20190403Wilding Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTTNG APPROVAL OF $ls
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-19-04
)) DTRECT TESTIMONY Or
) ndrcHAEL G. WTLDTNG
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-19-04
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Please state your name, business address, and present position with PacifiCorp,
dba Rocky Mountain Power (the "Company").
My name is Michael G. Wilding. My business address is 825 NE Multnomah Street,
Suite 600, Portland, Oregon 97232. My title is Director, Net Power Costs and
Regulatory Policy.
QUALIFICATIONS
Briefly describe your education and business experience.
I received a Master of Accounting from Weber State University and a Bachelor of
Science degree in accounting from Utah State University. I 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 the Company since 20 14.
Have you testilied in previous regulatory proceedings?
Yes. I have filed testimony in proceedings before the public service commissions in
Idaho, Utah, Wyoming, Oregon, Washington, and California.
PURPOSE OF TESTIMONY
What is the purpose of your testimony in this proceeding?
My testimony presents and supports the Company's calculation of the Energy Cost
Adjustment Mechanism ("ECAM") balancing account for the l2-month period of
January 1,2018 through December 31,2018 ("Deferral Period"). More specifically, I
provide the following:
. A summary of the ECAM calculation, including changes made to comply with
Commission orders;
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I See Order No, 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-15-09.
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. Details supporting the addition of approximately $15.1 million to the deferral
balance, including $4.9 million customers'share of excess ECAM-related costs,
$5.4 million Lake Side 2 Resource Adder, $3.3 million renewable energy
production tax credits ("PTCs"), $1.1 million Deer Creek amortization expense,
$0.2 million renewable energy credit ("REC") revenue differential, and $0.1
million interest accrued;
. Discussion of the main differences between adjusted actual net power costs
("Actual NPC") and net power costs in rates ("Base NPC"); and,
. Discussion about the Company's participation in the energy imbalance market
("EIM") with California Independent System Operator ("CAISO") and the
benefits from EIM that are passed through to customers.
a. What other witnesses present testimony for the ECAM and Tariff Schedule 94 in
this case?
A. Mr. Robert M. Meredith, Manager, Pricing and Cost of Service, provides testimony on
the proposed rates in Electric Service Schedule No. 94, Energy Cost Adjustment
("Schedule 94").
SUMMARY OF THE ECAM DEFERRAL CALCULATION
a. Please briefly describe the Company's ECAM authorized by the Commission.
A. In general, the ECAM tracks deviations betweenActualNPC and Base NPC and defers
90 percent of the difference for later recovery.1 Other items, described in detail later in
my testimony, are also tracked in the ECAM to true-up the amount in base rates to
actuals. These items include: a resource adder for the Lake Side 2 gas generation plant,
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PTCs, Idaho-allocated Deer Creek mine amortization expense, and revenues from the
sale of RECs.2 The balance that accumulates over a deferral period is then passed on to
customers as a rate surcharge or credit. The Schedule 94 rute, which appears as a
separate line item on customer bills, collects from or credits to customers the balance
of deferred costs. Schedule 94 is adjusted as needed in the Company's annual ECAM
filings.
The Company is required to file an application with the Commission annually
by April I to seek approval of the deferral amount and the new Schedule 94 rate, which
becomes effective June 1.
How is the ECAM deferral calculation presented in your testimony?
The calculation of the ECAM deferral is contained in Exhibit No. l, discussed later in
my testimony. Table I is a summary of the major components.
Are there any changes to the ECAM calculation?
Yes. [n Case No. PAC-E-I8-01, the Commission ordered3 the Company to include the
depreciation regulatory asset created in Case No. PAC-E-13-02 in future Idaho ECAM
filings. The Company has updated Exhibit No. I to include the depreciation regulatory
asset. In addition, the Company updated the LCAR rate to incorporate the impact of
the Tax Reform Act.
ECAM DEFERRAL CALCULATION
Please describe the calculation of the ECAM deferral included in this filing.
Thble I provides a summary of the total ECAM deferral and a breakdown of the
individual components of the ECAM. Additionally, Exhibit No. I presents the detailed
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2 See Order No. 33440 in Case No. PAC-E-15-09 pages 5-6.
3 See Order No. 34076 in Case No. PAC-E-18-01 page 4.
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calculation of the ECAM deferral on a monthly basis
Table I
Annual ECAM Calculation
Calendar Year 2018 ECAM Defenal
NPC Diftrertial
EITF 04-6 Adjustrrrcnt
LCAR
Total Deferral Before Sharing
Sharing Bard
C ustorner Reponsibiliry
Lake Side 2 Resource Adder
Prodtrction Tax C redits
Deer Creek Amortization Eryense
REC Deferral
Interest on Deferral
Annual Deferral (Jan - Dec 2018)
s 7,r s2,s87
(139,27t)
(1,522,906)
$ 5,490,509
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4,941,459
5,43t,705
3,287,899
1,134,O78
172,763
l32,8ll
s 15,100,774
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$
Table I summarizes the components of the ECAM balance. The first section
summarizes the Idaho-allocated share of those items for which Idaho customers and
the Company share responsibility, including: NPC differential, EITF 04-6 adjustment,
and LCAR costs. The next section calculates the 90 percent customers' share of the
items above and adds the following items which are refunded or collected in full (i.e.,
100 percent): the Lake Side 2 resource adder, PTCs, Deer Creek mine amortization
expense, and REC revenues. The total of these items represent the ECAM deferral.
Please explain how the depreciation regulatory asset has been included in the
ECAM calculation.
In Case No. PAC-E-I8-01, the Commission ordered the Company to include the
depreciation regulatory asset created in Case No. PAC-E-13-02 in future Idaho ECAM
filings. As seen on ExhibitNo. l, the beginning balance, monthly deferral, and monthly
amortization are included as part of the ECAM deferral balance. The Company applied
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ECAM Defertal Balance
Prior Deferral
Arurual Deferral (Jan - Dec 2Ol8)
Interest
ECAM Revenue Collection - Schedule 94
ActiviQr Through Decernber 31, 2O18
De preciation Re gulatory Asset Balance
Begirming Balance
Transfer due to Tax Reforrn Act
Annual Deftrral (Jan - Dec 2Ol8)
ECAM Revenue Collectircn - Schedule 94
Activity Through Decernber 31, 2O18
December 31, 2O18 Balance For Collection
Schedule 94 Collection - Jan - May 2Ol9
Irrterest
Expected Balance as of June lr 2Ol9
(86,905)
$
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$
$
s 13,938,857
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278 746
$ 17,365,652
$17
1o,123,o97
14,967,903
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(7,85 8,1 59)
4,733,277
(3,42s,O23)
1,926,432
(2,721,592)
(3,47O,983)
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g3 .425 million of current tax savings from the 201 8 Tax Act to offset the depreciation
regulatory asset in June 2018, in accordance with Order No. 34072 in Case No. GNR-
u-18-01.
a. Based on your calculations, what is the balance expected to be in the ECAM
deferral account as ofJune lr2019?
A. The projected balance in the ECAM deferral account as of June l, 2019 is
approximately $13.9 million. Table 2 summarizes the ECAM balancing account
activity starting with the calendar year 2017 ECAM deferral balance of $10.1 million
approved in Case No. PAC-E-18-01. Approximately $15.1 million is added to the
balance frbm the annual deferral and interest during the Deferral Period, offset by $7.9
million of ECAM revenue collections. Table 2 then summarizes the depreciation
regulatory asset balance activity; the sum of the two is the balance for collection as of
December 31,2018.
Table 2
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Please describe the ECAM calculations in Exhibit No. 1.
The ECAM deferral is calculated by comparing Idaho-allocated Actual NPC to the
NPC collected in rates on a monthly basis and deferring the differences into an ECAM
balancing account. Exhibit No. I includes details of the ECAM calculation. I have also
provided confidential work papers supporting this exhibit.
How are the Base NPC and Actual NPC calculated?
The monthly Base NPC collected in rates, as set forth in Exhibit No. I line 6, is
calculated by taking the dollar-per-megawatt-hour Base NPC rate multiplied by the
actual [daho retail sales. The Actual Idaho NPC, as set forth in Exhibit No. I line 15, is
calculated by dividing the monthly total Company Actual NPC in the Deferral Period
by the actual monthly system load in the Deferral Period. The total Company Actual
NPC dollar-per-megawatt-hour basis is then multiplied by Idaho actual monthly load
to calculate Actual Idaho NPC.
Please describe how the NPC deferral is calculated.
The deferral is calculated on a monthly basis by subtracting the Base NPC collected in
rates from the Actual Idaho NPC. For the Deferral Period, the NPC differential was
approximately $7.2 million before applying the 90 / l0 percent sharing.
What costs are included in the NPC differential for deferral?
The NPC differential for deferral captures all components of NPC as defined in the
Company's general rate case proceedings and modeled by the Company's production
dispatch model ("GRID"). Specifically, Base NPC and Actual NPC include amounts
booked to the following FERC accounts:
Account 447 - Sales for resale; excluding on-system wholesale sales and other
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revenues that are not modeled in GRID
Account 501 - Fuel, steam generation; excluding fuel handling, start-up fuel
(gas and diesel fuel, residual disposal), and other costs that are
not modeled in GRID
Account 503 - Steam from other sources
Account 547 - Fuel, other generation
Account 555 - Purchased power; excluding the Bonneville Power
Administration ("BPA") residential exchange credit pass-
through if applicable
Account 565 - Transmission of electricity by others
Are adjustments made to the Actual NPC before comparing them to Base NPC?
The Company adjusts Actual NPC to reflect the ratemaking treatment of several items,
including:
. out of period accounting entries booked in the Deferral Period that relate to
operations before implementation of the ECAM on July 1,2009;
. buy-through of economic curtailment by interruptible industrial customers;
o revenue from a contract related to the Leaning Juniper wind resource;
. situs assignment of the generation from Oregon solar resources procured to
satisff Oregon Revised Statute ("ORS") 757.370 solar capacity standard;
. situs assignment of Oregon allocated excess amortization related to a
prepaid wheeling expense;
. situs assignment of certain Utah solar resources;
. coal inventory adjustments to reflect coal costs in the correct period;
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o . legal fees related to fines and citations included in the cost of coal; and,
. adjustments related to liquidated damages that occurred outside the Deferral
Period (all liquidated damage fees per a coal supply agreement are booked
in accordance with generally accepted accounting principles).
Why is the July 1,2009 cutoff used to determine out of period entries?
Since the ECAM took effect, customers'rates have been adjusted to recover essentially
all of the Company's actual net power costs, excluding any differences due to the 90 /
l0 percent sharing band. Consequently, any accounting entries made during the current
Deferral Period that relate to any operating period since the ECAM took effect, should
also be reflected in customer rates, whether they increase or decrease Actual NPC.
Accounting entries related to operating periods before the inception of the ECAM
should not impact the ECAM deferral.
In addition to comparing Actual NPC to Base NPC, what other components are
included in the ECAM?
Six additional components are included in the ECAM calculations: (i) an adjustment
for deferred costs associated with coal mine stripping activities recorded under the
Financial Accounting Standards Board ("FASB") EITF 04-6; (ii) the LCAR
adjustment; (iii) a resource adder to collect the investment in the Lake Side 2 natural
gas generation facility; (iv) a true-up of PTCs; (v) unrecovered Deer Creek mine
investment that has been amortized after the closing of the mine and is not included in
Base NPC; and (vi) a true-up of REC revenues as authorized by the Commission in
Order No. 32196.
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How is the adjustment for accounting pronouncement EITF 04-6 included in the
ECAM?
The calculation of coal stripping costs on Line 17 of Exhibit No. I reflects ldaho's
allocated differences between the coal stripping costs incurred by the Company during
excavation and recorded on the Company's books pursuant to the guidance of the
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs
as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. For the
Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a $0.1 million
decrease to the ECAM deferral balance before the 90 / l0 percent sharing.
Please describe the LCAR adjustment.
The calculation of the LCAR adjustment is a symmetrical adjustment for over- or
under-collection of the energy-related portion of the Company's embedded revenue
requirement for production facilities as specified in Case No. GNR-E-10-03, OrderNo.
32206. The LCAR rate was updated to include the impact of the Tax Reform Act. The
LCAR accounts for variances in Idaho load that cause the Company to collect more or
less of these production-related costs. The LCAR rate of $5.54 per megawatt-hour is
used for the Deferral Period.
How is the LCAR adjustment calculated and what impact does it have on the
Deferral Period?
The LCAR adjustment assumes that the actual production-related costs of the LCAR
are equal to base, Exhibit No. I line 18. The actual production-related costs are then
compared to the LCAR revenue collection in rates, calculated by multiplying the LCAR
rate by the actual ldaho retail sales, Exhibit No. I line 2l . The LCAR adjustment is the
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t difference between the actual production-related costs and the LCAR revenue, line 22
of Exhibit No. l, and is a $1.5 million decrease to the ECAM deferral balance before
the 90 / 10 percent sharing.
Please describe the update to the LCAR rate due to the Tax Reform Act.
The LCAR tracks production-related fixed costs recovered in customers'rates. The Tax
Reform Act lowered the Company's overall pre-tax weighted average cost of capital
from 11.14 percentto 9.66 percent reducing the cost of these production assets and
lowering the LCAR rate from $6.07 to $5.54 per megawatt-hour, as reflected in Exhibit
No. l.
Please explain the sharing ratio between the Company and customers in the
ECAM.
The ECAM includes a symmetrical sharing ratio in which customers either pay or
receive 90 percent of the ECAM deferral balance, and the Company is responsible for
the remaining I 0 percent. Line 24 of Exhibit No. I represents the customers' 90 percent
share of the monthly deferral shown on line 23 of Exhibit No. l. For the Deferral
Period, the customers' share of the deferred balance is approximately $4.9 million. The
remaining balance of $0.5 million associated with the Company's l0 percent share is
not included in the deferral balance as it is not recoverable from customers.
What is the amount of the Lake Side 2 resource adder in the current filing?
Pursuant to the stipulation in Case No. PAC-E-13-04, approved by the Commission in
Order No. 32910, the Company included a resource adder to recover the investment in
the Lake Side 2 generation plant which is not yet included in rate base. The resource
adder amounts to $1.99l\4Wh of the Lake Side 2 generation capped at2,729,500 MWh
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t or $5.4 million for the calendar year. The total Lake Side 2 resource adder for the
Deferral Period was $5.4 million based on2,729,500 MWh of generation, line 27 of
Exhibit No. l.
a. What is the amount of the PTC true-up in the current filing?
A. The PTC Deferral, on line 32 of Exhibit No. l, is calculated by comparing the actual
Idaho-allocated PTCs to the PTC credit customers receive through base rates. The PTC
credit in base rates is calculated by multiplying the approved PTC rate of $l.99ilvlWh
by Idaho retail sales. The difference is a $3.3 million increase to the ECAM deferral.
a. Please explain the Deer Creek amortization expense.
A. The Company closed the Deer Creek Mine in 2015 before having fully recovered its
investment through rates. In Order No. 33304, Case No. PAC-E- l4- 10, the Commission
determined that the unrecovered investment would be amortized and recovered through
the ECAM. The Deferral Period is the last year of Deer Creek amortization expense.
The Idaho allocated Deer Creek amortization expense during calendar ye ar 2018 is $ I .l
million and includes the remaining balance, net of salvage value proceeds (Exhibit No.
1, Line 33).
a. What is the amount of REC revenue adjustment in the current filing?
A. The REC revenue adjustment, on line 38 of Exhibit No. l, is calculated by comparing
the actual Idaho-allocated REC revenue to the REC revenue credit customers receive
through base rates. The REC revenue credit in base rates is calculated by multiplying
the approved REC revenue rate of $0.0944Wh by Idaho retail sales. The difference is
a $0.2 million increase to the ECAM defenal.
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a. What is the total ECAM deferred balance calculated in Exhibit No. 1?
A. The total ECAM deferred balance as of December 31,2018 is approximately $15.0
million, shown on line 39 plus $132,81 I of interest on line 48 of Exhibit No. 1, for a
total deferral of approximately $15.1 million.
a. Does the calculation of the ECAM deferral in this application comply with the
parameters of the Idaho ECAM as approved by the Commission?
A. Yes. Therefore, the Company recommends the Commission approve the ECAM
application for recovery of the $15.1 million prudently incurred ECAM costs.
DIFFERENCES IN NPC
a. On a total-Company basis, what was the difference between Actual NPC and Base
NPC for the Deferral Period?
A. On a total-Company basis, Actual NPC for the Deferral Period were $1,586 million,
exceeding Base NPC for the Deferral Period by approximately $101 million. Table 3
provides a high level summary of the difference between Base NPC and Actual NPC
by category on a total-Company basis.
Table 3
Net Power Cost Reconciliation ($ millions)
Base NPC $ 1,485
Increase/@ecrease) to NPC :
Wholesale Sales Revenue
Purchased Power Eryense
Coal Fuel Expense
Natural Gas Expense
Wheeling and Other Expense
Total Increas e/@e cre as e)
96
90
(33)
(42)
(10)
$l0l
Adjusted Actual NPC $ 1,586
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Please describe the Base NPC the Company used to calculate the NPC component
of the ECAM deferral.
The Base NPC were set in Case No. PAC-E-16-12 and became effective January 1,
2017.Base NPC used the 12 month test period of January 2016 through December
2016 and set total-Company Base NPC at $1,485 million.
Please describe the primary differences between Actual NPC and Base NPC.
From an accounting perspective, and as shown in Table 3, Actual NPC were higher than
Base NPC due to a $96 million reduction in wholesale sales and a $90 million increase
in purchased power expense. The items were partially offset by a$42 million reduction
in natural gas expense, $33 million reduction in coal fuel expense, and a $10 million
reduction in wheeling and other expenses.
Please explain the changes in wholesale sales revenue.
Wholesale sales revenue declined relative to Base NPC due to higher market prices and
a reduction in the wholesale sales volume of market transactions (represented in the
GRID as short-term firm and system balancing sales).
Revenue from market transactions is approximately $90 million lower than
Base NPC due to higher market prices and lower volume of market sales transactions.
The average price of actual market sales transactions was $5.49lMWh, or 23 percent,
higher than the average price in Base NPC. Actual wholesale market volumes were
5,61I GWh, or 43 percent, lower than the Base NPC. In addition, an expired contract
accounted for $9 million of the decrease in wholesale sales revenue.
Please explain the changes in purchased power expense.
Purchased power expense increased due to a $93 million increase (44 percent) in
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qualifying facility ("QF") transactions, partially offset by the expiration of a long-term
purchase power contract. Actual QF transaction volumes were 1,563 GWh (44 percent)
higher than Base NPC. The expiration of the Hermiston purchase power agreement
("PPA") resulted in lower purchased power costs of $31 .3 million.
Additionally, expenses from market transactions (represented in GRID as short-
term firm and system balancing purchases) increased by $80.1 million compared to
Base NPC. Actual market purchases were 1,252 GWh (17 percent) higher than Base
NPC and the average price of actual market purchases transactions was $18.81/l\4wh
(75 percent) higher than Base NPC.
Please explain the changes in wheeling expenses.
Actual long-term wheeling expenses decreased by approximately $7.1 million when
compared to Base NPC due to expired wheeling contracts. This was partially offset by
an increase of $2.1 million of short-term wheeling expenses.
Please explain the changes in coal fuel expense.
Coal fuel expense decreased because coal generation volume decreased 2,615 GWh (7
percent) compared to Base NPC. The average cost of coal generation increased from
$19.96lMWh in Base NPC to $20.49lMWh in the Deferral Period, but the lower
generation volume results in an overall decrease of approximately $33 million in coal
fuel expense.
Please explain the changes in natural gas fuel expense.
The total natural gas fuel expense in Actual NPC decreased by approximately $42
million compared to Base NPC mainly due to a decrease in natural gas volume of 1,796
GWh (15 percent) below Base NPC during the Deferral Period. The average cost of
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o natural gas generation slightly decreased from $23.0644Wh in Base NPC to
$22.97/MWh in the Deferral Period.
a. Please provide an overview of the Enbridge natural gas pipeline rupture and its
impact on Company operations and costs.
A. On October 9, 2018, the Enbridge natural gas pipeline that transports natural gas
produced in the Western Canadian Sedimentary Basin to consumers in British
Columbia ("B.C.") and, through interconnecting pipelines, the Northwestern United
States ("U.S."), experienced a massive rupture. The pipeline was brought back into
service in late October 2018; however, at a reduced capacity until testing of the many
segments of the pipeline can be completed. Currently the pipeline is operating at
approximately 85 percent of capacity. Original estimates expected the pipeline to be
back in full service sometime late spring 2019; however, revised forecasts are now
calling for full service to be established sometime in September 2019. Spot natural gas
prices at the Sumas B.C.-U.S. border trading point have traded as high as $159 per
million British thermal units ($/IVIMBIu) on days of intense demand.
The pipeline rupture and reduced operating capacity has impacted electricity
prices primarily at the Mid-Columbia power market hub, but electricity prices are
increasing at other trading points where PacifiCorp transacts. Because of PacifiCorp's
geographical and resource diversity, the impact to the Company was not as severe as
other utilities and power producers that have a high reliance on Sumas natural gas
supplies. PacifiCorp has one natural gas-fired generator-the Chehalis plant-that is
sourced from the Sumas natural gas hub. Due to the pipeline rupture, at times the
availability of natural gas flowing to the Sumas gas hub has been limited which can
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cause the price to run the Chehalis plant to be uneconomical or at times even unable to
run. As a result, overall the natural gas constraint at Sumas has contributed to higher
prices at Mid-Columbia, putting upward pressure on net power costs.
What is the current status of natural gas flow at the Sumas natural gas hub?
As of the date of this filing, natural gas flows to the Sumas gas hub continue to be
restricted as pipeline repair and testing continues. Westcoast Pipeline, which operates
the Enbridge pipeline, has indicated that flows to Sumas will be restricted through the
summer of 2019. These restrictions will cause increased price volatility and higher
power prices this summer at Mid-Columbia.
IMPACT OF PARTICIPATING IN THE EIM
Are the actual benefits from participating in the EIM with CAISO included in the
ECAM deferral?
Yes. Participation in the EIM provides benefits to customers in the form of reduced
Actual NPC. The EIM benefits are embedded in Actual NPC through lower fuel and
purchased power costs. The Company is able to calculate the margin rcalized on its
EIM imports and exports, the inter-regional benefit. The Company's EIM inter-regional
benefit for the deferral period was approximately $57 million.
How does the Company calculate its actual EIM benefits?
Using actual information from the EIM, including five- and l5-minute pricing, the
Company identifies the incremental resource that could have facilitated the transfer to
an adjacent EIM area or the CAISO in each five-minute interval. The benefit is then
calculated as the difference between the revenue received less the expense of generation
assumed to supply the transfer. ln the event of an import, the benefit is equal to the cost
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of the import minus the avoided expense of the generation that would have otherwise
been dispatched.
O. Please summarize your testimony.
A. The ECAM deferral of $15.1 million, including interest, for the l2-month January l,
2018 through December 31,2018 period, was accurately calculated in compliance with
previous Commission orders. Exhibit No. I was updated for a new LCAR rate, the
depreciation regulatory asset, and a $0.957 per megawatt hour credit per Order No.
3407 6 in Case No. GNR-U- I 8-0 I , 20 I 8 Tax Act savings, was applied to partially offset
the ECAM deferred balances. Therefore, I respectfully request that the Commission
approve this application as filed with rates effective June 1,2019.
a. Does this conclude your direct testimony?
A. Yes.
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