20190404Larkin Direct.pdf

CASE NO. IPC_E-79_1.4
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BEEORE THE IDAHO PUBLTC UT]L]TIES COMM]SSION
IN THE MATTER OF THE APPLICATTON
OE IDAHO POWER COMPANY FOR
APPROVAL OF A POWER PURCHASE
AGREEMENT WITH JACKPOT HOLDINGS,
LLC, EOR THE SALE AND PURCHASE
OF UP TO 220 MEGAWATTS OF
RENEWABLE SOLAR GENERATION.
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
MATTHEW T. LARKIN
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O.Pl-ease state your name, business address, and
present position with
"Company").
A. My name
address is l22L West
am employed by Idaho
Senior Manager in the
Idaho Power Company ("Idaho Power" or
is Matthew T. Larkin. My business
Idaho Street, Boise, Idaho 83702. I
Power as the Revenue Requirement
Regulatory Affairs Department.
O. Please describe your educational- background.
A. I received a Bachel-or of Business
Administration degree in Finance from the University of
Oregon j-n 2001. In 2008, T earned a Master of Business
Administration degree from the University of Oregon. I
have also attended efectric utility ratemaking courses,
i-ncluding the Efectric Rates Advanced Course, offered by
the Edison Electric Institute, and Estimation of
El-ectricity Marginal- Costs and AppTication to Pricing,
presented by National- Economic Research Associates, Inc.
a. P1ease describe your work experience wlth
Idaho Power.
A. I began my employment with Idaho Power as a
Regulatory Analyst in January 2009. As a Regulatory
Analyst T, I provided support for the Company's regulatory
activities, including compliance reporting, financial-
analysis, and the development of revenue forecasts for
regulatory filings.
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1 In January 20L4, I was promoted to Senior Regulatory
2 Analyst where my responsJ-bilities expanded to j-nclude the
3 development of complex cost-related studies and the
4 analysis of strategic regulatory issues.
5 Since becoming the Revenue Requj-rement Senior
6 Manager in March 20t6, T have overseen the Company's
7 regulatory activities related to revenue requirement, such
B as power supply expense modeling, jurisdictional- separation
9 studies, and Idaho Power's Open Access Transmissj-on Tariff
10 f ormu]a rate .
11 I. PT'RPOSE BACKGROI'IID ATiID ST'MMARY
12 O. What is the Company requesting in this case?
13 A. Idaho Power is asking the Idaho Publ-ic
1,4 Utilities Commission (*IPUC" or "Commission") to approve
15 the Power Purchase Agreement (*PPA" or "Agreement") between
16 Idaho Power and Jackpot Holdings, LLC ("Jackpot Solar") for
11 the purchase of up to 220 meqawatts (\\MW") of solar
18 generation and to declare that all payments for the
19 purchases of generation under the PPA be a1lowed as
20 prudently incurred expenses for ratemaking purposes, with
2l the cost of the payments Idaho Power makes pursuant to the
22 contract recoverabl-e through the Power Cost Adjustment
23 mechanism. Although the Agreement contains provisions
24 granting to Idaho Power a right of first offer for
25 expansion energy, and for potential- ownership of the
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Idaho Power Company
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facility, should the parties reach a separate agreement as
Power, Idaho Power
approval with the
to the sal-e of the facility to Idaho
will make a separate filing for its
Commission.
O. What is the purpose of your testimony in this
case?
A. My testimony begins with a history of the
discussions between Idaho Power and Jackpot Solar detailing
the circumstances preceding the Company's request. I will
then present the economic analysis that supports Idaho
Power's executj-on of a PPA with Jackpot Solar. My
testj-mony demonstrates that the Jackpot Solar PPA will-
result in substantial benefits to customers in the form of
l-ower variab1e net power supply expense and, therefore, it
is in the public interest for the Commission to approve the
Agreement.
O. Please provide an overview of the PPA between
Idaho Power and Jackpot Sol-ar.
A. On March 22, 201,9, Idaho Power executed a PPA
with Jackpot Solar for the purchase of up to 220 MW of
renewable solar generation from a proposed Idaho solar
facility at what appears to be among nationwide record l-ow
prlcing.l Negotiations of the Agreement began shortly after
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1 Based on natj-onwlde priclng discussed in the Utifity Dive
articfe attached to my testj-mony as Exhibit No. 1.
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Idaho Power was first approached in late September 2078 by
Jackpot Sol-ar where it offered to seII to Idaho Power 120
MW of renewabl-e solar generation with pricing significantly
below both market prices and PubIic Utllity Regulatory
Pol-icies Act of 7918 (*PURPA") avoided cost rates.
The pricing 1n the PPA relies upon the sel-l-er's
ability to
investment
2079, after
safe harbor the current 30 percent federal
tax credit benefits prior to the end of December
which time those benefits step down. In order
10 to secure the necessary fj-nancial- commj-tments and initj-al-
11 development activities required to safe harbor the current
L2 investment tax credits and contract prici-ng, it was
13 necessary to have an executed contract for the purchase of
L4 the generation during the first quarter of 2079 and a
15 Commissj-on order approving it before the end of 20L9, when
76 the tax credits step down.
11 This PPA represents a significant benefit to Idaho
18 Power customers, and provides for the addition of a 1arge,
19 l-ocal-, 100 percent renewable generation project to Idaho
20 Power's generation portfolio at the same time as the
2L Company's reliance upon existing coal- generation facilitles
22 is reducing. Approval of this PPA is in the public
23 interest and the best interests of Idaho Power customers.
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O. What actions led
this Agreement woul-d best serve
customers over the long run?
Idaho Power to conclude that
the interests of its
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2078, Tdaho Power and Jackpot
Solar executed a Mutual Nondiscl-osure, Confidentiality, and
Exclusivity Agreement in order to commence the negotlation
and evaluation of the offered power purchase. The
excl-usivity agreement granted Idaho Power the excl-usive
right to purchase the generation from this facility through
March 25, 2019. During negotiations, Jackpot Solar offered
an addit.j-onal 100 MW of generation from an adjacent
development site, Franklin Solar, defj-ned in Section 8 of
the Agreement, which is provided as Attachment 1 to the
Company's Application filed in this case.
Idaho Power analyzed the impact of including the
offered generatj-on as part of operating its system in two
ways. First, the Company used the AURORA Electric Modeling
Forecasting and Analysis Software (*AURORA") to model the
Company's system operations and costs both with and wlthout
the additional solar generation using modeling assumpti-ons
reflectlng the preferred portfolio from the Company's 2017
Integrated Resource Pl-an ("IRP"). This analysis shows
significant cost savings and customer benefits from the
acquisition of the solar generation. Second, the Company
i-ncl-uded the 120 MW and 100 MW in its current 2079 IRP
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resource portfolio
capacity expansion
discuss later in my
that the new solar
analysis, which incorporated a
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Iong-term
will("LTCE") functionality that
testimony. This anal-ysis demonstrated
generation at the contracted
selected as a l-ow-cost resource capable of being
into fdaho Power's system by the majority of the
preliminary resource portfolios analyzed as part
Company's 2019 IRP.
O. How do the competitive procurement
the Publ-j-c Utility Commission of Oregon ('OPUC")
19 benefits customers, this resource acquisition
20 from the competitive procurement rules of the
pri-ce was
integrated
various
of the
rules of
10 apply to
11 this Agreement?
72 A. The IPUC requires Idaho Power t.o comply with
13 the competitj-ve procurement rul-es applicable in the
t4 Company's Oregon service area in the acquisition of new
15 supply-side resources. Case No. IPC-E-10-03, Order No.
76 32745. However, there was not sufficient time to conduct a
77 full competitj-ve procurement request for proposal-s process,
18 and as a time-Iimited opportunity of unique va1ue that
is exempt
OPUC.
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Do you present any exhibits with
Yes. Exhibit No. 1 supports the statement
Contract Price in the Jackpot Sol-ar PPA24 that the negotiated
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o.
testimony?
A.
in the nation. Exhibit No. 1 is a copy
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Idaho Power Company
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of a June 73, 2078, articl-e
Dive that describes a recent
from the publication Utility
solar energy contract entered
at $23.16lmegawatt-hour
articl-e also details the size
into by NV
("MWh") for
and pricing
discussion
Energy for 300 MW
25 years. Thj-s
for at least five other utility-scal-e PPAs in a
solar PPAs in the
Bel-ow is a
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regarding the fowest cost
natj-on. Jackpot Sol-ar's pricing, 120 MW at $27.15lMWh and
220 MW at $23.11lMWh, escalated at 1.5 percent annually, is
solidly among the lowest cost of these reported record low
cost PPAs.
11 O. Do you have any other exhibits?
L2 A. Yes, Exhibit No. 2 shows the Jackpot Solar PPA
13 Contract Price compared to current PURPA avoided cost
1,4 prices, ES well as Mid-Columbia (*Mid-C") market prices
15 over the term of the PPA. Jackpot Sol-ar is substantially
t6 lower cost than al-I
l1 summary table of the
18 presented in Exhibit
of these al-ternatives.
prices reflected in the
No. 2.
Pricing Methodology
Eirst ContractYear (Dec. 2022
- Nov. 2023)
Average Price
2 0-Year
Level-i- zed
Price
$ /uwrr $ /uwtr
Jackpot Holdings, LLC - 120 MW $21 .1s $24.37
Jackpot Holdings, LLC 220 MW $23.11 catr o2
Oregon Standard Avoided Costpri- ce $38.49 $s3.74
Idaho Published Avoided CostPrice s40.11 s80.21
Incremental- Cost IRP AvoidedCost Methodology $28. B9 $s8. s4
Mid-C Market I I
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Exhibit No. 3 shows the resul-ts of the 20L7 IRP
analysis and quantifies the benefits to customers. There
were three AURORA simulations: a base run of the 20L1
preferred portfolio, the 2017 preferred portfolio plus 120
MW of soIar, and the 2071 preferred portfolio plus 220 MW
of solar. The difference in the total cost of each
simul-ation quant j-f 1es the net benef j-t to customers.
Exhibit No. 4 is a summary of the resources added or
retired by year to reliably serve Idaho Power's load in the
preliminary 2079 IRP portfol-io analysis. As described in
more detail in the section "System Modeling, " the Company
is using the LTCE capabilities of the AURORA model to
produce economically optlmized portfol-ios under various
future conditions.
O. Please briefly summarize some of the relevant
terms of the PPA.
A. The PPA is filed as Attachment 1 to the
Company's Application in this case. Many of the PPA's more
significant terms and conditions are summarized in pages 4
through 1 of the Company's Application. Al-though the terms
and conditions of the PPA described in the Company's
Application are favorable PPA terms, for purposes of the
Company's economic analysis that I present, my testimony
pri-marily pertains to the terms related to pricing and the
project's operation date.
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O What prlce and operation date is contained in
the PPA?
A. The Contract Price for the purchase of 720 MW
and the purchase of the fuII 220 MW is set forth in Exhlbit
5 to the PPA. The first-year price for \20 MW is
$2!.7 s/MWh and the first-year price for 220 MW is
23.L1lMWh. Both esca1ate over the 2)-year term of the PPA
at 1.5 percent annuaI1y. This results in a 2O-year
levelized price of $24.31lMWh for 1,20 MW and $25.83/MWh for
220 MW. The Scheduled Commercial Operation Date j-s
December l, 2022, for 120 MW and December l, 2023, for the
additi-onal 100 MW.
O. Why does the PPA contain a price stream and
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14 Scheduled Commercial Operation Date for both 120 MW and 220
15 MW?
L6 A. Jackpot Solar initialty offered to sell- 1-20 MW
1,1 of output to Idaho Power, for which it had previously
18 completed and obtained a Generator Interconnection
1,9 Agreement ("GIA") as an Energy Resource (ER) . During
20 negotiations, Jackpot Sol-ar offered an additional 100 MW of
2t generation from an adjacent development site, Franklin
22 Sol-ar, defined in Section 8 of the Agreement. The price
23 sett1ed upon for the initial 120 MW is $2L.15lMWh, with the
24 additional- 100 MW priced three dollars higher at
25 $24.15lMWh. The Contract Price in Exhibit 5 of the PPA
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shows the $21.15lMWh for the 720 MW and for 220 MW shows a
weighted and blended prj-ce of $23.11lMWh. This is the
resul-t of retaj-nj-ng the $27.15lMWh for the initial- 120 MW
and adding the additional 100 MW at $24.1 5/MWh for a
weighted and blended price of $23.71lMWh for the entire 220
MW.
Because the additional 100 MW entered into the PPA
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negotiations midway through
not yet applied for, nor had
generation been studied for,
because the incremental 100
the process, Jackpot Solar had
the i-ncremental- 100 MW of
interconnection. Eurther,
MW had not been
t2 same economj-c analysis as the inj-tial 120 MW
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PPA.
through the
,itis
Section B.3represented as a purchase optlon in the
of the PPA contains provisions regarding
Output of 100 MW identified as Franklin
the Additional
Sol-ar. Section
L6 8.3. Contingent upon
71 100 MW and the outcome
the GIA process
of additional
for the additional
analyses, ds well as
Idaho Power has an18 the mutua]agreement of the parties,
purchase an additional 100option
at the prices set forth in Exhibit 5
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Scheduled Commercial Operation Date
MW, if that option is exercised, is
the Scheduled Commercial- Operationz3
MW (total- of 220 MW)
to the Agreement. The
for the additional 100
December 7, 2023, with
Date for the 120 MW
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to
remaining at December
otherwise agreed, this
7, 2022. Section 8.3.2. Unless
option expires on September 7, 20L9.
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Id. However, to be cl-ear, through the analysis I will-
discuss in the next section of my testimony, the Company
believes purchase of the full- 220 MW is in the best
interest of customers based on the anal-ysis conducted thus
far. The Company is continuing to revj-ew the additional-
100 MVI and the impacts to the system and will have that
review complete prior to the completion of this case. Due
to the significance of the tax credits avail-able on this
project, if the 100 MW is not approved prior to the end of
2079, it wil-l- no longer be an option. Therefore, the
Company's request in this case incl-udes approval of the
full- amount.
II. SYSTEM MODELING
O. Pl-ease summarize the economic analyses
conducted by Idaho Power to eval-uate the proposed PPA.
A. The proposed Jackpot Sol-ar project approached
Idaho Power at a unique time where the Company was able to
analyze the proposed PPA in two ways. First, Idaho Power
used the inputs and assumpti-ons from the 2011 IRP to
eval-uate the economics of the Jackpot Solar PPA under a
"with and without" Jackpot Solar generation and cost
scenario analysis. Second, as Idaho Power is currently in
of preparing its 2079
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the process
to model- the
and anal-ysis
proposed PPA within
for the 2079 IRP.
IRP, the Company was abl-e
the portfol-io development
The initial- portfolio
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1 analysi-s, including Jackpot Solar, was presented to the IRP
2 Advisory Committee, IRPAC, oD March L4, 2019.2
3 Q. What modeling tools did fdaho Power use to
4 perform its economic analysis of the proposed PPA?
5 A. Idaho Power used its AURORA model to perform
6 the initial- analysi-s of customer benefits based on the 2077
7 IRP, in the form of reduced variable net power supply
8 expense. This is al-so the model used by Idaho Power in the
9 portfol-io analysis of the IRP and other ratemaking
10 applicatj-ons. Idaho Power uses the AURORA electric market
11 mode1 as the primary tool to model- optimized portfol-ios of
72 resources and the hourly operating costs for each
13 portfolio, over a 2O-year planning period. The AURORA
14 modeling resul-ts provide detailed estimates of resource
15 costs, wholesale market energy pricing, resource operation,
\6 and emissions data.
71 O. How has Tdaho Power historically used the
18 AURORA mode]?
79 A. Idaho Power uses the AURORA model- for IRP
20 planning, variable power supply expense regulatory filings,
27 coal studies, PURPA prj-cing, and project valuations.
22 Within the context of IRP planning, the AURORA model has
2 Because ldaho Power's PPA with Jackpot SoJ-ar had not yet been
publicJ-y announced, the Company generally discussed the incl-usion of
100 MW and l-20 MW of j-ncrementaf solar generation rather than
specifical-ly detailing the Jackpot Solar project.
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1 been used to simulate the hourly economj-c dispatch of Idaho
2 Power-devel-oped portfol-ios over the 20-year IRP planning
3 period. Additionally, the AURORA model is used to perform
4 stochastic risk analysis within the IRP portfolio analysis.
5 Q. Did the Company expand its use of the AURORA
6 model in development of the 2019 IRP?
'l A. Yes. Based on feedback in the 2071 IRP, Idaho
I Power is for the first time using the LTCE modeling
9 capabll-ities within the AURORA model- to produce a Western
10 El-ectricity Coordinating Council- ("WECC") optimized
11 portfol-io under various future conditions for the 20L9 IRP.
t2 The WECC optimized portfolio incfudes the addition
supply- and demand-side resources for Idaho Power's
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system
units
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while simul-taneously evaluating current
for economic retirement. The sel-ection
generatlon
and retirement of
16 Idaho Power resources includes
77 reserves and planning margin as
18 model- calculates a forecasted total
19 cost (fixed and variable) over the
20 Is the AURORA model-
21, analyze the net costs/benefits of
maintaining sufficient
def ined in the model-. The
Idaho Power portfolio
20-year planning period.
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22 A. Yes, the analysis
23 from the 2017 acknowledged IRP
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in the
the appropriate tool- to
the Jackpot Sol-ar PPA?
the preferred portfol-io
consistent with how the
on
IS
has looked at resources over the year. The changes
2079 IRP AURORA model version and setup is designed
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1 to all-ow the Company to evaluate the economics of resources
2 as it has before, but also adds the functionality of
3 maintaining required planning margin and regulating reserve
4 through the LTCE and hourly dispatch modeling processes.
5 The portfolios are further evafuated under varying system
6 conditions, such as natural gas prices and carbon costs.
7 The resul-ting cost and reserves information from the AURORA
8 modeling serves to inform the selectj-on of a portfolio of
9 resources that adheres to the least-cost, l-east-risk
10 planning principles applied in Idaho Power's IRP.
11 O. Pl-ease describe how the Jackpot Sol-ar PPA was
72 evafuated using the 20L1 IRP AURORA versj,on and setup.
13 A. The economic analysis of the Jackpot Solar PPA
14 relied on an assessment of system dispatch costs based on
15 AURORA simulations over the time frame of 20L1-2036. The
76 baseline portfolio setup was the preferred portfolio and
77 model version used in modeling costs for the acknowl-edged
18 20!1 IRP. The Company compared the 2)-year cost streams
19 from AURORA simul-ations that included the Jackpot Solar PPA
20 and a base run excluding
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Sofar. Jackpot's 120 MW
year of 2022 and a price
5 percent annua11y.
at 220 MW with a
Jackpot
start ing
22 st.arting at $27.lslMwh escalated at 1
23 Idaho Power also mode1ed Jackpot Solar
24 starting price
annually. The
at $23.11lMWh, escalating at 1.5 percent
difference between the AURORA model
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simu1ations of Idaho Power's 20L1 IRP preferred portfolio
under planning case natural gas determined the cost or
benefit to total power supply costs.
O. What were the resul-ts of the eval-uation based
on the 2011 IRP methodology?
A. The base AURORA simul-ation of the preferred
portfolio from the 2011 IRP, without inclusion of
generation from Jackpot Sol-ar, resulted in nominal total
operating costs of $9,629,928,260. The same AURORA
10 simul-ation with the addition of the Jackpot Solar PPA
in total operating costs that were
120 MW and $9,418,800,440 for 220 MW, as
11 generation resul-ted
72 $9,539,401,190 for
descrlbed above.These results show customer benefits of13
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15 $90,226,410 at
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period.
generation from the Jackpot
720 MW and $150,821,810 at
So1ar PPA of
220 MW compared
18 simulation starting in 2022 through 2036 is provj-ded in
19 Exhibit No. 4. In general, the addition of the Jackpot
20 Sol-ar PPA reduced total- operating costs by offsetting
27 generation from higher priced resources and aIlowj-ng for
22 more surplus sal-es. Incl-usion of the generation f rom the
23 Jackpot Solar PPA shows substant j-al- customer benef its.
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baseline AURORA slmulation over the 20-year planning
The annual cost of each preliminary portfolio
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1 Q. Does the beneflt above include any value for
2 sale of the Renewable Energy Certificates ("RECs")
3 associated with the projects?
4 A. No. Even though Idaho Power owns 100 percent
5 of the RECs, Green Tags, and/or Environmental Attributes of
6 the generation under the PPA, the Company did not include
7 any value for the sal-e of RECs generated from the projects.
8 If REC sal-es were to be included, the net benefit to
9 customers woul-d be even hj-gher.
10 O. Pl-ease describe how the Jackpot Sol-ar PPA was
11 eval-uated in the AURORA LTCE analysis developed for the
72 20]-9 rRP.
13 A. As described above, for the 2019 fRP, Idaho
t4 Power is using the LTCE capabilities of the AURORA model to
15 produce an economically optimized WECC portfolio under
76 three natura1 gas price forecasts and four carbon price
l7 forecasts. This resul-ts in L2 portfolio combinations
18 resulting from the various gas and carbon price futures.
t9 The Company also included portfolio analysls with the same
20 L2 portfolios but with the j-ncreased import capablJ-ity of
2l the Boardman-to-Hemingway (B2H) transmission line starting
22 in 2026, resulting in a total of 24 portfolios.
23 To evaluate the Jackpot Solar PPA, Idaho Power
24 included the financial and operating characteristics of the
25 Jackpot Sol-ar PPA in the AURORA New Resource Table as
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resources avail-abl-e for
that would economj-cal1y
forecasted l-oad over the
AURORA New Resource Table
selection as part of a portfolio
and rel-iab1y serve Idaho Power's
2)-year plannlng period. The
included 120 MW of sofar priced
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at $21.l5lMwh avail-abl-e in 2022 and 100 MW of solar priced
at $26.08/MWh3 avail-abl-e in 2023. Each project could be
selected independently, but the combined capacity
represents the total- 220 MW in the Jackpot So1ar PPA.
O. What were the results of the AURORA LTCE
portfolio runs for the 201,9 IRP?
A. Idaho Power ran a total of 24 LTCE portfolj-os
in AURORA. Each optimlzed portfol-io was comprised of the
most cost-effectlve set of resources to serve Idaho Power's
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L4 l-oad over the 2)-year planning period
15 appropriate planning reserve margins.
76 the results of the 24 LTCE portfolios,
L7 by the resource type added or retired
while maintaining
Exhibit No. 4 shows
which are summarized
each year of the 20-
18 year time frame.
19 Resul-ts from the LTCE modeling are preliminary and
20 inc]ude:
27 The AURORA LTCE process selected new solar
22 resources in the 2022 and 2023 ti-me frame in 18 of the 24
23 portfofios.
: The finaf number lncluded in the PPA is lower than what was
initially proposed and run throuqh this anafysis, as described on pages
9-10 of this testimony.
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o Both the 720 MW and 100
representing the Jackpot Solar
the 24 portfolios.
It shoul-d al-so be noted
PPA, were
that in many of the
selected additional- sol-ar
MW sofar resources,
sel-ected in L4 of
optimized portfol-ios, the
and wind resources above
al-I at a higher cost than
While Idaho Power
the Jackpot Solar PPA capacity,
the Jackpot Sol-ar PPA.
AS
model-
total- portfolio costs (fixed
stil-1 currently evaluating
and variable) and reserves for
10 the 2019 IRP, it can be concluded that the Jackpot Solar
11 PPA resources are a least-cost resource due to the
12 selection of both projects in a majority of the LTCE
13 portfol-ios.
74 O. What effects did the Jackpot Solar PPA have on
15 other resources in the 2019 IRP portfolio development?
16 A. The resul-ts of the LTCE modeling show a high
71 correlation of new solar resources in 2022 and 2023 with a
18 Jim Bridger unit retirement in 2022. A Jim Bridger unit is
L9 retired tn 2022 in 18 of the 24 portfolios and of those 18,
20 74 have a new sol-ar resource in 2022 and 2023. This is a
2\ strong indication that the model has sufficient regulating
22 reserves to economically retire a reserve contributing coal-
23 unit.
24 O. Has the preferred portfolio for the 2079 IRP
25 been selected at this time?
LARKIN, DI 18
Idaho Power Company
1
2
3
4
5
6
1
B
9
A. No. The Company is currently engaged in the
process of running the AURORA model and evaluating each
portfolio under various cost and risk scenarios. The 2019
IRP is scheduled to be fil-ed the end of June 20!9.
o.
analysis, do
customers for
PPA?
Based on the results
you believe it is in
Idaho Power to enter
of the Company's
the best interest of
into the Jackpot Solar
10
A. Yes. The economic analysis performed by the
Company under the 2017 IRP methodology and the LTCE
modeling in AURORA demonstrate that the Jackpot Solar PPA
wil-l- be a cost-effective resource providing benefits for
being reliably integrated onto the
11
t2
13
14
15
L6
L1
customers
Company's
III
O.
system to
generation
A.
and capable of
system.
. INTEGRATION OF VARIABLE ENERGY RESOI'RCES
1B
19
20 IRP as well
Did the Company consider the abj-lity of its
integrate up to an additlonal 220 MW of solar
from the Jackpot Sol-ar PPA?
Yes. As suggested by feedback from the 2077
as the results of the Company's 2078 VariabLe
23
2!
22
24
Energy Resource Inteqration Analysis (*VER Study" or
"Study"), severaf improvements were incorporated into
AURORA and the resource portfolio analysis of the 20L9 IRP
to model the adequate maintenance of reserve margins as
resources are added or removed in the IRP portfol-ios.
LARKIN, DI 79
Idaho Power Company
25
2
3
4
5
6
7
a
9
1 Inclusion and selection of Jackpot Sol-ar's 120 MW and 100
MW in the 2019 IRP portfolio analysis where 1t was selected
as a l-ow-cost resource by the updated model-, which are
intended to account for the proper maintenance of reserve
margins, shows that Jackpot Solar's generation can reliably
be integrated by Idaho Power's system based on the
assumptions in the current model.
O. Pl-ease provide a summary of the Company's most
recent VER Study.
As of its complianceA10
11 Nos. 17-075 and in Oregon Docket
filing with Order
No. UM L193, Idaho
Part ,
t] -223
72 Power filed the VER Study, which described the methods
13 followed by
regulating74
Idaho Power to estimate the amounts of
reserves necessary to integrate variable energy
("VER") without compromising system reliability.15 resources
16 The methods followed were derived in col-l-aboration with the
l1 Study's Technical Revj-ew Committee, which included
18 personnel- from both the IPUC and OPUC Staff.
79 The study methods yielded regulating reserve
20 requirements necessary to ba1ance the system load net of
2l wind and solar generation ("net Ioad"). The regulating
22 reserve requJ-rements for net load are expressed in the VER
23 Study as the dynamic variable function of several factors:
24 . Season (spring, summer, faII, and winter),'
25
LARKIN, DT 20
Idaho Power Company
1 o Load base schedule (i.e., two-hour ahead
2 schedule);
3 o Time of day (for load);
4 o Wind base schedule; and
5 o Sol-ar base schedul-e.
6 The regulating reserve requirements necessary to
7 balance net l-oad for a gi-ven hour are conditional- based on
I the five factors above. The derivation of the regulating
9 reserve requirements from a net load perspective captures
10 the tendency of the three elements: 1oad, wind, and solar
11 to deviate from their respective base schedules in an
12 offsetting manner. Therefore, the amount
l-oad is Less than
of regulating
the sum of the13
74
15
16
77
1B
t9
20
2t
ZZ
23
24
reserve required for net
individual requirements for each element.
O. What conclusions were reached in the 2078 VER
Study?
A. The VER Study suggested that a unified VER
integration analysls may be a favored approach for
assessing impacts and costs for incremental wind and solar
additions going forward. However, the Study also indlcated
Idaho Power's system may be nearing a point where the
current confj-guration of reserve-providing resources (i.e.,
dispatchable thermal and hydro resources) can no longer
j-ntegrate additional- VERs without taking additional action
to address potential- reserve requirement shortfalls. The
LARKIN, DI 2I
Idaho Power Company
25
1 Study concluded that additional- investigation was warranted
2 inLo the combined effect of wind and soIar, in a unified
3 VER integration cost analysis.
4 Q. Did the VER Study quantify the amount of
5 additional- VERs Idaho Power's system could integrate?
6 A. Yes. The VER Study identified that, based
7 upon the current resources on the Company's system, 77 3 MW
I of additional- VERs could be integrated before reserve
9 margin viol-ations exceeded 10 percent of the operating
10 hours during the year. The Study al-so concl-uded that at
11 the hiqh re1ative penetration levels of variable wind and
L2 sol-ar that currentl-y exist on Idaho Power's system,
13 additional- analysis was warranted in the Company's IRP, and
74 as the Company gained more experience operati-ng as part of
15 the Energy Imbal-ance Market (EIM) .
76 O. How did the Company include variabl-e resource
77 integration in the 20L9 IRP analysis?
18 A. Eirst, it is important to note that for the
19 201-9 IRP, integratj-on charges are not util-ized as an input
20 into the AURORA model-. As previously mentioned, portfolio
2l development for the 2079 IRP is being performed through
22 LTCE modeling in the AURORA model. Under this approach,
23 the model's selection of resources is driven by the
24 objective to construct portfolios that are low cost and
25 achieve the plannj-ng margin and regulating reserve
LARKIN, DI 22
Idaho Power Company
1
2
3
4
5
6
1
B
9
requirements. Based on the VER
regulating reserve
hourly regulating
of load, wi-nd, and
requirements,
Study's dynamically defined
the 2079 IRP includes
reserves associated with current levels
l-oad
solar, ds well as future portfolios
and potentially higher level-shaving higher levels of
of VERs.
O. Are there any differences in the way AURORA
mode1s integration in the 2019 IRP analysis from that
utilized in the 20L8 VER Study?
10 A Yes. The VER Study modeling of the reserve
11 requirements util-ized the AURORA model Version 12.1.t046,
those onlyL2 which included nine thermal units, with four of
L4
provi-ding spin and non-spin reserves, and four HeIls Canyon
Complex ("HCC") units to provide the hourly defined reserve
requirements for a total combined nameplate rating of 1,810
MW. The HCC reserve carrying capability was 358 MW of
generation flexibility. The HCC units were model-ed as non-
hydro units in order to make sure water was moved around
during the month and no spiII occurred. The thermal units
include the four Jim Bridger coal- units and Langley Gulch
combined-cyc1e, combustion turbine units.
For the 20L9 IRP analysis, the VER Study provided
the rules to define hourly reserves needed to reliably
operate the system based on current and future quantities
of sol-ar and wind generation, and load forecasted by season
15
L6
71
1B
79
20
27
22
)?
Z4
LARKIN, DI 23
Idaho Power Company
13
25
1
2
3
4
5
6
1
B
9
and time of day. Improvements in Version 13 of the AURORA
mode1, compared to when the VER Study was performed, al-l-ows
the VER Study reserve rules to dynamically establish hourly
reserves for different quantities of variable resources in
a portfol-io. The reserves are defined separately,
i-ncorporating their combined diversity benefits dynamically
in the modeling. The reserve rufes applied in the 2079 IRP
include defining hourly reserve requirements for "Load Up,"4
"Load Downr" "Sol-ar Upr" "Sofar Downr" and "Wi-nd Up." The
"Wind Down" reserves are inc]uded in the "Load Down"
reserves as AURORA cannot dynamically apply the "Wind Down"
reserves rules as defined and applied in the VER Study.
O. How has the AURORA modeling improved since the
VER Study was performed?
A. The 2079 IRP is using the AURORA mode1 Version
13.2.1001, which incorporates improvements in modeling
reserve requirements combined with the Company's own
modeling improvements and assumptions. Speciflcally, the
HCC hydro units are able to use the hydro logic in AURORA,
which al-l-ows for spiII. The resources dedj-cated to
maintaining
spiI1, which
cost to the
the additional reserves incur costs such as
is captured withln the model as an increased
portfolio. The mode1 version enhancements
a Idaho Power is using the terms "Up" and "Down" for the
bidirectional reguJ-ating reserve necessary for bafancing 1oad, so1ar,
and wind.
10
11
72
13
74
15
76
71
18
T9
20
27
22
LARKIN, DI
Idaho Power
24
Company
23
1
2
3
4
5
6
1
B
9
all-ow the
providing
mirrors a more realj-stic HCC hydro operation.The existing
nearlythermal units' abil-lty to provide reserves is
identical to the previous setup.
The evol-ution of using the enhanced capabilities in
AURORA to define the resource portfolios using the LTCE
logic whil-e simultaneously incorporating the VER dynamic
reserve rul-es associated with varying quantities of
renewable resources is a signj-ficant advancement in
portfolio design at Idaho Power.
O. Has the enhanced model-ing performed for the
2019 IRP effectively replaced the 2018 VER Study results?
A. The 20L9 IRP analysis is a step toward a
unified VER j-ntegration cost analysis as conc1uded in the
VER Study. While the VER Study provided valuabl-e
information regarding the rul-es for reserve requirements,
the modeling performed for the 201,9 IRP provides more
Company to include al-l 72 HCC hydro units as
reserves in the 2019 IRP LTCE process, which
10
11
72
13
t4
15
76
71
1B
19 information on how VERs affect Idaho Power's system and the
20 ability to maintain sufficient reserves. The 20L9 IRP has
2l allowed Idaho Power, via the AURORA model, to
22 quantitatively capture and enforce the hourly flexibility
23 requirements for a portfolio to dynamically change
24 regulatlng reserves in line with the VER Study reserve
25
LARKIN, DI 25
Idaho Power Company
1
2
3
4
5
6
7
8
9
requirement rul-es in an economic manner during the
portfolio devel-opment process.
O. Why does the Company bel-ieve that it can now
successfully integrate more than L73 MW of renewabl-e
generation, as identified in the 2018
A. The results of the 2019
development show that both the 120 MW
VER Study?
IRP portfol-io
and 100 MW of the
of the 24 LTCE
: portfolios show new
10 solar resources se]ected in the 2022 and 2023 time frame
11 while a Jim Bridger unit retires in 2022. This is a strong
t2 indication that the model has sufficient regulating
13 reserves to economically retire a reserve contributing coal-
74 unit whil-e adding new solar resources. AdditlonalIy, Idaho
15 Power's l-oad is forecast to grow through the years 2022 and
76 2023, which allows more VERs to be successfully integrated.
1,1 The additional- VERs j-n the AURORA integrated portfol-io
18 analysis dynamically j-ncreases the system reserves
79 associated with increased VER energy by applying the VER
20 mode1 reliable system operations.However,
system
need to
2l incremental VERs are added to the
22 outside, or between, IRP cycles, there is stil-l- a
z3 identify the j-ncremental- cost of maintaini-ng adequate
reserves for rel-iable operations.
O. Do you have any concluding remarks?
24
LARKIN, DI 26
Idaho Power Company
Jackpot Solar
portfolios.
Study rul-es to
when additional-
PPA were selected in L4
Additionally, many of the
25
1 A. Yes. Tdaho Power's analyses show that
2 acquiring up to 220 MW of sol-ar as represented in the PPA
3 is estimated to save customers approximately $90,226,470 at
4 ]-20 MV0 and $150 ,827,810 at 220 MW due to a reduction in net
5 power supply expenses as compared to the modeled baseline.
6 Additionally, when the Jackpot Sol-ar project is included in
7 the LTCE process for the current 20L9 IRP, it is sel-ected
8 as a low-cost resource that can be integrated into Idaho
9 Power's system in the majority of the model-ed scenarios.
10 The Agreement has substantial customer benefits and is in
11 the public interest.
1,2 O. Does this complete your testimony?
13 A. Yes, it does.
\4
15
1,6
t7
18
L9
20
2L
22
23
24
25
LARKIN, DI 21
Idaho Power Company
1
2
3
4
5
6
1
B
9
ATTESTATION OF TESTIMONY
STATE OE IDAHO
SS.
County of Ada
I, Matthew T. Larki-n, having been duly sworn to
testify truthfully, and based upon my personal knowledge,
state the following:
I am employed by Idaho Power Company as the Revenue
Requirement Senior Manager in the Regulatory Affaj-rs
Department and am competent to be a witness in this
proceeding.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-filed testimony
and exhibits are true and correct to the best of my
information and belief.
DATED this 4ti' day of April 201,9.
Matthew T. Larkin
SUBSCRIBED AND SWORN to before me this 4th day of
24 April 2019.
10
11
72
13
74
15
76
71
18
19
20
27
22
23
25
26
21
28
29
S.
Notary Pub cforl
Residing at: Meridian Idaho
My commission expires z 02/04/202L
LARKIN, DI 28
Idaho Power Company
!b.
of
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-19-14
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO. 1
3t12t2019 NV Energy 2.3-cent solar contract could set new price record I Utility Dive
I ut LrrYDrvE
BRIEF
NV Energy Z.3-cent solar
eontract could set new price
reGord
By Gavin Bade
Published June 13, 2018
Dive Brief:
. A new solar energy contract proposed by NV Energy could
set a price record for the resource in the United States,
researchers say.
. On June 1, NV Energy filed for approval of a 300 MW power
purchase agreement with the Eagle Shadow Mountain solar
project at$23.761MWh for 25 years. That price beats a
$24.99/MWh contract signed this month in Arizona that GTM
Research says was the lowest-cost solar contract in the
nation.
. Eagle Shadow is part of an NV Energy proposal to add 1 GW
of renewables and 100 MW I 4OO MWh of energy storage.
That plan must still be approved by regulators and is
contingent on Nevada voters not approving a retail choice
ballot initiative.
Dive lnsight
Determining the true low cost champion in solar contracts is a
difficult task, Greentech Media notes. Some contracts Include
ambiguous pricing details and others have cost escalators, like
Sempra Renewables'Copper Mountain Solar 5 project, also part
of NV Energy's latest proposal.
Exhibit No. 1
Case No. IPC-E-19-14
M. Larkin, IPC 1/3Page 1 of 3
3t12t2019 NV Energy 2.3-cent solar contract could set new price record I Utility Dive
Copper Mountain's PPA comes in at $21.55/MWh, but it has a
2.5% annual cost escalator. Eagle Shadow's contract, by
contrast, is steady throughout its 2S-year term. The company
was able to offer the low price in part because it is utilizing
existing grid infrastructure from a nearby shuttered coal plant.
The PPAs are two of six NV Energy submitted to regulators for
approval at the beginning of the month, all of which netted
contracts under $30/MWh.
Name Developer Solar
capacity
Storage
capacity PPA price
Eagle
Shadow Sminutenergy 300 MW
Mountain
$23.76lMWh
$21.55/MWh with 2.5%
annual escalator
$29.8g/MWh
$26.50/MWh,
$275s/MW-month
capacity payment
Techren
V
Battle
Mountain
Solar
174 Power
Global
Cypress
Creek
25MW/
100
MWh
Copper
Mountain
5
Sempra
Renewables 250 MW
50 MW
101 MW
200
MW
Dodge
Flat
Fish
Springs
Ranch
NextEra
Energy
NextEra
Energy
25MW/
100 MW 100
MWh
$27.51/MWh
{$26.s1lMwh if Fish
Springs
approved), $6J10/MW-
month capacity
payment
$2s.96/MWh,
$5,2OOlMW-month
capacity payment
50MW/
200
MWh
Note: Dodge Flat and Fish Springs battery capacity payments escalate at
2% annually.
Exhibit No. 1
Case No. IPC-E-19-14
M. Larkin, tPC zts
Page 2 of 3
3112t2019 NV Energy 2,3-cent solar conlract could set new price record I Utility Dive
NV Energy's capacity pricing makes a direct comparison with
other solar-plus-storage contracts difficult, but the Nevada
projects appear competitive.
A recent Xcel Energy solicitation in Colorado returned
standalone storage projects with capacity payments of more
than $11,oOo/MW-month, but Greentech notes that the Nevada
projects will enjoy cost savings because they are paired with
solar projects.
ln addition to the solar PPAs, NV Energy also proposed to retire
lhe 127 MW unit 1 of the North Valmy coal plant by 2021, instead
of 2025. Previous analysis by environmental groups argued that
replacing the plant with renewable energy could save customers
money.
Both the coal retirement and solar PPAs could fall apart if voters
approve a ballot initiative to open the state to retail electricity
competition this November. lf that happens, the utility has said it
will not develop any more renewable energy than it is required
to by law.
Correction: A previous version of this post indicated that battery
capacity payments to all storage facilities would escalate at 2%
annually. That provision does not apply to the Battle Mountain
project proposal.
Recommended Reading:
rt'" Greentech Media
Nevada's 2.3-Cent Bid Beats Arizona's Record-Low Solar PPA
Price Zl
(-) Nevada PUC
Application of the Nevada Power Company 3i
Exhibit No. 1
Case No. IPC-E-19-14
M. Larkin, IPC 373
Page 3 of 3
https:/lwww.utilitydive.cominews/nv-energy-23-cent-solar-contract-could-set-new-price-record/5256101
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC.E.19.14
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
EXHIBIT NO.2
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Page 1 of2
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-19-14
IDAHO POWER COMPANY
LARKIN, DI
TESTIMONY
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Case No. IPC-E-19-14
M. Larkin, IPC
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