20210527Eller Exhibit 36-Redacted.pdf

REDACTED
CaseNo. PAC-E-21-07
Exhibit No. 36
Witness: Craig M. Eller
BEFORE TI{E IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Craig M. Eller
Intemrptible Product Value Update
May 2O2l
TTIIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED T]IIDER
SEPARATE COVER
BEX'ORE THE IDAHO PUBLIC UTILITIES COMITIISSION
TNTmMATTEROX'Tm )
APPLTCATTON OF ROCI(Y )
MOTINTATN POWERX'OR )
AUTHORTTY TO TNCREASE rrs )
RATES AI\iD CHARGES IN IDAHO )
AI\ID APPROVAL OX'PROPOSED )
ELECTRTC SERYTCE SCHEDTILES )
AND REGT}II\TIONS )
ROCKYMOT]NTAIN POWER
cAsE NO. PAC-W-2147
Direct Testimony of Michael G. Wilding
REDACTEI)
CASE NO. PAC-E-2I47
May 2021
TABLE OF CONTENTS
I. INTRODUCTIONANDQUALIFICATIONS
II. SUMMARYAND PURPOSE OF TESTIMONY.....
M. SUMMARY OF COMPANY NET POWER COSTS
A. Jim Bridger
B. Naughton
C. Wyodak
D. Dave Johncfnn
E. Hunter...
F. Huntington ...........
G. Craig...
H. Hayden
I. Colstrip.
VI. CUSTOMER BENEFITS OF THE ENERGYIMBALANCE MARKET
VII. CONCLUSION .........
ATTACHED EXIIIBITS
Exhibit No. 37-GRID Model NPC Report
............ I
............2
............3
............ 8
............9
ry. MODELING CHANGES TO GRID
A. Updated Scalars to the Official Forward Price Curve
B. Regulating Reserve Requirement................ ----.........12
C. Actual Capacity Factor for Owned Wind Generation and Purchased Wind Generation 13
D. Solar Hourly Shape ....14
V. SUMMARY OF COMPANY COAL COSTS ........... 16
l6
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.... l9
....20
....21
....21
))
....23
....23
....24
....26
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I. INTRODUCTIONAI\TDQUALIFICATIONS
Please state your name, business address, and present position with PacifiCorp
d/b/a Rocky Mountain Power (the "Company").
My name is Michael G. Wilding and my business address is 825 NE Multromah Street,
Suite 600, Portland, Oregon 97232. My title is Vice President, Energy Supply
Management ("ESM").
Please describe your education and professional experience.
I received a Master of Accounting from Weber State University and a Bachelor of
Science degree in accounting from Utah State University and am a Certified Public
Accountant licensed in the state of Utah. During my tenure at the Company, I have
worked on various regulatory projects including general rate cases, the multi-state
protocol, and net power cost filings. I have been employed by PacifiCorp since 2014.
Please explain your responsibilities as PacifrCorp's Vice President of ESM.
My current responsibilities include directing PacifiCorp's front ofiice organization or
ESM in commercial and trading activities. ESM is responsible for commercially
managing PacifiCorp's diverse generation portfolio. This includes the electric and
natural gas hedging, term and day-ahead trading, real-time trading, and system
balancing. I also manage PacifiCorp's renewable energy credit ("REC") portfolio
including the sale of RECs in excess of compliance requirements.
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Have you testified in previous regulatory proceedings?
Yes. I have filed testimony in proceedings before the Idaho Public Utilities Commission
("Commission"), and the public utility commissions in California, Oregon, LJtah,
Washington, and Wyoming.
[. SUMMARYAI\D PTJRPOSE OF TESTIMOIYY
What is the purpose of your testimony in this proceeding?
The purpose of my testimony is to present the Company's proposed net power costs
("NPC") for the l2-month period ending December 31,2021 ("test period"). The
proposed NPC will become the new base NPC for the Energy Cost Adjustment
Mechanism ("ECAM"), beginning January 1,2022. Specifically, my testimony:
. Summarizes forecasted NPC for the 2021 test period in this general rate case
("GRC") and explains the calculation of NPC using the Company's Generation
and Regulation Initiative Decision Tools ("GR[D") model;
. Describes several modeling changes the Company has made in order to improve
the NPC forecast accuracy since the base NPC rates were reset in Case No.
PAC-E-16-12, based on the 2015 Annual Results of Operations Report
(*2015 Update");
. Explains the primary drivers behind the decrease in NPC compared to the
current base NPC approved by the Commission and incorporated into customer
rates in the 2015 Update, that includes a discussion of the changes to the
Company's resource portfolio since that time; and,
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. Discusses the Company's treatment of its participation in the Western Energy
Imbalance Market ("EIM") and the expected incremental benefits relative to
the NPC forecast produced by the GRID model.
Is there a summary of the proposed ECAM Base amounts to be set in this Iiling
for future ECAM filings?
Yes. ExhibitNo.44 attached to the testimony of Mr. Steven R. McDougal, summarizes
the proposed base amounts for all elements for ECAM deferrals beginning January 1,
2022.In addition to NPC discussed in my testimony, the ECAM deferral includes the
difference between actual and base amounts for production tax credits, renewable
energy certificate sales, and load change adjustment revenues.
III. SUMMARYOF COMPANY NET POWER COSTS
Please explain the components of the Company's NPC.
NPC are defined as the sum of fuel expenses, wholesale purchase power expenses and
wheeling expenses, less wholesale sales revenue. The NPC forecast approved in this
case becomes the base NPC used for comparison to actual NPC in subsequent ECAM
filings.
Please explain how the Company calculates NPC.
NPC are calculated for the test period based on projected data using GRID, a production
cost model that simulates the operation of the Company's power system on an hourly
basis. GRID respects all system requirements and constraints and uses incremental
pricing to dispatch the Company's generation trnits for a cost minimizing output where
demand and supply are balanced.
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Is the Company's general approach to the calculation of NPC using the GRID
model the same in this case as in previous cases?
Yes. The Company has used the GRID model to determine NPC in its ldaho filings for
many years. However, to improve the accuracy of the NPC forecast, the Company has
implemented certain modeling changes in this case.
What GRID inputs were updated for this filing?
All inputs have been updated since the 2015 Update, including system load, wholesale
sales and purchase contrac6 for electricity, wheeling expense, market prices for
electricity and natural gas also known as the Offrcial Forward Price Curve ("OFPC"),
transmission topology, and the characteristics and availability of the Company's
generation facilities.
What is the date of the OFPC the Company used for its NPC?
The NPC used the OFPC dated March3l,202l.
What reports does the GRID model produce?
The major output from the GRID model is the NPC report. This is attached to my
testimony as Exhibit No. 37. The GRID model also produces more detailed reports in
hourly, daily, monthly, and annual formats by heavy-load hours ("HLH") and light-load
hours ("LLH").
What are the proposed system-wide NPC for the test period?
The proposed NPC for the test period are $1,365 million on a total-Company basis and
$86.5 million on an Idaho-allocated basis.
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Please generally describe the changes in NPC compared to the 2015 Update.
The decrease in NPC is driven by lower coal fuel expense, lower natural gas expense,
increased zero-fuel cost renewable generation, and increased wholesale sales revenue.
The decrease is partially offset by an increase in wheeling and purchased power
expense. Figure I below illustrates the total-Company change in NPC by category
compared to the NPC approved in the 2015 Update.
Figure I
Net Porer Cost Reconcilietion
ID Bese IIPIC PAC-f-lGl2
($ nillions)
sl,.lts
SAIWh
s25.05
Increasc./(Decreasc) to NPC:
\ltolcsab Satcs Rsrmw
Purchesod Power Expease
CoalFwlE:pcnsc
NahralGas FuclBpeosc
\&tocling md Other Expcase
Iotd Increesc/@ecreese) to ittFC
(r2e)
237
(l8l)
(s6)
9
ID GRC 2(nI
(r20)
$rJ6s $23.36
As shown in Figure l, total-Company NPC has decreased from $1,485 million to
$1,365 million, which is $120 million (8.1 percent) lower than in the 2015 Update. The
total-Company price per megawatt-hour ("MWh") has decreased from $25.05 per
MWh to $23.36 per MWh. Unless otherwise noted, references to NPC or various
individual cost items throughout my testimony are stated in total-Company system
amounts.
Please explain the increase in wholesale sales nevenue.
The increase in wholesale sales revenue (which decreases NPC) is driven by higher
wholesale sales volumes, which are 2,960 gigawatt-hours ("GWh") higher than in the
2015 Update. Wholesale sales revenue is $129 million higher than the 2015 Update
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with the increase coming from market transactions (represented in GRID as short-terrn
firm, and system balancing sales). The increase in volume is driven by higher average
market prices forecast in the test period. The average market price of wholesale sales
is $43.62 per MWh, an 86 percent increase over the average market sale price in the
2015 Update, which was $23.46 per MWh.
Why did purchased power expense increase?
The increase in purchased power expense is driven by an increase in the volume of
system balancing purchases as well as higher system balancing prices. Additionally, the
volume of long-term purchases has increased, primarily in the form of purchases from
qualified facilities ("QFs"). Market purchases (represented in GRID as short-term firm
and system balancing purchases) in the current case have an average price of $3 5 .4 I per
MWh, while the 2015 Update had an average price of $25.06 per MWh, a rise of
approximately 4l percent. The market purchase volume is 767 GWh higher than in the
2015 Update on a total-Company basis.
This case also includes nine new long-term contracts with an average price of
$19.08 per MWh, with the expiration of four long-terrn contacts with an average price
of $65.68 per MWh.
Several new QFs have come online since the 2015 Update. The total expense
for power purchased from QFs increased by $122 million which is driven by an
anticipated generation volume increase of 2,068 GWh compared to the 2015 Update.
The average price for QFs included in this case is $59.39 per MWh, compared to the
average price of QFs in the 2015 Update of $59.55 per MWh.
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Please explain the decrease in coal expense in the current proceeding.
Total-Company coal fuel expense is $180.5 million lower than the 2015 Update due to
lower coal generation volume, partially offset by higher coal prices, and increased
generation from zero fuel cost renewable resources. The lower coal fuel expense is
driven in part by the closure of the Cholla Unit 4 power plant, which the Company
removed from service in December 2020. Excluding the impacts of the closure of
Cholla Unit 4, coal generation is approximately 6,835 GWh or 19 percent, lower than
the 2015 Update. The average coal generation price across PacifiCorp's generation fleet
is $0.12 per MWh higher than the average coal generation price from the 2015 Update.
The increase is driven by changes in third-party coal supply and rail contracts. I provide
additional detail regarding the coal fuel expense later in my testimony.
Please discuss the change in natural gas fuel expense compared to the 2015
Update.
Total-Company natural gas fuel expense is $56 million lower than the natural gas fuel
expense in the 2015 Update. The decreased natural gas fuel expense is primarily due to
lower forecasted generation volume, partially offset by higher natural gas market
prices. The average cost ofnatural gas generation increased l7 percent from $23.06 per
MWh to $26.95 per MWh in the current proceeding. Generation from natural gas power
plants is 3,862 GWh less than the 2015 Update, a decrease of 3l percent.
Please describe the increase in the wheeling and other expense category.
Expenses in this category are higher due to an $8 million service fee charged by the
California Independent System Operator ("CAISO") for grid management related to
the new nodal pricing model developed as a requirement of the 2020 inter-jurisdictional
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cost allocation agreement, and expedited payment schedule for the Mead-Phoenix
Transmission line amortization due to the Cholla 4 retirement in December 2020. This
increase is partially offset by the expiration of some legacy wheeling contracts.
Please explain the changes to the Company's generation resources since the 2015
Update.
There have been multiple changes to the Company's generation resources since the
2015 Update. The following is a list of some of the major changes affecting NPC:
. Cholla Unit 4 Termination - Cholla Unit 4 was removed from service in
December 2020, and will not operate during the test period;
. Naughton Unit 3 Gas Conversion - Naughton Unit 3 was converted from a
coal-fired resource to a natural gas resourcein2020;
. Nazu Renewable Resources - Approximately 1,500 MW of new owned wind
and transmission, along with other power purchase agreements are included in
the test period.
TV. MODELING CHANGES TO GRII)
Has the Company made any changes to improve the accuracy of its NPC
modeling?
Yes. The Company has made various modifications to the GRID inputs in order to
increase the accuracy of forecast NPC, including changes to the following items:
. Updated the scalar method for the OFPC;
. Updated the regulating reserve requirement based on the Flexible Reserve
Study in the 2019 lntegrated Resource Plan ("IRP");
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. Included actual capacity factors for owned wind power plants and purchased
wind power plants; and
. Developed a solar hourly profile consistent with the method used for the wind
hourly profile.
Details supporting each modeling change are provided below.
O. Why is the Company proposing changes to NPC modeling in this case?
A. Base NPC have not been updated since 2015. The modeling changes proposed in this
case are necessary to improve the accuracy of the forecast.
A. Updated Scalars to the Oflicial Forward Price Curve
a. Please briefly describe the hourly scalars and how they are applied to the OFPC
the Company used in GRID.
A. Scalars are multipliers that are applied to the monthly prices from the OFPC to derive
an hourly price profile. In other words, scalars give the monthly prices an hourly shape.
These multipliers are unique for every hour in a month for a given day type (i.e.,
weekdays excluding holidays, Saturdays excluding holidays, and Sundays/holidays),
and therefore yield hour-to-hour price variability that is consistent with historical price
data. Scalars greater than one would result in an hourly price for a given day type that
is higherthan the monthly forward price, and scalars that are less than one would result
in an hourly price for a given day type that is lower than the monthly forward price.
For example, if the average market price during hour-ending at 10 am in May is $ 18
per MWh, and the average market price during all hours in May is $20 per MWh, then
the scalar for hour-ending at l0 am in May would be 0.9 or 90 percent.l The hourly
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price profile that is a result of applying scalars to forward monthly prices yields hourly
prices that, when averaged across a given month, precisely equal the forward monthly
prices in the OFPC.
Please explain the change to the hourly scalars used in this case.
To better reflect ongoing changes in power markets and to increase transparency,
PacifiCorp is no longer using five years of historical hourly prices from PowerDex.
Instead, PacifiCorp is using the CAISO day-ahead hourly market prices at Califomia-
Oregon Border ("COB") and Palo Verde ("PV") for the most recent 24-month period.
The change in data inputs that determine the scalars does not, however, alter the
application of the scalars as described above.
Why is PacifiCorp making this change to its scalars?
The use of the CAISO day-ahead hourly market prices as a basis for the updated
forecast scalars follows the actual hourly shape by producing a peak in the morning
hours, depressed prices during mid-day, and larger peak in the evening hours. This type
of shape is expected given the solar penetration in the West and is the result of higher
quality CAISO trade data that better reflects actual and ongoing conditions in the power
markets. The volume of actual trade data reported from CAISO is substantially higher
than the volume of actual ffade data that is reported in PowerDex. The use of the
CAISO trade data results in scalars that beffer represent the increasing solar capacity in
California and price volatility on a day-ahead basis. Finally, the historical CAISO day-
ahead hourly prices are publicly available resulting in greater transparency compared
to the proprietary PowerDex prices.
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Why is the use of data from the most recent 24 months reasonable?
The scalars give the monthly prices an hourly shape and the most recent 24 months is
indicative of the hourly shapes the Company expects to see in the markets in the future.
Both PacifiCorp and the western interconnect have experienced a significant increase
in the number of renewable resources, including additional solar resources in the last
24 months, and this trend is expected to continue over the next several years.2 This
trend of increased solar resources has a meaningful impact on market price shape and
because the industry is constantly evolving, the use of two-year data versus five years
allows the Company to implement the most current market trends available.
Are there considerations in the calculations of hourly scalars for very high or very
low price variations?
Yes. CAISO prices can vary widely, and the price shape for an hour and month can be
skewed by the presence of a few very high or very low prices. Therefore, the CAISO
prices used to calculate the hourly scalars are capped to limit the impact of potentially
more exteme results. Large price variations are generally a result of unexpected
conditions, which can include significant deviations from forecasted load, wind, or
solar. Such deviations are largely random, so the presence of extreme values is
generally a chance occr[rence, rather than a characteristic ofa given hour. Therefore,
the CAISO prices used to calculate the scalars are capped at +$250 per MWh
and $50 per MWh.
Additionally, as the historical monthly prices approach zero, the magnitude of
the shaping becomes unrealistically large. When this happens, the historical prices are
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2 U.S, Energy Information Administration. Annual Energy Outlook 202 l, available at
https://www.eia. gov/outlooks/aeo/pdf/04%20AEO2021%20Electricity.pdt'.
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I uniformly shifted until the average monthly price over the calculation period is $25 per
MWh, at which point, the scalars are calculated based on the adjusted historical prices
resulting in a more reasonable shape.
B. Regulating Reserve Requirement
How did PacifiCorp update its regulating reserve requirement modeling?
The Company's regulating reserve requirements are now based on the 2019 Flexible
Reserve Study (*2019 FRS") that was submitted as part of the development of the 2019
IRP.3
How has the modeling of regulating reserve requirement changed as a result of
the 2019 FRS?
The Company included several modeling changes compared to the 2014 Wind
Integration Study ("WIS") that was used in the 2015 Update:a
. The regulating reserve requirement is a function of a specific value that is fixed in
all hours and a variable regulation reserve requirement that is based on the change
in the resource balance from hour to hour.
. The regulating reserve requirement varies when wind and solar generation changes.
The load and variable energy resource ("VER") have fixed amount of regulation
reserve requirements. VERs refer to variable energy resources, which: (l) are
renewable; (2) cannot be stored by the facility owner or operator; and (3) have
variability that is beyond the control of the facility owner or operator.
3 PacifiCorpb 2019 Integrated Resource Plan, Case No. PAC-E-19-16.
a The system impact to NPC from the change of using the 2014 WIS to the 2019 FRS is diflicult to quantifo due
to the many changes to the Company's system since the 2015 Update. Various generation resources have been
added and removed from the system which afTects how the regulating reserves studies are prepared and applied
to NPC.
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o A unit can be allocated reserves up to the lesser of its 30-minute ramp rate and the
difference between its minimum and maximum operating levels. If a unit is
allocated reserves, the allocated capacity is subtracted from the unit's maximum
operating level, resulting in a reduced maximum dispatch level.
. The 2014 WIS included EIM diversity benefits associated with transfers between
PacifiCorp's west balancing authority area and CAISO. Since then, several
additional utilities have joined EIM, and diversity benefits have increased. After
accounting for EIM diversity benefits, the 2014 WIS identified a total regulation
requirement of approximately 561 megawatts ("MW") to integrate load and wind.
The 2019 FRS identified a total regulation requirement of 531 MW to integrate
load, wind and solar.
For additional details, please refer to the Company's regulating reserve
requirements based on the 2019 Flexible Reserve Study that was included in the
2019IRP.
C. Actual Capacity Factor for Owned Wind Generation and Purchased Wind
Generation
Please describe the adjustment made to the forecast capacity factor for Company-
owned wind generation and purchased wind generation.
Previously, the generation from PacifiCorp's owned wind power plants and purchased
wind was based on long-range forecasts provided to the Company by the project
developers. In this case, PacifiCorp proposes to calculate the annual capacity factor
using a cumulative average methodology for any wind power plants with a history
longer than four years. For those projects with less than four years of history the project
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developer's forecast is used until four years of actual results become available at which
point, actual historical data is then used.
Actual wind generation at these facilities has varied somewhat from developer
forecasts, so this change brings the modeling of wind plants in line with the historical
actuals, which will better reflect a reasonable level of generation for the future period.
With the increase in solar generation on the Company's system, does the Company
plan to use the historical average method for the forecasted capacity factor for its
owned and purchased solar resources?
Yes. Currently, the Company uses the long-range forecasts provided by the project
developers for all owned and purchased solar resources since they have been on the
Company's system for less than a four-year period. The Company proposes to switch
to the annual capacity factor using a cumulative average methodology for any solar
power plants with a history of longer than four years.
D. Solar Hourly Shape
Please explain how the Company used historical solar output to calculate the solar
generation shape in this case.
In this case, the Company continues to use the P505 forecast approach for determining
total solar generation and used the Company's actual2019 energy output data from its
purchased solar facilities to shape hourly solar generation profiles. The Company
scaled actual generation levels up or down so that, when the ou@ut is averaged over
5 A P50 forecast projects generation at a level that is expected to have an equal probability ofbeing higher or
lower than forecast. Typically, such a forecast is developed for an individual project by combining solar
exposure taken before the project is constructed with a detailed plant location and performance characteristics.
The projected output in a given month is then averaged across a given month to produce a 12 x24 matrix of
average hourly output.
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the course of a month, it is the same as in the P50 forecast. In other words, the total
energy output of the solar facilities is the same as the P50 forecast used in previous
cases, but the shape of the generation varies on an hourly basis consistent with actual
output during 2019. This method is consistent with the wind hourly shape method used
by the Company in the 2015 Update.
Why did the Company choose to use the hourly solar profrle to reflect historical
per{ormance?
Figure 4 illustrates the difference in solar generation profiles. The solid line shows one
solar plant's hourly energy, and the dashed line shows the solar hourly shape for the
same dates without hourly shaping. The shaded area shows the difference betureen the
two hourly shapes and represents the difference in solar generation for that day. The
dashed line does nothave any day-to-day variation in each month. The solid line better
represenB the solar inputs that vary hourly based on historical volatility, with the same
total monthly solar generation volume as the P50 forecast.
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Figure 4
Solar Hourly Shapes
r r rWithout Hourly Shape
-With
SolarShape
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V. STJMMARY OF COMPANY COAL COSTS
How does PacifiCorp plan to meet fuel supplies for its coal power plants lm2021?
PacifiCorp employs a diversified coal supply srategy, with 8l percent of its 2021 coal
requirements supplied by third-party coal supplies and 19 percent with coal from its
captive affiliate mines. The third-party contacts consist of fixed-price and variable-
priced contacts. Coal amounts in my testimony are shown on a total-Company basis.
A. Jim Bridger
Please describe the coal supply arrangement for the Jim Bridger power plant for
2021.
The Jim Bridger power plant is supplied by the Company-owned Bridger Coal
Company ("BCC") mine and the Black Butte mine in the test period.
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Please describe the change in Bridger CoaI Company costs in this case.
BCC costs in this case are forecast to be! miflion lower than the 2015 Update. The
cost for the BCC deliveries decreased uv I per ton, to* Iper ton in
the 2015 Update to I per ton in this case. The reduction is primarily due to the
reduction of materials and supplies of! million,I milion labor and benefits,
I[,nittio" for improved heat content, ! milion for an increase to the final
reclamation credit, ! million for coal inventory and ! mittion for other
miscellaneous costs, partially offset by an increase of! million for final reclamation
contributions. In the 2015 Update, the BCC mine plan assumed underground coal
production would cease in 2023 and surface mine production would end in 2037. I1r
this case, the BCC mine plan assumes that underground coal production will end in
202I andsurface mine production will end in 2028.
What is the expected change in third-party coal prices for the Jim Bridger power
plant in this case?
Delivered costs for thil million tons of Black Butte coal increased fro-f ner
ton in the 2015 Update ," il per ton in this case, o,f million overall. The price
of Black Butte coal increased! per ton, from a cost of! per ton in the 2015
Update to I per ton in this case. The coal price increase is approximately
lmillion, or I percent. The Union Pacific Railroad agreement is forecast to
increase UV l-illion in delivered costs. These increases are primarily due to
inflation.
Wilding, Di - 17
Roclcy Mountain Power
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B. Naughton
Please describe the coal supply arrangement for the Naughton power plant in
2021,.
The Naughton power plant is supplied by the adjacent Kemmerer mine under a long-
term coal supply agreement ("CSA") through 2021. The CSA contains an
environmental response provision to reduce the minimum annual tonnage volume
quantity in the event of a reduction in coal-fired generation at the plant due to changes
in environmental laws or rules.
As a result of Naughton Unit 3 converting from a coal-fired to a natural gas-
fired resource,6PacifiCorp exercised this provision and the annual minimum take-or-
pay quantity was reduced from! miflion tons tolmillion tons. tn lieu of a full take-
or-pay payment of approximately fner ton or il million for the I miflion tons
below lmillion, an environmental shortfall payment of only I per ton or
! million, will be owed in202l related toI million shorrfall tons on deliveries of
! miilion tons in the 2O20-2021 contract year. For the six-month stub period from
h:i,y 2O2l through December 2OZl, an environmental shortfall payment of only!
per ton orI million will be owed related to! million shortfall tons on deliveries
of I million tons. The environmental shortfall payment is a direct result of the
reduction in the coal purchases due to Naughton Unit 3 discontinuing as a coal-fired
unit.
Wilding, Di - 18
Rocky Mountain Power
6 As discussed in the direct testimony of Mr. Robert Van Engelenhoven in this case.
REDACTED
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Please describe the changes to Naughton power plant's coal cost from the 2015
Update.
Total delivered coal cost at Naughton iocreasedf per ton, fro-Iper ton in
the 2015 Update to lner ton in this case resulting in an overall increase of
lmiilion. The 2021 pice forecast is based upon the 2019 price reopener with
escalations based upon projected diesel fuel prices and other price indices. The contract
escalation results in a price increase oflrnilion after royalties and taxes. Another
driver ofthe price increase is thelmillion environmental shortfall payment in202l.
The change in the amount of coal purchased under each price tier-namely less lower-
priced tier-2 coal-increases costs by! million. The forecasted tier-2 coal delivered
in calendar year 2o2l i.I tons less than the 2015 Update. The increase in coal
costs is partially offset by a decrease to the diesel fuel hedge loss of! million and a
reduction of I milion for contract amortization costs. The amortization of these
costs was completed at the end of 2016.
C. Wyodak
Please describe the price incrrcase related to the \ilyodak power plant contract.
Delivered coal cost increased from! per ton in the 2015 Update to! per ton
in this case, or ! rnlttio" overall. The cost increase is primarily the result of
escalation in diesel fuel and other conffact indices, partially offset by the results of the
2019 price reopener
Wilding, Di - 19
Rocky Mountain Power
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D. Dave Johnston
Please describe the Dave Johnston power plant coal supply cost increase.
Dave Johnston power plant delivered coal cost decreased bV! million compared to
the 2015 Update, otlp.t ent. The reduction is due to a decrease in coal costs of
! million, as described in further detail below partially offset by an increase in rail
costs of approximately! million.
Please describe the open coal position for the Dave Johnston power plant in2O2l,
The Dave Johnston power plant is projected to consume approximateblmillion tons
in}O2l;the Company currently has! million tons of coal under contract for the plant
resulting in an unidentified or open position of I million tons. The Company will
solicit coal supplies from Powder River Basin (*PRB") mines through a request for
proposals during 2021 to fill a reasonable portion of the open position, which may be
adjusted according to market conditions. The Company has used this fueling strategy
for the Dave Johnston power plant for several years.
What are the coal supply arrangements for the Dave Johnston power plant in this
case?
Arch Coal's Coal Creek mine will supply ! roittio, tons, Peabody Energy's North
Antelope Rochelle mine will supply! million tons and Peabody Energy's Caballo
mine will supply ! mitlion tons in 2O2l (lpercent of the plant's requirements).
The coal cost decreate of! million is the aggregate of a decrease oil million for
refined coal and a decrease to the cost of coal of ! million, partially offset by an
increase to the rail costs oil million.
Wilding, Di - 20
Rocky Mountain Power
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E. Hunter
Please explain how the Company's Hunter power plant is supplied with coal in
this case.
The Hunter plant has two coal supply agreements to fuel the plant. One is with
Wolverine Fuels, LLC (Wolverine) and the other is with Bronco Utah Operations, LLC
(Bronco). Both agreements are "delivered to plant" agreements.
Please describe the change in coal costs at the Hunter power plant in this case.
Coal prices have decreasedlner ton, fromI per ton in the 2015 Update to
I per ton in this .ur" f*illion overall). rhe! million decrease is primarily
due to the price decreases for the new CSA(s) beginning in 2021 for a decrease of
! million, lmillion for refined coal andlmillion for the expiring Westridge
agreement, partially offset bV almillion for the Energy West pension costs.
F. Huntington
Please describe the coal supply arrangement for the Huntington power plant in
2021.
The primary coal supply to the Huntington power plant is provided through a
requirements CSA with Wolverine. This is a "delivered to the plant" agreement with
Wolverine responsible for transportation of the coal from the sourced mines to the plant,
although PacifiCorp is responsible for limited trucking cost escalation. In the 2015
Update, the Huntington power plant also received coal under a CSAwith Rhino Energy,
LLC's Castle Valley mine. That CSA ended December 31,2020.
Wilding, Di-21
Rocky Mountain Power
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What coal supply costs for the Huntington power plant are included in this case?
For the Huntington power plant, delivered coal prices increased fromf per ton in
the 2015 Update tolper ton in this case, an overall increase ofl per ton or
! million. The overall price per ton for the Wolverine contract increased! per
ton, from! per ton in the 2015 Update tol per ton in this case,lmillion
overall o" I million tons. The increase is due to contractual price changes and
escalation associated with transportation co sts.
Does the current proceeding reflect Enerry West pension costs?
Yes. This proceeding includes! million, PacifiCorp's share, for contributions to
the lgT4United Mine Workers Association pension pl*.'I miflion of the pension
cost is included in the Huntington plant fuel costs and! miilion, is included in the
Hunter plant fuel costs in this case.
G. Craig
Please describe the coal supply arrangements for the Craig power plant.
In 2021, the Craig power plant will be supplied by the Trapper mine, which is an
affiliate captive mine owned by three of the five Craig power plant owners.
PacifiCorp's share of the mine is 29.14 percent. The pricing under the CSA is based
upon the annual mine cost associated with the Trapper mine.
Have coal costs changed from the 2015 Update?
Yes. For the Craig power plant, delivered coal prices decreased from! per ton in
the 2015 Update al per ton in this case, for a decrease oil million. Trapper
mine costs have decreased! per ton, from! per ton in the 2015 Update to
7 In the Maller of the Application of Roclcy Mounlain Power for Approval of a Transaction to Close Deer Creek
Mine and for a Defened Accounting Order, 2015 WL 3440548, PAC-E-14-10 (Order 33304) (May 27,2015\.
Wilding, Di-22
Rocky Mountain Power
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I per ton in this .ut", ulmillion overall price decrease. The price decrease is
due to increased volume from the Trapper mine and decreases to overall mining costs
at the Trapper mine. There is also a decrease due to the reduction of diesel fuel hedge
losses ofl million.
II. Hayden
Please describe the change in llayden power plant's coal cost from the 2015
Update.
Delivered coal prices increased! per ton, fro-Iper ton in the 2015 Update
tol per ton in this case. The increase is primarily due to inflation, partially offset
by the 2018 price reopener. Under the terms of the January 1, 2018 reopener provision,
the coal price was lowered and adjusts on a fixed annual schedule from 2018 to 2022.
I. Colstrip
Please describe the change in coal cost at the Colstrip power plant in this case.
Delivered coal prices increased! perton, from! perton in the 2015 Update
aI per ton in this case, an increase off million. PacifiCorp based the costs
for the Colstrip power plant on the new CSA that was signed December 5, 2019. The
CSAhas changed from a
Please summarize how the changes to the coal fuel expenses described in this
section affect NPC in this case.
Customers have benefited from the Company's diversified fueling strategy, which
relies upon fixed-price contracts, index-priced contracts, and affiliate-owned mines to
meet the fuel needs of its coal-fired power plants. Several factors have contributed to
the $l8l million decrease in coal-fuel expense in this filing, primarily reduced coal
Wilding, Di-23
Rocky Mountain Power
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volumes. PacifiCorp's fueling strategy has resulted in long-term, stable coal supplies
for its customers.
VI. CUSTOMER BENEFITS OF THE ENIERGY IMBALANCE MARKET
Please describe the EIM and the Company's participation in the EIM.
The EIM is a real-time balancing market that optimizes generator dispatch every five
and l5 minutes within and among PacifiCorp, the CAISO and other EIM participants.
Through the EIM, the Company's participating generation units are optimally
scheduled and dispatched using the CAISO's security constrained unit optimization and
economic dispatch models. The EIM's automated, expanded footprint and co-
optimized dispatch replaced the Company's isolated and manual dispatch within its trvo
balancing authority areas ("BAAs"). Participation in the EIM benefits customers by
reducing NPC, with relatively low ongoing operation costs.
Has the EIM continued to provide customer benefits since the 2015 Update?
Yes. The Company has participated in the EIM since 2014. The EIM has continued to
provide benefits to customers through more effrcient and economical dispatch, inter-
regional transfers (i.e., exports and imports between EIM participants), reduced reserve
requirements, and greenhouse gas ("GHG") revenue. Each year the benefits have
increased as regional participation in the inter-regional markets has increased.
Please summarize the EIM benefits included in this case.
The NPC forecast from GRID includes an adjustment to reflect incremental EIM
benefits from inter-regional dispatch reduced flexibility reserves, and GHG revenue.
Specifically, the NPC forecast includes approximat.ly I million in EIM benefits
and ! million in GHG revenue. In this case, the Company's share of the reserve
Wilding, Di - 24
Rocky Mountain Power
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benefit based on the diversified footprint of the EIM is explicitly accounted for and the
regulating reserve requirement is reduced by approximately 104 MW.8
What are the EIM inter-regional transfer benefits?
The inter-regional transfer benefits reflect the benefits received by PacifiCorp when it
economically exports energy to the EIM and when it economically imports energy from
the EIM which allows displacement of a more expensive resource on the Company
system. Generally, the benefit of EIM exports is equal to the revenue received less the
production cost of generation assumed to supply the transfer. The production cost used
in the Company's calculation of EIM benefits is the marginal cost to produce an
additional MWh at a given resource. The Company's production costs used to calculate
EIM benefits are equal to the resource bids submitted to the EIM. The benefit of EIM
imports is equal to the import expense less the avoided expense of the generation that
would have otherwise been dispatched.
How does the Company calculate the inter-regional dispatch EIM benefits
forecast?
The Company uses historical actual EIM inter-regional transfer benefits in statistical
models to forecast EIM transfer benefits as a function of market prices and transfer
volume inputs, which are the underlying drivers of actual EIM transfer benefits. The
price inputs are the energy and natural gas market prices from the OFPC. The transfer
volume inputs are the total transfer capacity of transmission along with spring
oversupply conditions, based on the current and expected solar capacity in California.
This market fundamentals approach to forecasting EIM transfer benefits mimics the
8 See 2019_Integrated Resource Plan.-Volume-Il.-Appendices-A-I-. Appendix F, pp. l0l-102 , Case No. PAC-
E-19-16 (October 18, 201 9).
Wilding, Di - 25
Rocky Mountain Power
I method which the Company uses to calculate actual EIM transfer benefits and
maintains consistency with the bilateral market price inputs that drive the Company's
GRID forecasted NPC. By utilizing the same inputs for the forecast of EIM inter-
regional transfer benefits and the calculation of actual EIM inter-regional transfer
benefits the GRID forecasted NPC are aligned and produce a reasonable forecast of
EIM inter-regional transfer benefits. The regression modeling for this rate case is a
method which provides the comprehensive view from all the variables actually
impacting inter-regional EIM benefits in the future.
How does the Company calculate the EIM GHG benefits?
GHG benefits are realized when the GHG revenue is higher than the Company's
resulting compliance cost. GHG revenues are received from the energy dispatched to
serve the CAISO's GHG obligations and the associated payment for GHG compliance
costs, which is embedded within the EIM price as the marginal cost of GHG. The
Company's compliance cost is the expenditure to procure the necessary California
CarbonAllowances for the portion of the energy dispatched to serve the CAISO's GHG
obligations.
VII. CONCLUSION
Please summarize your direct testimony.
The Company's NPC for the 2O2l test period in this case have decreased by
$120 million on a total-Company basis, 8.1 percent, since the 2015 Update. This
reduction is largely driven by reductions in coal fuel expense, increased sales revenue,
lower natural gas fuel expense, and increased zero-fuel cost renewable generation,
partially offset by increased purchased power expense, and a small increase in wheeling
Wilding, Di-26
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expense. The Company has updated its GRD modeling in order to send appropriate
price signals to customers, improve the accuracy of the net power cost forecast, and
recognize costs and benefits not previously modeled.
Please summarize your recommendation to the Commission.
I recommend that the Commission approve the proposed GRID modeling
improvements as outlined in my testimony and adopt the proposed base NPC for the
test period of $1.365 billion on a total-Company basis, or $86.5 million on an Idaho-
allocated basis.
Does this conclude your direct testimony?
Yes.
Wilding, Di-27
Rocky Mountain Power