe Idaho Power has, over the years, developed a meaningful and
productive IRP process and that the company and its IRPAC have worked dilgently and
productively in producing the 20111RP that is before the Commission for review and possible
acceptance. As with the 2006 IRP (and 2008 IRP Update) and the 2009 IRP, this Plan represents
continued improvements to Idaho Powers integrated resource planning process.
The Allance recommends that the Commission accepts Idaho Power's 2011, but with several
reservations as outlined below. Notably, while we support Idaho Power's preferred portfolio for
Period One (2011-2020), we do not support the company's alternate portfolio (Portfolio 1-4
SCCT), which the company proposes in the event the Boardman to Hemingway transmission
line that is the heart of Preferred Portfolio 1-3 does not materialize. Furthermore, as discussed
in more detail below, we do not believe Idaho Power in this IRP has sufficiently addressed the
future of its coal-fired generation fleet and specifically the environmental and economic risks
associated with Idaho Power's continued dependence on coal-fired generation for such a
significant portion of its overall supply-side portfolio. We recommend that the Commission
direct Idaho Power to perform a more extensive analysis of its coal resources as a requirement
for acceptance of its 2013 IRP. Also, as mentioned below, we are disappointed in the lack of
non-QF renewable resources in the first 10 years ofthis IRP.
THE PREFERRED PORTFOLIOS
Idaho Power's Preferred Portfolio 1-3, based primarily on the proposed Boardman to
Hemingway transmission project, is reasonable in the current resource planning environment
and adequately balances cost, risk, and environmental concerns. The Alliance's preference in
utilty resource planning is always biased in favor of non-wires alternatives and against
development of new large fossil fuel supply side resources. However, we recognize the need
for additional transmission from Idaho Powers control area to the Pacific Northwest to address
congestion and reliability issues facing existing transmission infrastructure. If built, we expect
Boardman-Hemingway will be a valuable resource to access Northwest markets for off-system
purchases and sales and also for system stabilty and reliabilty. In addition, we presume B2H
wil enable Idaho Power to more easily integrate additional renewable resources into its system
by virtue of the expanding flexibility presented by markets outside Idaho Power's control area.
We concur with Idaho Power that east-side off-system purchases are not preferred given their
cost during the peak times when Idaho Power would need to acquire the additional energy. The
well-known summer-winter peaking synergy between Idaho Power's control area and the
Pacific Northwest markets fits well if it is determined that market purchases are the primary
resource for the first 10 years of the planning period.
We continue to harbor the concerns we raised during the IRPAC process about the escalating
cost and contingencies for the B2H project (from the $634 millon estimate in the 2009 IRP to
the $820 milion estimate in the 2011IRP) and also about its timeline in light of the ongoing
land use planning process, environmental reviews, and the properly required reviews by
Oregon regulators. We question the decision to reduce the Boardman-Hemingway contingency
estimate from 30 percent to 20 percent "because of the higher level of project definition and
detail, and increased level of confidence in the line location and the engineering and design
aspects ofthe project" (P. 54). We agree that more is known about this project than in the 2009
IRP, but we also note that estimating the cost of this project, which is still in its formative stage,
has proven exceedingly difficult. In light of Idaho Power's acknowledged "significant increases
in material prices and construction costs, primarily due to increased material and labor prices
and line-route modifications to move the routing away from agricultural land" (P. 53), we
recommend that the Commission postpone a decision to reduce the contingency estimate until
the 2013 IRP.
While we understand there will be a demand by third parties for transmission services such as
B2H to meet state renewable portfolio standards and for other purposes, we are nonetheless
concerned about the ability of Idaho Power to subscribe the portion of the line not needed by
the company and the impacts that unknowns such as Idaho Power's peak summertime need for
B2H as well as ownership levels in the project may have on the project's cost and timing.
With regard to Alternate Portfolio 1-4 for the first 10-year period, we cannot support a portfolio
that is so long in natural gas-fired simple-cycle combustion turbines (434MW) to meet capacity
deficits in the event B2H is not built or is significantly delayed. This is especially true in light of
Idaho Power's position that implementing Portfolio 1-4 in Period One might trigger a cascade of
decisions for Period 2 that could replace possible renewable resources with additional regional
transmission investments (APPLICATION, P. 4). The Allance is among proponents of Portfolio 1-
1 (Sun & Steam) and appreciates Idaho Power's decision to model the portfolio as proposed by
the Allance and other conservation interests. We believe Portfolio 1-1 as well as 1-2 (Solar) and
1-7 (Balanced) are more appropriate substitutes in the event Preferred Portfolio 1-3 does not
materialize in a timely fashion. While we understand current gas markets favorably position
investments in natural gas resources at the present, we repeat concerns we raised in past Idaho
Power IRPs that such large-scale additional investments in gas-fired generation present
potentially significant cost and environmental risks to the company, its customers, and its
shareholders. As has been recommended to the Oregon PUC in Idaho Power's 2011IRP, we
recommend the Idaho Commission explore alternatives to accepting Portfolio 1-4 as a fallback
to Portfolio 1-3. This is especially true in light of the relatively short planning and construction
time for SCCT plants and the fact that Idaho Powers next IRP is a short two years away. We
expect that by the time Idaho Power were to build a new gas peaking plant (2016 or beyond),
prices for alternate resources such as solar PV or solar thermal wil be even more competitive
with natural gas plants than they are today.
Finally, we are pleased that the 10 portfolios in the 2021-2030 timeframe were analyzed by
coupling them with the single preferred portfolio for the 2011-2020 period.
GREENHOUSE GAS EMISSIONS AND CARBON REDUCTIONS
The Allance appreciates that Idaho Power is tracking possible federal carbon cost and penalty
trends. The IRP acknowledges Idaho Powers Board of Directors' September 2009 "guidelines to
establish a goal to reduce the C02 emissions intensity ofthe company's utilty operations" as a
result of the May 2009 IDACORP shareholders vote (P. 6). It appears, however, that the
emissions have been partially stabilzed rather than significantly reduced, although even that
characterization is difficult to determine given the short time-frame since Idaho Power
announced its efforts to address greenhouse gas emission intensities. The company's carbon
reduction efforts to date may be due to a number of factors, including how various hydro
conditions affect the operations of Idaho Power's hydropower generation and in turn how that
affects the operations of the coal plants. It is disappointing that the IRP does not better
position the company for more ambitious carbon reduction plans. In fact, the current carbon
reduction strategy seems predicated largely on changing hydropower operations, increased
cloud seeding, new or expanded water leases and the like. The draft acknowledges as much on
P.6:
'This reduction in intensity relative to the 2010 level reflects an increase in hydro
generation as a result of the current water conditions, and reduced coal-fired
generation. "
That indicates that trends in Idaho Power's carbon emissions intensity are episodic and
dependent in part on hydro conditions over which the company has little control. The numbers
during low-water years would presumably be far different if Idaho Power was forced to rely
more on its company-owned thermal generation and market purchases, for which the "green"
versus "brown" power imports are difficult if not impossible to ascertain.
Other than reducing its reliance on its coal fleet during times of abundant water supply, there is
insufficient evidence that Idaho Power is dedicated to pursuing reduced operations of the coal
fleet with a goal of reducing greenhouse gas emissions (as opposed to reducing coal operations
coincident with times of high hydro production). For instance, the IRP at P. 6 refers to the 2009
Board of Directors action this way:
"In September 2009, Idaho Power's Board of Directors approved guidelines to establish a
goal to reduce the C02 emissions intensity of the company's utilty operations. The
guidelines are intended to prepare the company for potential legislative and or
regulatory restrictions on greenhouse gas (GHG) emissions, while minimizing the cost of
complying with such reductions on Idaho Power's customers./I
This seems to blur the issue if not the company's intent. It was not the intent of the
shareholders in 2009 to "minimize the cost of complying with such reductions on Idaho Power's
customers." It was unambiguously the intent of shareholders that Idaho Power reduces its
carbon emissions. The Allance recommends the Commission take notice of the Company's
commitment - or lack of it - to make serious reductions in its greenhouse gas emissions beyond
those that are attributable to hydro conditions that make reduced coal operations possible.
To its credit, Idaho Power models its resource portfolios with an eye to a possible C02
emissions adder price. However, this IRP seems to reduce the $43 per ton cost (in 2009 U.S.
dollars) GHG adder (P. 72, 2009 IRP) to $20 per ton (P. 73, 2011IRP). The political changes in
Congress notwithstanding, this can be interpreted as Idaho Power anticipating a lower
probability offuture carbon costs due to political reasons. As a result, a lowered GHG price has
downstream impacts such as affecting portfolio costs and calculations. Estimated carbon adder
prices are not an exercise in abstract resource planning: They can have direct impacts on how
portfolio costs and risks are allocated, and they can illustrate "tipping points" at which dispatch
of high-carbon resources such as coal becomes uneconomic. The 2011IRP does not shine light
on the reasoning behind such a dramatic reduction in Idaho Power's "expected case" GHG
adder, and the Alliance recommends that the Commission direct Idaho Power to more clearly
explain the reasoning behind its anticipated reduction in the per-ton carbon adder from the
2009 IRP to the proposed 20111RP.
COAL AND COAL PLANT OPERATIONS
The Allance raised this issue in comments on the 2009 IRP and continues to be concerned
about whether Idaho Power's 2011IRP reflects the risks we believe are associated with what
seems to be a business-as-usual approach to the operations of the 1,100MW of coal-fired
generation in which the company has an interest. Idaho Power in 2009 took a hands-off
approach to whether the Boardman coal plant in Oregon would be decommissioned early, even
though it and its customers had a direct financial interest in the plant's future. That decision has
now been made for Idaho Power, inasmuch as Portland General Electric has decided to retire
Boardman ahead of its expected 2040 decommissioning. The same approach seems to have
been taken with regard to Idaho Power's assets at Bridger and Valmy. We acknowledge that
Idaho Power does not manage these coal plants and does not control whether its Wyoming and
Nevada coal assets are decommissioned or retrofitted and in what time-frame. But that does
not mean Idaho Power cannot exhibit more of a leadership role in what is now a region-wide
drift away from coal-fired power plants in favor of efficiency, renewables, and in some cases
even natural gas.
It took until this IRP for Idaho Power to acknowledge - and plan for - what was viewed
regionally as the inevitable early decommissioning of Boardman. We are particularly troubled
with the observation that "Though coal-fired power plants require significant capital
commitments to develop, coal resources take advantage of a low-cost fuel and provide reliable
and dispatchable energy. Coal supplies are abundant in the Intermountain Region and are
sufficient to fuel Idaho Power's existing plants for many years to come.//(P. 49).
Plant modifications required to meet air-quality standards for Boardman are scheduled for
2011, 2014, and 2018, while modifications at Bridger are scheduled for 2015, 2016, 2021 and
2022 (P.68). These modifications are enormously expensive, and customers wil be saddled with
a continuing investment in an unsustainable resource. In the case of North Valmy alone,
documents filed in Idaho Power's 2011IRP case in Oregon place the cost of installing a scrubber
on Valmy Unit 1 at about $250 milion - more than twice the cost of Idaho Power's new
300MW langley Gulch gas-fired power plant at New Plymouth. The Alliance believes that a
utilty IRP shçlUld explore in detail the least-cost and least-risk resource alternatives, be they
retrofitted coal plants or renewable energy resources or DSM investments.
This is important to this IRP and to the 2013 IRP because as each year passes, utility owners of
coal-fired power plants face important decisions on whether to prepare to retire those plants in
the face of increasingly expensive environmental control requirements or whether to make
those investments as sunk costs with the knowledge that the plants pose escalating risk to
utilty customers who must bear the costs of maintaining these aging coal fleets. As the
Commission knows, PacifiCorp/Pacific Power/Rocky Mountain Power is currently facing
extraordinary scrutiny as utilty regulators and stakeholders in Utah and Oregon scrutinize the
utility's coal plant investments and operational plans in the years to come. Pacific Power faces
having to perform a detailed cost-benefit analysis on each of its 26 coal plants in order to have
its current IRP acknowledged by the Oregon PUC. The company may face a similar requirement
in Utah as its IRP is processed there. PacifiCorp faces more than $4 bilion in future coal plant
investments that will be required to keep its coal fleet in conformance with state and national
environmental standards over the coming three decades. These investments wil have direct
impacts on Rocky Mountain Power's Idaho customers, just as similar investments will have
direct impacts on Idaho Power's customers.
The Allance is not requesting that the Idaho Commission direct Idaho Power to conduct such
an analysis for purposes ofthis IRP. We are, however, requesting that the Commission direct
Idaho Power to prepare such an analysis as part of its 2013 IRP. The IRP is the proper place to
determine the validity of a utility's resource choices and its portfolio, and in the case of Idaho
Power that analysis continues to be lacking. Until such an analysis is performed, utilty
customers cannot know whether their dollars are being spent on the most cost-effective and
least-risk energy alternatives. The IRP docket and the next rate case docket are the two forums
most suitable for a more detailed analysis of how a utilty's "business as usual" approach to the
management of its coal portfolio affects ratepayers today and well into the future. Every dollar
that is spent by a utilty to keep a coal plant in conformance with environmental standards is a
dollar that is diverted from new energy efficiency and other clean energy investments. And as
each year passes, these sunk investments into coal plants add to the rate burdens placed on
utility customers. Just as the Commission did in past IRP acceptance orders alerting utilties to
its concerns about mounting reliance on natural gas plants, so it should in the case of utility
reliance on coal-fired power generation. The Alliance believes that, when thoroughly accounted
for in terms of risk and cost-benefit, many of these coal plants in Idaho Power's portfolio will
not pass prudency muster when compared to investments in cleaner alternatives. As a result,
Idaho's regulated electric utilities should be required to more thoroughly justify their
investments to keep their coal plants within regulatory approvaL.
Rather than develop an exit strategy, Idaho Power in this IRP seems to be planning an extended
marriage to a generation resource that is being shunned by most utilties in the Pacific
Northwest. The massive investments in coal plant environmental improvements fly in the face
ofthe environmental and risk-avoidance advantages of decarbonizing Idaho Power's resources,
and in our view these coal plant investments continue to place the company, its shareholders,
and its customers at risk. The longer this issue is kicked down the road and into future IRPs and
rate cases, the more ratepayer dollars wil be misdirected at the expense of more prudent least-
cost supply side and demand side investments.
IDAHO POWER'S OREGON PUC DOCKET
As mentioned above, in conjunction with the Idaho PUC case, Idaho Power is seeking
acknowledgement of its 20111RP by the Oregon Public Utilties Commission (OPUC). The
Alliance presumes the Idaho Commission is aware of the proceedings in Oregon, but wants to
include some of the highlights in that case because they bear directly on the Allance's requests
in this case. For reference, Idaho Power's 20111RP before the Oregon PUC is designated LC 53.
In the Oregon proceeding, the Citizens' Utilty Board of Oregon (CU B) and the Renewable
Northwest Project (RNP) have raised issues that are similar to those raised by the Allance
relative to Idaho Power's coal assets in this proceeding. In Idaho Power's reply comments to
opening comments by CUB and RNP, the company objects to CUB's request that the OPUC
direct Idaho Power to conduct "a unit-by-unit analysis and comparison of clean air investments
versus plant retirement and modeling of early plant closures to evaluate overall system
impacts./I RNP also asks the OPUC to require Idaho Power to "analyze the costsand risks of
maintaining its coal plants and how carbon costs and environmental regulations could alter
their cost-competitiveness in the future."
Of importance in this case is Idaho Power's argument in the Oregon case that a unit-by-unit
analysis at this point would be speculative. More precisely, according to Idaho Power's OPUC
filng: "The Company requests that the Commission reject CUB's request to withhold
acknowledgment of this IRP pending the completion of this analysis and instead include a
requirement that the Company's next IRP, which wil be filed in 2013, include the requested
analysis. /I
In addition, Idaho Powers OPUC reply comments at P. 5 state: "The company intends to use
third-party consultants, in conjunction with studies conducted by the operators of the coal
plants as well as internally generated analyses to evaluate environmental compliance costs
associated with its coal plants. At this time, Idaho Power anticipates that it wil use these
analyses as part of preparing its 2013 IRP. /I
That being the case, and if Idaho Power is committing to the OPUC that it wil conduct such
analyses, the Alliance believes it is appropriate in light of its arguments above that the IPUC
place a similar requirement on the company as it prepares its 2013 IRP for submittal to the
Commission. The company has committed to Oregon regulators to perform such an analysis,
and it stands to reason that the analysis should be part of the record in this proceeding.
PUBLIC POLICY and POLITICAL, REGULATORY AND OPERATIONAL ISSUES
With regard to new large loads (P. 8), we share the company's frustration at having to
accommodate such loads on short notice when would-be customers approach the state with
possible relocation plans, rather than work with the utilities on a time frame that allows the
utilties to best plan to accommodate these large loads. We do not believe Idaho Power should
be placed in a position in which it stands ready to meet new load on very short notice outside
of its planning processes. Rather, we would like to see a system in place in which the state has a
more effective process in which utilities can be apprised well in advance of possible new large
customers seeking service. Regardless, for the sake of existing customers, we believe such new
large loads should not immediately be granted embedded rates, which would shift the cost of
meeting these large loads to all customers. We believe the "Hoku model" is reasonable in
allowing new customers and Idaho Power the flexibilty to accommodate new load in part with
marginal-cost pricing while working to phase that load into rates over time.
As important, we are not convinced of the value of adding an additional 80MWof capacity from
a SCCT gas plant at a cost of $60 millon, regardless of the potential of using that generation for
surplus sales "to help offset the fixed costs of ownership" (P. 9). Absent a need for the
additional generation, we fail to see how such a large investment can survive a prudency
review. If the Commission is interested in exploring the concept of adding new generation to
meet an unknown new demand, we recommend a docket be opened or a workshop convened
to provide for ample stakeholder participation and review. Absent a more rigorous analysis of
the need for an additional 80MW of peak-hour load to be met by generation from unknown
resources, we do not believe such an expenditure can be considered prudent. If the
Commission disagrees and believes Idaho Power has provided ample evidence for this added
but unidentified load, we would recommend that the bulk of the 80MW be met not with supply
side resources but rather with expanded DSM resources.
On the issue of asset ownership (P. 9), we have commented in the past on our desire to see
Idaho Power's resource portfolio ownership become more diversified. Under current practices,
Idaho Power has an acknowledged bias toward company-owned thermal and hydropower
generation while entering into power purchase agreements for much ofthe balance. We note
that 86 percent of Idaho Power's electricity supply comes from company-owned hydro, gas,
and coal resources (P. 25), and that seems unusually high. We are aware ofthe impacts PPAs
might have on Idaho Power's debt and credit rating (P. 9), yet we believe the time has come for
Idaho Power to exhibit more leadership by developing some of its own renewable generation.
So long as the company adheres to its strategy of owning only hydropower and coal or gas
generation resources, it cannot begin the inevitable process of developing its own renewable
resources.
Regarding emissions offsets (P. 9), we urge Idaho Power to exhibit great caution in relying on
purchases of such offsets with the goal of reducing exposure to future carbon regulations.
While we see value in emissions offsets in some cases, Idaho Power customers expect their
power to come from renewable resources more than from purchasing the equivalent value of
carbon reductions elsewhere. For the time being, we believe robust investments in renewable
energy and energy efficiency wil serve the same role as investments in offsets. Regarding Idaho
Power's proposal in the IRP (P. 10) that "it should be able to recover the cost of purchasing
emissions offset options as well as the cost of any emissions offsets purchased," we believe this
kind of policy is very premature. Idaho Power is under PUC order to sell its renewable energy
credits (RECs) for the time being, absent any federal requirements that might require REC
ownership by utilities and return the sale proceeds to customers and shareholders. Similarly,
since there is no requirement for Idaho Power to possess emissions offsets, it is premature for
the company to consider purchasing them and attempting to recover the costs from customers.
We recommend the Commission explore the emissions offsets issue in more detail separate
from this proceeding.
Idaho Power discussed a possible solar pilot project in its 2009 IRP, and it is doing so again in
this IRP (P. 10-11). We are disappointed that plans for a solar project have not already borne
fruit, and believe Idaho Power must make this a priority or this potentially important
contribution to the IRP could again fail to materialize. In that this is a pilot project, we do not
believe Idaho Power should wait until solar prices reach a "sweet spot" to embark on the pilot.
We are encouraged that an RFP "to design and construct a 500kW-1MW solar PV resources to
be located in Idaho Power's service area" is contemplated before the end of this year, and we
recommend the Commission take notice of this commitment in its IRP acceptance order so that
we can avoid the kind of schedule creep that has befallen solar pilots in the past. We also
encourage consideration of additional pilots similar to this one, whether they are in the IRP or
not. If there are concerns that the project cost is greater than the PUC may allow for recovery
purposes, then we would recommend Idaho Power suggest the use of other resources, such as
proceeds from the sale of excess S02 allowances, as alternative funding sources.
Also in the IRP's solar demonstration project discussion as it pertains to the treatment of RECs
at P. 11, we question the basis for the IRP's claim that, "In general, a majority of Idaho Power's
customers support this policy, as 95 percent of the revenue from the sale of RECs is returned to
customers to keep rates low." This may be an assumption on the company's part as there are
no references to any customer surveys on this issue. That's all the more relevant given the very
next sentence in this section: "However, there is a growing segment of customers who desire,
and are wiling, to pay a premium for, green energy."
We believe the IRP's discussion ofthe Idaho Strategic Energy Allance (P. 13-14) falls short of
accurately representing the constitution of the ISEA's Board of Directors. The IRP says on P. 14
that "The Alliance is governed by a board of directors comprised of representatives from Idaho
stakeholders and industry experts." This is partly true. The ISEA Board consists of 11 members,
but setting aside those Board members who do not work for the state, there are eight board
members. Five of those eight members are representatives of Idaho utilties; two represent
large utilty customers or customer groups. The IRP leaves the impression that the ISEA Board,
which on Page 13 is described as a "joint effort between all stakeholders in developing options
and solutions for Idaho's energy future," is actually representative of utility stakeholders when,
as described above, it is not.
The discussion of FERC relicensing (p. 14), while important, would benefit readers more if it
included a discussion ofthe cost of FERC relicensing of Idaho Power's hydro plants to customers
and how those costs wil be recovered. It would be reasonable to include in this discussion the
costs incurred so far in the Hells Canyon relicensing effort, and to the extent possible the
expected total cost of the FERC relicensing. That information is now before the Commission.
The numbers are huge, and customers are entitled to have a sense of what they wil be asked to
pay for in the future.
The discussion ofthe fixed cost adjustment (P. 17) is accurate, but would benefit from an
update noting that Idaho Power requested that the decoupling mechanism be made permanent
as part of its 2011 general rate case filing and, more recently, in its separate FCA case, IPC-E-11-
19. We support the company on this issue.
On the issue of nuclear power (P. 50), we are puzzled by the analysis in the third paragraph and
in particular the passage that reads, "Additionally, if the IRP identified a nuclear resource in the
preferred portfolio, Idaho Power would plan to partner with other utilties in a plant built
around a smaller modular design with Idaho Powers share being approximately 250MW."
There is no explanation as to who Idaho Power might partner with in such an endeavor, how
much it would cost, and who would develop the unidentified resource. In our view, it is also
impractical to attempt to characterize the capital cost estimate, as a reliable estimate does not
exist, nor does the capacity factor of such a resource.
PEAK DEMAND
As in 2009, we remain concerned about the rate of Idaho Power's growth in peak demand
compared to the projected growth in energy. The IRP notes that "The simple peak-hour load
growth calculation indicates Idaho Power would need to add peaking capacity equivalent to the
173MW Bennett Mountain plant every 3 years throughout the entire planning period "(P. 25).
That is clearly not sustainable, nor is it prudent power planning or sound environmental policy,
and it doesn't appear to be Idaho Power's intent in any case. The draft notes that peak
calculation "does not include the expected effects of demand response programs," (P. 25), but
it does underscore the urgency of expanding such programs.
We understand that some calculations indicate there is a tipping point at which demand
response investments do not provide the same return as investments in new peaking plants,
but we are unconvinced that peakers are a sound substitute for additional demand response
based on cost alone. There are significant social and environmental implications in choosing
new peaking plants over peak energy management programs, and building new plant should
not be the default choice based on cost alone. Addressing the growth in peak demand has been
a priority for Idaho Power as reflected in the 6.1MW of peak-hour load reduction in 2004 and
the 330MW of peak-hour load reduction in 2011 (P. 41), and it must remain so. That's
particularly important given the 1.9 benefit/cost ratio of demand response programs compared
with building a new supply-side resource (P. 42).
While we appreciate the recognition in the lRP that "Demand response... cannot continually
satisfy all of the load and resource balance deficits throughout the IRP planning period, rather
the goal of setting the appropriate levels of demand response is to delay the addition of new
supply-side peaking resources until the full capacity of a SCCT would be fully utilzed,/I(P. 42), we
caution that a proposal to add a new SCCT to Idaho Power's supply-side resource portfolio for
purposes of meeting peak demand within the first 10 years of this planning period wil be met
with deserved and rigorous opposition.
IDAHO ENERGY PLAN
We appreciate Idaho Power's acknowledgment ofthe 2007 Idaho Energy Plan, even though
most of the Plan's recommendations remain unimplemented. As we commented in the prior
IRP: "It is helpful for the company to recognize the 2007 Idaho Energy Plan and the
recommendations it includes for electric utilities, regulators, the Idaho legislature, and other
state entities. It would have been more helpful had Idaho Power referred to the Energy Plan
more specifically. For example, recommendations E-2 and E-4, which call on the PUC to work
with utilities to establish realistic conservation targets and determine appropriate incentives for
meeting those targets." We continue to believe these recommendations have merit and
deserve more attention from our utilties and the Puc.
The IRP's characterization of the Energy Plan, while accurate, seems incomplete. The reference
to "access to conventional energy resources to keep Idaho's energy costs as low as possible" (P.
13) seems out of place inasmuch as the bulk of the energy plan - and all of its electricity
recommendations - deal with energy efficiency and renewable energy rather than the need to
acquire new "conventional" energy resources.
RENEWABLES
It is noteworthy that Portfolio 1-3 for the first 10 years of the planning period contemplates no
acquisition of new renewable energy resources beyond contractual obligations to enter into
agreements with Qualifying Facilities. However, recent events at the PUC would seem to
significantly reduce the chances of that occurring during this planning period. While there is
geothermal, solar and small hydro in Portfolio 2-6, we consider those mostly placeholders that
signal the company's wilingness to acquire new renewables of undetermined nature. Stil, the
draft IRP contains only 162MW of planned renewables acquisition. We are concerned that the
proposed 2030 fuel mix (P. 7) contains only 7 percent wind, 3 percent geothermal, and 1
percent solar.
DISTRIBUTED GENERATION
While we agree that distributed generation as described in the IRP (essentially using customer
generators to provide peak power during times of extreme demand) had merit in very limited
amounts and also as some potential in meeting Idaho Power's reserve requirements, we concur
with the decision not to implement this resource at this time (P. 48).
We have ongoing concerns about air quality impacts from firing up diesel generators during
summertime peaks. Given the IRP's position on distributed generation not being an option for
the near-term ("At this time the company does not intend to pursue the implementation of a
distributed generation program/' P. 48), the intervening time should be used to more
thoroughly analyze the potential of such a program, how it would be implemented, and to
acquire better information on air quality impacts. If the generators would likely not be
deployed, but could be counted on for reserves, then there might be value in exploring this
further in the next IRP.
DEMAND-SIDE MANAGEMENT
The draft's cost estimate of 3.6 cents/kWh for existing DSM programs and 5.1 cents for new
programs reflects the great value of these resources against most supply-side resources. As in
the past, we applaud Idaho Power's achievements in expanding its DSM programs.
As we mentioned during the IRP process, however, we would like to see Idaho Power consider
incorporating a block or blocks of additional DSM, in future portfolio analyses as it does for
supply-side resources. Doing so would properly position DSM resources on the same plane as
supply-side resources.
CONCLUSION
The Alliance appreciates the efforts put forth by Idaho Power in this IRP. We believe the
company has made significant strides in its DSM programs and recognize its progress to date in
implementing its efficiency programs. As mentioned above, we believe the company's efforts in
its efficiency arena have been successful and have borne fruit. Stil, we believe Idaho Powers
efforts to reduce its greenhouse gas emissions have fallen short and must be improved upon.
The company's GHG reduction efforts to date do not seem to meet the expectations placed
upon Idaho Power by its shareholders.
We recommend that the Commission accept Idaho Power's 2011IRP but also recommend that'
the Commission decline to accept Idaho Power's alternate portfolio for its first 10-year planning
period.
Respectfully submitted,
Ken Miler
Clean Energy Program Director)
Snake River Allance
208 344-9161
km iller(êsnakerivera Ii iance .org
www.snakeriveralliance.org