20140224final_order_no_32980.pdf

Office of the Secretary
Service Date
February 24,2014
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S 2013 INTEGRATED
RESOURCE PLAN
CASE NO. IPC.E.13.15
ACCEPTANCE OF FILING
ORDER NO. 32980
)
)
)
)
)
On June 28,20L3,Idaho Power Company ("Idaho Power" or the "Company") filed
its 2013 Integrated Resource Plan ("IRP"). On August 7 ,2013, the Commission issued a Notice
of Filing and Notice of Modified Procedure allowing interested parties until November 5, 2013,
to comment on the IRP. See Order No. 32868. The Idaho Conservation League ("ICL"), Snake
River Alliance ("SRA"), Renewable Energy Coalition, and J.R. Simplot Company intervened as
parties to the case, and Commission Staff, ICL, SRA, and 12 members of the public filed written
comments. The Company then filed a reply.l
Having reviewed the record, including the IRP, the comments, and the reply, the
Commission issues this Order accepting the Company's 2013 IRP.
BACKGROUND
An IRP is a utility's status report on its ongoing, changing plans to adequately and
reliably serve its customers at the lowest system cost and least risk over the next 20 years. The
report informs the Commission and the public about the utility's plans, and is similar to an
accounting balance sheet; i.e., it is a "freeze frame" look at the utility's fluid, resource planning
process. See Order No.22299. The Commission requires the utility to: update the IRP at least
biennially, allow the public to participate and comment during the IRP process, and implement
the IRP. See id. and Order No. 25260.
The IRP should explain the utility's present load/resource position, its expected
responses to possible future events, and the role of conservation therein. It should discuss "any
flexibilities and analyses considered during comprehensive resource planning, such as: (1)
examination of load forecast uncertainties; (2) effects of known or potential changes to existing
I ICL and SRA filed comments that were one and two days late. ICL then moved the Commission to accept its late
filing. See ICL's Motion to Accept Late Filed Comments. In its reply, the Company says it "is concerned" about
the late filings but "does not formally object" to them. See Company Reply, at 2, fn. l. As the Company does not
object to the late filings, we grant ICL's Motion and accept both sets of late-filed comments.
ACCEPTANCE OF FILING
oRDER NO. 32980 I
resources; (3) consideration of demand- and supply-side resource options; and (4) contingencies
for upgrading, optioning and acquiring resources at optimum times (considering cost,
availability, lead time, reliability, risk, etc.) as future events unfold." See Order No. 22299. The
IRP should separately address:
(1) "Existing resource stack" by identifying all existing power supply
resources;
(2) "Load forecast" by discussing expectedZ0-year load growth scenarios for
retail markets and for the federal wholesale market including
"requirements" customers, firm sales, and economy (spot) sales. This
section should be a short synopsis of the utility's present load condition,
expectations, and level ofconfidence; and
(3) "Additional resource menu" by describing the utility's plan for meeting all
potential jurisdictional load over the ZO-year planning period, with
references to expected costs, reliability, and risks inherent in the range of
credible future scenarios.
Id.
The IRP is not merely an academic or regulatory exercise but is intended to
demonstrate to the Commission and the public that the Company has considered, and prepared
for, a multitude of scenarios. The Commission expects each company submitting an IRP to
vigorously test the assumptions used in its plan to better ensure that the results of its IRP
accurately reflect changing markets and customer demand.
THE 2013IRP
A. Overview
The Company's 2013 IRP addresses supply-side and demand-side resource options,
planning period load forecasts, potential resource portfolios, risk analysis, and an action plan for
implementing the IRP. The IRP filing consists of four documents: (1) the 2013 IRP; (2)
Appendix A - Sales and Load Forecast; (3) Appendix B - Demand-Side Management 2012
Annual Report; and (4) Appendix C - Technical Appendix.
The Company says it incorporated stakeholder and public input into its IRP by
working with the Integrated Resource Plan Advisory Council ("IRPAC"). The IRPAC meetings
were open to the public, and the Company says the IRPAC and members of the public made a
significant contribution to the IRP.
ACCEPTANCE OF FILING
ORDER NO. 32980
B. IRP Goals and Assumptions
The Company states its 2013 IRP's primary goals are to: (1) identify sufficient
resources to reliably serve growing energy demands over the Z}-year planning period; (2) ensure
the selected resource portfolio balances cost, risk, and environmental concerns; (3) give equal
and balanced treatment to supply-side resource and demand-side measures; and (4) involve the
public in the planning process.
The 2013 IRP includes many assumptions about what may happen during the 2O-year
planning period. For example, it assumes that the Company will continue to be responsible for
acquiring resources sufficient to serve its Idaho and Oregon customers and to operate as a
vertically-integrated utility. It also assumes the Company will add 170,000 customers, and that
its average load will increase by 2l average megawatts (l.IVo) per year through 2032. The
Company continues to use 70ft percentile water conditions and 70ft percentile average load for
average monthly energy planning. For peak-hour capacity planning, the Company uses 90'h
percentile water conditions and 95th percentile peak-hour load. The Company says increases in
population and energy demand will require it to add physical resources for use with demand-side
measures.
C. Preferued Resource Portfolio
The Company performed a Resource Alternatives Analysis when preparing the 2013
IRP. It initially compared many different supply-side resources and then examined nine resource
portfolios in further detail. Two portfolios rely on the Boardman to Hemingway transmission
line ("B2H") and associated market purchases. Three portfolios look at alternatives to B2H, and
four portfolios explore reducing and eliminating existing coal-fired generation from the
Company's resource portfolio. The Company also will use demand response programs
throughout the planning period to meet resource needs; specifically, the Company plans to use
up to 150 MW of demand response before the B2H line is complete. The IRP predicts B2H to be
on-line in 2018.
D. Expanded IRP Analysis
In response to the Commission's Order accepting the 2011 IRP (Order No. 32425),
the 2013 IRP discusses: (1) the Company's involvement in the Gateway West transmission line;
(2) the Company's progress on its solar demonstration project; (3) the Company's relicensing
ACCEPTANCE OF FILING
ORDER NO. 32980
efforts for its Hells Canyon hydro projects; (4) the potential for early retirement of existing coal
plants; and (5) transmission siting and market price risks.
THE COMMENTS
Commission Staff, ICL, SRA and members of the public filed written comments in
the case, and the Company filed a reply. The comments and reply are summarized below.
A. Commission Staff
Staff says the 2Ol3 IRP contains extensive analyses, gives reasonably equal
consideration to supply- and demand-side resources, and provides acceptable opportunities for
public input. Staff opines that the 2013 IRP complies with Commission Order Nos. 22299 and
25260, and thus recommended the Commission accept it. Staff also suggested the Company
improve future IRPs as follows:
1. Load and Resource Balance. The 2013 IRP assumes drier-than-median water
conditions and higher-than-median load conditions to ensure that the Company's system has
enough generating capacity to meet daily operating-reserve requirements. To identify the need
for and timing of future resources, the Company prepares a load and resource balance that
accounts for generation from the Company's existing resources and planned purchases. See
2013 IRP at 59. Staff reviewed the load and resource balance and says the Company should
consider using less restrictive peakJoad planning criteria, like a specific planning reserve margin
or more probabilistic water and load conditions (e.g.,8OVo load and water conditions). Staff
believes less restrictive criteria will result in smaller deficits and potentially delay the need to
build a resource to meet a low-probability event. See Staff Comments at 4.
In reply, the Company says its current peak-hour planning criteria are 90'h percentile
water conditions and 95ft percentile peak load. These conservative planning criteria provide
necessary operating reserves, but do not account for transmission-related contingencies like loop
flow or the impact of losing transmission due to fires or localized weather events. These issues
have the potential to severely impact the Company's ability to serve customers under peak load
conditions. The Company thus opposes any change to its peak-hour planning criteria.
Company Reply at 19-20.
2. Natural Gas Forecasts. Future natural gas price assumptions significantly influence
how the Company evaluates and ranks resource portfolios. When forecasting natural gas prices,
the Company uses gas forecasts provided by the U.S. Energy Information Administration's
ACCEPTANCE OF FILING
oRDER NO. 32980 4
("EIA") Annual Energy Outlook. See 2Ol3IRP at 62. Staff reviewed the Company's forecasts
and says the Company should use the EIA's nominal forecast instead of applying the Company's
own escalation factor to the 2010 constant dollar forecast. Staff believes the Company's
escalation factor may overstate fuel costs for natural gas facilities. Staff Comments at 5-6.
In reply, the Company says it will use the EIA nominal forecast starting with the 2015
IRP. Company Reply at 18.
3. Demand-Side Management. Staff makes three DSM-related recommendations:
a. Conservation Potential Study. Before analyzing the load and resource balance,
the Company adjusts it to account for DSM resources by using a third-party Conservation
Potential Study or Assessment ("CPA") to set achievable savings over the Z0-year planning
period. The CPA estimates achievable savings at 234 aN/fW and economic potential savings at
438 aMW. Staff attributes the gap between achievable savings and economic potential savings
to low program participation rates. Staff thus recommended the Company try to increase
customer participation in the programs. Staff Comments at 6-7.
In reply, the Company says: (1) it will pursue all cost-effective energy efficiency; (2)
achievable potential does not limit its pursuit of energy efficiency; (3) it will pursue energy
efficiency achievable potential when possible; and (4) including energy efficiency achievable
potential in the IRP is reasonable. Company Reply at 10-11
b. Future Savings. Staff has two concerns about the IRP's discussion of DSM
savings. First, the load and resource balance inexplicably excludes new residential energy
efficiency savings in 2013 and 2014. Second, the Action Plan lacks detail on the Company's
future energy efficiency acquisition plans. Staff recommended the Company's future IRP should
include this information. Staff Comments at 7-8.
ln reply, the Company says: (1) its load and resource balance actually includes less
than I aMW of residential energy efficiency savings potentials. But when rounded, the number
appears as a zero in the Company's filings; and (2) the IRP's Action Plan omits energy
efficiency acquisition. But the IRP discusses energy efficiency acquisition elsewhere by
identifying the Company's DSM programs and activities and the achievable energy efficiency
potential by sector and end-use. Further, the Company constantly pursues energy efficiency
savings and includes it in the load and resource balance. Company Reply at 10-11.
ACCEPTANCE OF FILING
oRDER NO. 32980
c. Dynamic Pricing Programs. Staff says the Company's IRP ignores expanded
dynamic pricing programs, and that the Company should study dynamic pricing options,
enrollment strategies, and potential savings for the next IRP. Staff Comments at 8.
In reply, the Company says it has offered dynamic pricing plans, including time-of-
day and seasonal pricing, to most customer sectors since 2004. The Company is studying how
customer behavior and revenue impact the residential time-of-day pilot plan, and it will continue
exploring the best time to implement dynamic pricing options. Company Reply at22.
4. Resource Alternatives Analysis. Staff notes that the IRP includes the full cost of
distributed solar photovoltaics ("PV"), including customer costs. However, some IRPAC
members argue that the IRP should only concern itself with utility costs and represent PV as
costless. Staff concurs that the IRP should analyze only utility costs, but Staff believes treating
customer-owned PV as costless ignores entry barriers and leads to poor conclusions. Even
though the cost to install PV is decreasing, Staff believes PV will be an unlikely resource
alternative until consensus on pricing assumptions exists. Staff recommended the Company
investigate whether incentive programs could heighten interest in expanding PV installations in
sufficient capacity (10 IvIW and above) to merit including PV as an alternative resource. Staff
says the analysis would provide a good foundation for discussion in the next IRP cycle and result
in a representative price in the resource alternatives analysis. Staff Comments at 8-10.
In reply, the Company notes that it already is considering options for possible
distributed generation programs and will include its analysis/evaluation in the 2015 IRP.
Company Reply at 17-18.
5. Portfolio Design and Selection. The Company designed its IRP resource portfolios
to meet expected deficits for the next 20 years. The portfolios with B2H assume that B2H will
come on-line in 2018, but the Company now expects that B2H will come on-line in 2020 or
beyond. Staff thus recommended the Company's next IRP provide a contingency plan that
assumes B2H is delayed by two to five years. Staff Comments at 10-11. See also ICL
Comments at 5-6; SRA Comments at 2 (recommending that the Commission order "an update
well in advance of the next IRP").
In reply, the Company notes: (1) it expected B2H to be on-line in 2018 when it
prepared its 2013 IRP; (2) its preferred resource portfolio relies on demand response programs to
meet summer deficits until B2H is complete, and the Company has sufficient demand response
ACCEPTANCE OF FILING
oRDER NO. 32980 6
program capacity to meet surrmer deficits until 2020; and (3) the next IRP will continue to
evaluate B2H's status and whether demand response programs can satisfy demands until B2H is
on-line. Company Reply at l2-I3.
6. Preferred Resource Portfolio and Action Plan. The Company's preferred portfolio
includes demand response and B2H. The Company believes the preferred portfolio is the least-
cost, least-risk portfolio, and Staff says the Company's view is generally well-supported. Staff
has some reservations about the B2H timeline as explained above.
Staff also notes that the Company makes no assumptions about the impact of the
Gateway West transmission project. Staff recommended the Company's next IRP address this
issue. Staff Comments at l1; see also SRA Comments at 4 (Idaho Power has not demonstrated
that its customers will benefit from its participation in the Gateway West project, and it should
be treated as an uncofllmitted resource until siting and other problems are resolved).
With regard to Gateway West, the Company notes that it has no available
transmission capacity from the Midpoint substation in southern Idaho to the Company's primary
load center in the Treasure Valley. Gateway West will provide extra capacity along this path and
let the Company move more energy across its system, especially when wind generation is at high
levels. The extra capacity also will provide options for siting future supply-side resources. The
Company expects to continue participating in the Gateway West permitting process to ensure the
Company has adequate transmission capacity from Midpoint to the Treasure Valley. The
Company is cooperating with the Bureau of Land Management ("BLM") as the BLM continues
to analyze environmental issues, and the BLM estimates a final decision may not occur for two
years. Company Reply at 13-14.
B. Public
Members of the public offered comments similar to those of the intervenors. See
Section C, below.
Some commenters said this year's IRP process was the best yet in terms of public
participation, but that it can still improve. For example, Mr. Heckler said the Company should
change how and when it discusses certain topics with the IRPAC. Heckler Comments at 2 (the
Company has agreed to meet with Mr. Heckler on these points). Another commenter suggested
that IRPAC members be regularly replaced with new people/interest groups who can better
represent customers and offer fresh ideas.
ACCEPTANCE OF FILING
oRDER NO. 32980
Members of the public criticized the Company's analysis of solar PV and its
continued reliance on coal, and urged it to more aggressively explore alternatives like sustainable
resources, demand response, and energy savings programs.
Other comments included that the IRP should address using rate design to lower
customer bills, that the Company should consider using time-of-day pricing for residential
customers from June 15 through August 15 to reduce peak-load growth, and that air-conditioning
loads might be lowered by establishing a combined Idaho Power and Intermountain Gas
efficiency pool to pay for weatherization for customers that use natural gas heating but electric
air conditioning.
One commenter, Ms. White, criticized the IRP for inadequately addressing variables
bearing on risk of investing in resource alternatives. For example, the IRP inconsistently applies
the cost of contingency capacity requirements by selectively translating risks into costs for some
alternatives but not for others: ". . . the risk that the sun doesn't shine translates into a cost in the
IRP's comparison of solar to alternative resources. But the cost of risks associated with
disrupted operation of the Bridger coal facilities is not integrated into the cost of continuing to
rely on these alternatives." See White Comments at 1-5.
In reply to Ms. White's comment that the IRP inconsistently applies the cost of
contingency capacity requirements, the Company says its IRP applies a forced outage rate to
thermal resources when determining the peak-hour capacity factor for the resource. For analysis
purpose, the forced outage rates applied to coal plants, combined-cycle and simple-cycle
combustion turbines, and combined heat and power typically range from 5 to 8 percent, which
results in peak-hour capacity factors of 92 to 95 percent. Company Reply at 23-24, citing 2013
IRP, Table 7.1 at84.
Ms. White also criticized the IRP forecast for omitting trends and technologies that
would materially impact the forecast, such as projected improvements in storage technology.
White Comments at5-9.
In reply to Ms. White's comments about storage, the Company says it investigates
storage technologies as part of the IRP and between IRPs and that none have proven to be cost-
effective. Company Reply at23, citing 2013 IRP, Figure 5.8 at 67 (noting that pumped storage
fueled by LL Wind (500 NIW) had a levelized energy cost of $239 per megawatt-hour).
ACCEPTANCE OF FILING
ORDER NO. 32980
C. Intervenors (ICL and SRA)
Intervenors SRA and ICL raise concerns about the IRP. Based on these concerns,
SRA says the Commission should accept the IRP, subject to modification. ICL, on the other
hand, says the Commission should reject the IRP and order the Company to immediately resume
the planning process. See ICL Comments at I and 8. The intervenors' concerns are as follows.
1. Stale Load-and-Resource Balance. The intervenors claim the 2013 IRP's load and
resource balance is outdated. For example, while the 2013 IRP projects a capacity deficit
beginning in 2016, the Company's November 2Ol3 filing in Case No. IPC-E-I3-?I says peak-
hour deficits will begin in July 202I. The 2013 IRP will thus contribute to an overbuilt system.
The Commission should thus order the Company to reconcile this significant difference and
update the IRP to reflect the most recent information. See ICL Comments at 2; SRA Comments
at 4.
In reply, the Company explains that the IRP forecasts the Company's first capacity
deficit as occurring in 2016 if demand response programs or other new resources are not taken
into account. If demand response programs had been accounted for, the IRP would have shown
the first deficits beginning in2O23. The Company filed its application in Case No. IPC-E-13-21
per the Commission's Order to update information that influences the first deficit year and other
inputs used to set negotiated PURPA rates. The updated information, including the load
forecast, natural gas price forecast, and any changes in PURPA or other long-term power
purchase agreements, changed the first capacity deficit year to 2021. Company Reply at2O-2I.
2. Inadequate Assessment of Demand-Side Resources. ICL says the 2013 IRP does
not treat demand-side and supply-side resources equally. For example, the Company and IRPAC
met several times to discuss supply-side resources, and stakeholders had the opportunity to
advocate for different levels of supply-side resources during portfolio design workshops.
However, this meaningful public involvement did not occur for demand-side resources. Instead,
the Company told the IRPAC, without explanation, that the Company assumes it will maintain
current demand-side resource levels. ICL Comments at 2.
The Company disagrees with this comment for several reasons. First, the Company
says the 2013 IRP shows increasing amounts of energy efficiency through the 20-year planning
period. See Company Reply at 11, citing IRP p. 43. Second, the Company says it treats demand-
ACCEPTANCE OF FILING
oRDER NO. 32980 9
side and supply-side resources equally, and includes all achievable energy efficiency potential in
the load and resource balance before considering supply-side resources. Id.
3. Undisclosed Intentions as to NEEA Funding. SRA appreciates that the Company
expanded its energy efficiency program, but it is concerned about the Company's commitment to
funding the Northwest Energy Efficiency Alliance ("NEEA"). SRA recommended the
Commission require the Company to explain its NEEA-related intentions.
ln reply, the Company says its critical evaluation of its continued relationship with
NEEA is reasonable and reflects the Company's commitment to obtain cost-effective energy
efficiency solutions for its customers. In2009, the year leading up to NEEA's current, 2010-
2014 funding cycle, the Company asked NEEA to change its funding model to allow the
Company to fund those activities that most benefited the Company's customers. Idaho Power
continues to ask for such a funding model. In the meantime, it continues to participate in the
current funding cycle, but it has provided notice of its intent to not pursue a commitment with
NEEA for the next funding cycle in20l5-2019. Company Reply at 8-10.
4. Undercounting the Cost to Continue Coal Generation. The intervenors say the
2013 IRP undercounts the risks and costs of continued coal operation and the benefits of using
alternate resources. The intervenors note, for example, that the Company's existing diverse
resource stack can cost-effectively meet the Company's needs far into the future. They also say
the Company's position that it can only replace coal units with similarly located alternative
resources that match the coal unit's nameplate capacity is unsupported. ICL Comments at 2-3.
There is no analysis of how removing an individual coal unit would change the overall resource
balance and the company ignores that it could replace retired coal plants with distributed
generation. SeeICL Comments at 3; SRA Comments at2-3.
The Company disagrees with the intervenors' position that the Company's surplus
energy obviates any need to entirely replace any retired coal-unit capacity. The Company
believes the intervenors fail to recognize that the Company's summer-generation (peak-hour)
capacity needs are larger and show up earlier than monthly average energy needs throughout the
IRP planning horizon. The Company says that retiring a coal unit without replacing its capacity
would prevent the Company from serving customers during the summer peak-load season.
Company Reply at 4.
ACCEPTANCE OF FILING
oRDER NO. 32980 l0
5. Inadequate Consideration of Energy Efficiency as a Resource. ICL says the IRP's
coal replacement portfolios fail to consider new energy efficiency as a resource. See ICL
Comments at 3-4; see also White Comments at 7 (the IRP's Resource Alternative Analysis does
not treat energy efficiency as a scalable resource but as a reduction in load).
In reply, the Company notes that the IRP evaluates all achievable, cost-effective
energy efficiency programs, and that comments to the contrary may stem from a
misunderstanding that the IRP's Resource Alternatives Analysis should contain that discussion.
The Company explains that for the 2013IRP, it retained EnerNoc Utility Solutions Consulting to
study the Company's energy efficiency potential over 20 years. The study resulted in an
achievable energy efficiency potential forecast that was fully incorporated into the IRP planning
process before the consideration of any new supply-side resources. The Company did not,
therefore, include energy efficiency programs a second time in the IRP's Resource Alternatives
Analysis. Company Reply at 12.
6. Reliance on a Flawed Coal Study. The intervenors are concerned that the IRP
omits some environmental compliance costs that the Company will incur to continue operating
its coal plants. It fails, for example, to address all the pollutants for which environmental control
costs will be imposed. It also tails to address the costs of additional environmental controls for
particulate matter, cooling water, and coal ash. ICL Comments at 3-4; See also SRA Comments
at2 (criticizing the Company's proposal to invest in coal plants without knowing whether future
regulations may make the plants uneconomic to operate, and without having a prudent strategy to
eventually divest those plants; the Company should explain how it will obtain resources to meet
load if the coal plants become uneconomic relative to other resources); White Comments at 7.
In reply, the Company says it stands on the record in the Bridger CPCN case (IPC-E-
13-15) with regard to emissions controls for the Jim Bridger power plant. The Company further
notes that its 2013 IRP and Coal Unit Environment lnvestment Analysis ("Coal Study") were
prepared using the most current information available. The Company says it updates the IRP
every two years, and it will update the Coal Study this summer and use the updated Coal Study
to prepare the 2015 IRP. The Company says ICL's criticism that the Coal Study and 2013 IRP
do not incorporate all potential future emissions costs is meritless. The Coal Study and 2013 IRP
incorporate the capital cost of all reasonably anticipated measures required to maintain
compliance, including anticipated impacts of existing and expected regulations, including Clean
ACCEPTANCE OF FILING
oRDER NO. 32980 11
Water Act requirements for existing coal plants; Coal Combustion Residuals; National Ambient
Air Quality Standards; and Mercury and Air Toxic Standards. Id. at 3-4.
7. Arbitrarily Altering the Third-Party Carbon Price Forecast. A "carbon adder" is an
investment planning tool that utilities use to calculate a generation source's value after factoring
in the risk that future carbon regulations will require the utility to mitigate Greenhouse Gas
emissions from that source. In this IRP, the Company says it worked with the IRPAC to
determine low, high, and expected (or planning) carbon adder scenarios. The low carbon cost
scenario is a zero-cost case where no future cost is associated with carbon emissions. The high
carbon cost scenario is based in part on data from carbon dioxide price forecasts published by
Synapse Energy Economics,Inc. See 2013 IRP at 68.
ICL says the Company should not use a zero-cost, low carbon scenario when the
Commission has recently acknowledged it is "more likely than not that the EPA will . . . enact
additional regulations of fossil fuels. . . ." ICL Comments at 5, quoting Order No. 32890 at 12.
ICL also complains that the Company arbitrarily adjusted the Synapse forecasts to track the
Company's Coal Study. Id. at 4-5; see a/so SRA Comments at 3.
In reply, the Company says it used Synapse's high-case forecasts for the IRP's upper
boundary condition. It used the unlikely, zero-cost low boundary condition for risk analysis
purposes because the Company's IRPs have included carbon adders for 20 years but no COz
regulations have been promulgated. Further, several IRPAC members supported using the zero-
cost low case. The Company says it set the planning case only after consulting with IRPAC and
looking at other utilities' carbon adder assumptions. The Company's resulting planning scenario
has carbon costs like those in Portland General Electric Company's planning case and slightly
below those in the low cases estimated by Synapse and the Climate Protection Act of 2013.
Company Reply at 6-8.
8. Poor Solar Assumptions. Certain commenters criticize the Company's analysis of
solar PV resources. For example, they point out that the Company only considered south-
oriented PV panels even though the Company's peak-energy needs occur when the sun is in the
southwest. They also note that the Company inflates the cost of distributed solar PV by ignoring
that solar PV costs are declining and that cost-sharing can occur with system owners. At least
one commenter observed that a utility scale solar project would be more likely to be installed in
ACCEPTANCE OF FILING
ORDER NO. 32980 12
sunnier Owyhee County than in Boise as the Company assumes. See e.g.,ICL Comments at 6;
SRA Comments at 5, White Comments at 7; Heckler Comments at 5;Weber Comments at 3.
In reply, the Company acknowledges the effect of a southwest PV panel orientation
and notes that page 95 of the IRP's Technical Appendix specifically discusses southwest-
oriented PV installations. The Company says it considered many variables when analyzing solar
but it ultimately focused on south oriented systems because the "vast majority" of solar PV on
the Company's system comes from programs (e.g., the net metering program) in which
customers are financially incented to orient their panels to the south to maximize overall annual
production. Company Reply at 15.
The Company also acknowledges that there is a downward trend in solar PV costs,
and it says the IRP accounts for this trend while escalating the cost for all other resource types at
3 percent annually. Id. at 16.
With regard to claims that it ignores the possibility of cost-sharing for solar PV, the
Company explains that it evaluates resource costs on a total resource cost basis because the
Company's customers ultimately will pay the capital cost of a resource regardless of who builds
it or how it is acquired. Id.
9. Flawed Wind-[ntegration Study. The 2013 IRP relies on the Wind Integration
Study Report that the Company filed as part of the 201I IRP. In the study, the Company
investigates how much wind generation its system can accommodate without impacting reliability.
See 2013 IRP at 16. ICL claims the Company's study is flawed because it: (1) ignores the
flexibility to integrate variable resources available in the FERC licenses for the Mid Snake River
Dams; (2) considers one-hour transmission scheduling when the trend is toward l5-minute
schedules; and (3) fails to describe forecasting improvements that can reduce integration costs.
SeeICL Comments at 6.
In reply, the Company explains that the IRP looks forward 20 years while the wind
integration study evaluates the cost of integrating wind today under current conditions. The
Company says it is not appropriate for the Company's wind integration study to account for
things that currently do not exist because the results of the study are used to determine wind
integration charges for PURPA contracts. The Company says it will update the wind integration
study if and when these advances or other material changes occur that might influence the cost to
integrate wind. Company Reply at2l-22.
ACCEPTANCE OF FILING
oRDER NO. 32980 13
10. No Plan to Pursue Energy Imbalance Market Benefits. An Energy Imbalance
Market ("EIM") is a means of supplying and dispatching electricity to balance generation and
load fluctuations by aggregating the variability of generation and load over multiple balancing
authority areas. ICL complains that the IRP says an EIM could benefit Idaho Power and the
Northwest Power Pool region but discloses no concrete plans for the Company to pursue that
opportunity. ICL Comments at 7.
In reply, the Company notes that it is one of more than 20 entities supporting a
Northwest Power Pool ("NWPP") study that found that implementing an EM could yield certain
cost-effective benefits. However, as noted in the Company's IRP, the study also found that
"many institutional issues remain before an EIM can be implemented in the Pacific Northwest."
Company Reply at 18-19, quoting 2017 IRP at 17. The Company says it continues to participate
in the NWPP's discussions about the possibility of implementing an EIM, but it has little control
over the many remaining unresolved issues that will need to be agreed upon before an EIM can
be implemented. Company Reply at2l.
11. Inadequate Risk Management. ICL and SRA believe the 2013 IRP inadequately
addresses the risks of: (1) increasingly stringent environmental controls being required for the
Company's coal plants; (2) the Company's 2}-year commitment to relying on coal from plants
the Company does not control, like Valmyt and (3) delay in completing large scale generation
projects like B2H, or gas power plants (SRA at3-4). See ICL Comments at7-8; SRA at 2-4.
The Company replied that concerns about the risk of new environmental regulations,
and possible delays in B2H, were already addressed. In reply to the concerns about relying on
coal from plants that it does not control, the Company says the IRP and preferred portfolio
assume North Valmy will operate for the Z0-year planning period, and the Company's partner at
Valmy, NV Energy, cannot decommission any part of Valmy without the Company's consent.
See Company Reply at 5. Further, some portfolios did consider the retirement of North Valmy to
quantify the impact of shutting down parts of Valmy in2O?l and2o25. However, the Company
did not select them as the preferred portfolio because they did not perform well from a cost and
risk perspective. Id. at 5-6.
12. Shoshone Falls Upgrade. Idaho Power plans to upgrade Shoshone Falls with a
new turbine. SRA questions how upgrading Shoshone Falls will benefit customers when the
Company expects deficits during the summer peak-demand period, but Shoshone Falls is not a
ACCEPTANCE OF FILING
ORDER NO. 32980 t4
reliable summertime peak-power producer. SRA recommended the Commission direct the
Company to provide an analysis of how the proposed upgrade will help the Company meet peak
requirements. SRA Comments at5; see alsoWeber Comments at2 (a Shoshone Falls upgrade is
not the best committed resource given long-term declining streamflows and poor peak capacity).
In reply, the Company concedes the proposed Shoshone Falls upgrade would provide
little summertime capacity and would increase generation in months when the Company has
surplus energy. But the Company says the benefits of the upgrade are: (1) it would lower overall
power supply costs by allowing the Company to sell surplus energy on the market; and (2)
facilitate generation from a non-COz emitting resource. The Company says that despite recent
drops in market prices, Shoshone Falls remains marginally beneficial. And, because the FERC
license amendment requires the upgrade project to be complete in 2017, the Company will begin
rebuilding the spillway in 20L4. The Company is, however, exploring whether to ask for an
extension of this deadline. Company Reply at22-23.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over Idaho Power, an electric utility, and the issues
in this case under Title 61 of the Idaho Code and the Commission Rules of Procedure, IDAPA
31.01.01.000 et seq. The Commission has reviewed the filings in this case, including the 2013
IRP, the comments, and the Company's reply. Based on that review, the Commission finds that
the Company's 2013 IRP contains the required information and is in the appropriate format as
established in Commission Order Nos. 22299 and 25260. Accordingly, we find it reasonable to
accept the Company's 2013 IRP.
We appreciate the robust involvement and thoughtful written comments of the
interested parties in this case. Several commenters commended the Company's efforts to
increase public involvement in the IRP process. We encourage the commenters and other
interested persons to participate in the Company's ongoing IPR process and to provide further
input and suggestions to the Company as it develops its next IRP.2 We expect the Company to
carefully and fully consider and discuss at the IRPAC meetings the various criticisms and
suggestions that are and have been offered.
2 We decline to adopt ICL's suggestion that we direct the Company to "reinitiate the IRP process as soon as possible
in 2014." See ICL Comments at l. As noted above, the IRP is an ongoing process. We appreciate ICL's
involvement in that process, and we encourage ICL to continue to participate in it.
ACCEPTANCE OF FILING
oRDER NO. 32980 r5
In particular, we expect the Company to monitor developments at the national level
and to account for their impact in its resource planning. For example, while we believe the
Company reasonably used a zero-cost, low carbon scenario in this IRP to reflect continuing
delay in the promulgation of long-expected, federal CO2 regulations, we expect the Company to
monitor the development of such regulations, discuss their status during the IRP process, and to
update the IRP's low-cost scenario to reasonably account for changing circumstances. We also
expect the Company to collaborate with stakeholders on how best to use energy efficiency as a
resource, to be actively involved in matters relating to Valmy, and to promptly apprise us of
developments that could impact the Company's continued reliance on that coal-fired resource.
As always, our acceptance of the Company's 2013 IRP should not be interpreted as
an endorsement of any particular element of the plan or of any proposed resource acquisition
contained in the plan. An IRP is a utility planning document that incorporates many assumptions
and projections at a specific point in time. By accepting the Company's filing, we acknowledge
only the Company's ongoing planning process, not the conclusions or results reached through
that process.
ORDER
ru IS HEREBY ORDERED that the Company's 2013 IRP is accepted for filing.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See ldaho Code $ 6l-626.
ACCEPTANCE OF FILING
ORDER NO. 32980 16
DONE by Order of the Idatro Public Utilities Commission at Boise, Idaho this 2y'"
day of February 2014.
ATTEST:
O:IPC-E- l 3- l5_kk2
ACCEPTANCE OF FILING
oRDER NO. 32980
, COMMISSIONER
MARSHA H. SMITH, COMMISSIONER
E
t7