20151005Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLTC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472W, WASHINGTON
BOISE, IDAHO 83702-5918
Attomey for the Commission Staff
IN THE MATTER OF IDAHO POWER
COMPANY'S 2OI5 INTEGRATED RESOURCE
PLAN.
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.IPC-E-15-19
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's Application.
BACKGROUND
On June 30,2015,Idaho Power Company filed its 2015 Integrated Resource Plan
(IRP). The IRP is a status report on a utility's ongoing, changing plans to adequately and
reliably serve its customers at the lowest system cost and least risk over the next 20 years. The
IRP should explain the utility's present load./resource position, the utility's expected responses to
possible future events, and the role of conservation in those responses. The IRP should also
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 resources; (3) consideration of demand-side and supply-side resource options; and (a)
contingencies for upgrading, optioning and acquiring resources at optimum times (considering
STAFF COMMENTS OCTOBER 5,2015
cost, availability, lead time, reliability, risk, etc.) as future events unfold." See Order No.22299.
The IRP should separately address:
o "Existing resource stack," by identifying all existing power supply
resources;o o'Load forecast," by discussing expected2}-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. "Additional resource menu," by describing the utility's plan for meeting
all potential jurisdictional load over the 2}-year planning period, with
references to expected costs, reliability, and risks inherent in the range of
credible future scenarios.
Id. The Commission requires the utility to update the IRP every two years, allow the public to
participate and comment during the IRP process, and implement the IRP. See Order Nos. 22299
and25260.
In its Application, the Company explains that its 2015 IRP addresses available supply-
side and demand-side resource options, planning period load forecasts, potential resource
portfolios, a risk analysis, and an action plan that details how the Company intends to implement
the IRP. The IRP filing consists of four documents: (l) the 2015 IRP; (2) Appendix A - Sales
and Load Forecast; (3) Appendix B - Demand-Side Management2)l4 Annual Report; and (a)
Appendix C - Technical Appendix.
The Company notes that it incorporated stakeholder and public input into its IRP by
working with an Integrated Resource Plan Advisory Council (IRPAC) consisting of various
stakeholders. Besides holding 12 IRPAC meetings, the Company also held public working
group meetings to discuss energy efficiency, solar resources, and coal resources. The Company
also notes that it is presenting the IRP to the public at different community meetings, to civic
groups, and through seminars as requested.
The Company explains that the 2015 IRP's primary goals are to: (l) identiff 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.
STAFF COMMENTS OCTOBER 5,2015
STAFF REVIEW
Staff actively participated in the IRPAC and believes the Company's IRP satisfies the
Commission's requirements as specified in Order No.22299. Although Staff has
recommendations that would improve the Company's IRP process and conclusion, Staff believes
the current IRP achieves the goals referenced above and is an improvement over the 2013 IRP.
Staff particularly supports the variety of portfolios developed and modeled for this IRP, which
included a host of resource retirement and replacement scenarios, alternatives to Boardman to
Hemingway (B2H), and expanded energy-efficiency and demand-response resources. Staff also
supports the Company's proposed pilot projects, which include solar Photovoltaics (PV) to
address distribution feeder voltage loss, ice-based thermal energy storage, and community solar.
In addition, the Company modeled Clean Air Act (CAA) Section 111(d) compliance
possibilities, stochastic risk, and at the request of stakeholders, provided a year-to-year price
variability risk assessment for each portfolio, as well as a tipping point analysis to evaluate how
declining capital costs for utility-scale solar PV and pumped hydro generation effect total
portfolio costs. Although the 2015 IRP emphasizes the quantitative analytical process, the
Company cites qualitative risk factors as the reason for selecting the preferred portfolio that the
quantitative analysis did not find to be either least cost or least risk.
Load and Resource Balance
The Company's system peak and load forecasts reflect continued economic improvement
in the Company's service territory. The IRP anticipates the number of customers will grow from
515,000 in 2014 to 711,000 in 2034, mainly due to net in-migration from other states. In
addition, the Company expects average energy use to increase by 1.2 percent per year, and peak
hour demand to increase by 1.5 percent per year. The IRP predicts 1.3 percent residential load
growth, commercial load growth of 1.0 percent, irrigation load growth of 0.5 percent, and
industrial load growth of 2.0 percent, and additional firm load growth of 0.6 percent. Similar to
customer count projections, the customer class growth projections reflect improving economic
conditions.
The load and resource balance shows the Company has no energy-related deficits
throughout the planning period. A capacity deficit is expected to occur in2025, which steadily
increases through the next 9 years of the planning horizon. Without more resources, the peak-
hour capacity shortfall grows from 14 megawatts (MW) in2025 to 786 MW in 2034. The
STAFF COMMENTS OCTOBER 5,2015
largest capacity deficits occur in the summer months when irrigation load coincides with
residential and commercial air conditioning load. The Company continues to use 70th percentile
water conditions and 70th percentile average load for energy planning. For peak-hour capacity
planning, the Company uses 90th percentile water conditions and 95th percentile peak-hour load.
Demand-side Management (DSM)
The Company convened two Energy Efficiency Working Group meetings to discuss
stakeholder concerns about demand-side management (DSM) program delivery, the Company's
Conservation Potential Assessment (CPA), energy efficiency modeling in the IRP, and
quantifuing the value of transmission and distribution investments deferred by energy
efficiency.l
Conservation Potential Assessment (CPA)
Staff previously expressed concern about the significant gap between the amount of
"economic" (or cost-effective) energy efficiency potential identified in the Company's CPA and
the sub-set of efficiency potential believed to be "achievable" based on program participation
assumptions. This gap impacts the IRP because the Company's load forecast historically has
deducted "achievable" energy savings identified in the CPA. The remaining load is then met
using supply-side resource portfolios evaluated according to cost and risk.
During the first workshop, the Company's third-party consultant presented the CPA's
preliminary results. These results showed that program participation assumptions had been
adjusted to more closely align with the Northwest Power and Conservation Council's ramp rates,
which assume 85 percent of economic potential is "achievable." Since regional utilities
consistently meet efficiency targets based on the Northwest Power and Conservation Council's
ramp rates, and the Company almost always exceeds targets based on more relaxed program
participation assumptions, Staff believes the CPA's updated ramp rates improve on previous
CPAs because they more realistically estimate DSM resource potential.
However, the Company's CPA screens energy efficiency potential for cost-effectiveness
based on a measure's total cost and not the Company's cost to acquire the resource. In practice,
I In Errata to Order No. 33 161 , the Commission directed parties to address issues raised by Staff and other parties in
the context of the Company's next IRP filing. Order No. 33365 found it reasonable for the Company to have
"deferred DSM program delivery discussions to the EEAG." Order at 12.
STAFF COMMENTS OCTOBER 5,2015
this means the CPA excludes cost-effective measures, which limits the potential DSM resources
considered in the IRP. Including costs for DSM resources beyond the Company's costs does not
constitute equal treatment when compared to supply-side resources. Staff continues to believe
that "the IRP should analyze only utility costs."2
Modeling Energ,,Efficiency in IRPs
A main topic at the Energy Efficiency Working Group meetings was the Company's
method for including energy efficiency in its IRP planning process. Stakeholders questioned
whether deducting "achievable" energy savings from the Company's load forecast meets the
IRP's goal of providing equal and balanced treatment to supply-side and demand-side
management resources. In response, the Company stated that deducting DSM from the load
forecast before considering any supply-side resources gives DSM resources preferential
treatment. Staff does not agree with the Company's view. By deducting "achievable" potential
estimates from the load forecast, the amount of DSM in every resource portfolio is identical and
static, regardless of the portfolios' other characteristics or the range of possible future scenarios.
At the Company's request, Staff presented a comparison of how different Idaho utilities'
incorporate DSM in their IRP processes. As explained below, Staff concluded that PacifiCorp
and Avista model energy efficiency differently than the Company.
PacifiCorp's CPA identifies the technical potential and uses the Northwest Power and
Conservation Council's ramp rates on achievability to determine that 85 percent of the technical
potential is "technically achievable." By including 85 percent of the technical potential,
PacihCorp allows a greater amount of DSM to be modeled against supply-side resources. The
"technically achievable" potential is organized into 27 separate supply curve "cost bundles."
PacifiCorp's IRP modeling software (System Optimizer) includes each DSM cost-bundle as a
resource and compares them simultaneously with supply-side resources across a variety of risk
scenarios. Importantly, PacifiCorp's CPA does not determine the cost-effectiveness of the
Company's DSM resources. Instead, System Optimizer decides which resources-both demand
and supply-side-are economic based on each future scenario. PacifiCorp's method is similar to
that of the Northwest Power and Conservation Council and Puget Sound Energy.
2 Staff Comments, IPC-E-l 3-15, at 9.
STAFF COMMENTS OCTOBER 5,2015
Avista's 2015 IRP adopted similar methodology. However, instead of 85 percent, Avista
includes 100 percent of all technical potential in its resource selection model, PRiSM, and rather
than creating cost-bundles, Avista includes each measure as a distinct resource in PRiSM, which
selects resource combinations specifically designed to meet a variety of load and risk scenarios.
Staff believes modeling demand-side resources simultaneously with supply-side
resources could improve the Company's methodology in two ways. First, it provides more equal
treatment of both resource types. Second, it recognizes that the value of demand-side resources
is not static, but fluctuates based on the Company's alternate resources and scenarios. For
example, the value of DSM in a high gas and high carbon scenario increases relative to
conventional supply-side models. A resource selection model in which all resources compete
against each other adapts to meet the requirements of differing scenarios. In contrast, using the
same amount of DSM in each portfolio based on a fixed measure of cost-effectiveness assumes
that the value of DSM should not change under different scenarios.
Deferred Transmission and Distribution
The Energy Efficiency Working Group meetings also discussed including the value of
deferred transmission and distribution from energy efficiency investments in avoided cost
calculations. PacifiCorp, Avista, and the Northwest Power and Conservation Council all include
this value in their avoided costs. The Company has "committed to continuing to investigate" this
benefit,3 and the Commission has encouraged the Company to complete its investigation and
report its findings to stakeholders.a
Dynamic Pricing P ro grams
Like the 2013 IRP, the 2015 IRP did not consider reducing peak load through expanded
dynamic pricing. In the 2013 IRP case, Staff recommended that the Company investigate how
dynamic pricing could reduce peak loads. The Company responded to this recommendation by
stating that it is "conducting a study to determine customer behavior and revenue impact of the
residential time-of-day-pilot plan" and "will continue to evaluate dynamic pricing options . . . to
determine the appropriate time for implementation."s The Company presented the results of its
3 ldaho Power's 2015 Integrated Resource Plan, at 48.
a Order No. 33365 at I l.
5 ldaho Power Company's Reply Comments, IPC-E-13-15, at22.
STAFF COMMENTS OCTOBER 5,2015
Time of Use (TOU) study to the EEAG in February 2015. Unfortunately, the study was not
informative because the Company's "quasi-experimental design"6 did not involve a random
sample of customers. Instead, the voluntary TOU plan primarily encouraged participation from
structural winners, i.e., from people whose bills would decrease without any change in behavior.
When soliciting participants, the Company encouraged customers to consult the rate comparison
tool on its website to determine if their bills would go up or down under the TOU rate schedule.
Because the Company encouraged participation by people who would not need to change their
consumption patterns to benefit from the new rate schedule, the TOU study found no statistically
significant change in energy consumption and only a small reduction in peak usage. As a result,
these findings are not helpful for informing future dynamic pricing plans.
Portfolio Design
The 2015 IRP analyzed portfolios that were primarily developed during a Portfolio
Design Workshop in early January. The IRP analyzed 23 portfolios, which grouped resources
into categories based on resource similarities. These categories included a status quo portfolio,T
a few portfolios without any coal retirements, portfolios with North Valmy retirements ranging
from 2019 to 2025, Jim Bridger retirements ranging 2023 to 2032, a combination of North
Valmy and Bridger retirements, and a set of portfolio alternatives to the B2H transmission line.
Except for the alternative to B2H portfolios, all portfolios included B2H with an online date
between 2021 and2025.
The Company took considerable effort to construct and analyze a wide range of resource
portfolios based on stakeholder feedback. However, the resource combinations in each portfolio
were primarily based on the Company and stakeholders' resource preferences. For example,
solar advocates proposed portfolios with heavy PV penetration, the Company proposed
portfolios that included the B2H transmission line and natural gas plants, and conservation
advocates proposed coal-retirement portfolios. The portfolios competed against each other in
terms of cost and risk under a variety of future scenarios, but the selection method may not (nor
is it designed to) ensure that any of the portfolios atalyzed combine the resources best suited to
meet the most likely future. Staff believes a better portfolio design approach would forecast
6 Idaho Power, Time of Day: Impact Study Results, Fall 2014, at 3.
7 Not compliant with CAA Section I l1(d).
STAFF COMMENTS OCTOBER 5,2015
specific scenarios and then strategically select resource portfolios to mitigate the most significant
and probable risks of those scenarios.
Portfolio Selection
After completing the portfolio design process, the Company analyzed the portfolios for
costs and risk. The Company's analysis involved three steps.
First, fixed and variable costs were established for each of the 23 portfolios.
Second, all23 portfolios were subjected to a CAA Section I I 1(d) sensitivity analysis
based on three scenarios: l) state-by-state mass-based compliance; 2) system-wide mass-based
compliance; and 3) emissions-intensity compliance with building blocks. The state-by-state
mass-based compliance and emissions-intensity compliance were further analyzed for 30
percent, 55 percent, and 70 percent Langley Gulch capacity factors.
Third, a representative sample of I I portfolios based on the initial cost estimate and
resource mix was selected for the stochastic risk analysis. In the risk analysis, each portfolio was
subjected to a set of 100 stochastic iterations based on changes in three variables-natural gas
prices, customer load, and hydroelectric variability-to determine the 20-year Net Present Value
(NPV) of each portfolio to serve customer load under all 100 stochastic iterations.
In both the initial cost assessment and the CAA Section I I l(d) sensitivity analysis,
Portfolio 9 is the least cost portfolio.s See Attachments A and B to Staff Comments.
Additionally, the subsequent stochastic risk analysis concluded that "[portfolio] 9 . . . is the least-
cost portfolio for the full set of 100 iteratio ns."e See Attachment C to Staff Comments.
As requested by IRPAC members, the Company assessed year-to-year price variability
among the portfolios. The Company found that Portfolio 3, which includes a high penetration of
utility-scale PV solar, had the least annual variability. The Company also conducted a Loss of
Load Expectation (LOLE) analysis. The Company found that portfolios 2(a), 6(b), 8, 10, 11, and
13 were the "best performers with an LOLE under 2 hours per year over the 2)-year planning
horizon."l0 The Company did not indicate whether any other portfolio failed the standard.
8 Portfolio 9 includes the retirement of North Valmy Unit I in 2019, Unit 2 retirement in2025, and B2H in2025.
See Idaho Power's 2015 IRP, at 105.
e Idaho Power's 2015 IRP, at 123.
ro ldaho Power's 2015 IRP, at 139.
STAFF COMMENTS OCTOBER 5,2015
Although Portfolio 6(b) is not the least-cost portfolio on an initial-cost basis, or the least-
risk portfolio based on a variety of futures and stochastic risk modeling, the Company selected
Portfolio 6(b) as its preferred portfolio. This portfolio assumes that B2H will be completed and
both North Valmy units will be retired in2025. The portfolio does not add other resources until
60 MW of demand response and20 MW of ice-based thermal energy storage are added in 2030,
and a 300 MW combined-cycle combustion turbine (CCCT) is added in 2031.
The Company notes the unequivocal findings of its stochastic risk analysis (see Staff
Attachment C):
. . . [T]he lack of significant cross of lines [in the risk analysis] is a testament to
the resource diversity of Idaho Power's existing portfolio and the portfolios of
new resources considered in the IRP; under no set of stochastic futures is a
portfolio a clear and runaway cost winner, only to be countered by a different set
of futures for which it is just as clearly a losing portfolio susceptible to
significantly higher costs than other portfolios.ll
Staff agrees with this assessment because it affirms the Company's robust risk analysis.
However, Staff believes the assessment undermines the Company's selection of Portfolio 6(b) as
the preferred portfolio because the risk analysis finds that Portfolio 6(b) is the sixth most risky
portfolio out of the eleven studied.
In defense of its preferred portfolio, the Company states: "portfolios with early North
Valmy retirement performed well in the 2015 IRP analysis, analyses show favorable economics
for portfolios with retirement of North Valmy Unit I as early as2019. However, these portfolios
carry considerable risk associated with uncertainty in:"12
o CAA Section 1l l(d) regulation, particularly on the interim compliance period beginning
in2020;
o PURPA solar, and the impact of future project cancellations on capacity additions in the
early 2020s;
o regulatory acceptance of accelerated depreciation and associated rate impacts for early
coal unit retirement;
o B2H's completion date; and
o retirement planning for a jointly owned power plant.
rr Idaho Power's 2015 Integrated Resource Plan, at 123.
12 Idaho Power's 2015 Integrated Resource Plan, at 10.
STAFF COMMENTS 9 OCTOBER 5,2015
The Company explains that the lack of resource needs before Valmy's 2025 retirement
protects preferred Portfolio 6(b) from the risks associated with these uncertainties. Staff supports
the Company's thoughtful consideration of qualitative risk factors. However, it is difficult to
conclude that these factors justify overriding the conclusive results of the Company's risk
analysis.
Of the five risk factors identified above, two-CAA Section 111(d) and PURPA-have
become less uncertain since the IRP was filed. For example, the EPA's final I l1(d) rule reduces
Idaho's emission-reduction targets and extends the compliance period when compared to the
draft rule that the Company used to assess the IRP portfolios. Furthermore, Commission Order
No. 33357 limits PURPA contracts to two years, which decreases uncertainty around future
PURPA projects. The final CAA Section 111(d) rules and Commission Order No. 33357 do not
eliminate the risks from these factors-Idaho's implementation plan for Section 111(d) has not
been determined and 320 MW of contracted PURPA solar projects have yet to be built-but the
uncertainty has clearly been reduced.
A third risk factor, acceptance of accelerated depreciation for early plant retirement by
regulatory agencies, is significant but may be manageable. For example, if the Company can
demonstrate to the Commission an early plant shutdown with accelerated depreciation would
clearly benefit customers, regulatory acceptance may become more likely given other
alternatives. Staff thus believes the Company increases regulatory uncertainty by selecting a
more expensive and risky preferred portfolio rather than proposing accelerated depreciation with
a least cost/least risk preferred portfolio.
The fourth and fifth risk factors-uncertainty regarding B2H's online date and
negotiating an offline date for North Valmy with NV Energy-are also important. In its 2013
IRP Comments, Staff recommended-but the Company did not adopt-a risk analysis to
quantify the chance of B2H being delayed beyond its previous online date of 2018. The online
date has now been pushed back to 2021 and is included as a qualitative risk. While B2H's online
date may change, this risk affects nearly all the portfolios to some degree since only a small
handful provide alternatives to B2H.
Negotiating North Valmy's retirement with NV Energy is another risk factor. Staff
understands this issue is dynamic, which probably precludes public discussions about the
likelihood of aligning retirement dates between the two utilities. But as an equal owner in North
STAFF COMMENTS l0 OCTOBER 5,2015
Valmy, the Company is better positioned to negotiate for least-cost/least-risk operational terms
than it is for resources in which it is a minority partner, such as B2H and the Bridger coal plant.
Staff believes the Company should have provided more detailed and thorough evidence
about why it overrode the results of its cost and risk analyses to choose a portfolio that is neither
least cost nor least risk.
Action Plan
The Company states its action plan for 201 5 to 201 8 includes continued permitting and
planning for B2H, and investigating North Valmy retirement in collaboration with the plant's
co-owner, NV Energy. The action plan also discusses ongoing permitting and planning related
for the Gateway West transmission line project; evaluating how the EPA's final CAA regulations
impact fossil fuel plants; pursuing cost-effective energy efficiency; amending the Federal Energy
Regulatory Commission license to reduce the 50 MW Shoshone Falls project expansion from 50
MW to 4 MW scheduled to go on-line in2019; completing selective catalytic reduction (SCR)
retrofits for Jim Bridger Units 3 and 4; and beginning to evaluate the economics of SCR retrofits
for Jim Bridger Units I and2.
Staffbelieves this action plan is sufficient to implement the preferred portfolio.
However, the least cost/least risk portfolio includes the retirement of Valmy Unit 1 in 2019. By
implementing a 201 5 to 201 8 action plan that does not include specific steps to meet that goal,
the Company will almost certainly miss the opportunity to implement the Company's identif,red
least cost/least risk resource portfolio.
STAFF' RECOMMENDATION
After reviewing the Company's 2015 IRP, Staff believes that the Company performed
extensive analyses, gave reasonably equal consideration of supply and demand-side resources,
and provided acceptable opportunities for public input, resulting in an IRP that satisfies the
requirements set forth in Commission Order Nos. 25260 and22299. Staff thus recommends the
Commission acknowledge the Company's 2015 IRP.
llSTAFF COMMENTS OCTOBER 5,2075
Respecttully submitted this .{t day of October 2015.
/u /_L
Karl T. Klein
Deputy Attomey General
Technical Staff: Stacey Donohue
i:umisc/comments/ipcel5.l9kksd comments
STAFF COMMENTS t2 OCTOBER 5,2015
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Attachment A
Case No. IPC-E-15-19
staff comments
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,Attachment B
Case No. IPC-E-15-19
Staff Comments
10/05/15 Page I of2
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Attachment B
Case No. IPC-E-15-19
Staff Comments
10/05/15 Page2 of2
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Affachment C
Case No. IPC-E-15-19
Staff Comments
10105115
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 5TH DAY OF OCTOBER 2015,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-15.I9, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-mail: [e-mail]
dockets@idahopower. com
GREGORY W SAID
MICHAEL YOLTNGBLOOD
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail: [e-mail]
myoungblood@ idahopower. com
SECRETARY
CERTIFICATE OF SERVICE