20170331Wilding Direct and Exhibits.pdf

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BEFORE TIIB IDAHO PUBLIC UTILITIES COMIVISSION
IN TIIE MATTER OF THE APPLICATION
OF ROCKY MOT]NTAIN POWER
REQTTESTING APPROVAL OF TIIE $7.5
MILLION ITET POWER COST DEFERRAL
AI\ID AUTHORITY TO DECREASE RATES
BY $6.9 MILLION
ROCKY MOT]NTAIN POWER
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CASE NO. PAC.E-I7-02
DIRECT TESTIMOI\W OT'
MICHAEL G. WILDING
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CASE NO. PAC.E.II-u2
March 2017
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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 Manager, Net Power Costs.
Qualifications
A.
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. Prior to joining the Company, I was employed
as an internal auditor for Intermountain Healthcare and an auditor for the Utah State
Tax Commission. I have been employed by the Company since February 2014.
Purpose of Testimony
a 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 l3-month period from
December 1,2015 through December 31,2016 ("Deferral Period"). More specifically,
my testimony provides the following:
o I summary of the ECAM calculation, including changes made to comply with
recent Commission orders;
. Details supporting the addition of $7.5 million (*2016 Deferral") to the deferral
balance, bringing the total balance to approximately $12.7 million as of December
31,2016;
. Additional details ofthe ECAM calculation and a description of the Company's net
A.
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o 1 power costs ('NPC"); and
2 . Discussion about the Company's participation in the energy imbalance market
3 ("EIM") with Califomia Independent System Operator ("CAISO") and the benefits
4 passed through to customers.
5 Q. Are additional witnesses presenting testimony in this case?
6 A. Yes. Mr. Robert M. Meredith, Manager, Pricing & Cost of Service, is sponsoring
7 testimony supporting the Company's proposed ECAM collection rates in Electric
8 Service Schedule No. 94, Energy Cost Adjustment ("Schedule 94"). The Company
9 proposes to modiff Schedule 94 to be effective June 1, 2017, to collect $7.5 million
10 duringtheperiodofJune 1,2017 throughMay3l,2018.Thisiscomparedtothecurrent
11 collection rate of approximately $14.5 million. Additionally, Mr. Ted Weston is
12 sponsoring testimony on an alternative rate proposal to offset an on-going depreciation
13 regulatory asset deferral in order to mitigate a future increase.
14 Summary of the ECAM Deferral Calculation
15 a. Please briefly describe the Company's ECAM authorized by the Commission.
16 A. In general, the ECAM tracks deviations between actual NPC and NPC in base rates and
17 defers 90 percent of the difference for later recovery.r Other items, which I describe in
l8 detail later in my testimony, are also tracked in the ECAM to true-up the amount in
19 base rates to actuals include: load control or demand side management (DSM) costs
20 (December 2015 only), a resource adder for the Lake Side 2 gas generation plant,
2l renewable energy production tax credits ("PTCs"), Idaho-allocated Deer Creek Mine
22 amortization expense, md revenues from the sale of renewable energy credits
I Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-I5-09.
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("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 rate, 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 ECAM defenal period is December 1,2015 to December 31, 2016. All
subsequent ECAM filings will be based on calendar year deferrals.3
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 rute, which
becomes effective June 1.
How is the20l6 ECAM deferral calculation presented in your testimony?
The calculation of the 2016 ECAM deferral is contained in Exhibit No. l, which I
discuss later in my testimony. A sunmary of the major components is contained in
Thble l below.
What changes to the ECAM calculation have been implemented in this liling to
comply with Commission orders from previous cases?
In Case No. PAC-E-15-09 the Commission approved changes to increase base rates
effective January 1,2016. The changes to base rates included updated NPC, which no
longer includes Deer Creek depreciation expense, and a reduction of the revenue credit
from the sale of RECs. Additionally, PTCs for wind generation are tracked in the
ECAM beginning January 1,2016.
In Case No. PAC-E-15-09 the Commission also approved changes to the ECAM
structure. First, the ECAM calculation directly compares NPC collected through base
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2 Order No. 33440 in Case No. PAC-E-15-09 pages 5 - 6
3 Order No. 33440 in Case No. PAC-E-15-09 page 6.
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I 1 rates to actual NPC eliminating the need for a back-cast adjustment to account for the
over/under-collection of NPC. Beginning January 1,2016, the sale of sulfi.r dioxide
("SOz") emission allowances and load control or demand side management ("DSM")
costs are no longer tracked in the ECAM. In the 2016 Deferral, December 2015 was
the last month DSM costs and SOz sales were included in the ECAM, there were no
sales of SOz emission allowances. Revenues from the sale of RECs, and other
components like the LCAR, the Lake Side 2 resource adder, and Deer Creek Mine
anortization expense all continue to be included in the ECAM. The annual filing date
for ECAM deferrals changed from February I to April 1 and the deferral period was
transitioned to a calendar year reporting period.
Will additional changes be made to the ECAM in the Company's 2018 filing?
Yes. In Case No. PAC-E-16-12the Commission approved new base rates to be tracked
in the ECAM beginning January 1,2017.
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Please explain the calculation of the ECAM balance for the Deferral Period.
Detailed calculations are provided in Exhibit No. 1, attached to my testimony. Table I
below summarizes the various components of the 2016 Deferral.
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Table 1
NPC Differential for Deferral
EITF 04-6 Ad.justment
LCAR
DSM Costs
Total Deferral Before Sharine
Sharing Band
Customer Responsibility
Lake Side 2 Resource Adder
Production Tiax Credits
Deer Creek Amortization Expense
REC Deferral
Interest
Total Comnany Recoverv for NPC
Idaho Customers
$ (1,051,065)
49,006
231,490
(71.884)
s (842.4s4\
90 percent
$ (7s8.208)
5,860,701
496,611
1,379,929
349,709
198 103
$ 7.526.845
Table 1 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,
LCAR, and DSM costs. The next section calculates the 90 percent customers' share of
the above items and adds the following items for which customers are refunded or
surcharged 100 percent: the Lake Side 2 resource adder, PTCs, Deer Creek mine
amortization expense, and REC revenues. The total of these items represent the 2016
Deferral. The 2016 Deferral of $7.5 million is a result of the $0.8 million refund to
customers for their share of the NPC differential, which includes adjustments for EITF
04-6, LCAR, and DSM costs, $5.9 million Lake Side 2 Resource Adder, $0.5 million
PTCs, $1.4 million Deer Creek amortization expense, $0.3 million REC revenue
differential, and $0.2 million interest accrued on the 2016 Defenal.
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Based on your calculations, what is the balance expected to be in the ECAM
deferral account as ofJune lr20l7?
The projected balance in the ECAM deferral account as of June 1,2017 is $7.5 million.
Table 2 summarizes the deferral account activity starting with the $23.8 million balance
approved in Case No. PAC-E-16-05. The balance is adjusted for collections and interest
accrued during the Deferral Period. The estimated ECAM deferral account balance of
$7.5 million due for collection from all Idaho customers as of June I,2017, consists of
the estimated prior period balance, $7.5 million from the 2016 Deferral Period, and
interest accrued.
Table 2
Balancing Account Activity
Idaho Customers
Balancing Account Activity
Prior Deferral
ECAM Revenue Collection - Schedule 94
Interest
Activitv Throueh December 31. 2016
Dec 15 - Dec 16 ECAM Deferral
December 31. 2016 Balance For Collection
Schedule 94 Collection - Jan -May 2017
Interest
Expected Balance as ofJune 1,2017
$23,812,074
(18,659,710)
3,658
$ 5.156.021
7.526.845
$ 12.682.866
$ (5,168,288)
10,283
$ 7.524.861
What is the proposed collection amount from customers under Schedule 94
beginning June 1, 2017?
The Company has designed the Schedule 94 rates to collect $7.5 million over a 12-
month period from all Idaho customers. The testimony of Company witness Mr.
Meredith explains the rate design and Exhibit No. 3 summarizes the rate impact to each
customer class associated with this ECAM rate change.
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o I Q. Have the separate balancing accounts forMonsanto andAgrium been eliminated?
2 A. Yes, per Commission Order No. 32910 in Case No. PAC-E-I3-04 the ECAM deferral
3 is calculated on a total Idaho basis. The amortization of past ECAM balances for both
4 Monsanto and Agrium ended March 2016, and the separate balancing accounts have
5 been eliminated.
6 Description of the ECAM Calculations
7 Q. Please describe the ECAM calculations in your Exhibit No. 1.
8 A. The ECAM deferral is calculated by comparing Idaho-allocated Actual NPC to the
9 NPC collected in rates on a monthly basis and deferring the differences into an ECAM
10 balancing account. Exhibit No. 1 includes details of the ECAM calculation, I've also
I I provided my confidential work papers supporting this exhibit.
12 a. How are the Base NPC and Actual NPC calculated?
13 A. The monthly Base NPC collected in rates, as set forth in Exhibit No. 1 line 6, is
14 calculated by taking the dollar-per-megawatt-hour Base NPC rate multiplied by the
15 actual Idaho retail sales. The Actual Idaho NPC, as set forth in Exhibit No. I line 15, is
16 calculated by dividing the monthly total Company Actual NPC in the Deferral Period
17 by the actual monthly system load in the Deferral Period. The total Company Actual
18 NPC dollar-per-megawatt-hour basis is then multiplied by Idaho actual monthly load
19 to calculate Actual ID NPC.
20 a. Please describe how the NPC deferral is calculated.
2l A. The deferral is calculated on a monthly basis by subtracting the Base NPC collected in
22 rates from the Actual Idaho NPC. For the thirteen-month period ending December
23 2016, the NPC differential was approximately $1.1 million credit to customers before
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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 GRID. Specifically, Base
NPC and Actual NPC include amounts booked to the following Federal Energy
Regulatory Commission ("FERC") accounts:
Account 447 - Sales for resale; excluding on-system wholesale sales and other
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 prior to comparing to Base NPC?
Yes. The Actual NPC recorded on the Company's books are adjusted to reflect the
ratemaking treatment of several items, including:
. out ofperiod accounting entries;
. buy-through of economic curtailment by intem-rptible industrial customers;
. situs assignment of the generation from Oregon solar resources procured to
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satisff ORS 757.370 solar capacity standard;
. legal fees included in the cost of coal related to fines and citations;
. the true-up of coal inventories;
. revenue imputation of the sales contract with the Sacramento Municipal Utility
District; and
. revenue associated with the Company's Leaning Juniper facility due to a
contract unique to that wind project.
What is an out of period accounting entry?
Out of period accounting entries are items booked during the Deferral Period that
pertain to an operating period prior to the inception of the ECAM on July 1,2009.
However, there were no out of period accounting entries booked in the Deferral Period.
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 /
10 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 prior to the inception of the ECAM
should not impact the ECAM deferral.
In addition to the comparison ofActual NPC to Base NPC, what other components
are included in the ECAM?
There are seven additional components included in the ECAM calculations: (i) an
adjustment for deferred costs associated with coal mine stripping activities recorded
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t I under the Financial Accounting Standards Board ("FASB") EITF 04-6, (ii) the LCAR
adjustment, (iii) a true-up of DSM costs, (iv) a resource adder to collect the investment
in the Lake Side 2 nat:tnal gas generation facility, (v) a true-up of PTCs, (vi)
unrecovered Deer Creek Mine investment that has been amortized after the closing of
the mine and is not included in Base NPC, (vii) and a true-up of REC revenues as
authorized by the Commission in Order No. 32196.
Are SOu sales revenues included in the ECAM?
Under Order No. 33440 in Case No. PAC-E-15-09, SOz sales revenues are no longer
tracked in the ECAM, effective January 1,2016. There were no SOz sales in December
2015.
How is the adjustment for accounting pronouncement EITF 04-6 included in the
ECAM?
Line 17 of Exhibit No. 1 reflects Idaho'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, andthe amortization of the coal stripping costs as approved by the Commission.a
For the Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a
$49,006 increase to the NPC deferral balance before the 90 / 10 percent sharing.
Please describe the LCAR adjustment.
The calculation of the LCAR adjustrnent 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, Order No.
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4 Cur. No. PAC-E-09-08, Order No. 30987
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32206. 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 was updated in
Order No. 33440 to reflect base loads (at sales) corresponding to the period used to set
base rates. The LCAR rate of $6.07 per megawatt-hour is used for December 2015. The
updated LCAR rate of $5.68 per megawatt-hour was effective January l, 201 6.
How is the LCAR adjustment calculated and what impact does it have on the 2016
Deferral?
The LCAR adjustment assumes that the actual production-related costs of the LCAR
are equal to base, Exhibit No. 1 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 Idaho retail sales, Exhibit No. I line 21. The LCAR adjustment is the
difference between the actual production-related costs and the LCAR revenue, line 22
of Exhibit No. 1, and is a $0.2 million increase to the NPC deferral balance before the
90 I l0 percent sharing.
How is the DSM cost adjustment calculated in the ECAM?
The DSM cost adjustment is calculated by subtracting the actual Idaho-allocated costs
for DSM load control programs from the DSM revenue collected through base rates.
The DSM revenue collected through base rates is calculated by multiplying the
approved DSM costs rate established in a general rate case by actual Idaho retail sales.
The difference, shown on line 27 of Exhibit No. 1, is included as a $71,884 reduction
to the NPC defenal balance before the 90 / 10 percent sharing.
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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 l0 percent. Line29 of ExhibitNo. 1 represents the customers'90 percent
share of the monthly deferral shown on line 28 of Exhibit No. 1. For the Deferral
Period, the customers' share of the deferred balance is approximately a $0.8 million
refund. The remaining refund of $84,245 associated with the Company's l0 percent
share is not included in the deferral balance as it is not refundable to 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 and 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 $1.99lMWh of the Lake Side 2 generation capped at2,729,500 MWh
for the calendar year. The total Lake Side 2 resource adder for December 2015 was
$0.4 million based on215,576 MWh of generation. The total adder for the prior year
deferral was $4.1 million based on2,06I,278 MWh of generation for the months of
January through November 2015. The total Lake Side 2 resource adder for January
through December 2016 was $6.0 million based on2,995,420 MWh of generation, but
is capped at2,729,500 MWh or $5.4 million for the calendar year. The total Lake Side
2 resource adder for the Deferral Period is $5.9 million, Exhibit No. I line 32.
What is the amount of PTC true-up in the current filing?
The PTC Deferral is calculated by subtracting the actual Idaho-allocated PTCs from
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the PTC credit customers receive through base rates. The PTC credit in base rates is
calculated by multiplying the approved PTC rate by Idaho retail sales. The difference,
shown on line 37 of Exhibit No. 1, is included as a $0.5 million increase to the 2016
Deferral balance.
Please explain the Deer Creek amortization expense.
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 -14-10, the Commission
approved the Company's request for a deferred Accounting Order and to establish a
regulatory asset for the Deer Creek Mine unrecovered investment. Additionally, it was
determined that the unrecovered investment would be amortized over a five year period
and recovered through the ECAM.
What is the amount of the Deer Creek amortization expense in the current filing?
The Deer Creek amortization expense included in the ECAM is a $1.4 million increase
to the deferral balance (Exhibit No. I , Line 3 8). Under the stipulation approved in Order
No. 33440 in Case No. PAC-E-15-09, the Deer Creek amortization expense for
December 2015 was calculated by subtracting the Deer Creek depreciation collected
through base rates from the actual Idaho allocated Deer Creek amortization expense.
Full recovery of the Idaho-allocated Deer Creek amortization expense for January
through December 2016 is included in the ECAM since the Deer Creek depreciation
expense is no longer included in base rates.
What is the amount of REC revenue adjustment in the current filing?
The REC revenue adjustment is calculated by subtracting the actual Idaho-allocated
REC revenue from the REC revenue credit customers receive through base rates. The
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1 REC revenue credit in base rates is calculated by multiplying the approved REC
2 revenue rate by Idaho retail sales. The difference, shown on line 43 of Exhibit No. l, is
3 included as a $0.3 million increase to the deferral balance.
4 a. What is the total ECAM deferred balance calculated in Exhibit No. 1?
5 A. The total ECAM deferred balance as of December 31,2016 is $12.7 million, shown on
6 line 54 of ExhibitNo. l.
7 0. Does the calculation of the deferred NPC adjustment in this application comply
8 with the parameters of the Idaho ECAM as approved by the Commission?
9 A. Yes. Therefore, the Company recommends the Commission approve the ECAM
l0 application for recovery of the $7.5 million prudently incurred ECAM deferral.
l1 Summary of the NPC Differences
12 a. Please explain the difference between adjusted actual NPC ("Actual NPC") and
13 the NPC in base rates ("Base NPC").
14 A. The ECAM period is transitioning to a calendar year basis and for this ECAM, there
l5 are thirteen months in the deferral period. Actual NPC for the one month of December
16 2015 are approximately $124.7 million total Company and Base NPC for December
17 2015 are $126.3 million set in the 201I Rate Case. Actual NPC for the twelve month
18 period of January through December 2016 are approximately $1,463 million. Base
19 NPC for January through December 2016 are $1,529 million and was set in Case No.
20 PAC-E-15-09. Total Company Actual NPC for the thirteen month Deferral Period are
2l $1,587 million compared to total company Base NPC of $1,655 million.
22 a. When will Base NPC be updated in rates?
23 A. Base rates decreased $3.2 million effective January 1,2017, under Order No. 33668 in
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CaseNo. PAC-E-I6-12. BaseNPC decreasedto $1,485 milliontotal Company or $91.6
million Idaho allocated basis. The Company has agreed to not file a general rate case
with rates effective prior to January 1 , 20 I 8.
Has the Company provided quarterly ECAM reports as directed by the
Commission in Case No. PAC-E-12-03?
Yes. The Company has provided preliminary ECAM calculations on a quarterly basis
to enable ongoing analysis of the ECAM. The last quarterly report, provided for the
period December 2015 through September 2016, reported an ECAM deferral of $0.3
million after sharing, the Lake Side 2 resource adder of $5.2 million, a PTC true-up of
$0.4 million, Deer Creek arnortization expense of $l million, and a REC true-up of
$0.4 million.
What are the major drivers that result in a difference between Actual NPC and
Base NPC for December 2015?
On a total Company basis, Base NPC was $0.8 million higher than Actual NPC for the
period of December 2015. However, after adjusting for load and the Base NPC
collected in rates, the Idaho NPC differential is$89,222, Exhibit 1 line 16. Actual NPC
were lower than Base NPC for the period of December 2015 due to lower natural gas
generation costs and purchased power expenses which was partially offset by lower
wholesale sales revenue and higher coal generation costs.
What are the major drivers that result in a difference between Actual NPC and
Base NPC for the period of January through December 2016?
The $66 million difference on a total company basis between Base NPC and Actual
NPC for the period of January through December 2016 is summarized in Table 3 below
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Table 3
Ileferral Period NtrC Recorrciliation
Actual NPC were lower than Base NPC due to a $214 million reduction in
purchased power expense, $42 million reduction in coal fuel expense, $61 million
reduction in natural gas expense,$24 million reduction in wheeling and other expenses
and a $15 million settlement adjustment from PAC-E-I5-09, partially offset by $290
million decrease in wholesale sales revenue.
Please explain the changes in wholesale sales revenue.
The decline in wholesale sales revenue was driven by a reduction in wholesale sales
volume of market transactions (represented in the Company's production dispatch
model ("GR[D") as short-term firm and system balancing sales) and lower market
prices.
Revenue from market transactions is approximately $267 million lower than
Base NPC due to lower volume of market sales transactions and lower market prices.
Actual wholesale market volumes were 8,531 GWh, or 59 percent, lower than the Base
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I ncrease/(Derreasel to NPC:
Wholesale Sales
Purchased Power
Coal Generation
Gas Generation
Wheeling and Other
Tctd lncraa*el{Decrea*}
BasE NPC PAC-E-15-O9 Settlernent Adiustnent
Total Company l{FC Oifferelre
$1F2e
($551
9r,463
lO Base NPC PAC-E-15,99
Adjusted Actual NFC ?O16
EBA Deferral Period
Jan - D€c 2016
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o I NPC. The average price of actual market sales transactions was $3.90A4Wh,or 14
percent, lower than the average price in Base NPC.
Please explain the changes in purchased power expense.
The reduction in purchased power expense was largely due to a decrease in both market
purchases and long-term purchase power contracts. Expenses from market transactions
(represented in GRID as short-term firm and system balancing purchases) accounted
for $166 million of the reduction of purchased power costs. Actual market purchases
were 3,998 GWh, or 46 percent, lower than Base NPC and the average price of actual
market purchase transactions was $ 11 .17lMWh , or 39 percent, lower than Base NPC.
The expiration of the Hermiston power purchase agreement ("PPA") and the
Georgia-Pacific Camas contract resulted in lower purchased power costs of $53.8
million, and lower contract volumes with Deseret accounted for $5 million of the
reduction. The decrease was partially offset by $27) million from 14 new large
qualifuing facility ("QF") contracts that were not included in Base NPC.
Please explain the changes in natural gas fuel expense.
The total natural gas fuel expense in Actual NPC decreased by $61 million compared
to Base NPC and was driven by lower volumes. Natural gas volume decreased 1,434
GWh (13 percent) and the average cost of natural gas generation remained relatively
flat from $28.09/MWh in Base NPC to $26.0044Wh, or seven percent.
Please explain the changes in coal fuel expense.
Coal fuel expense was $42 million lower than Base NPC, driven by decreased
generation and partially offset by an increase in the average cost of coal generation.
Coal generation volume decreased by 4,536 GWh or l1 percent. The average cost of
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I coal generation increased from $19.30/\{Wh in Base NPC to $20.54lMWh in the
Deferral Period January through December 2016 driven by increased coal costs at the
Jim Bridger plant.
Jim Bridger Coal Costs
a.Please explain the changes in the coal fuel expense at Jim Bridger compared to the
Deferral Period.
The total coal fuel expense at the Jim Bridger plant was approximately $4.0 million
higher than Base NPC, however generation was 1,234 GWh lower. The average cost of
generation at Jim Bridger increased $4.37ArIWh , or 17 percent, compared to Base NPC.
The main driver in the increase of the average cost of coal generation at Jim Bridger is
the increase in coal costs which are $35.0 million higher than the coal costs included
in Base NPC. Third party coal costs increased by $1.44 per ton, or $2.3 million, and
Bridger Coal Company ("BCC") mine costs increased by $11.05 per ton, or $32.7
million.
Please explain the cost increase in third party delivered coal costs.
The $2.3 million increase is primarily due to higher pricing under the new Black Butte
mine contract in the Deferral Period, replacing 333 thousand tons of lower-priced coal
carried over from the prior Black Butte coal contract that was delivered in the first
quarter of 2015 in the Base NPC period. The Company entered into the new Black
Butte mine contract after issuing a Request for Proposals in June 2014 to determine the
least cost fuel replacement option.
Please describe the change in BCC coal costs relative to the deferral period.
BCC costs increased by approximately $32.7 million due to the following reasons: 1)
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t 1 lower British thermal unit ("Btu") content of coal, $3.3 million; 2) spreading costs over
the reduced volume of tons produced, $9.3 million; 3) abandonment cost of the Joy
Longwall, $12.5 million; and 4) costs of the Joy Longwall recovery efforts, $7.6
million.
Please explain why coal with a lower Btu content increases coal costs.
The Btu content of coal is positively correlated to the amount of energy produced from
burning the coal; the higher the Btu content, the more energy the coal produces when
burned. Because the actual Btu content of BCC coal was lower than the Btu content of
BCC coal in Base NPC, it was necessary to burn higher quantities of BCC coal than
would have been burned had the actual Btu content equaled the Btu content in Base
NPC.
Please explain how the decreased generation at Jim Bridger impacted BCC's
costs.
Generation decreased at the Jim Bridger plant by 13 percent compared to Base NPC
resulting in less coal being burned. As seen in Table 4 below, BCC deliveries decreased
from 3.7 million tons in the base period to 2.8 million tons in 2016, a reduction of 23
percent, and BCC production decreased from 3.3 million tons in the base period to 2.4
million tons in 2016, a reduction of 26 percent. Lower production levels at BCC
increases the BCC cost per ton as costs are spread over fewer tons of coal. Notably, if
the Btu content of BCC coal would have been higher, less BCC coal would have been
needed to produce the actual Jim Bridger generation.
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Table 4
Please describe the costs associated with the Joy Longwall.
During mining operations at the end of December 2015, a section of panels in the Joy
Longwall became stuck in soft claystone material due to difficult geological conditions.
Significant efforts were made by BCC to return the Joy Longwall to operations in 2016;
however, due to unsafe working conditions the Joy Longwall was ultimately
abandoned. Included in the 2016 ECAM is the Company's portion of the Joy Longwall
recovery and abandonment costs. The recovery costs are the expenses incurred in the
effort to return the Joy Longwall to operations. The abandonment costs include the net
book value (cost of the asset less accumulated depreciation) of the lost asset, longwall
related construction work in process ("CWIP"), materials and supply ("M&S")
inventory items, and deferred longwall costs.
Is this the longwall that the Company sold to BCC at the time of the Deer Creek
Mine closure?
Yes. In an arm's length transaction, the Company sold the Joy Longwall to BCC in
September 2015 for the appraised value. The sale of the Joy Longwall reduced the Deer
Creek amortization expense, which is included in the 2016 ECAM.
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Tons - PacifiCorp Partion
Bridg er Plant Deliveries Bridser Mine Production
\-ariance
2016
A ctuals
ID Base NPC
(1.15 - 12,'15)Vadance
:016
Actuals
ID BaseNPC
{li l5 - 12,'i5)
nillions
4.4 (0.e)5.3
Third Partl' Sources
er Ptant Total
1.6
3.7
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(0.8)
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er Coal
Surface Mine
Underpround N,Iine
16
o a. What were the geological conditions that led to the Joy Longwall becoming stuck?
A. Exhibit No. 2 is a depiction (not to scale) of the mining conditions of the longwall
panel, or section of the mine, where the Joy Longwall was stopped by adverse
geological conditions. In Exhibit No. 2 the green line is the top of the coal seam and
the pink line is the bottom. Underneath the coal seam is alayer of hard sandstone which
is the mine floor. This sandstone layer, or mine floor, varies in depth of approximately
one to three feet atany given spot in the longwall panel, and underneath the mine floor
is soft claystone material. During operation of the Joy Longwall, the coal seam thinned
and undulations, or structural rolls, in the floor became more pronounced and frequent.
The Joy Longwall crew attempted to navigate through this area and the soft claystone
material under the mine floor became exposed. This is shown in Exhibit No. 2 as the
dashed portion of the pink line.
a. What actions were taken to climb above the claystone material and place the Joy
Longwall back on the mine floor (i.e. the hard sandstone layer)?
A. The operators of the Joy Longwall attempted to climb onto the hard sandstone layer by
changing the cutting profile of the Joy Longwall. However, the shearer (the part of the
longwall that cuts into the coal seam) was unable to operate because it was colliding
with other parts of the Joy Longwall. The lack of clearance limited the longwall crew's
ability to reestablish a hard, competent floor.
a. Did other issues complicate Joy Longwall mining efforts?
A. Yes. Other issues including mechanical downtime on the shearer equipment and
underground conveying system, extreme weather conditions freezing surface coal
transfer facilities, reduced availability of experienced workforce, poor quality mine
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floor, and deteriorating mine roof conditions. Collectively, these issues impeded the
Joy Longwall's ability to climb out of the claystone material.
Please describe efforts to advance the Joy Longwall and resume coal production
activities.
Effiorts to climb out of the soft claystone material and reestablish competent roof
conditions included pumping foam, tech seal and grout in the area above the Joy
Longwall, installing supports beneath the Joy Longwall, freezing the soft claystone
material, and injecting bonding agents into floor and roof.
Were the efforts to stabilize deteriorating section conditions and advance the
longwall system successful?
No. None of the efforts described above were able to successfully provide the overall
floor stability required to advance the Joy Longwall. Ultimately, working conditions
became unsafe and a decision to terminate Joy Longwall recovery efforts was made in
early October 2016, with the abandonment costs booked in September 2016.
Why were such efforts made to advance the Joy Longwall and resume production
activities?
The Joy Longwall was a valuable asset and the Company felt it was prudent to give its
best efforts to return the Joy Longwall to production. The mining conditions
encountered in the front part of the longwall panel were encouraging, resulting in
favorable productivity rates and coal quality, and the longwall panel had approximately
400,000 tons remaining to be mined. Aside from the monetary value, the Joy Longwall
provided operational benefits because it has a lower minimum operating height than
the DBT Longwall. This operating flexibility enabled the Joy Longwall to extract a
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I 1 higher quality product in areas with thinning coal seams relative to the DBT Longwall.
Impact of Participating in the EIM
a Are the actual benefits from participating in the EIM with CAISO included in the
EBA deferral?
Yes. Participation in the EIM provides benefits to customers in the form of reduced
Actual NPC. Financially binding EIM operation went live November 1,2014, and all
net benefits arising from EIM operation from December 1, 2015 to December 31,2016,
are included in the 2016 Deferral.
Has the Company quantified the benefits realized during 2016 from participating
in the EIM?
Yes, the Company has calculated the EIM inter-regional benefit, i.e. the margin realized
on EIM imports and exports. The Company's EIM inter-regional benefit for the month
December 2015 was approximately $1.3 million. The Company's EIM inter-regional
benefit for the 2016 calendar year was approximately $19.5 million.
How does the Company calculate its actual EIM benefits?
Using actual information from the EIM, including five- and fifteen-minute pricing, the
Company identifies the incremental resource that could have facilitated the transfer to
an adjacent EIM area or the CAISO in each hve-minute interval. The benefit is then
calculated as the difference between the revenue received less the expense of generation
assumed to supply the tansfer. In the event of an import, the benefit is equal to the cost
of the import minus the avoided expense of the generation that would have otherwise
been dispatched.
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What are the estimated 2016 EIM benefits as reported by CAISO?
CAISO publishes quarterly EIM Benefit Reports ("CAISO Benefit Reports")
estimating the benefits realized through EIM operation for each entity that participates
in the EIM. The CAISO Benefit Reports estimated EIM benefits atfibutable to
PacifiCorp of approximately $45.5 million on a total-company basis for calendar year
2016.In comparison, the CAISO estimated benefits for the 2015 calendar year were
approximately $26.2 million on a total-company basis. The benefits estimated for
PacifiCorp in the CAISO Reports include the benefits of EIM operation due to more
effrcient dispatch (both inter- and intra-regional), reduced renewable energy
curtailment, and reduced fl exibility reserves.
What is the difference between the EIM benefits estimated by CAISO and the
inter-regional EIM benefits calculated by the Company?
The EIM benefits are embedded in the Actual NPC through lower fuel and purchased
power costs. However, the Company is able to calculate the margin realizedon its EIM
imports and exports, the inter-regional benefit. In its quarterly EIM Benefit Report,
CAISO estimates all the benefits of participating in the EIM, including intra-regional
dispatch savings (optimizing the resources in PacifiCorp's two BAAs), inter-regional
dispatch savings (transacting with other EIM participants), reduced renewable energy
curtailment, and flexibility reserve savings (reduced reserves due to diversity across
the EIM footprint).
The CAISO calculation utilizes a counterfactual scenario that is built to mimic
the more manual dispatch process PacifiCorp utilized in actual operations prior to
participation in the EIM. Based on the subjectivity of the counterfactual scenario, the
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EIM benefits reports by CAISO are presented as an estimate.
a. Does this conclude your direct testimony?
A. Yes.
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Wilding, Di-25
Rocky Mountain Power
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Case No. PAC-E-17-02
ExhibitNo. 1
Witness: Michael G. Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Michael G. Wilding
March2017
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Roct<y Mountain Power
Exhibit No. 1 Page 1 of 1
Case No. PAC-E-17-02
Witness: Michael G. Wilding
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ExhibitNo.2
Witness: Michael G. Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Michael G. Wilding
March2017
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Rocky Mountain Power
Exhibit No. 2 Page 1 ot 1
Case No. PAC-E-17-02
\Mtness: Michael G. Wilding
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Idaho Enerry Cost Adjustment Mechanism
December 1, 2015 - December 3lr2016
Exhibit No. 2
Conditions at the Time of the Joy Longwall Abandonment
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