20171127Comments.pdf

SEAN COSTELLO
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 8743
RECEIVED
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Street Address for Express Mail
472 W . WASHINGTON
BOISE, IDAHO 83702-5918
Attomey for the Commission Staff
BEFORE THE IDAHO PUBLTC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S 2OI7 INTEGRATED RESOURCE
PLAN
CASE NO. IPC-E.17.11
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through
its Attorney of record, Sean Costello, Deputy Attorney General, and in response to the Notice
of Modified Procedure and Notice of Comment Deadline issued in Order No. 33889 on
September 26, 2017 , in Case No. IPC-E- 17- I I to submit the following comments.
BACKGROUND
On June 30,2017, Idaho Power Company filed its 20lT lntegrated Resource Plan (IRP).
The IRP is a status report on a utility's ongoing, evolving plans to adequately and reliably serve
its customers at the lowest system cost and least risk over the next 20 years. The Commission
requires the utility to update the IRP biennially, allow the public to participate in its
development, and to implement the IRP. See Order Nos. 22299 and25260. The Company's
pending Application asks the Commission to acknowledge that it has complied in filing its 2017
IRP. By acknowledging the IRP, the Commission has stated that it is acknowledging the
Company's ongoing planning process, not the conclusions or results reached through that
process. See OrderNo. 33441.
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ISTAFF COMMENTS NOVEMBER27,2OI7
More specifically, the Commission has asked that a utility's IRP explain its current
load/resource position, its expected responses to possible future events, and the role of
conservation in its explanations and expectations. 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- 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:
"Existing resource stack," by identifying all existing power supply
resources;
"Load forecast," by discussing expected 20-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 2l-year planning period, with
references to expected costs, reliability, and risks inherent in the range of
credible future scenarios.
rd.
In this case, in its Application, the Company explained that its 2017 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 2017 IRP. The IRP filing consisted of four documents: (1) the 2017 IRP; (2)
Appendix A - Sales and Load Forecast; (3) Appendix B - Demand-Side Management2}T4
Annual Report; and (a) Appendix C - Technical Appendix.
The Company noted that it incorporated stakeholder and public input into its 2017 IRP by
working with an Integrated Resource Plan Advisory Council (IRPAC), consisting of various
stakeholders, and held eight IRPAC meetings while developing the 2017 IRP, including a
workshop designed to explore the potential for distributed generation to defer grid investment.
The Company further explained that the primary goals of its 2017 IRP are to: (1) identifu
sufficient resources to reliably serve growing demand for energy over the 2)-year planning
period (2017-2036); (2) ensure the selected resource portfolio balances cost, risk, and
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2STAFF COMMENTS NOVEMBER27,2OI7
environmental concerns; (3) give balanced treatment to supply-side resource and demand-side
measures; and (4) involve the public in the planning process in a meaningful way.
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 believes the IRP
satisfies these requirements and several aspects of the IRP were well-constructed, Staff also finds
that this IRP has significant deficiencies which unduly influenced the final portfolio selection.
While IRPs are conducted every two years to capture any changes anticipated in the planning
period, the Company repeatedly emphasized the importance of this IRP in making two critical
resource decisions that must be initiated before the next IRP: 1) investing in Selective Catalytic
Reduction Units (SCRs) for Units 1 and2 at its Jim Bridger Coal Facility in Wyomingand2)
evaluating the economics of the Boardman to Hemingway transmission line (B2H).
Staff supports the Company's analysis of generation, average energy forecasting, and the
analytical construction of its portfolio development process, but believes that the Company's
methodology for peak capacity forecasting, the natural gas price assumptions, and similarity of
the modeled portfolios to each other combined to make this IRP far less robust than the 2015 IRP
process. In addition, the Company did not take any steps towards improving its methodology for
modeling demand-side resources similarly to supply-side resources.
Load and Resource Balance
The Company's system peak and load forecasts reflect continued growth in the
Company's service territory. The IRP anticipates the number of customers will grow from
534,000 in 2016 to 756,000 by 2036. The Company anticipates that average energy use will
grow by 0.9 percent per year (a reduction from the 1.2 percent increase forecasted in the 2015
IRP) and peak hour demand to grow by 1.4 percent per year (a reduction from the I .5 percent
increase forecasted in the 2015 IRP).
The 2017IRP predicts l.22percent residential load growth, 0.74 percent commercial
load growth, 0.58 percent irrigation load growth, 0.70 percent industrial load growth, and
additional firm load growth of 0 .7 6 percent. Nearly all of these are reductions from the 20 I 5
IRP forecasts, which were 1.3 percent for the residential, 1.0 for commercial, 0.5 for irrigation,
J NOVEMBER27,2OI7STAFF COMMENTS
2.0 for industrial, and 0.6 for additional firm load growth. The Company's forecasts also show
that the greatest increases in load appear in the early years of the planning period (2017 through
2022) with the increases leveling off in the out years (2022 through 2036).
The Company's load and resource balance compares the capabilities of existing Company
resources with monthly forecast average load and peak demand over the 2O-year IRP planning
period. Without new resources, the Company expects a capacity deficit in July 2026 (the 2015
IRP predicted a2025 capacity deficit) and the first average load (energy) deficit in July 2029 (the
2015 IRP predicted no deficits through 2034). The Company forecasts that first year peak hour
capacity deficit of 34 MW in2026 grows to 986 MW in 2036. The largest capacity deficits
occur in the summer months when irrigation load coincides with residential and commercial air
conditioning load.
As it has for several IRP cycles, the Company uses the 70th percentile water conditions
and the 70th percentile average load for energy planning. For peak-hour capacity plaruring, the
Company uses 90th percentile water and 95th percentile peak-hour load.
Staff notes that the Company's load and resource balance analyses are sensitive to its
growth rate assumptions and believes that the Company should include an analysis of the
sensitivity of projected peak capacity deficit dates to changes in assumed growth rates in future
IRPs. Staff also believes that the Company's peak load forecasts could be improved by
incorporating class-specific forecasts in its analysis.
In a typical year, the Company generates approximately 73 percent of its energy
requirement using Company-owned resources and purchases the remaining 27 percent. The
Company's hydroelectric resources account for the largest share of energy (39 percent) provided
to Idaho Power's customers, followed by coal (24 percent) and diesel/natural gas generation (10
percent). See IRP at23.
To some degree, the ability of all of these resources to deliver power is dependent on
local environmental conditions, but the Company's hydroelectric resources in particular, are
heavily dependent on forecasted hydrological and watershed conditions such as stream flow,
snow pack, and temperature. The Company forecasts resource capacity with stochastic models
that take these variables into account, and uses the results to determine the probabilities of
streamflow conditions necessary to operate its hydroelectric plants. The Company bases its
energy adequacy analysis on 70th percentile stream flow condition. It bases its peak hour
4STAFF COMMENTS NOVEMBER2T ,2017
resource adequacy on 90th percentile streamflow conditions. Staff acknowledges the Company's
comprehensive approach to modeling its resource capabilities, particularly its hydroelectric
modeling.
The Company's average monthly load forecast predicts the amount of energy that it
expects customers to use each month. The average energy load forecast is used to predict the
variable costs that the Company incurs producing and procuring energy. The Company
developed its monthly average load forecast by adding together the individual 70th percentile
forecast monthly loads from each of its customer classes. These class-specific forecasts were
developed using assumptions about customer growth rates for each class, energy consumption as
a function of weather (Heating Degree Days), and assumptions about changes in average
consumption per customer over time. Staff believes this methodology is sufficient for the IRP
planning process, but also believes that the Company should include an analysis of the
methodology's sensitivity to growth rate and modeling assumptions.
While average energy forecasting is an important aspect of resource planning, decisions
to build or buy generation and transmission plant are driven primarily by peak demand rather
than average load. Despite the oversized importance of peak demand forecasting in resource
planning, Staff notes that the Company's system peak demand forecasting methodology is much
less refined than its average load forecasting methodology. The Company's peak demand
forecast model was developed by applying monthly 95th percentile peak temperatures to a single
system-wide regression model, rather than to the multiple class-specific forecasts, which is how
the average energy forecast was developed. These values were then extrapolated for 20 years
resulting in an average 1.4 percent system-wide growth rate per year.
Because of the impact of peak capacity deficits on resource planning needs, Staff
conducted a sensitivity analysis to determine the effects of a slightly smaller peak growth rate
would have on the Company's first capacity deficit. Staff s analysis found that an extremely
small (0.1 percent) decrease in the annual projected growth rate pushed the Company's first
capacity deficit date out by an entire year.l Larger changes in either direction compounds the
impact to the first capacity deficiency date. Since all portfolios modeled in the IRP process must
' This finding is consistent with the difference between the results of the Company's 2015 and2017 IRP analyses.
Using a I .5 percent peak load growh assumption in the 20 I 5 IRP, the Company identified a 2025 first capacity
deficit date. In the 2017 IRP, the Company used a 1.4 percent peak load growth assumption and identified a2026
first capacity deficit date.
5STAFF COMMENTS NOVEMBER27,2OI7
meet the first annual capacity date, a small change to this internally-generated growth rate
assumption can have major impacts on the forecasted resource costs identified by the Company
in the IRP process.
Given the importance of demand forecasting to the IRP results, Staff believes that the
Company should refine its demand model to include individual coincident peak demand
forecasts for each customer class, similar to how it creates average load forecasts. Staff also
believes that the Company should include sensitivity analyses for the Company's key growth rate
and modeling assumptions. This will help the Company and stakeholders identif, the potential
for the system to be overbuilt in the event that the demand forecast over-estimates actual demand
and identify the most cost-effective ways to meet capacity deficits in the early years of the IRP
planning period.
Natural Gas Price Forecast
The most critical difference in this IRP was the Company's decision to change the source
of its natural gas price forecast. In the 2013 and 2015 IRPs, the Company used the EIA's Henry
Hub reference case forecast adjusted for Sumas basis pricing to reflect the Company's city gate
price. The reference case is the median forecast which the Company specifically requested to
use for IRP planning puposes in its 2013 IRP. At the time, the Company explained that the EIA
planning case was the most credible gas price forecast available. Stakeholders at that meeting
were in near unanimous agreement.
In the 2017 IRP, the Company made an abrupt and unexpected departure from that
position. Instead of using the reference case, the Company announced that it would use the
EIA's Henry Hub "High Oil and Gas Resource and Technology Case."2 This forecast assumes
extremely low natural gas prices throughout the 2O-year planning period on the basis that natural
gas drilling technology will advance so quickly beyond currently available technology that
production will increase at a volume that keeps natural gas prices almost entirely flat for next
twenty years. As demonstrated in Attachment A3 it is the lowest EIA gas price forecast.
2 This is not to be confused with the EIA's Mountain Region forecast, also available in high, low, and reference
ranges, which is used in SAR methodology pricing calculations.
3 Attachment A is slide #5 from the Company's January 12,2017,IRPAC presentation. The "2017 EIA Low"
reflects the "High Oil and Gas Resource and Technology Case" and the "2017 EIA Planning" case represents the
reference case.
6STAFF COMMENTS NOVEMBER2T ,2017
This change surprised stakeholders and prompted intense discussions during the IRP
meetings. In those meetings, the Company defended the shift by stating that the EIA reference
case had over-estimated the price of natural gas over the past two IRP cycles. In its view, the
move to the "High Oil and Gas Resource and Technology Case" corrected that over-estimation
and is reasonable because it is consistent with Intercontinental Exchange (ICE) futures natural
gas settles transactions. See Attachment A.
In the IRP meetings, stakeholders stated that many in the natural gas industry, including
forecasters, failed to anticipate shale gas fracking and the unprecedented fall in natural gas
prices. Stakeholders also asked the Company why it was reasonable to assume that six years of
Intercontinental Exchange (lCE) futures prices would persist over the subsequent fourteen years
even though the Company's graph shows no data beyond 2023. The Company merely
maintained that the futures market reflects actual transactions occurring for those years and
therefore serves as a credible indicator about what prices will be in the future.
After much discussion, the IRPAC stakeholders unanimously opposed moving to the new
forecast. Importantly, Idaho Power's Oil and Gas Industry advisor on the IRPAC repeatedly
voiced concerns with the new forecast because he believes natural gas prices are likely to rise as
utilities across the country shift from coal-fired generation to natural gas generation and as
exports of Liquefied Natural Gas (LNG) increase.
Staff conducted considerable research on this issue in Case No. GNR-E-17-02, where the
Company proposed the EIA "High Oil and Gas Resource and Technology Case" as the basis for
SAR Methodology avoided costs. That research informed Staff s analysis of the Company's
2017 IRP and, as a result, Staff disagrees with the Company's logic and position on this issue.a
First, the EIA has significantly reduced the reference case forecast to capture the decline
in market prices. Staff also confirmed with the EIA that the reference case includes ICE future
options as a key component of its near-term price forecasting. This is standard practice in
natural gas price forecasting and is clearly demonstrated by the low gas price in early years of
the reference case.
4 Staff notes that Idaho Power withdrew its request to switch to the EIA's "High Oil and Gas production case" in
Case No. GNR-E-17-02 on August 23,2017.
7STAFF COMMENTS NOVEMBER2T ,2OI7
Second, ICE futures contracts are option contracts. They provide buyers and sellers the
option to make the trade at a certain price on a certain day if both parties still agree to those
terms when the contract date arrives. Futures options include clauses that allow either party to
exit the agreement by paying a penalty or losing the upfront cost paid to secure the option.
Under that structure, buyers and sellers in the futures market are protected from drastic
divergences between their contracted futures prices and actual spot market prices.
Third, buyers participate in the ICE futures market as a hedge specifically because they
believe future spot market prices will be higher than prices available on the spot market on that
day and year. Sellers in the futures market also understand that prices are likely to rise, but are
willing to commit to those prices to ensure that at least some of their product sells. So rather
than being a reflection of actual future spot market pricing, ICE futures options are merely a
reflection of what today's market is willing to pay now to have that option within the next six
years.
Fourth, the volume of trades in the futures market declines dramatically over time as very
few buyers or sellers are willing to commit to a futures option beyond the sixth year. As shown
in Attachment B,5 trading volume is highest in the first year, steadily declines through the
remaining five years, and ceases to exist entirely by 2028. Staff believes it is unreasonable to
base a 2}-year forecast on six years of declining sales volume data.
Lastly, using a very low natural gas price forecast is the equivalent of planning to a "best
case" scenario. This directly contradicts how the Company plans for water conditions, average
load, and peak-hour capacity. As previously noted, the Company uses 70th percentile water
conditions and the 70th percentile average load for energy planning. For peak-hour capacity
planning, the Company uses 90th percentile water and 95th percentile peak-hour load. While the
EIA reference case would be approximately a5Oth percentile gas price assumption, Staff
estimates that the "High Oil and Gas production Case" forecast is closer to perhaps a 5th or 1Oth
percentile assumption. Since the Company does not assume favorable conditions for any of its
other planning metrics, Staff does not believe it is appropriate to assume the lowest available gas
price forecast.
Most importantly, assuming extremely low gas prices creates a disproportionate upside
price risk. A very low gas price forecast makes resources whose variable costs are closely linked
5 Attachment B is Idaho Power's response to Simplot's Request for Production No. 13, pages2-4, in GNR-E-17-02.
8STAFF COMMENTS NOVEMBER27,2Ol7
to gas prices (such as natural gas plants and transmission) appear less costly than other resources
which have lower variable price risk (such as coal-fired or solar generation). That means that an
IRP could use the low gas price forecast to select large capital investments which are linked to
natural gas. The Company benefits from the capital investment and passes the significant risk of
variable price increases to customers.
Equal Treatment of Demand and Supply-Side Resources
Staff continues to have two concems with the Company's treatment of demand-side
resources in its planning process. First, the Company still includes non-utility costs when
assessing the costs of DSM, and second, the Company deducts demand-side resources from the
load forecast rather than modeling it alongside supply-side resources similar to the method used
by Avista, PacifiCorp, and other regional utilities. The Company's current practice minimizes
the amount of cost-effective energy efficiency included in the resource plan and also means that
each portfolio and every future scenario includes exactly the same amount of energy efficiency,
despite the fact the value of energy efficiency rises in a high natural gas or high carbon scenario.
In Order No. 33441, the Commission encouraged the Company to explore whether "its
IRP could more effectively incorporate energy efficiency by using a model that is similar to
those used by PacifiCorp, Avista, the Northwest Power and Conservation Council, or Puget
Sound Energy." In its Application in this case, the Company maintains that it "led discussions
with the 2017 IRPAC describing its approach of developing portfolios that include an IRP target
for energy efficiency expansion under planning (or expected) case inputs and assumptions." The
Company believes that changing its methodology is not warranted because the contractor who
developed its Conservation Potential Assessment (CPA), Applied Energy Group (AEG), adhered
to the standards outlined in the National Action Plan for Energy Efficiency (NAPEE) Guide for
Conducting Energy Efficiency Potential Studies. However, AEG's practices and the NAPEE
standards are both consistent with Staff s position as it relates to the equal treatment of demand
and supply-side resources in the IRP process.
Idaho Power directed AEG to include non-utility costs when it established the costs of
demand-side resources in its potential study. Including costs not incurred by the utility is
inconsistent with supply-side planning practices. During the January 72,2017,IRPAC meeting
referenced in the Company's Application, Staff asked AEG how difficult it would be to include
9STAFF COMMENTS NOVEMBER27,2OI7
only utility-costs in its CPA assessment. AEG confirmed that it would be quite simple and that
AEG had already produced a CPA for another state using that methodology.
The NAPEE guidelines, which are generally quite broad, specifically permit using utility-
only costs when modeling energy efficiency (see NAPEE at 3-6 though 3-7) and do not address
or take any position on how energy efficiency potential should be incorporated in IRPs.
Regardless of the methodology used to determine the amount of energy efficiency
potential, the Company still fails to incorporate energy efficiency as a resource alongside supply-
side resources in its IRP modeling process. Instead, it still deducts the energy efficiency
potential from forecasted load and then, with the exception of some additional demand response,
builds supply-side resources to meet the remaining load. This means that the exact same amount
of energy efficiency is included in every resource portfolio and in all possible risk scenarios
(e.g., high gas prices, low hydroelectric conditions, high carbon prices) even though the value of
energy efficiency obviously increases under each of those circumstances.
In contrast, Avista has moved from a static, non-utility cost analysis - similar to Idaho
Power's current methodology - to an almost entirely dynamic, utility cost-based analysis of
demand-side resources between its 20 i 5 and 2017 IRPs. AEG performed Avista's CPAs in both
of those IRPs.
Deferred Transmission and Distribution
Consistent with the Company's previous commitments and the encouragement provided
it in Order No. 33365,6 the Company has studied the value of transmission and distribution
benefits that can be deferred with demand-side resources. The results of this study were
presented to the IRPAC on October 13,2017. While Staff appreciates the Company's analysis,
the benefits were calculated using a 7 -year stream of deferred investments rather than the 2)-year
stream used in all other resource investments. Pursuant to Order No. 33908, Staff looks forward
to working with the Company through its Energy Efficiency Advisory Group (EEAG) to address
this issue and "report back to the Commission if the 2}-year analysis is not acceptable." See
Order at 7.
6 Case No. IPC-E-15-06.
STAFF COMMENTS 10 NOVEMBER27,2OI7
Portfolio Design
The Company designed the portfolios for this IRP in order to make two important near-
term resource decisions: 1) deciding to make SCR investments required for Jim Bridger Units I
and2by 2022 and202l, respectively; and 2) deciding to proceed with the B2H transmission
line. A series of systematic altematives to each of those resources investments was analyzed and
modeled to inform both decisions.
The Company states that four scenarios were analyzedto study the SCR investments:
1) Scenario 1: Install SCRs and operate Units I and2 through the entire planning period;
2) Scenario 2: Do not make SCR investments and retire Units 1 and2 in202812024;
3) Scenario 3: Do not make SCR investments and retire Units 1 and2 in203212028; and
4) Scenario 4: Do not make SCR investments and retire Units I and2 in202212021.
Under each of these four Jim Bridger scenarios, the Company developed three
altematives (for a total of 12 portfolios),7 which are:
(a) A portfolio includingB2H and reciprocating gas engine generation;
(b) A portfolio including utility-scale solar and reciprocating gas engine generation; and
(c) A portfolio including reciprocating gas engine generation and a Combined Cycle
Combustion Turbine (CCCT).
This approach is a more systematic method for designing resource portfolios than the
previous IRP. Although the systematic approach can be preferable because it provides a more
meaningful way to ensure that portfolios within the design do not unintentionally exclude the
most beneficial portfolio, the method used by the Company falls short in a very critical way: the
original l2 resource portfolios only analyzed three categories of generation (natural gas fired
generation, transmission, and utility-scale solar).
Considering that the Company went to great lengths to research, produce, and update the
fixed and variable costs of about 30 resources before designing portfolios, Staff asked the
Company in the IRP meetings why it chose to constrain the resources that it modeled so
dramatically. In response, the Company reiterated that the purpose of this IRP was to determine
if the Company should invest in SCRs at Bridger and pursue B2H. The Company believed that
these resources were the least expensive and therefore provided the most difficult threshold that
the SCR/B2H decisions must pass in order to be economic.
? All 12 portfolios comply with the final Clean Air Act (CAA) Section I l1(d) mass-based emission limits.
STAFF COMMENTS il NOVEMBER2T ,2017
At Staff s request, the Company added 50MW of cost-effective demand response to the
non-B2H portfolios. However, no other least cost resources, such as additional cost-effective
energy efficiency, time-of-use rates, or any other type of generation were included in any
portfolio.
In addition, the Company made no effort to design portfolios in order to minimize risk
and cost in a most probable future. Staff continues to believe that a better portfolio design
approach would be to forecast a host of specific future scenarios around customer load, gas,
hydro, and carbon variations and then strategically select resource portfolios to mitigate the
largest and most likely risks associated with each scenario. The Company maintained that its
Bridger retirement dates were future scenarios around which its portfolios were designed. But
since the decision to run or retire the plant lies with the plant owners, it does not qualify as an
exogenous risk for the Company to mitigate.
Another Staff concern with the portfolio design process is the assumption that the Bridger
units could avoid SCR installation on the compliance dates of 202212021 in exchange for early
retirement. The Company maintains that similar agreements have been reached across the West
on multiple coal plants. Staff does not dispute that. However, current EPA leadership may be
less inclined to encourage early retirement of coal plants than the leadership in place when
previous deals were struck. If early retirement in lieu of SCRs is not achievable, customers
could end up paying for SCRs in addition to the other resources which were built in advance to
replace the Unit I and2 generation.
Portfolio Selection
After completing the portfolio design process, the Company analyzed each portfolio for
cost and risk in a two-step process.
First, fixed and variable costs were calculated to establish the net present value (NPV)
over the 2}-year planning period for all twelve portfolios. The lowest cost option was Portfolio
7, which included Bridger Units I and2 retiring in202812032,82H coming online in2026, and
then either a reciprocating engine or a CCCT being built in all but one year between 2031 and
2036.
Second, all 12 portfolios were subjected to stochastic risk analysis to see how the ranking
of portfolio cost changed when the three variable assumptions were changed: natural gas prices,
STAFF COMMENTS t2 NOVEMBER27,2OI7
customer load, and hydroelectric generating conditions. The Company created a set of 100
iterations based on those three variables and then calculated the 2)-year NPV for each of the l2
portfolios. Portfolio 7 was the lowest cost portfolio for 92 of the 100 stochastic iterations, and
also the lowest for average, median, lowest minimum value, and lowest maximum value.
This was not a surprising result. The insufficient resource diversity among the 12
portfolios meant that as the input assumptions change, the cost of nearly all the portfolios would
rise and fall together. This is especially true when many of the portfolios rely so heavily on
resources susceptible to natural gas price changes, including transmission and natural gas-fired
generation.
Although a risk assessment of very similar resources is not very robust, the Company's
analysis confirmed that Portfolio 5 (which included 520 MW of installed solar capacity and
B2H) had the lOth highest average cost across the futures, but the lowest variation in cost across
the futures. In contrast, Portfolio 7 (B2H and natural gas plants) had the lowest average cost but
the 9th highest standard variation. This means that Portfolio 5 is far less susceptible to changes
in the input variables than Portfolio 7. However, the Company maintains that the $20 million
difference in standard deviation between Portfolio 5 and Portfolio 7 is dwarfed by the $175
million average price difference between the two portfolios. That is true, but in part because the
average resource costs of Portfolio 7 benefit more from the Company's unreasonably low gas
price forecast than the resources costs in Portfolio 5. Staffalso notes that unreasonably low gas
prices assumptions disadvantage portfolios with coal-hred generation and SCR investments.
Based on the results of the stochastic risk analysis, the Company selected Portfolio 7 as
its preferred portfolio. In addition, the variable price risk in Portfolio 7 being disproportionately
borne by customers, Staff is also concerned that Portfolio 7 assumes that Bridger Units 1 and 2
would be allowed to operate for 10 andT years, respectively, after the mandated SCR
compliance dates.
Action Plan
The stated goal of this IRP was to make a determination on SCR investments at Bridger
and the economics of B2H. The Company states that its action plan for 2017 through2}2l
includes beginning and successfully completing negotiations necessary to allow Bridger Units I
and2 to operate beyond their compliance dates without SCRs and retire in2028 and2032.
STAFF COMMENTS l3 NOVEMBER27,2OI7
Regarding B2H, the Company states that the action plan includes continued permitting as
well as preliminary construction beginning in 2018. The action plan also includes moving
forward with the previously determined plan to retire Valmy Units I and 2 in 2019 and 2025 and
acquire the subsequent transmission availability from northern Nevada. Other items in the action
plan include proceeding with the Gateway West transmission project, pursuing the cost-effective
energy efficiency identified through the CPA process, preparing for EIM participation in April
2018, ongoing involvement in the CAA Section 111(d) proceedings, and investigation of solar
PV contribution to peak and loss of load probability in preparation for the 2019 IRP.
Staff believes this plan is adequate to implement the preferred portfolio. However, Staff
believes that the Company's methodology for peak capacity forecasting, the limited energy
efficiency resource modeling, the very low natural gas price assumptions, and similarity of the
modeled portfolios to each other combined to make this IRP far less robust than its predecessor.
RECOMMENDATIONS
After reviewing the Company's 2017 IRP, Staff believes that the Company performed
sufficient analysis, 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.
Respectfully submitted this zvn day of November 2017
Sean Costello
Deputy Attorney General
Technical Staff: Stacey Donohue
Michael Morrison
Umisc/Comments/ipcel 7. I Iscsdmm comments
STAFF COMMENTS t4 NOVEMBER27,2OI7
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Attachment A
Case No. IPC-E-17-l I
Staff Comments
I t/27 /17
I
</|
nlsutl r/s
a
Open interest as of:
June 12,2017
Month
Henry Hub Natural Gas Lad
Oay FinancialVolume
Contract size= 2,500 mmBtu
Open
lnterosl Total mmBtu
56,5'17 141,292,500
52,128 130,320,000
49,427 123,567,500
62,089 155,222,500
47,450 118,625,000
48,653 121,632,500
64,155 160,387,500
35,064 87,660,000
41,473 103,682,500
50,676 126,690,000
35,278 88,195,000
33,128 82,820,000
u,738 86,845,000
35,146 87,865,000
33,322 83,305,000
46,051 115,127,500
31,355 78,387,500
33,445 83,612,500
19,929 49,822,500
16,547 41,367,500
18,857 47.142,500
14,321 35,802,500
14,497 36.242,500
14,078 35,195,000
143U 35,835,000
14,297 35,742,500
13,962 34,905,000
14,777 36,942,500
14,180 35,450,000
15,015 37,537,500
11,147 27,867 ,500'10,177 25,442,500
10,785 26,962,500
9,877 24,692,500
10.344 25,860,000
9,976 24,940,000
10,465 26,162,500
10,506 26,265,000
10,167 25,417,500
10,397 25,992,500
10,085 2s,212,500
10,015 25,037,500
5,197 12,992,500
4,792 1 1,980,000
5,162 12,905,000
4,902 12,255,000
5,06s 12,662,500
4,976 12,440,000
5,127 12,817,500
5,164 12,910,000
4,948 12,370,000
4,975 12,437,sOO
4,856 12,140,000
5,018 12,545,000
Henry Hub Natural Gas Futures
Contract size= 10,000 mmBtu
Open
lnteresl Total mmBtu
Total Open lnteresl in
mmBtu
2,252,172,500
2,067,720,000
1,823,077,500
1,996,722,s00
845,325,000
793.762,500
1 ,281,187 ,500
538,490,000
843,642,500
1,01 1,350,000
487,545,000
302,700,000
339,655,000
287,145,000
259,31 5,000
534,587,500
285,307,500
31 1,492,500
1 56,982,500
76,647,500
95,242,500
92,602,500
51,822,500
49,51 5,000
48,865,000
48,31 2,500
47,045,000
70,91 2,500
49,890,000
52,057,500
37,287,500
30,762,500
32,91 2,500
32,302,500
32,250,000
30,370,000
31,422,500
31 ,165,000
30,3'17,500
31,132,500
30,422,500
33.227,500
14,372,500
1 3,270,000
14,075,000
1 3,07s,000
1 3,342,500
1 3, 1 20,000
13,477,500
1 3,580,000
1 3, 1 10,000
13,127,500
1 2,820,000
1 3,575,000
JUL 17
AUG 17
SEP 17
ocr 17
NOV 17
oEc 17
JAN 18
FEB 18
MAR 18
APR 18
MAY 18
JUN 18
JUL 18
AUG 18
SEP 18
OCT 18
NOV 18
DEC 18
JAN 19
FEB 19
MAR 19
APR 19
N/IAY 19
JUN 19
JUL 19
AUG 19
SEP 19
ocT 19
NOV 19
DEC 19
JAN 20
FEB 20
MAR 20
APR 20
MAY 20
JUN 20
JUL 20
AUG 20
SEP 20
OCT 20
NOV 20
DEC 20
JAN 2,I
FEB 21
MAR 21
APR 21
MAY 21
JUN 21
JUI 21
AUG 21
SEP 21
ocr 21
NOV 21
DEC2l
211,088
1 93,740
1 69,951
't 84,150
72,670
67,213
112,080
45,083
73,996
88,466
39,935
2'1,988
25,281
1 9,928
17,601
41,946
20,692
22,788
'10,716
3,528
4,810
5,680
1,558
1,432
1,303
1,257
1,214
3,397
1,444
1,452
942
532
595
761
639
543
526
490
490
514
521
819
138
129
117
82
68
68
66
67
74
69
68
103
2.1 10,880,000
1,937,400,000
1,699,510,000
1,841,500,000
726,700,000
672, 1 30,000
1,1 20,800,000
450,830,000
739,960,000
884,660,000
399,350,000
219,880,000
252,810,000
1 99,280,000
1 76,01 0,000
41 9,460,000
206,920,000
227,880,000
1 07, 1 60,000
35,280,000
48,1 00,000
56,800,000
1 5,580,000
14,320,000
13,030,000
1 2,570,000
12,140,000
33,970,000
14,2140,000
14,520,000
9,420,000
s,320,000
5,950,000
7,610,000
6,390,000
5,430,000
5,260,000
4,900,000
4,900,000
5,'140,000
5,2'10,000
8, 1 90,000
1,380,000
1,290,000
1 , 1 70,000
820,000
680,000
680,000
660,000
670,000
740,000
690,000
680,000
'1,030,000
Attachment B
Case No. IPC-E-17-11
Staff Comments
lll27ll7 Page I of 3
Open interesl as of:
June 12,2017
Month
Henry Hub Natural Gas Las{
Day Financial Volume
Contract size= 2,500 mmBtu
Open
lnteresi Total mmBtu
3,749
3,388
3,757
3,701
3,805
3,672
3,777
3,773
3,663
3,891
3,509
3,621
2,478
2,360
2,595
2,516
2,595
2,516
2,571
2,571
2,492
2,571
2,492
2.571
1,740
1,636
1,740
1,688
1,740
1,688
1,740
1,740
1,688
1,740
1,688
1,740
1,092
984
1,092
1,056
1,092
1,056
1,092
1,092
'1,056
1,092
1,056
1,092
536
488
536
520
536
520
Henry Hub Natural Gas Futures
Contract size= 10,000 mmBtu
Open
lntereS Total mmBtu
50,000
50,000
60,000
1 30,000
140,000
1 30,000
140,000
140,000
1 30,000
1 30,000
1 30,000
20,000
30,000
Total Open lnteresi in
mmBtu
9,422,500
8,520,000
9,452,500
9,382,500
9,6s2,500
9,310,000
9,582,500
9,572,500
9,287,500
9,857,500
8,902,500
9,072,500
6,225,000
5,900,000
6,487,500
6,400,000
6,617,500
6,400,000
6,427,500
6,427.500
6,230,000
6,467,500
6,230,000
6,427,500
4,350,000
4,090,000
4,350,000
4,220,000
4,370,000
4,230,000
4,350,000
4,350,000
4,220.000
4,350,000
4,220,000
4,350,000
2,730,000
2,460,000
2,730,000
2,640,000
2,740,000
2,640,000
2,730,000
2,730,000
2,640,000
2,730,000
2,640,000
2,730,000
1,340,000
1,220,000
1,340,000
1,300,000
1,340,000
1,300,000
JAN 22
FEB 22
MAR 22
APR22
MAY 22
JUN 22
JUL22
AUG 22
SEP 22
oc'l 22
NOV 22
oEc 22
JAN 23
FEB 23
MAR 23
APR 23
MAY 23
JUN 23
JUL 23
AUG 23
SEP 23
OCT 23
NOV 23
DEC 23
JAN 24
FEB 24
MAR 24
APR 24
MAY 24
JUN 24
JUL24
AUG 24
SEP 24
ocT 24
NOV 24
oEc24
JAN 25
FEB 25
MAR 25
APR 25
MAY 25
JUN 25
JUL 25
AUG 25
SEP 25
ocr 25
NOV 25
oEc 25
JAN 26
FEB 26
MAR 26
APR 26
MAY 26
JUN 26
9,372,500
8,470,000
9,392,500
9,252,500
9,51 2,500
9,1 80,000
9,442,500
9,432,500
9,1 57,500
9,727,500
8,772,500
9,052,500
6, 1 95,000
5,900,000
6,487,500
6,290,000
6,487,500
6,290,000
6,427,500
6,427,500
6,230,000
6,427,500
6,230,000
6.427,500
4,350,000
4,090,000
4,350,000
4,220,000
4,350,000
4,220,OOO
4,350,000
4,350,000
4,220,000
4,350,000
4.220,000
4,350,000
2,730,000
2,460,000
2,730,000
2,640,000
2,730,000
2,640,000
2,730,000
2,730,000
2,640,000
2,7s0,000
2,640,000
2,730,000
1,340,000
1,220,000
1,340,000
1,300,000
1,340,000
1,300,000
1 10,000
1 30,000
1 10,000
40,000
20,000
1 0,000
I 0,000
5
5
6
13
14
13
14
14
13
13
13
2
3
11
13
11
4
2
1
Attachment B
Case No. IPC-E-17-l I
Staff Comments
1ll21ll7 Page2 of 3
Open intere$ as of:
June 12,2017
Month
Henry Hub Natural Gas Lasl
Day FinancialVolume
Contract size= 2,500 mmBtu
Openlnterest Total mmBtu
1,340,000
1,340,000
1,300,000
1,340,000
1,300,000
1,340,000
542,500
507,500
542,500
52s,000
542,500
525,000
542,500
542,500
525,000
542,500
525,000
u2,500
Henry Hub Natural Gas Futures
Contract size= 10,000 mmBtu
Open
lnteresl Total mmBtu
Total Open lnteresl in
mmBtu
JUL 26
AUG 26
SEP 26
ocT 26
NOV 26
DEC 26
JAN 27
Feb 27
Mar 27
Apr 27
May 27
Jun 27
Jul 27
Aug 27
Sep 27
Ocl27
Nov 27
Dec 27
JAN 28
FEB 28
MAR 28
APR 28
MAY 28
JUN 28
JUL 28
AUG 28
SEP 28
OCT 28
NOV 28
DEC 28
536
536
520
536
520
536
1,340,000
1,340,000
1 ,300,000
1,340,000
1,300,000
1,340,000
u2,500
507,500
542,500
52s,000
542,500
525,000
542,500
542,500
525,000
u2,500
525,000
542,500
Attachment B
Case No. IPC-E-17-11
Staff Comments
l1l27l17 Page 3 of 3
217
203
217
210
217
210
217
217
210
217
210
217
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 27TH DAY OF NOVEMBER 2017,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-I7-II, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-mail : [e-mail]
dockets@idahopower. com
PETER J. RICHARDSON
RICHARDSON ADAMS, PLLC
PO BOX 7218
BOISE ID 83702
E-mail : [e-mail]
ERIC L. OLSEN
ECHO HAWK & OLSEN, PLLC
505 PERSHING AVENUE STE IOO
PO BOX 6119
POCATELLO ID 83205
E-mail: elo@,echohawk.com
C. TOM ARKOOSH
ARKOOSH LAW OFFICES
802 W BANNOCK STREET STE 9OO
PO BOX 2900
BOISE ID 83701
E-mail : [e-mail]
[e-mail]
TIMOTHY E TATUM
MICHAEL J YOLINGBLOOD
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
myoung
DR. DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail : [e-mail]
ANTHONY YANKEL
I27OO LAKE AVENUE T]NIT 2505
LAKEWOOD OH 44107
E-mail: [e-mail]
PETE BENNETT
MICRON TECHNOLOGY INC
8OOO SOUTH FEDERAL WAY
BOISE TD 83707
E-mail : cbennett@micron. com
.com
CERTIFICATE OF SERVICE
THORVALD A. NELSON
EMANUEL T. COCIAN
KIM STANGER
HOLLAND & HART
6380 S. FIDDLERS GREEN CIRCLE
STE 5OO
GREENWOOD VILLAGE CO 80111
E-mail : [e-mail]
etcocian@hollandhart. com
kc stan ger@holl andhart. com
khall@hollandhart. com
GREGORY M ADAMS
RICHARDSON ADAMS, PLLC
515 N 27TH STREET
BOISE ID 83702
E-mail : s.r e p(d.richard sonadam s.com
GLORIA D SMITH
SIERRA CLUB
2101 WEBSTER STREET, SUITE 13OO
OAKLAND CA94612
E-mail: [e-mail]
JIM KREIDER
STOP B2H
60366 MARVIN RD
LA GRANDE OR 97850
-b
SECRETAR
CERTIFICATE OF SERVICE