20171127Comments (2).pdf

RECTIVED
Idaho Public Utilities Commissioners472w.\washington tfill t{$Y 2? PH 12: 39
November 25,2077
Boise' lD 83702
it-r{i:r-' r;irul ln
Subject comments regarding Idaho r""Sl'b'i,tp#riry&iBP,lP.[^*o Resource plan
Refetence: IPC-E-17-11 - APPLICATION FOR ACCEPTANCE OF 2017 IRP
Dear Commissioners:
I have actively participated in every IRP Idaho Power has ptepated ovet the last decade and ahalf. Based
on that historical perspective, I am concerned that the 2017 IRP is grossly deficient in two major areas:
1) addressing basic ti.sks associated with its preferred portfolio and
2) usrng a fatally flawed analysis to evaluate relevant new technologies.
I ask that you take steps to ensure that similar deficiencies are not repeated in the Company's future
integrated resource plans.
1) RISK - B2H is not shown to be an adequate capacity resource for meeting extreme summer
peak loads.
As has been the case in recent IRPs, IPC projects that it will remain capacity (rather than energy)
constrained over the next decade. Under the 2077 preferred portfolio, the frst capaciq shortfall occurs in
2026. The first energy shortfall is rn 20291.
In the 2017 IRP, IPC plans to lean on others to cover the capacity shortfalls caused by summer peak loads.
During the 2020s, the portion of peak load resources IPC plans to acquire via market purchases rjses from
a few dozen megawatts in2020 (3'h of total peak load) to more than 1,010 megawatts Q6o/o of peak load)
tn2029.2 The preferred portfolio assumes there will be > 1 gigawatt of capacity resources available for
purchase during an extreme heat wave lfl 2029. That assumption seems like a risk that should be
evaluated.
The 2017 IRP does not explain where the genetation that will feed that gigawatt of market purchases will
come ftom. A few days into a major summet heat wave a decade from now, we may find that the Mid-C
market doesn't have a gigawatt to spare. Consider -
o Summer peak is rising much faster than winter peak in the NW as residential AC west of Cascades
expands dramaticalTy. Latest NWPCC regional adequacy plans (RAAC) show rising summer capaciry
shortfalls as ear\ as 2022. RAAC says 1GW of new generation is needed in NN7.
o Colstrip units 3 & 4 may be shut-dowfl a ye t after B2H comes online reducing NW capacity by an
additional 1,480 MWs
. Puget Sound Energy's latest IRP also plans to hit mid-C for peak capacity
o IPC appears to assume that Portland General will build a new gas plant almost adjacent to the
Boardman terminus of the B2H line. With its established greenhouse gas policies Oregon may not look
kindly on budding new gas plants in state to serve ) 116 aMWs3 of load in Idaho.
. \X&y build transmission to access new gas in Oregon instead of just building new generation rn Idaho in
increments when needed?
' Tables 7.4 and 7.5 - IRP page 96
2 Peak-Hour Load and Resource Balance - Appendix C pages 43 & 52
' B2H capacity factor of 33oh* 350MWs = 116.7 aMW - IRP page 76
To summarize via the ar,alogy of drinking soda through a straw - if we build a B2H straw in order to access the
Mid-C soda can we be sure that on some extremely hot sulrrner day rn the not too distant future, when we really
need a drink, that we won't find the soda cup too close to empty to fully quench our thkst? The IRP text isn't clear
on whether adequate capacity will be available late next decade at Mid-C. Addrtional transparency would be
appreciated.
2) FLAWED ANALYSIS - 2017 IRP analysis didn't fairly evaluate Distdbuted Energy Resoutces
IPC has tilted the scales to benefit their preferred portfolio by unfairly ovet-estimating the future costs of
solar and storage and systematically under-estimating the bene{its these resources can provide. The
Company has failed to update the way they analyze disuibuted energy resource altematives. They do not
adequately evaluate opportunities that new technologies can ptovide. The most obvious, but not sole,
deficiency arises from how they modeled future solar costs.
The 201,7 IRP has utility scale solar costs increasing by 2.1o/o per yeat over the next 20 years. In sharp
contrast, almost all studies anticipate PV costs will decline substantially in coming years. One respected
source projects the levelized cost of solar PV to fall 660/o between 2017 and 20404. PV costs are projected
to have fallen more than25o/oby 2026 when IPC projects its frst flew resource requirement.
Rather than falling 25o/o,lPC projects solar PV costs to rise more than2Oo/o between 201.7 and2O26-s
Thus IPC may have over-stated PV costs in 2026 by 45o/o, the year in which they propose to bring B2H
online. Solar costs were over stated by even greater amounts in the 2030s when IPC proposes to build
new natural gas generation. With the 45o/o tn 2026 solar cost ovet-estimates (and even highet ovet-
estimates in future years) in mind, consider how IPC analyzed future PV price trends.
In their "tipping-point" analysis IPC found that a 50o/o reduction in their estimate of the capital cost of
solar would make portfolio P11 (with no B2H and both Bridger units retired n 2021 and 2022) only a half
of one per cent more expensive than their pteferred P7 portfolio.6 The preferred P7 portfolio catdes costs
in excess of $6 billion. The P11 portfolio is $.03 billion more expensive.
One half of one per cent could easily be within the inherent range of error in such analyses. There are
multiple ways in which that $.03 billion may have been ovet-chatged to the P11 and other non-B2H
portfolios, including -
Like solar, future year storage costs were also grossly over-estimated. IPC estimates stofage
that costs will increas e 2.7o/o per year; Lazard forecasts them to fall at tw'ice that rate.
The 2017 IRP fails to model combinations of DERs (eg solar plus some storage) that could
better match both capaciry and energy needs.
In prior IRPs, IPC has indicated that on the very hottest days, losses in transmitting energy
from source to load can exceed 74o/o of gross generation. It is not clear that potential
reduction in hottest day transmission losses have been credited to DERs in this IRP
Historically, scale economies gave cenftalized generation and hub-and-spoke distribution
models inherent cost advantages. T&D costs were treated as if they wete "fixed", that is they
o Bloomberg New Energy Finance, New Energy Outlook,June 1.5,201.7
u A 2.lo/o/year increase (7.027)e produces a 20.60/o rise in projected solar cost between 201.7 and2026
n Sol"r Tipping-Point Analysis - IRP page 118 where 507o solar cost reduction shows P11 having a NPV
only $3lmillion highet than P7 NPV of $6,336 million for a .49o/o difference in total costs between the two
dramatically different port folio alternatives.
a
a
didn't vary substantially with different centta\zed generation portfolios and thus didn't need to
be considered in portfolio cost analyses. IPC's T&D capital expenditures have outpaced their
expenditures on generation resources over the past 20 yearc. Distributing generation (and
storage) close to load can reduce the need for maintenance and upgrades to the transmission
and distribution system. This IRP does not include any value for reduced future T&D
expenditures.
Based on the following factots, it is very possible thatPT is neither the lowest dsk not the lowest cost
future portfolio:
. over-estimates of future solar costs
o de{iciencies in IPC's valuation of storage costs,
o ignoring the potenttal for deferal of futute T&D system upgrades,
o reduced transmission losses from locating solar and storage closer to the load being served
and,
o failure to find the best resource combinations by not using an optimization modeling tool
Obseruation and Opinion
What is listed above is based on facts. The following is my opinion and an observation.
Opinion - I've been involved with the Idaho Power IRP process for the last 15 yea$. Frequendy I haven't
agreed with all of IPC's conclusions. Not having all my values reflected in an IRP is one thirg. This IRP
is different in that I don't ftiflk IPC has performed a fat analysis. In my opinion, the 2017 IRP does not
represent an analysis so much as a justification. I see an overpowering bias in favot of the Company's pre-
ordained preferred outcomes. The lack of a transparent, fair evaluation of alternatives, ftom my
perspective, violates the public's interest.
Observation - Over past 15 years I've engaged with dozens of engineers and subject matter experts at IPC.
In my opinion they are collectively of a caliber equal ot surpassing the skill levels of compatable folks I
worked with at Boeing and several other multi-national corpotations. Idaho Power professionals ate more
than capable of evaluating the risks and opportunities that technological improvements in DERs offer for
reliably and cost effectively serving IPC customers.
In recent IRPs I have commented favotably on the progress Idaho Power made in improving their IRP
analyses. This IRP cycle looks to me like tettograde action - a last gasp by the old "cenrtalized
generation" guard at IPC to the detriment of the youflger crowd who see the potential fot using new
technologies closer to the grid edge to improve service where the customers reside.
Please direct the Company to clear up its act in the 2019. And have faith in those younger Idaho Power
experts. They will make you and Idaho Powet's customets proud.
Idaho Powet customer
ruW
Benjamin J. Otto (ISB No. 8292)
710 N 6th Street
Boise,ID 83701
Ph: [phone]x12
Fax: [phone]
botto @idahoconservation. org
RECEIVED
?$l1tt0Y 27 PH 2: 25
'
i
"r
i rlr?i }J3rC#n?rh l8 t' o*
Attomey for the Idaho Conservation League
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO
POWER COMPANY'S 2017
INTEGRATED RESOURCE PLAN.
CASE NO. IPC.E.-I7-II)
)
)
)
IDAHO CONSERVATION
LEAGUE'S COMMENTS
The Idaho Conservation League (ICL) submits these public comments regarding Idaho
Power's 20lT lntegrated Resource Plan (IRP).While not a formal party to this docket, ICL has
reviewed the Company's IRP and is an active participant on Idaho Power's IRP Advisory
Council since at least the 2013 cycle
For the reasons detailed below we recommend the Commission not acknowledge the
2017 IRP. In sum, both the process and the inputs used by Idaho Power render this IRP incapable
of identifying a least cost, least risk portfolio. The Commissioned should not acknowledge this
flawed process.
Gas Price Forecast
In the 2017 IRP, Idaho Power uses a speculative gas price that assumes new gas supplies,
new technology, and new infrastructure projects that far exceed any existing industry forecasts.
The IRP Advisory Council repeatedly questioned Idaho Power's proposed gas prices;
nevertheless, the Company insisted on using the Company's preferred forecast.
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According to Idaho Power, "future natural gas price assumptions significantly influence
the financial results of the operational modeling used to evaluate and rank resource portfolios."
IRP at 84. The Commission should pay careful attention to which gas forecast the Company uses
in resource planning because it is a fundamental driver in the IRP process, and the Power Cost
Adjustment places 95Yo of the risk of gas price uncertainty on customers. In other words,
selecting an accurate forecast is important, and Idaho Power does not have a strong incentive to
be accurate, so the Commission must be vigilant.
Previously Idaho Power used the U.S. Energt Information Administration Annual Energ,,
Outlook Reference Case to forecast future gas prices. While any forecast has uncertainty, ICL
supports using the Reference Case because it is publicly available, produced by a trusted public
entity, is based on current market fundamentals, and "incorporates assumptions about changes in
upstream technologies and industry practices in developing tight oil, tight gas, and shale gas
plays." AEO 2016 at ES-5. Because the forecast is long-terrn, some assumption about future
trends is unavoidable. The EIA Reference Case makes reasonable assumptions about future
policy, technology, and prices. The EIA uses a set of alternate cases to test different assumptions.
For 2017,Idaho Power proposes to use an extreme case in the Outlook called High Oil
snd Gas Resource and Technologt Case. IRP at 84. The EIA explains this altemate case
stretches far beyond the Reference Case to consider "assumptions of a larger resource base and
more rapid improvement in production technologies" leading to the US becoming a major
exporter of natural gas. AEO 2016 at ES-6. The speculative forecast assumes an amount of gas, a
level of technology, and the existence of major infrastructure that both exceeds the forecasts
already in the Reference Case and do not yet exist. [n short, Idaho Power uses the most extreme
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view of factors that could lead to low natural gas prices, as evidenced from this chart from the
2016 AEO,pageMT-23.
Natural gas prices depend on oil prices,
technology improvement, and resource
recoYeryrates
Figure MT-42. Annual average Henry Hub natural
gas spot market prices in five cases, 19901040 Q0l5
dollars per million Btu)
2015 P12
10 Low and Gas Resource and Technology
High Oil Price
Reference
Price
High Oil and Gas Resource and
0
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040
To justiff using this speculative gas price forecast Idaho Power points to gas prices from
2009-2016, arguing this short-term trend better aligns with the speculative forecast and is "more
consistent with recent price trends than the Reference Case." IRP at 84. The Commission should
reject this thin justification for two reasons.
First, this recent price trend is already captured in the EIA Reference Case.Idaho Power
has no greater insight than the EIA regarding the impact of past prices on future prices. Second,
looking at short-term prices to make long-term resource decisions is poor public policy. Gas
plants and transmission lines have useful lives measured in decades. Once built, customers are
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exposed to the cost of gas for decades. And, under the Power Cost Adjustment, customers bear
95%o of the burden of getting the forecast wrong.
Any long-term decision should be based on facts, not speculation, and account for the
risk of being wrong. Here, Idaho Power proposes using a speculative price forecast that results in
artificially low gas prices thereby creating risk for customers that resource costs will only be
more expensive than expected in the future. The Commission should reject this as poor public
policy and planning methodology.
Because the gas price forecast used in the 2017 IRP is highly speculative and exposes
customers to severe risk of higher than expected power costs, the Commission should not
acknowledge the IRP. Going forward, ICL recommends the Commission direct Idaho Power to
retum to using the U.S. EIA Annual Energy Outlook Reference Case.
Load Forecast
An accurate load forecast is a fundamental input to the IRP process because it determines
the level of "need" any future portfolio must satisfr. As a foundational input, getting the forecast
accurate is a critical component to the IRP process. Two methodological errors undercut the
validity of the 2017 IRP load forecast: the forecast of irrigation loads and the lack of
consideration of changing weather trends.
Idaho Power forecasts irrigation loads to grow faster than in the 2015 IRP, but this
forecast excludes the impact of legally binding agreements among water users. During the IRP
Advisory Council meetings, several members questioned the veracity of Idaho Power's irrigation
forecast. Representatives of the water users specifically pointed to a commitment to reduce
groundwater use for the long term, both by reducing pumping and limiting conversions from
surface to ground water, reflected in Settlement Agreement Entered Into June 30, 2015 Between
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Participating Members of the Surface Water Coalition and Participating Members of the ldaho
Ground Water Appropriators, Inc..Idaho Power's irrigation load forecast does not include the
impact of this major agreement, and thus over estimates load growth, particularly peak load
growth. ICL recommends the Commission direct Idaho Power to incorporate the impacts of this
legally binding agreement when forecasting irrigation loads.
Regarding weather, Idaho Power explains, "weather conditions are the primary factor
affecting the load forecast on a monthly or seasonal basis." IRP at 73. The Company uses
historical weather trends to predict the future. However, the Company makes no mention that
changing atmospheric chemistry is driving changes to overall climate, which we experience
primarily as changes from normal weather patterns. ICL acknowledges the impacts of climate
change on energy demands are uncertain. Almost all of the utility planning if full of uncertainty
- loads, gas prices, resource costs, river flows. Just as Idaho Power has found methods to address
these complex issues, the Company has the ability to address the known uncertainty of our
changing climate. At the very least the Commission should direct Idaho Power to consult with
Idaho based researchers at our universities or the Idaho National Lab regarding scientific
assessments of potential changes to energy use like increased air conditioning demand and
shifting irrigation loads.
Because Idaho Power's load forecast excludes known changes to the irrigation class and
ignores observed changes to historical weather patterns, ICL recommends the Commission not
acknowledge the 201 7 IRP.
Hydroelectric Forecast
Hydroelectric generation is the backbone of Idaho Power's system with the Hells Canyon
Complex alone providing 34Yo of the Company's total generation capacity. IRP at 11. This fact
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means accurately forecasting the quantity and timing of future river flows is an essential input to
the IRP process. Traditionally Idaho Power has used historical stream flows to predict the future.
Throughout the IRP Advisory Council process ICL raised the issue that the scientific certainty of
climate change means that historical conditions may no longer be a reliable indicator of the
future. We encouraged the Company to at least ask scientist researching the Pacific Northwest
for any information on projected climate impacts on the hydrologic cycle. Unfortunately, Idaho
Power continues to ignore this issue.
The 2017 IRP contains the exact same discussion of the issue as the 20 I 5 and 2013 IRPs:
"Idaho Power recognizes the need to remain appraised of scientific advancements
concerning climate change on the regional and global scale. Idaho Power believes too
much uncertainty exists to predict the scale and timing of hydrologic effects due to
climate change. Therefore, no adjustments related to climate change have been made in
the2017IRP. Further discussion of climate change and expectations of possible effects
on Snake River water supply is available starting on page 64 of the IDACOPR Inc.2016
Form l0-K." IRP at 81, 2015 IRP at 82, See also 2013IRP at 58.
Because hydroelectric power is the foundation of Idaho Power's integrated system, the
Commission should expect the Company to make some effort to understand the potential impacts
of the changing climate. The IRP is full of uncertain forecasts for load, gas prices, and resource
costs. Just as Idaho Power develops methods to address these uncertain forecasts, the Company
can begin to understand the potential impacts of climate change. And regardless of whether the
Company's Form 10-K contains more information, this should be included in the IRP so that the
Commission and other stakeholders have the necessary information to assess this plan. Merely
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reprinting stale statements from 2013, despite Advisory Council members asking for more
analysis and proposing new ideas, evidences the Company will never take this issue seriously.
That is unless the Commission refuses to acknowledge this IRP until Idaho Power at least
attempts to understand the future impacts to the backbone of their generation fleet.
Going forward,ICL recommends the Commission direct Idaho Power to work
researchers at the University of Idaho Climate Science Lab or the Boise State University Hydro
Climate group in the College of Engineering, to devise methods to incorporate climate science
into streamflow forecasts.
Resource Options
Throughout the process, IRP Advisory Council questioned the Company's resource costs
estimates for a range of resource types. Below ICL provides some comments on particular
resources to illuminate this issue. As a general matter though, ICL supports Idaho Power's
continued use of an industry standard, publicly available report such as the Lazard Levelized
Cost of Energt Analysli as the starting point for resource costs. IRP at 35. This widely accepted
report looks at a variety ofgeneration resources and provides a range ofcosts for each depending
on particular assumptions. However, Idaho Power's resource costs estimates quickly lose
legitimacy as the process progresses.
Estimates of resource capital costs
The first problem occurs when Idaho Power refines this basic cost information on a "case
by case basis depending on the credibility of the source and the age of the information." IRP at
35. Idaho Power's assessment of the costs of solar generation is a good example.
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The forecast cost of solar power was a continuing source of uncertainty between Idaho
Power and the IRP Advisory Council. Regarding utility scale solar,Idaho Power points to the
Lazard Levelized Cost of Energt Version 10 as the source. IRP at 36. That report shows a range
of costs from $49 to $61 per MWh, depending on the assumptions. Meanwhile Idaho Power
calculates a price that is off the Lazard scale, $74 per MWh, without clearly explaining how they
arrived at this estimate. Nowhere in the [RP document does Idaho Power explain the credible
source they relied upon to make this case-by-case determination.
One possible reason for this oddly inflated cost estimate is Idaho Power's assumptions
for transmission costs associated with utility solar. The Company shows these assumptions in
Table 6.3, pages 69-70. Curiously, Idaho Power assumes a 30 MW solar plant requires a 230 KV
transmission line; the same size of transmission line for a 500 MW gas pant. Meanwhile a
geothermal or CHP plant of 35 MW needs only a 138 KV line. The Company did not explain
this difference when asked by the IRP Advisory Council and does not do so in the IRP. Further,
Idaho Power makes no effort to capture one of the key features of solar - the ability to optimize
the gird location due to the un-necessity of locating near fuel supplies or cooling water sources.
Regarding distributed solar,Idaho Power claims theLazardreport is "not indicative of
solar costs in the Idaho Power service area" and cites to the National Renewable Energt Lab
Open PV. IRP at 36. ICL researched this database and discovered it contains a total of 19
records for the entire state, 10 with cost information, but none more recent than July 2012. This
database is simply not a credible source for accurate cost information in Idaho. Idaho Power also
points to the DOE Tracking the Sun report, but this report uses 2015 national average data, so
again is not credible for an Idaho specific assessment. Instead of pointing to reports with
questionable usefulness, ICL recommended to the IRP Advisory Council, and recommends again
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here, that Idaho Power survey installers of PV in the service territory as the most accurate and
timely information available.
Idaho Power's estimate of the costs for small-scale hydroelectric power is another
example of unexplained assumptions by the Company. The IRP points to a 2009 ldaho Strategic
Energt Alliance Hydro Power Task Force Report that found 150 - 800 MW of potential new
generation at existing infrastructure or water impoundments. But Idaho Power translates this
wide variety of locations and projects into a single estimate of the cost of energy and capacity.
IRP at 38. Small hydroelectric projects are location specific, so average costs mask available low
cost options. This example is indicative of every single point estimate used by Idaho Power;
without explaining the source of the Company's assumptions this Commission has no way to
conclude if the IRP is a credible assessment of future portfolios.
The cost and performance attributes of energy storage technology were another source of
discussion for the IRP Advisory Council. One of the topics discussed was that storage
technologies could provide a host of grid services beyond the traditional IRP concerns of energy
and capacity. These gird service attributes are becoming increasingly important because, as
Idaho Power explains, "as more intermittent renewable resources like wind and solar continue to
be built within the region, the need for energy storage is amplified." IRP at 43. Table 7.3, on
page 92, does identify some resource attributes like balancing and flexibility. But despite Idaho
Power's need for storage, and request of Advisory Council, the Company did not quantify the
potential grid services various storage technologies can provide, as evidenced by only showing
the levelized cost of energy and capacity for storage. IRP at 44-45
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The Commission should not acknowledge the IRP until ldaho Power provides credible
and transparent explanations for how they convert a range of costs into single point estimates
that allegedly encompass the full suite of values provided by each resource.
Capocity Factors
Another major input to a resource cost estimate Idaho Power's assumed capacity factors
for each generation resource. Higher capacity factors assume plants operate more frequently and
thus spread costs over more production, making the per-unit cost appear low. Meanwhile lower
capacity factors assume plants run less often and the cost per unit of output increases.
Determining an accurate capacity factor is an important input to ensure an accurate and fair
comparison generation resource options.
The Company's estimate applied to gas plants illustrates the problem with Idaho Power's
unexplained assumptions. For dispatchable resources, like natural gas, the capacity factor
represents how often the plant will actually dispatch as part of the interconnected system. In the
2017 IRP, Idaho Power assumes new Combined Cycle Combustion Turbines have a70%o
capacity factor - in order words, the plant will run 70oh of all hours for the next 30 years. IRP at
40. This amount seems highly speculative given the forecast of low wholesale market prices
combined with a region that is energy-long for several years ahead. Similarly, Idaho Power
assumes the B2H line will have a capacity factor of 33%o.IRP at 89. But the Company does not
now have any contracts in place to purchase energy or capacity the line would deliver. When
ICL asked about these unexplained assumptions in the IRP Advisory Council meetings, the
Company simply did not respond to the question.
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The Commission should not acknowledge the IRP until the Company discloses, in
writing, the methodologies and sources they use to determine the capacity factor for every
resource option they consider.
Utility Ownership Bias
The20lT IRP continues to show a strong bias towards utility ownership of resources.
After stating the overall results of the load forecast the Company states: "Additional company-
owned resources will be needed to meet these increased demands." IRP at 1. This ownership bias
impedes the ability to find the least cost, least risk portfolio to meet customer needs. Customers
desire energy services that are reliable and fair priced. Utility ownership is no prerequisite to this
outcome. Idaho Power currently has Power Purchase Agreements (PPA), which presumably
provide reliable, affordable service. IRP at 32-33.Idaho Power alleges that only considering
utility owned resources "allows a like-versus-like comparison". IRP at 85. But this statement
ignores the potential benefits to customers that arise from the unique attributes of PPA's - the
timing and flexibility of delivery, cost reductions due to tax structures, and cost reduction due to
the expertise of development focused companies. Idaho Power's continued pursuit of the B2H
transmission project will necessarily increase the Company's reliance on PPAs; that is unless the
Company plans to hook customers to the notoriously volatile spot market. The Commission
should not acknowledge the IRP until the Company gives fair and transparent consideration of
purchase agreements in addition to company owned assets.
Demand Side Resources
This Commission expects all utilities to give equal and balanced treatment to both supply
and demand side options. In this IRP Idaho Power continues the Company's longstanding
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practice of drastically undercounting the potential for demand side resources to meet customer
needs. The treatment of demand side resources is not a side issue. Idaho Power explains that
energy efficiency progftlms are expected to grow to provide 273 average MWs and470 MWs of
peak reduction by 2036.IRP at 47. This shows that Demand Side Management resources are
now, and will continue to be, a major part of the integrated system. Accordingly, the
Commission should pay careful attention to the assumptions underlying Idaho Power's treatment
of demand side resources.
The most important assumption to consider for IRP purposes is the ability to acquire the
resource. This is true for supply side resources and is reflected by considerations like market
availability, permitting requirements, and fuel availability. For demand side resources, for more
than a decade, Idaho Power has assumed they can only acquire the assumed level of efficiency
deemed "achievable" and set the IRP targets accordingly. The graph below shows the Company
consistently exceeds this achievable IRP target by abofi25%o.
209
Figure 5.1
2co2 2003 2004 2005 2006 2007 2008 2009 2010 201',t 2012 2013 2014 2015 2016
r IPC Savings (with NEEA)
-lRP
Targets
Cumulative annual growth in energy efficiency
1
==(!
ooCD
GF
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(E
oo,
(E
art
o
Es3
E
o
2fi
2N
150
00
50
0
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t2
't67
150
114
32
20t1224
bb
48
Figure 5.1, on page 48
This strong track record raises two comments. First, the record shows that Idaho Power's
DSM team is very good at acquiring sufficient savings to meet or exceed planning targets. Thus,
the risk of planning for efficiency that does not materialize is minimal. Second, Idaho Power is
consistently over forecasting loads, thus artificially accelerating resource needs, by including a
forecast of future efficiency that is well below historical achievements. Some level of caution is
good in planning; but consistently under forecasting efficiency by almost 25Yo for more than a
decade is too cautious. Further, this consistently disproven assumption stands in stark contrast to
the utilities generalized and unexplained assumptions about acquiring supply side resources.
The Commission should not acknowledge the IRP until Idaho Power improves the
planning processto avoid this chronic under forecasting of efficiency achievements.
Portfolio Design
Beyond flawed forecasts and resource inputs, Idaho Power's method for developing
resource portfolios is fundamentally broken. The Commission should not acknowledge this IRP
because Idaho Power's method of manually creating alternate portfolios, particularly in the
manner done in this 2017 IRP, is incapable of finding the truly least-cost, least-risk option. ICL's
survey of a range of IRP's finds two basic methods for developing portfolios. One method is to
use portfolio optimization models where stakeholders input resource attributes and the software
uses mathematical methods to find the optimal portfolio for a range of cost and risk criteria. This
is essentially the method used by PacifiCorp and Avista. This methodology enables an iterative
process that captures resource interactions and allows for consideration of dispatching existing
resources versus other options to find optimal solutions. The other method is where the planner's
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hand-select preferred resource options. As used by Idaho Power in2017, this method results in a
constrained consideration of resource options.
In20l7,ldaho Power described the "objective" of the alternative resource portfolios was
to consider two key questions: Whether to install pollution control equipment at Bridger Units 1
and2, and whether to continue to pursue Boardman to Hemingway Transmission line. To
achieve this objective, Idaho Power presented to the Advisory Council a " factorial design"
consisting of four Bridger coal scenarios, two of which would violate existing Clean Air Act
regulations, tested against a limited set of alternative portfolios: B2H and gas plants, natural gas
plants and a small addition of demand response, or natural gas plants, solar, and a little bit of
demand response. IRP at 97 - 108. Idaho Power explains they choose portfolio design "to
determine whether a B2H-based portfolio can be outperformed based on current costs estimates
of alternative resources." IRP at97. By Idaho Power's own words, this method is designed to
make decisions about specific resources, not find the least-cost, least-risk integrated system.
ICL contrasts this process with the 2015 IRP. Then Idaho Power provided the Advisory
Council with load and resource balances showing both energy and capacity deficits under a range
of coal unit closure dates. Based on this information, the Advisory Council then designed a suite
of portfolios that resolved each of these balances using different generation mixes. While still
inferior to methodologies that utilize portfolio optimization models, this 2015 process did allow
for some iteration of portfolios and diversity of resource options. By contrast, in the 20l7IRP,
Idaho Power chose to constrain the available resource options and presented all the portfolios to
the Advisory Council as complete products. The Company made no apparent effort to work with
the Advisory Council to optimize the portfolio options and did not consider any portfolios that
do not rely on large amounts of volatile natural gas or wholesale purchases.
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The Commission should not acknowledge this flawed methodology. Further, ICL
recommends the Commission direct Idaho Power to return to a more inclusive and informative
portfolio design method in future IRPs. We submit the key features of this method are: providing
monthly energy and hourly capacity positions, allowing for a range of resources to fill portfolios,
and devising a method to optimize portfolios through an iterative, and objective, process.
Risk Assessment
ICL recommends the Commission not acknowledge Idaho Power's 2017 IRP because it
does not accurately assess the risks faced by customers under any of the portfolio options. Idaho
Power used three variables to assess risk: natural gas prices, customer loads, and hydroelectric
variability. IRP at 114 - 115. This list is incomplete for a planning effort designed to test the
costs and risk of increasingly relying on either wholesale electric markets, via the B2H project,
or natural gas markets, via each alternate portfolio.
While historically natural gas prices may have provided a proxy for wholesale electric
markets, this may no longer be accurate in the Pacific Northwest. Any observer of our region can
see the massive increase of wind generation in our region. Meanwhile across the western
interconnect, changing market dynamics and mechanisms means wholesale electricity prices are
no longer inextricably tied to natural gas rates. Further, Idaho Power indicates the Company
"currently has no long-term whole sale energy contracts." IRP at 33. So committing to B2H
means the Company is committing to a whole new category of risk - wholesale price volatility.
To accurately assess the risk to customers of pursuing the B2H project the Commission should
require Idaho Power to assess the risks of wholesale electricity markets and natural gas prices
independently.
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Even for the elements considered, Idaho Power's risk assessment in complete. As
described above, ICL submits that Idaho Power's practice of relying exclusively on historical
records to assess future hydroelectric and customer load conditions may no longer be valid. At
the very least the Commission should require Idaho Power to explain why, based on the science,
the past is an accurate predictor of future climactic conditions. Because resource planning is a
long-term proposition, the risk assessment must take a similarly long-term view of probabilities
and outcomes.
Regarding "qualitative" risks, Idaho Power's 2017 IRP continues to show the limited
utility of this portion of the planning process. In this section of the IRP Idaho Power identifies a
list of risks to things like water supply, relicensing, regulations, resource adequacy, acquiring
demand side resources, and "technological obsolescence". IRP at 1 19 - 121. For each category,
Idaho Power merely identifies the broad nature of the risk. The Company makes no effort to
explain the likelihood or severity of any outcome. The Company makes no effort to explain why
some portfolios either exacerbate or mitigate any of these risks. ICL continues to search for the
utility of merely identifuing possible risks without explaining the potential impacts or means to
address them. Before acknowledging this IRP, the Commission should direct Idaho Power to
consider both the outcome and means to address potential qualitative risk factors.
Conclusion
Integrated Resource Planning can be a powerful tool to ensure utilities and stakeholders
prepare for a constantly changing future. The Idaho Commission's reviews the utilities'
"ongoing planning process, not the conclusions or the results reached through that process."
Order No. 33441. For the reasons summarized below, ICL recommends the Commission not
acknowledge Idaho Power's 2017 IRP:
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Idaho Power's speculative natural gas price forecast and refusal to consider the impacts
of climate change on hydroelectric generation mean this IRP does not properly
char acterize existing power supply.
Idaho Power's load forecast does not integrate changes to the irrigation loads that may
stem from the water users historic agreement, or consider the changes to customer
demands attributable to changing climate conditions.
For additional resources, Idaho Power did not explain how they arrived at single point
estimates from a range of resource costs and used a hand selected set of alternate
portfolios dominated by natural gas.
Idaho Power's risk assessment is incomplete by not including wholesale market prices as
and independent a quantitative factor.
Respectfully submitted this 27'h day of Novemb er 2017,
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Benjamin J Otto
Idaho Conservation League
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