20160201Wilding Direct and Exhibit 1.pdf

BEFORE THE IDAIIO PUBLIC UTILITIES COM]VtrSSION
rN Trm MATTER OF TrrE APPLTCATTON ) CASE NO. PAC-E-16-05
oF ROCKY MOUNTAIN POWER )
REQIIESTTNG APPROVAL OF TIIE $16.7 ) DTRECT TESTIMON"Y OF
MILLION NET POWER COST DEFERRAL ) MICHAEL WILDING
AI\ID AUTHORITY TO DECREASE RATES )
BY $9.0 MTLLTON )
)
ROCKY MOT]NTAIN POWER
CASE NO. PAC-8.16-05
February 2016
1 Q. Please state your name, business address and present position with
2 PacifiCorp, dba Rocky Mountain Power (the'oCompany").
3 A. My name is Michael Wilding. My business address is 825 NE Multnomah St.,
4 Suite 600, Portland, Oregon 97232. My title is Net Power Cost Specialist.
5 Qualifications
6 a. Briefly describe your education and business experience.
7 A. I received a Master of Accounting from Weber State University and a Bachelor of
8 Science degree in accounting from Utah State University. I am a Certified Public
9 Accountant licensed in the state of Utah. Prior to joining the Company, I was
10 employed as an internal auditor for Intermountain Healthcare and an auditor for
11 the Utah State Tax Commission. I have been employed by the Company since
12 February 2014.
13 Summary of Testimony
14 a. What is the purpose of your testimony in this proceeding?
15 A. My testimony presents and supports the Company's calculation of the Energy
16 Cost Adjustment Mechanism ("ECAM") balancing account for the l2-month
17 period from December 1, 2014 through November 30, 2015 ("Deferral Period").
18 More specifically, my testimony provides the following:
19 o A srmrmary of the ECAM calculation, including changes made to comply with
20 recent Commission orders.
2l o Details supporting the addition of $16.7 million (*2015 Deferral") to the
22 deferral balance, bringing the total balance to $23.9 million as of November
23 30,2015.
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o Additional details of the ECAM calculation and a description of the
Company's net power costs ("NPC").
Are additional witnesses presenting testimony in this case?
Yes. Ms. Joelle R. Steward, Director Rates & Regulatory Af[airs, is sponsoring
testimony supporting the Company's proposed ECAM collection rates in Electric
Service Schedule No. 94, Energy Cost Adjustment ("schedule 94"). The
Company proposes to modifl, Schedule 94 to be effective April 1, 2016 to collect
approximately $16.9 million during the period of April 1,2016 through May 31,
2017. This is compared to the current collection rate of approximately $23.4
million.
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 between actual NPC and NPC in base
rates and defers 90 percent of the difference for later recovery.r Other items,
which I describe in detail later in my testimony, ure also tracked in the ECAM to
true up the amount in base rates to actuals include: sales of sulfur dioxide ("SOz")
emission allowances, load control or demand side management ("DSM") costs,
and revenues from the sale of renewable energy credits ("RECs"), a resource
adder for the new Lake Side 2 gas generation plant, and the unrecovered Deer
Creek Mine investment which is being amortized over a five-year period. The
balance that accumulates over a deferral period is then passed on to customers as
I Order No. 30904 in Case No. PAC-E-08-08 approved the stipulation entered into by the Commission
Staff, the Idaho Irrigation Pumpers Association, Monsanto and the Company that set up the structure and
content of the ECAM mechanism.
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a rate snrcharge 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 annual deferral period for the ECAM is December 1 to
November 30. The Company is required to file an application with the
Commission annually by February I to seek approval of the defenal amount and
new Schedule 94 rate effective April 1.
How is the 2015 ECAM deferral calculation presented in your testimony?
The calculation of the 2015 ECAM deferral is contained in Exhibit No. 1. A
sunmary of the major components is contained in Table 1 below. Later in my
testimony I discuss the details of the calculations contained in Exhibit No. l.
What changes to the ECAM calculation have been implemented in this filing
to comply with Commission orders from previous cases?
The Lake Side 2 generation facility began commercial operation in May 2014, so
beginning January 1,2015, pursuant to Order No. 32910,2 the ECAM includes a
resource adder to recover the investment in the new Lake Side 2 generation
facility until it is reflected in rates as a component of rate base. The ECAM
deferral is based on the Lake Side 2 acfilal generation multiplied by $1.99lItIWh,
and capped at a total of S5.43 million or 2,729,500 MWh. The Lake Side 2
generation adder for the deferral period is $4.1 million.
In 2015 the Company closed the Deer Creek Mine and, pursuant to Order
No. 33304 in Case No. PAC-E-I4-10 and the stipulation approved in Order No.
33440, Case No. PAC-E-15-09, the ECAM includes the recovery of the remaining
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' See page 2, section 4 from Case No. PAC-E-13-04.
1 Deer Creek amortization expense.
2 a. Will additional changes be made to the ECAM in the Company's2017 filing?
3 A. Yes. In Case No. PAC-E-15-09 the Commission approved additional changes to
4 the ECAM structure, effective January I,2016. First, the ECAM calculation will
5 directly compare NPC collected through base rates to actual NPC eliminating the
6 need for a back cast adjustment to account for the over/under-collection of NPC.
7 Beginning January 1,2016, the sales of SOz emission allowances and DSM costs
8 will no longer be tracked in the ECAM. The revenues from the sale of RECs, the
9 LCAR, the Lake Side 2 resource adder, and the Deer Creek Mine amortization
10 expense will all continue to be included in the ECAM. Additionally, the
l1 Production Tax Credits ("PTCs") for wind generation will be tracked in the
12 ECAM beginning January 1,2016. The annual filing date for ECAM deferrals
13 will also change from February I to April 1 and the deferral period will transition
14 to a calendar year.
l5 2015 Deferral
16 a. Please explain the calculation of the ECAM balance for the Deferral Period.
17 A. Detailed calculations are provided in Exhibit No. l, attached to my testimony, and
18 Table 1 below summarizes the various components of the deferral.
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Table 1
NPC Differe ntia I for Deferra I
LCAR
so2
DSM Costs
EITF 04-5 Adjustme nt
Tota I Deferra I Before Sha ring
Sharing Band
Customer Reponsi bi I ity
REC Defe rra I
Lake Side 2 Resource Adder
Deer Creek Amortization Expense
Back-Cast Adjustment
lnterest
Tota! Company Recovery for NPC Deferral
ldaho
Customers
5 g,zagJao
(389,057)
(20)
(s43,999)
5 8,zs4,zt3
9iYo
$ 7,428,792
6,160,170
4,107,943
626,238
( 1,688,064)
97
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, LCA& SO2
allowance sales, DSM costs, and the EITF 04-6 adjustment. The next section
calculates the 90 percent customers' share of the above items and adds the
following for which customers are refunded or surcharged 100 percent: Idaho-
allocated REC revenue true-up or difference, the Lake Side 2 resource adder, and
the Deer Creek arnortization. The back cast adjustment is added to ensure there is
no over or under-collection of NPC, DSM costs, LCAR, Deer Creek amortization,
and revenues from the sale of RECs. The total of these items represents the 2015
Deferral. The 2015 Deferral of $16.7 million is a result of the $7.4 million
customers' share of the NPC differential, including the adjustments for LCA&
SOz sales, DSM costs and EITF 04-6, $6.1 million REC revenue differential, $4.1
million Lake Side 2 Resource Adder, and $0.6 million Deer Creek amortization
expense. The back cast adjustment reduces the 2015 Deferral by $1.7 million. The
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remaining $0.1 million is interest accrued on the 2015 Defenal.
Based on your calculations, what is the balance expected to be in the ECAM
deferral account as ofApril lr2016?
The projected balance in the ECAM deferral account as of April 1,2016 is $16.9
million. Table 2 summarizes the deferral account activity starting with the $26.7
million balance approved in Case No. PAC-E-I5-01. That balance is adjusted for
collections and interest accrued during the Deferral Period. The 2015 Deferral
was added to the deferral account along with the estimated remaining balance of
5134,437 pertaining to unrecovered2014 defenal. The estimated deferral account
balance of $16.9 million due for collection from all Idaho customers as of April 1,
2016, consists of the $16.7 million from the 2015 Deferral Period, the estimated
prior period balance, and interest accrued.
Table 2
Balancins Account Activiw
All ldaho Tariff
Customers Customers Monsanto Agrium Total
Account Activity
PriorDeferral S 16,393,738 S 1,750,965 S Z,g+g,oso S 6re,+S+ 5 26,720,238
ECAM Revenue Collection - Schedule 94 (11,714,989) 1L,629,547\ 15,957,5721 1467,84L1 (L9,769,949)
nterest 129,351 3,019 50,77L 3,809 186,950
TarriffCustomermoved to All lO 4/Ll20l5 734,437 (L34,437\ -
ActivityThroughNorember3o,2ol4 S 4,942,536 $ $ 2,042,250 S 152,452 I 7,L37,238
Dec 14 - Nov 15 ECAM Deferral 16,726,087
30, 2014 Balance For collection $ 21,668,624 S $ Z,UZ,ZSO S 152,452 S zr,aa,rzS
94Collection - Dec2014- March
201s $ (480s,815)$ s (2,04s,5s4)s (1s2,706)s 17nterest 8,4t6 - 3,4U 2
:xpected Balance as of April 1,2015 S 16,871,223 S S S
a. What is the proposed collection amount due from customers under Schedule
94 beginning April 1,2016?
A. Schedule 94 is designed to collect $16.9 million over a l4-month period from all
Idaho customers. The testimony of Company witness Ms. Steward explains the
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rate design and Exhibit No. 2 summarizes the rate impact to each customer class
associated with this ECAM rate change.
Summary of the NPC Differences
a. Please explain the difference between adjusted actual NPC ("Actual NPC")
and the NPC in base rates ("Base NPC").
A. On a total Company basis, Actual NPC for the Deferral Period were
approximately $1.535 billion. During the Deferral Period, the Base NPC in rates
originated from the 2011 Rate Case. The stipulation approved in that case
established Base NPC of $1.385 billion for 2013 and per Order No. 32910 in Case
No. PAC-E-13-04 the 2013 base has remained in place during 2015. To
accurately track the Deer Creek amortization expense, beginning January 1,2015
the stipulation approved in Order No. 33440 in Case No. PAC-E-I5-09, splits the
Base NPC in two parts: Base NPC and the Base Deer Creek depreciation expense.
The Base Deer Creek depreciation expense for the period of January through
November 2015 is $9 million. The Base NPC for the same period is $1.376
bil1ion.3
Did the Company anticipate that Actual NPC would be higher than the NPC
included in rates during the Deferral Period?
Yes. In June 2013 the Company reached an agreement with multiple parties in
Case No. PAC-E-13-04 establishing an alternative rate plan in lieu of filing
another general rate case. Mr. Ted Weston's testimony filed in support of that
stipulation, indicated that the rates currently in effect justified a price increase,
3 Case No. PAC-E- I 5-09 Stipulation Paragraph # I I . The amounts of Base NPC and Base Deer Creek
depreciation differ slightly from the stipulation because the two bases identified in the stipulation were for
the full calendar year but are only effective for eleven months of the Deferral Period.
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primarily driven by three factors: higher actual net power costs, lower REC
revenues, and increased depreciation expense.o The first two factors are the main
drivers of the difference in costs in the Deferral Period. Mr. Weston explained
that the potential to recover increased actual NPC and lower REC revenue
through the ECAM enabled the Company to delay the rate case anticipated in
2013 and to pursue and execute the alternative rate plan.s
Did parties to the stipulation understand the impact these settlements would
have on the ECAM?
Yes. As noted by Mr. Weston, the parties supported this approach knowing they
would benefit from the delay in paying the higher level of net power costs.
When will Base NPC be updated in rates?
Base rates increased $10.2 million effective January l, 2016, pursuant to the
stipulation approved in Order No. 33440 in Case No. PAC-E-I5-09. Base NPC
increased to $1.529 billion total Company or $94.8 million Idaho allocated.
Changes to the base credits for RECs and PTCs also contributed to the total rate
increase. Additionally, parties agreed that the Company would file an application
no later than September 1, 2016, to again update Base NPC effective January 1,
2017.In exchange, the Company agreed that it would not file a general rate case
with rates effective prior to January 1, 2018.
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
o Case No. PAC-E-I3-04, Stipulation Testimony of J. Ted Weston at 3-4.t Case No. PAC-E-I3-04, Stipulation Testimony of J. Ted Weston at 9-10.
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basis to enable ongoing analysis of the ECAM. The last quarterly report, provided
for the period December 2014 through August 2015, reported an incremental NPC
deferral of $7.5 million, a REC adjustment of $4.6 million, the Lake Side 2
resource adder of $3.2 million, and the Deer Creek amortization expense of $0.5
million.
a. What are the major drivers that result in a difference between Actual NPC
and Base NPC during the Deferral Period?
A. The $160 million difference on a total company basis between Base NPC and
Actual NPC during the Deferral Period is summarized in Table 3 below by the
major categories in the NPC report.
Table 3
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Deferral Period NPC Reconciliation ($millions)
ECAM Deferra!
Period
lD Base NPC 2011 GRC PAC-E-11-12
lncrease/(Decrease) to NPC:
Wholesale Sales
Purchased Power
CoalGeneration
Gas Generation
Wheeling Hydro and Other
Total lncrease/(Decrease)
Settlement Adjustment
Deer Creek De preciation Adj ustment
Total Company NPC DiffErence
Adjusted Actual NPC 2015
$1,376
451
r't)-i\
101
i1$3i
1
$224
(73)
9
$160
$1,535
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An apples-to-apples comparison of Base NPC and Actual NPC is difficult due to
the disparity in timing between the test period used to determine Base NPC in the
2011 Rate Case and the period over which those rates have been in effect. Base
NPC were set using a calendar year 2011 test period and the settlement in the
2011 Rate Case included a "black box" adjustment to determine Base NPC.
Additionally, Base NPC has been reduced to carve out the Base Deer Creek
depreciation.
Notwithstanding the issues you describe above, can you explain some of the
differences in NPC categories?
Yes. The major contributor to the variance in NPC is a reduction in wholesale
sales revenue. The increase in NPC due to lower wholesale sales and higher coal
is partially offset by reduced purchased power expenses and gas fuel expenses.
Higher load and lower wind and hydro generation also contributed to higher costs
compared to Base NPC, with the impact of each spread across multiple cost
categories.
Please explain the reduction in wholesale sales revenue.
The reduction in wholesale sales revenue is driven by the expiration of four long-
term sales contracts and reduced revenue from short-term wholesale market sales.
Wholesale sales contracts with Nevada Power, Pacific Gas and Electric, Public
Service Company of Colorado, and Southern California Edison were included in
Base NPC but have since expired. Expiration of these contracts accounted for $73
million reduction in wholesale sales revenue and a 2,145 GWh reduction in sales
volume; which accounts for approximately 16 percent of the reduction in
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wholesale sales revenues.
Revenue from market transactions (represented in the Company's
production dispatch model ("GR[D") as short-term firm and system balancing
sales) is approximately $362 million lower than Base NPC. The drop in revenue is
due to both the volume variance and the average price of market sales
transactions. The market sales transactions in the Base NPC were 3,585 GWh
higher than actual market sales transactions during the Deferral Period at an
average price of $52.43lMWh compared to actual market sales during the
Deferral Period at an average price of $28.96lMWh. The drop in wholesale
market price alone accounts for about 48 percent of the reduction in wholesale
sales revenues.
Please explain the reduction in purchased power expense.
Similar to wholesale sales, the reduction in purchased power expense is driven by
the expiration of several long-term contracts and reduced expenses from
wholesale market purchases. Long term contracts expiring prior to the end of the
Deferral Period include purchases from Grant County Public Utility District
("PUD"), Chelan County PUD, Black Hills Power, and Roseburg Forest Products;
a Kennecott generation incentive; two call options with Morgan Stanley; and a
peaking contract with the Bonneville Power Administration. The expiration of
these contracts accounts for a reduction of approximately $72 million in
purchased power expense. In addition, expenses related to several qualiffing
facility (*QF") contracts decreased approximately $28 million due to customers'
QF generation serving their own load. The loss of the energy from these long-
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term contracts contributed to the lower wholesale sales volumes previously noted.
Expenses from market transactions (represented in GRID as short-term
firm and system balancing purchases) are approximately $105 million lower than
Base NPC. This drop in expenses is due mainly to reduced volume of market
purchases, partially offset by an increase in the average price of market purchase
transactions.
Are there any new long term purchase contracts that partially offset the
overall reduction in purchased power expense?
Yes. There are five wind and one geothermal QFs that had little or no generation
in Base NPC, increasing purchased power expense approximately $29.3 million.
These include the Power County Norttr and South QFs which came online at the
end of 2011, the Roseburg Dillard QF came online at the beginning of 2012, the
Five Pine and North Point QFs which came online at the end of 2012, and the
Foote Creek III that began selling power to the Company at the end of 2014. The
Company also executed a purchase agreement with Constellation Energy to
purchase seasonal power during surlmer peak months. Additionally, as part of the
Company's addition of Eagle Mountain, Utah, into its service territory it absorbed
a purchase power agreement with Utah Associated Municipal Power Systems
("UAMPS").
Please explain the change in coal fuel expense.
Coal generation volume was relatively unchanged compared to the Base NPC,
decreasing by only 634 GWh (-1.5 percent). Of the decrease in generation
volume, 581 GWh is due to the closure of the Carbon plant at the end of April
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2015. The average cost of coal generation increased from $16.604{Wh in Base
NPC to $19.30/MWh in the Deferral Period, contributing to an overall increase of
$101 million in coal fuel expense. Base NPC was set in 2011 and there have been
some notable changes that have affected coal fuel costs including contractual coal
price increases, new coal contracts, and increased mine operating costs at the
Bridger Coal Company mine.
Please explain the decrease in natural gas fuel expense.
The actual natural gas fuel expense was $102 million less than the natural gas fuel
expense in rates. This difference is a result of a decrease in natural gas prices. The
actual average cost of natural gas generation was $31.09ArIWh compared to
$64.584{Wh in Base NPC. The decrease in natural gas prices is partially offset
by increased natural gas generation at the Lake Side I and2 plants. The Lake Side
2 combined cycle combustion turbine plant reached commercial operationinr,2014
and was not included in Base NPC.
How did changes in load and hydro and wind generation impact NPC?
Actual system load during the Deferral Period was 945 GWh (two percent) higher
than the load in Base NPC, and hydro generation in the Deferral Period was 1,030
GWh (26 percent) lower than in Base NPC. Wind generation was 652 GWh (21
percent) lower than in Base NPC as well. The impact of higher load and lower
hydro and wind generation is spread across the different NPC components, and
contributes to the reduced wholesale sales revenue shown in Table 3.
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Description of the ECAM Calculations
a. Please describe the ECAM calculations in your Exhibit No. 1.
A. The ECAM defenal is calculated by comparing the Actual NPC to the Base NPC
on a monthly basis and deferring the differences into an ECAM balancing
account. The defenal amount is the difference in the system dollar-per-megawatt-
hour rate multiplied by the Idaho retail load. Exhibit No. 1 includes details of the
ECAM calculation, and the confidential work papers contain supporting
information.
How are the Base NPC and Actual NPC dollar-per-megawatt-hour rates
calculated?
The monthly Base NPC are divided by the corresponding monthly normalized
base load to express the costs on a dollar-per-megawatt-hour basis, as set forth in
Exhibit No. 1, line 1. The Actual NPC rate on a dollar-per-megawatt-hour basis is
calculated by dividing the monthly Actual NPC in the Deferral Period by the
actual monthly system load in the Deferral Period, as set forth in Exhibit No. 1,
line 8. On a dollar-per-megawatt-hour basis, the Base NPC average is
$23.564{Wh, while the Actual NPC averaged $25.921MWh, or $2.36 A4Wh
higher.
Please describe how the NPC deferral is calculated.
The deferral is calculated on a monthly basis by subtracting the Base NPC rate
from the Actual NPC rate. The resulting monthly NPC rate differential (Exhibit
No. 1, line 9) is then multiplied by the actual Idaho retail load at input (Exhibit
No. l, line 10) to calculate the NPC differential for deferral (Exhibit No. 1, line
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12). For the l2-month period ended November 2015 the NPC differential was
approximately $9.3 million before application of the 90 I 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 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:
o Out of period accounting entries;
o buy-through of economic curtailment by intemrptible industrial customers;
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. situs assignment of the generation from Oregon solar resources procured to
satisfy ORS 757.370 solar capacity standard;
o legal fees included in the cost of coal related to fines and citations;
o the true-up of coal inventories;
o the true-up of energy returned to a third party to compensate for prior line
losses;
. 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.
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.
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In addition to the comparison of Actual NPC to Base NPC, what other
components are included in the ECAM?
There are eight additional components included in the ECAM calculations: (i) the
LCAR adjustment (ii) a credit for any SOz allowance sales, (iii) a true-up of DSM
costs, (iv) an adjustment for deferred costs associated with coal mine stripping
activities recorded under the Financial Accounting Standards Board ("FASB")
EITF 04-6, (v) unrecovered Deer Creek Mine investment that has been amortized
after the closing of the mine and is not included in Base NPC, (vi) a resource
adder to collect the investment in the Lake Side 2 natural gas generation facility,
(vii) a true-up of REC revenues as authorized by the Commission in Order No.
32196, (viii) and a back cast adjustment that accounts for any over- or under-
collection of NPC, LCAR, DSM costs, Deer Creek amortization expense, and
REC revenues.
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, Order No. 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 last set in Order No. 32432 at $5.47 per megawatt-hour. This rate has
been in effect since April I,20ll.
Wilding, Di - 17
Rocky Mountain Power
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How is the LCAR adjustment calculated and what impact does it have on the
2015 Deferral?
The LCAR adjustment is calculated by subtracting the Idaho load at input
established in a general rate case ("Base Load" shown in Exhibit No. l, line 13),
from actual Idaho load at input ("Actual Load" shown in Exhibit No. l, line l4).
The difference (Exhibit No. 1, line 15) is then multiplied by the LCAR rate of
$5.47 per megawatt-hour in all months of the Deferral Period (Exhibit No. 1, line
16) to arrive at the LCAR adjustment (Exhibit No. 1, linelT) resulting in a $0.4
million decrease to the NPC deferral before the 90 / l0 percent sharing.
How are SO2 sales revenues included in the ECAM?
Line 18 of Exhibit No. I contains the SOz sales revenue during the Deferral
Period on a total Company basis. Line 20 of Exhibit No. I is Idaho's allocated
share of the SOz sales revenue which is calculated using Idaho's System Energy
("SE") allocation factor authorized by the Commission from the 2011 Rate Case.
For the Deferral Period, the total SOz sales revenue credit is a $20 reduction to the
NPC defenal balance before the 90 / 10 percent sharing.
How is the DSM cost adjustment calculated in the ECAM?
The DSM cost adjustment is a comparison of actual costs for DSM load control
programs compared to the base level established in the 201I Rate Case. The
stipulation approved in the 201I Rate Case established the base amount to be
tracked in the ECAM as $1,045,423. Idaho-allocated actual DSM load control
costs during the Deferral Period were approximately $0.5 million. The difference,
shown on line 23 of Exhibit No. 1, is included as a $0.5 million reduction to the
Wilding, Di - 18
Rocky Mountain Power
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NPC deferral balance before the 90 / l0 percent sharing.
How is the adjustment for accounting pronouncement EITF 04-6 included in
the ECAM?
Line 24 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, and the arnortization of the coal striping costs as approved by the
Commission.6 For the Deferral Period, the total EITF 04-6 coal stripping deferral
adjustment is an $82,470 decrease to the NPC deferral balance before the 90 / 10
sharing.
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 10 percent. Line 28 of Exhibit No. 1, represents the customers'
90 percent share of the monthly deferral shown on line 26 of Exhibit No. 1. For
the Deferral Period, the customers' share of the deferred balance is approximately
$7.4 million. The remaining balance of approximately $0.8 million is not included
in the deferral calculation and is not recoverable from customers.
What is the amount of REC revenue true-up in the current filing?
As authorizedby the Commission in Case No. PAC-E-10-07, Order No. 32196,
the Company included the difference between actual REC revenues during the
Deferral Period and the amount of REC revenues included in base rates. The REC
Wilding, Di - 19
Rocky Mountain Power
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u Case No. PAC-E-09-08, Order No. 30987.
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revenue true-up included in the ECAM is symmetrical but no sharing band is
applied - the entire difference between base and actual REC revenues is either
refunded or surcharged to customers. Base rates during the Deferral Period
included $6.5 million in Idaho-allocated REC revenue. Idaho's actual REC
revenues for that same time period were approximately $0.4 million, a difference
of approximately $6.2 million (Exhibit No. l, line 31).
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 not yet included in rate
base. The resource adder amounts to $I.99lIvIWh of the Lake Side 2 generation
capped at $5.4 million dollars or 2,729,500 MWh for the calendar year. The total
Lake Side 2 resource adder for January through November 2015 was $4.1 million
based on2,061,278 MWh of generation. As December 2015 will be included in
the 2017 ECAM filing the Company will limit any future recovery for that month
to an annual total of $5.4 million for 2015.
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 investrnent
would be amortized over a five-year period and recovered through the ECAM.
Wilding, Di - 20
Rocky Mountain Power
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The stipulation approved in Order No. 33440, Case No. PAC-E-I5-09 specified
that the Deer Creek amortization expense included in the ECAM will be reduced
by the Deer Creek depreciation expense currently in rates. Beginning January 1,
2016, Deer Creek's depreciation expense will not be included in base rates instead
it will be fully recovered through the ECAM.
What is the amount of the Deer Creek amortization expense in the current
fiIing?
The Deer Creek amortization expense included in the ECAM is $0.6 million
(Exhibit No. 1, Line 37). Pursuant to the stipulation approved in Order No. 33440
in Case No. PAC-E-15-09 the Deer Creek amortization expense was calculated by
subtracting the base period Idaho-allocated Deer Creek depreciation of $0.6
million from the actual Idaho allocated Deer Creek amortization of $1.2 million.
Please explain the back cast adjustment.
In Case No. PAC-E-14-01, the Commission Staff developed, what I refer to as, a
back cast adjustment to check for any over- or under-collection of NPC, LCAR,
DSM costs, and REC revenue during the Deferral Period. The back cast is
performed by summing the NPC collected in rates and the NPC differential from
the ECAM before sharing. This amount is compared to actual NPC on an Idaho-
allocated basis, and the difference is subject to the 90 I l0 percent sharing band.
The same calculation is used for the LCAR, DSM costs, Deer Creek amortization
expense, and REC revenue, except that REC revenue and Deer Creek are not
subject to the sharing band. The total back cast adjustment reduces the ECAM
$1.7 million (ExhibitNo. 1, Line 43).
Wilding, Di-21
Rocky Mountain Power
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What is the total ECAM deferred balance calculated in Exhibit No. 1?
The total ECAM defened balance as of November 30, 2015 is $23.9 million,
shown on line 72 of Exhibit No. l.
How is this balance divided among customers?
Consistent with the stipulation approved in Order No. 32910 in Case No. PAC-E-
13-04, beginning December 1,2013, the ECAM has been calculated on a total
Idaho basis; Monsanto and Agrium's share were not calculated separately.
Does the calculation of the deferred NPC adjustment in this application
comply with the parameters of the Idaho ECAM as approved by the
Commission?
Yes. Therefore, the Company recommends the Commission approve the ECAM
application for recovery of the $16.7 million prudently incurred NPC.
Does this conclude your direct testimony?
Yes.
Wilding, Di - 22
Rocky Mountain Power
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CaseNo. PAC-E-16-05
ExhibitNo. I
Witress: Michael Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Michael Wilding
February 2016
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Exhibit No. 'l Page 1 of 1
Case No. PAC-E-16-05
Witness: Michael \Mlding
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