20200805Comments.pdf

DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03t2
IDAHO BAR NO.9917
:0:l AiiG -5
i:iICEiYED
Plt 3: 55
'-,.:-,, ,iils,i$Sltr{
Street Address for Express Mail:
1I33I W CHINDEN BVLD, BLDG 8, SUME 201.A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN
POWER'S 2019 ELECTRIC INTT,GRATED
RESOURCE PLAN
CASE NO. PAC.E.19.16
COMMENTS OF THE
COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission, by and through its Attorney of
record, Dayn Hardie, Deputy Attorney General, submits the following comments.
BACKGROUND
On October 25,2019, PacifiCorp dba Rocky Mountain power (..Company,,) frled its 2019
Electric Integrated Resource Plan ("2019 IRP") pursuant to the Commission's rules and in
compliance with the biennial IRP filing requirements mandated in order No.22299. The
Company's Application requested acknowledgement of the 20lg IRp.
The company's IRP filing consists of the following items: l) 20lg lnregrated Resource
Plan - Volume l;2) 2019 Integrated Resource Plan - Volume II, Appendices A-L; 3) 2019
lntegrated Resource Plan - volume II, Appendices M-R;4) Supplemental Data Discs; and 5)
Supplemental Corrections (October 25,2019 and November 8, 2019).
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STAFFCOMMENTS AUGUST 5,2O2O
On December 3, 2019, the Commission issued a Notice of Filing and Notice of
Intervention Deadline. Order No. 34494. No one applied to intervene.
STAFF REVIEW
Staff believes the Company has met the requirements for an Integrated Resource PIan set
forth in commission order No. 22299 and recommends the Commission acknowledge the
Company's 2019 IRP filing. Order No . 22299 reqtires that the Company provides:
1. An examination of load forecast unceflainties;
2. An identification of effects of known or potential changes to existing resources;
3. Consideration of demand and supply side resource options; and
4- Recognition of contingencies for upgrading, optioning, and acquiring resources at
optimum times (considering cost, availability, lead time, reliability, risk, etc.) as
future events unfold.
Stafls recommendation is supported by its review of the IRp filing, the Company,s
responses to production requests, and the Company's effort to solicit comments from
stakeholders through the public input process. Staff directly participated in all IRP stakeholder
meetings.
The 2019IRP is the product of the company's most comprehensive IRp analysis to date.
staffbelieves that the company has substantially improved its methodology for evaluating the
costs, benefits, and timing of integrating new generation and transmission resources into its
system. The Company has also extensively examined the reliability implications of its resource
options.
Staff has identified areas where it believes additional review or focus is waranted. These
include:
o Capacity Deficiency Date in the Load and Existing Resource Balance;
r Integrating updated coal unit decommissioning cost studies into the planning
process;
. Long-run gas cost assumptions. The Company,s 2019 IRp gas cost forecast is
significantly higher than the Company,s 2017 forecast;
r Transmission Planning; and
. Continuation of Demand Side Management (DSM) and time-of-use efforts.
2STAFF COMMENTS AUGUST 5,2020
2019 IRP Overview
The primary objective of the Company's 20l9IRP is to identify the best mix of resources
to serve customers' energy requirements in future years. The best mix of resources is identified
through analysis that measures both cost and risk. The least-cost, least-risk resource portfolio,
defined as the "preferred portfolio," is a portfolio that can be delivered through specific action
items at a reasonable cost and with manageable risk, while considering customer demand for
clean energy and ensuring compliance with state and federal regulatory objectives.
The 2019 IRP prefered portfolio reflects accelerated coal retirements and expanded
investment in new wind and solar resources, battery storage, and demand side management. By
2025, the prefened portfolio includes nearly 3,500 MW ofnew wind resources, 3,000 MW of
new soltu resources, nearly 600 MW of battery storage capacity, 860 MW of incremental energy
eff,rciency resources and new direct load control capacity. Over the 20-year planning horizon,
the IRP preferred portfolio includes more than 4,600 MW of new wind resources, more than
6,300 MW of new solar resources, more than 2,800 MW of battery storage, and morc than
1,890 MW of incremental energy efficiency resources and new direct load control capacity.
The preferred portfolio also includes new transmission investments across the Company's
tenitory needed to remove existing transmission constraints and improve grid resilience so the
Iowest-cost renewable resources can be delivered to customers. For delivery of new renewable
power to customers, the Company's 2019IRP preferred portfolio also includes the construction
of Gateway South, a 400-mile transmission line connecting southeast Wyoming with northem
Utah.
The Company enhanced its 20l9IRP modeling to address the choice ofcoal plant
retirement dates . In 2017 IRP comments, Staff stated the Company relied on predetermined
retirement dates tied to environmental compliance rather than evaluating the economic viability
ofcoal units over a range of potential retirement dates. Predetermining retirement dates in the
2017 IRP prevented the optimization model from selecting coal plant retirement dates based on
economics. In the 2017 IRP, Staff was also concerned that including benefits beyond the 20-year
planning horizon distorted comparisons between pofifolios. The Company, in its 2019 IRp, has
fully addressed these issues. The Company has also improved its ability to conduct a robust
analysis of its resources - including its coal unit retirements - and refined its understanding of
system reliability associated with increased amounts of renewable resources. The methodology
JSTAFF COMMENT.S AUGUST 5,2020
used in the coal studies informed the preferred resource portfolio reflected in the Company,s
IRP.
Table No. 1 below shows accelerated coal plant retirement dates in the 2019IRp
compared to the retirement dates in the 2017 IRP. As Table No. I shows, coal plant retirements
in the 2019 IRP are four to nineteen years earlier than previously planned. The multi-state
process ("MSP") is also engaged in coal plant retirement analyses.
Table No. I - 20ll and 2019 IRP Planned CoaI Unit Retirement Dates
The 2019 IRP includes new battery storage for the first time as part ofthe least-cost, least
risk preferued portfolio. Battery storage is used to support reliability ofa system increasingly
supponed by renewable resources and variable generation. Ta,r incentives are important in
supporting the economic viability of battery storage.
The use of front office transactions ("FOT") in rhe resource mix is reduced in the 2019
IRP compared to prior IRPs. In this IRP, the Company has treated FOTs as proxy resources,
assumed to be firm, representing on-going procurement activity to help cover short positions,
with FOTs being made on a balance of month, day-ahead, hour-ahead, or intra hour basis. The
Company states that FOT limits are based upon its active participation in wholesale power
markets, physical delivery constraints, market liquidity and market depth, and regional resource
supply. Staffbelieves that reduced reliance on FOTs is prudent given supply uncertainties for
later dates in the forecast model. Increased renewable generation and battery storage are drivers
in the FOT reduction.
4
Coal Unit
Retirement Date
2019 IRP
Retirement Date
2017 IRP
Difference in
Years
Jim Bridger Unit I 2023 2028 5
Jim Bridger Unit 2 2028 2032 6
Naughton Unit I 2025 2029 4
Naughton Unit 2 2025 2029 4
Craig Unit 2 2026 2034 8
Colstrip Unit 3 2027 2M6 19
Colstrip Unit 4 2027 2046 l9
STAFF COMMENTS AUGUST 5, 2O2O
The 2019IRP includes the conversion of the Naughton 3 coal unit to natural gas. Staff
supports this conversion because it is a cost-effective transition from coal and retains a firm
dispatchable resource.
Canaclfv Deficiencv Date ln the Load and Existine Resource Balance
The load and resource balance presented in Chapter 5 of the IRp identifies the
Company's capacity and energy deficiencies before identifying the resources that will be used to
economically meet future load and reliability needs. The capacity deficiency information is also
used in a biennial capacity deficiency hling, which occurs after the acknowledgement of the IRp,
to determine avoided cost rates under PURPA. Based on the load and resource balance,
Pacificorp's system first becomes capacity deficient during the 2028 summer peak. (see Table
No. 5.12 of the Company's IRP).
The capacity deficiency in the load and resource balance, both the timing and the amount
of the deficiency, will be used to determine when new PURPA contracts are eligible to receive
capacity payments. However, Staff is concerned that the inclusion of the Company's coal plant
retirements in the load and existing resource balance may affect the deficit date.
The load and existing resource balance identihes resource deficiencies in the Company's
system acting as a starting point for developing and evaluating future resource portfolios. A
decision to close a plant early must be evaluated against other alternatives that maintain system
reliability and should be made as part ofthe portfolio development and evaluation phase of the
IRP. Regardless of whether the decision to close a plant early is driven by economics or by
environmental compliance, the Company should choose the least cost alternative that maintains
system reliability, which likely requires additional replacement resource(s). The early retirement
and the replacement resources should be considered as a combined resource decision and should
only be included together so an accurate deficit date can be determined. However, the company
has reflected coal plant retirements from the preferred portfolio in its load and resource balance
contained in Tables 5.12 and 5.13 of the 2019 IRp, which staff believes is improper for purposes
of establishing a first deficiency date for PURPA.
5STAFF COMMENTS AUGUST 5,2020
Coal Unit Dec ssionins Costs
On January l'1,2020 and March 16,2020, the Company filed supplemental confidential
decommissioning studies for each of the Company's remaining coal units. The studies provided an
in-depth third-party analysis for the requirements and costs associated with closing each of the
remaining coal units. Decommissioning costs aire important in determining a plant's economic
viability and substantiate future timing ofthe coal unit closures. These updated studies, completed
after the 2019 IRP filing, should be used in the forecast model supporring the 2021 IRp.
Forecast ed Natural Gas Prices
The Company used a relatively high natural gas price forecast in its 2019 IRp. This is a
significant change from its 2017 IRP, where the company used a relatively low natural gas price
forecast.
From 2022 through the end of the planning period in 2039, the Company's long{erm
forecasted natural gas prices in the 2019 IRP significantly exceed the forecast prices in the U.S.
Energy Information Administration's ("EIA") "Reference" case and..High Oil and Gas Supply',
(lowerprice)case.rThecompany'sforecastedpricesexceedEIA'sReferencecasepricesby
more than 307o in ten ofthe 18 years in the 2022-2039 period. The company's prices exceed
EIA's High oil and Gas supply case prices by more than 4ovo in 17 of the l8 years of the 2022-
2039 period. As shown in the figure below, the Company's forecast more closely tracks EIA's
higher priced "Low Oil and Gas Supply" (higher price) case.
I Source of EIA natural gas forecast data: httns://www .cia.qov/outloo acl duta,/hrowser/#/lid= I l-
AEO2020&cion=0 0&cuscs=rcl?020&start=20 I 9&e nd=2050&f:O&sid=rcl2020 d l Il l l9ir,60- 13
AEO2020-t:020-d I I 2 I I 9u.:10- l.l-AEO20]0-rc12 020-d I l2l l9a.:19- l .l AEO20l0&s ulcckcv=t)
STAFFCOMMENTS 6 AUGUST 5, 2O2O
Table No. 2 - 2019 IRP Gas Price Forecasts
2019 IRP Gas Price Forecast vs EIA Cases
(SMMBtu)
s9.00
s8.00
S7.oo
56.00
S5.oo
s4.00
53.00
s2.00
$1.00
s-
".drs,""*+"-f
dPr&""dr$,",".d".d.trd"st"dlrdi.uo&"drof"e""d"e.re"
.... ElARef
-ElALowerPrice
--- EtAHi€herprice
-2019lRpNote: Lower Price case is EIA's "High Gas and Oil Supply',
Higher Price case is EIA's "Low Gas and Oil Supply,,
The company's gas price forecast also exceeds the forecasts of selected natural gas
industry consultants and of other utilities regulated by the Commission. staff reviewed long-
term gas cost forecasts from consultancies Deloite, McKinsey, and Knoema. All of these
forecasts are lower than the Company's 2019 forecast. Deloite's forecast closely tracks the most
recent EIA Reference case forecast.
In Staffls comments on the Company's 2017 IRp natural gas price forecast, Staff
expressed concern that the relatively low gas price estimates would cause the resource
optimization model to select more than the optimal level of natural gas plants and transmission
resources (because market electricity prices are strongly correlated with natura[ gas prices).
In the 2019 IRP the opposite has occurred. The Company is using a relatively high
natural gas price forecast, so natural gas plants and transmission resources are disadvantaged as
compared to renewable resources. Ifgas price forecasts are too high, it can create an incenrive to
increase investment in renewable resources beyond the economically efficient or optima1 level.
The Company's 2019 preferred portfolio includes a large share ofrenewable resources
compared to past IRPS. state laws in oregon and washington mandate the removal of coal
generation from their rates and impose either carbon limits or cap and trade. oregon.and
washington also have ambitious renewable portfolio standards C'Rps"). Idaho does not impose
7STAFF COMMENTS AUGUST 5,2O2O
the same mandates or share the same timetable for RPS. By over-estimating long-run natural gas
prices, a portfolio excessively rich in renewable resources may be erroneously identified as least
cost. Under this scenario, Idaho customers could potentially pay higher prices for electricity and
could be supporting Oregon's and Washington's regulatory priorities.
ransmission Plannin
One notable aspect of the Company's transmission planning within the lRp is that the
Boardman to Hemingway C'B2H') transmission project is not shown as part of the Company,s
preferred portfolio. The Company curuently provides funding to B2H within a partnership
agreement, along with Idaho Power and the Bonneville Power Administration.
The Company indicates that although B2H and Gateway west are beyond the scope of its
2019 IRP, that both transmission projects are expected to bring future benefits to the region. ln
response to staff s discovery requests, the Company stated that it continues to evaluate B2H, and
that it expects to further address this project in its 202 I IRP. The company also stated that it
continues to invest in planning and permitting for the project and that it is well-positioned to
advance the project at the appropriate rime.
Staff is concerned that the Company appears to have plans to move forward with B2H
even though its own modeling has not identified it as a least cost resource. This project may
provide certain benefitts, but defined quantifiable benefits and revenue streams must be included
before it is prudent for Idaho customers to fund construction as a system resource.
Demand Side Manasement and Time-of-Use
The Company has a mature portfolio of energy efficiency and demand response programs
it effectively deploys to reduce and reshape loads. Because these programs are cost-effective,
they reduce the costs the Company incurs to serve customers.
The Company's demand response is quite large - it currently has 92,000 customers and
provides 200 MW of operating reserve capacity that can be dispatched within seconds. The
Company has recently begun work to expand the capability of its demand response program by
creating a grid-scale solution that turns demand response resources into frequency-responsive
operating reserves. The Company's effofts to economiczrlly expand its cost-effective demand
response programs are encouraged.
8STAFFCOMMENTS AUGUST 5,2O2O
Time-of-use rates can promote peak load reductions and load shifting to off-peak times.
These changes may lower power costs and help reduce or defer capital expenditure and
incremental operation and maintenance expenses. Additionally, time-of-use customers may
reduce their monthly bills by adjusting when they consume electricity.
The Company currently offers several optional time-of-use programs to Idaho customers:
Schedule 35 for general service customers, Schedule 35A for irrigation customers, and Schedule
36 for residential customers. Irrigation customers also have an option to participate in a third-
party operated krigation Load Control Program. Customers are offered a financial incentive to
participate, which gives the Company the right to interupt service during peak periods. The
Company should continue to evaluate the expected costs and benefits of potential time-of-use
and demand response programs in Idaho, including mandatory time-of-use for larger
commercial, industrial, and irrigation customers.
The Company also has existing and proposed time-of-use rates in other states. Efforts to
maintain and expand cost-effective time-of-use across the Company's system may provide
improvements in system load characteristics that potentially benefit all customers. The
Company has a noteworthy residential electric vehicle rate in Utah with time periods based on
the Company's system and distribution system peaks2, and price differentials between periods
based on stakeholder workshop feedback. Rate designs incorporating customers' preferences
can improve satisfaction and may boost subscription to time-of-use programs.
The Company has proposed new time-of-use programs in Washington and Oregon.
Washington's proposed time-of-use periods are based on Mid-Columbia wholesale price
projections and Oregon's are based on historic energy imbalance market prices. price
differentials between time-of-use periods for Washington programs are based on wholesale price
differentials. Oregon's price differential is consistent with price differentials in Idaho's Rate
Schedule 36. PacifiCorp's varied criteria for time-of-use rate design is appropriate for a system
with diverse climate regions and end-uses.
2 An emphasis on system peak is focused on upstream generation and bulk transmission needs (coincident peak)
and an emphasis on distributiofl peaks is focused on more localized needs (non-coincidcnt peaks).
9STAFF COMMENTS AUGUST 5,2020
STAFF RECOMMENDATIONS
The Company's 2019 IRP satisfies all the requirements in Order No. 22299; thercfore,
Staff recommends the Commission acknowledge PacifiCorp's 2019 IRP filing. Additionally,
Staff recommends continued attention to the areas discussed above:
o Capacity Deficiency Date in the Load and Existing Resource Balance;
o Integrating updated coal unit decommissioning cost studies into the planning
process;
. Long-run gas cost assumptions. The Company's 2019 IRP gas cost forecast is
significantly higher than the Company's 2017 forecast;
o Transmission Planning; and
r Continuation of DSM
. and time-of-use efforts.
Respectfully submitted this 5+L day of August 2020.
Hardie
Deputy Attomey al
Technical Staff: Bentley Erdwurm
Rick Keller
Brad Iverson-Long
Mike Morrison
Yao Yin
i:umisc/cornrEnts/paccl 9.1 6dhberlblmmyy comnrcnts
STAFFCOMMENTS l0 AUGUST 5, 2O2O
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 5'h DAY OF AUGUST 2020,
SERVED THE FOREGOTNG COMMENTS OF TIIE COMMSSION STAFF, IN
CASE NO. PAC.E-19-16, BYE-MAILING A COPY T}IEREOF, TO THE
FOLLOWING:
TEDWESTON
ROCKY MOUNTAIN POWER
1407 WN TEMPLE STE 330
SALT LAKE CMY UT 84116
E-MAIL: [e-mail]
DATA REQI]EST RESPONSE CENTER
E.MAILONLY:
uest@ fico .com
[e-mail]
ADAMLOWNEY
McDOWELL RACKNER GIBSON
419 SW 1ITH AYE STE 4OO
PORTLAND OR 97205
E-MAIL: [e-mail]
YS
CERTIFICATE OF SERVICE