20150202Wilding Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
AUTHORITY TO INCREASE RATES BY
$10.7 MILLION TO RECOVER
DEFERRED NET POWER COSTS
THROUGH THE ENERGY COST
ADJUSTMENT MECHAIIISM
) CASE NO. PAC-E-15-01
)) DIRECT TESTIMONY OF
) MICHAEL WILDING
)
)
)
ROCKY MOUNTAIN POWER
CASE NO. PAC.E.15-01
February 2015
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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 Wilding. My business address is 825 NE Multnomah Street,
Suite 600, Portland, Oregon 97232. My title is Senior Net Power Cost Analyst.
Qualifications
a. Briefly describe your education and business experience.
A. 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.
Summary of Testimony
a. What is the purpose of your testimony in this proceeding?
A. My testimony presents and supports the Company's calculation of the Energy
Cost Adjustment Mechanism ("ECAM") balancing account for the twelve-month
period from December l, 2013 through November 30, 2014 ("Deferral Period").
More specifically, my testimony provides the following:
o A summary of the ECAM calculation, including changes made to comply with
recent Commission orders.
o Details supporting the addition of $16.6 million ("2014 Deferral") to the
deferral balance, bringing the total balance to 527 million as of November 30,
2014.
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1 o Additional details of the ECAM calculation and a description of the
2 Company's net power costs ("NPC").
3 Q. Are additional witnesses presenting testimony in this case?
4 A. Yes. Ms. Joelle R. Steward, Director, Pricing, Cost of Service & Regulatory
5 Operations, is sponsoring testimony supporting the Company's proposed ECAM
6 collection rates in Schedule 94. The Company is proposing to modiff Electric
7 Service Schedule No.94, Energy Cost Adjustment, effective April 1,2015, to
8 collect approximately $23.3 million on an annual basis as compared to the current
9 collection rate of approximately $12.7 million.
10 Summary of the ECAM Deferral Calculation
I I O. Please briefly describe the Company's ECAM authorized by the
12 Commission.
13 A. In general, the ECAM tracks deviations between actual NPC and the NPC in base
14 rates and defers 90 percent of the difference for later recovery.' Other items which
15 I describe in detail later in my testimony, include sales of sulfur dioxide ("SOz")
16 emission allowances, load control or demand side management ("DSM") costs,
17 and revenues from the sale of renewable energy credits ("RECs"), are also tracked
18 in the ECAM to true-up the amount in base rates to actuals. The balance that
19 accumulates over a deferral period is then passed on to customers as a rate
20 surcharge or credit. The ECAM Schedule 94 rate, which appears as a separate line
2l item on customer bills, collects from or credits to customers the balance of
22 deferred costs. Schedule 94 is adjusted as needed in the Company's annual
' Order No. 30904 in Case No. PAC-E-08-08 approved the stipulation entered into by the Commission
Staff, the Idaho Inigation Pumpers Association, Monsanto and the Company that set up the structure and
content of the ECAM mechanism.
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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 by February I of each year to seek approval of the deferral amount
and to adjust the ECAM rate effective April l.
How are the 2015 ECAM deferral calculations presented in your testimony?
The calculation of the 2015 ECAM deferral is contained in Exhibit No. l. A
summary of the major components is contained in Table I 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 to comply
with Commission orders from previous cases?
Consistent with the stipulation approved in Order No. 32910, Case No. PAC-E-
13-04, beginning December l, 2013, the ECAM is calculated on a total Idaho
basis; Monsanto and Agrium's share were not calculated separately. However,
separate deferral accounts have been maintained to properly account for pre-
December 2013 balances. Pursuant to Order No. 33008 in Case No. PAC-E-14-
01, the Company implemented Staffs back cast calculation to perform a check
for over/under-collection of NPC, load control costs, and RECs.
Lake Side 2 began commercial operation in May 2014, so beginning
January 1,2015, pursuant to the stipulation in Case No. PAC-E-13-04, the ECAM
will include 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 will be based on the Lake Side 2 actual generation multiplied by
$1.9944WH, and capped at a total of $5.43 million or 2,729,500 MWh.
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2014 Deferral
a. Please describe the ECAM components that make up the 2014 Deferral.
A. The 2014 Deferral is the sum of customers' 90 percent share of the following
items: the difference between the actual and in-rates NPC, the Load Change
Adjustment Revenue ("LCAR"), the SOz allowance sales, the load control cost
adjustment, and the Emerging Issues Task Force ("EITF") 04-6 coal cost
adjustment. An additional true-up of 100 percent of the revenue difference from
the sale of RECs is also included. Consistent with the Commission's order in Case
No. PAC-E-14-01, a back cast adjustment is made to the ECAM balance to
account for any over- or under-collection of NPC, load control costs, and RECs.
Detailed calculations are provided in Exhibit No. 1, attached to my testimony, and
Table I below summarizes the various components of the deferral.
Table 1
ldaho
Customers
Differential for Deferral StZ,
(619,085so2 (
lrrigation Load Control 963,027
EITF 04-6 Adjustment (65,
Total Deferral Before Sharing L3,O12,449
Sharing Band
Customer Reponsibility 5LL,77L
REC Deferral 6,054,558
Back-Cast Adjustments (7,247,
I nte rest
Total Company Recorery for NPC Deferral
Please explain the calculation of the ECAM balance for the Deferral Period.
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, LCAR, SOz
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sales, irrigation load control costs, and the EITF 04-6 adjustment. The next
section calculates the 90 percent customers' share of those items and adds the
Idaho-allocated REC revenue true-up or difference, for which customers are
refunded or surcharged 100 percent. The back cast adjustment is added to assure
there is no over or under-collection of NPC, irrigation load control, and revenues
from the sale of RECs. The total of these items represents the 2014 Deferral. The
2014Deferral of $16.6 million is a result of the $l1.7 million customers' share of
the NPC differential, including the adjustments for LCAR, SOz sales, load control
costs and EITF 04-6, and the $6.1 million REC revenue differential. The back cast
adjustment reduces the 2014 Deferral by the $1.2 million. The remaining $0.1
million is interest accrued on the 2014 Deferral.
Based on your calculations, what is the balance expected to be in the ECAM
deferral account as ofApril 1,2015?
A. The projected balance of the ECAM Balancing Accounts as of April 1,2015 is
$23.3 million. Table 2 summarizes the balancing account's activity starting with
the $23.7 million balance in the ECAM deferral account as approved in Case No.
PAC-E-14-01. That balance is adjusted for collections and interest accrued during
the Deferral Period, and an adjustment was made for the Wholesale Loss
Adjustment required by Order 33094. The 2014 Deferral is added to the deferral
account for all Idaho customers, and as noted above separate deferral accounts for
Agrium and Monsanto have been maintained to properly account for pre-
December 2013 balances. The estimated deferral account balance of $23.3 million
due for collection as of April 1,2015, consists of Monsanto's outstanding balance
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of approximately $6.2 million, Agrium's outstanding balance of $0.5 million,
Tariff Customers' outstanding balance of approximately $69,000, and the $16.6
million from the Deferral Period which will be due from all Idaho customers.
Table 2
Balancing Account Activity
4 a. What is the proposed collection amount due from customers under Schedule
5 94 beginning April 1,2015?
6 A. Schedule 94 was designed to collect $23.3 million as explained in the testimony
7 of Company witness Ms. Steward. The Company proposes to collect
8 approximately $16.6 million from all Idaho customers beginning April l, 2015. In
9 addition the ECAM rate for Monsanto and Agrium will be designed to collect the
l0 prior year balances of approximately $6.6 million. Ms. Steward's testimony
11 details the rate impact of the updated ECAM collections.
12 Summary of the NPC Differences
13 0. Please explain the difference between adjusted actual NPC ("Actual NPC")
14 and the NPC in base rates ("Base NPC").
15 A. On a total Company basis, Actual NPC for the Deferral Period were
16 approximately $1.639 billion. During the Deferral Period, the Base NPC in rates
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All ldaho Tariff
CustomeE Customers Monsanto Agrium Total
Balancing Accoum Activity
Prior Deferral 59,535,217 513,170,906 S997,651 523,703,774
ECAM Revenue Collection (7,76O,OL81 (5,397,4771 (393,865) (1
lnterest 53,267 707,62L 8,198 159,085
WLA Adjustment per Order 33094 (67,5001 53,000 4,500 -
Activity Through November 30, 2014 51,750,955 57,949,050 5516484
Norember 30, 2014 Balance For Collection s15,634,562 $1,750,955 s7,949,050 5615,484
Schedule 94 Collection - Dec 2014 - March2o1s (51,6s4,7261 (57,7e7,4271 (S1s6,6e3)
lnterest 2,938 23,624 7,785
Expected Balance as of April 1, 2015
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originated from the 201I Rate Case. The stipulation approved in that case
established Base NPC of $ I .385 billion for 2013 and per Order No. 3291 0 in Case
No. PAC-E-13-04 the 2013 base has remained in place during 2014 for the
ECAM.
Did the Company anticipate that actual NPC would be higher than the NPC
included in rates during the Deferral Period?
Yes. [n 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. J. Ted Weston's testimony filed in support of that
stipulation indicated that the rates currently in effect justified a price increase,
primarily driven by three factors: higher actual net power costs, lower REC
revenues, and increased depreciation expense.2 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.3
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.
' Case No. PAC-E-13-04, Stipulation Testimony of J. Ted Weston at 3-4.
' Case No. PAC-E-13-04, Stipulation Testimony of J. Ted Weston at 9-10.
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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 2013 through August 2074, reported an incremental NPC
deferral of $l 1.7 million and a REC adjustment of $4.5 million.
What are the major drivers that result in a difference between Actual NPC
and Base NPC?
The $254 million difference on a total company basis between Base NPC and
Actual NPC during the Deferral Period is summarized in Table 3 below by the
major categories in the NPC report.
Table 3
Deferral Period NPC Reconciliation ($millions)
EBA Deferral
Period
lD Base NPC 2011 GRC PAC-E-11-12
lncrease/(Decrease) to NPC:
Wholesale Sales
Purchased Power
Coal Generation
Gas Generation
Wheeling Hydro and Other
Total lncrease/(Decrease)
Settlement Adjustment
Total Company NPC Difference
Adjusted Actual NPC 2014
$1,385
374
(181)
108
19
7
$327
(73)
$254
$1,639
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 201I Rate Case and the period over which those rates have been in effect.
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Base NPC were set using a calendar year 20ll test period and the settlement in
the 2011 Rate Case included a "black box" adjustment to determine Base NPC.
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
and gas fuel expenses is partially offset by reduced purchased power 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 2.1 million MWh reduction in
sales volume. This reduction in sales is partially offset by the addition of the sales
contract with Shell Energy which accounted for $8 million of wholesale sales
revenue and0.2 million MWh of sales volume. The expiration of these long-term
contracts account for about 17 percent of the reduction in wholesale sales
revenues.
Revenue from market transactions (represented in the Company's
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production dispatch model ("GRID") as short-term firm and system balancing
sales) is approximately $307 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 2,927 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 $32.69ll\4Wh. The drop in wholesale
market price alone accounts for about 51 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 Kennecoff 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 qualifuing
facility ("QF") contracts decreased approximately $60 million due to customers'
QF generation serving their own load. The loss of the energy from these long-
term contracts contributed to the lower wholesale sales volumes previously noted.
Expenses from market transactions (represented in GRID as short-term
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firm and system balancing purchases) are approximately $l I I 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 new wind and one geothermal QFs that had little or no
generation in Base NPC, increasing purchased power expense approximately
$33.3 million. These include the Power County North 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 summer peak months.
Please explain the change in coal fuel expense.
Coal generation volume was relatively unchanged compared to the Base NPC,
increasing by only 210 GWh (0.5 percent). However, the average cost of coal
generation increased from $l6.60iMwh in Base NPC to $19.09/MWh in the
Deferral Period, contributing to an overall increase of $108 million in coal fuel
expense. Base NPC was set in 201I 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 and Deer Creek
mines.
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I Q. Please explain the change in natural gas fuel expense.
2 A. The actual natural gas fuel expense was $19 million greater than the natural gas
3 fuel expense in rates. This difference is a result of an increase in natural gas
4 generation volume of 4,647 GWh or 77 percent above Base NPC. The Lake Side
5 2 combined cycle combustion turbine plant reached commercial operation during
6 the Deferral Period increasing gas generation approximately 1,472 GWh. The
7 remaining increase in natural gas generation volume occurred mainly at the
8 Company's Lake Side I and Chehalis plants. Lake Side I generated more due to
9 more favorable economics in the Deferral Period when compared to the Base
l0 NPC study. Starting in December 2013, the Chehalis plant moved to the
I I Company's balancing authority area and was able to provide reserves during the
12 Deferral Period, causing it to be operated more than previously modeled in GRID
l3 where it was not able to provide reserves.
14 a. How did changes in load and hydro and wind generation impact NPC?
15 A. Actual system load during the Deferral Period was 2,153 GWh (four percent)
16 higher than the load in Base NPC, and hydro generation in the Deferral Period
17 was 394 GWh (10 percent) lower than in Base NPC. The impact of higher load
18 and lower hydro and wind generation is spread across the different NPC
19 components, and contributes to the reduced wholesale sales revenue shown in
20 Table 3.
2l Description of the ECAM Calculations
22 a. Please describe the ECAM calculations in your Exhibit No. 1.
23 A. The ECAM deferral is calculated by comparing the Actual NPC to the Base NPC
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on a monthly basis and deferring the differences into an ECAM balancing
account. The deferral amount is the difference in the system dollar-per-megawatt-
hour rate multiplied by the Idaho retail load. Exhibit No. I includes details of the
ECAM calculation and the confidential workpapers contain supporting
information.
How are the Base NPC and Actual NPC dollar-per-megawatt-hour rates
calculated?
The monthly NPC for Base NPC are divided by the corresponding monthly
normalized load to express the costs on a dollar-per-megawatt-hour basis, as set
forth in Exhibit No. l, 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 Defenal Period, as set forth in Exhibit No.
1, line 8. On a dollar-per-megawatt-hour basis, the Base NPC average is
$23.731MWh, and the Actual NPC averaged $27.05/MWh, or $3.32 /I,lWh
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 l0) to calculate the NPC differential for deferral (Exhibit No. 1, line
12). For the l2-month period ended November 2014 the NPC differential was
approximately $12.7 million before application of the 90 / l0 percent sharing.
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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:
o out of period accounting entries;
o buy-through of economic curtailment by interruptible industrial customers;
o situs assignment of the generation from Oregon solar resources procured to
satisfy ORS 757.370 solar capacity standard;
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. 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 / 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
prior to the inception of the ECAM should not impact the ECAM deferral.
In addition to the comparison of Actual NPC to Base NPC, what other
components are included in the ECAM?
There are six additional components included in the ECAM calculations: (i) the
LCAR adjustment (ii) a credit for any SOz allowance sales, (iii) a true-up of load
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control 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) a true-up of REC revenues as authorized by the
Commission in Order No. 32196, (vi) and a back cast adjustment that accounts for
any over- or under-collection ofNPC, load control costs, 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 l,20ll.
How is the LCAR adjustment calculated and what is the impact on the 2013
Deferral?
The LCAR adjustment is calculated by subtracting the Idaho load at input
established in rates ("Base Load" shown in Exhibit No. l, line 13), from actual
Idaho load at input ("Actual Load" shown in Exhibit No. 1, line l4). The
difference (Exhibit No. l, line l5) is then multiplied by the LCAR rate of $5.47
per megawatt-hour in all months of the Deferral Period (Exhibit No. l, line l6) to
arrive at the LCAR adjustment (Exhibit No. 1, linelT) resulting in a $619,086
decrease to the NPC deferral before the 90 / l0 percent sharing.
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How are SOz sales revenues included in the ECAM?
Line 18 of Exhibit No. 1 contains the SOz sales revenue during the Deferral
Period on a total Company basis. Line 20 of Exhibit No. I is ldaho'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 201I Rate Case.
For the Defenal Period, the total SOz sales revenue credit is a $71 reduction to the
NPC deferral balance before the 90 / l0 percent sharing.
How is the load control cost adjustment calculated in the ECAM?
The load control cost adjustment is a comparison of actual costs for load control
programs compared to the base level established in the 2011 Rate Case. The
stipulation approved in the 20ll Rate Case established the base amount to be
tracked in the ECAM as $1,045,423. Idaho-allocated actual load control costs
during the Deferral Period were approximately $2 million. The difference, shown
on line 23 of Exhibit No. l, is included as a $l million addition to the 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. I reflects Idaho's allocated differences between the coal
stripping costs incurred by the Company and recorded on the Company's books
pursuant to the guidance of the accounting pronouncement EITF 04-6, and the
amortization of the coal striping costs when the coal was excavated. For the
Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a
$66,928 decrease to the NPC deferral balance before the 90 / l0 sharing.
Wilding, Di - 17
Rocky Mountain Power
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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 10 percent. Line 28 of Exhibit No. l, represents the customers'
90 percent share of the monthly deferral shown on line 26 of Exhibit No. l. For
the Deferral Period, the customers' share of the deferred balance is approximately
$11.7 million. The remaining balance of approximately $1.3 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 authorized by 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
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 $0.5 million, a difference
of approximately $6 million (Exhibit No. l, line 3l).
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, load
control costs, and REC revenue during the Deferral Period. The back cast is
Wilding, Di - l8
Rocky Mountain Power
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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 / l0 percent sharing band.
The same calculation is used for load control costs and REC revenue, except that
REC revenue is not subject to the sharing band. The total back cast adjustment
reduces the ECAM $1.2 million (Exhibit No. 1, Line 35).
What is the total ECAM deferred balance as calculated in Exhibit No. 1?
The total ECAM deferred balance as of November 30, 2014 is $27 million, shown
on line 62 of ExhibitNo. 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 be calculated separately.
However, the balances associated with deferrals prior to December 1,2013 have
continued to be identified separately and included in rates for Monsanto, Agrium,
and remaining tariff customers until fully recovered.
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 $16.6 million prudently incurred NPC.
Does this conclude your direct testimony?
Yes.
Wilding, Di - 19
Rocky Mountain Power
0.
A.
o.
A.
Case No. PAC-E-15-01
Exhibit No. 1
Witness: Michael Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTATN POWER
Exhibit Accompanying Direct Testimony of Michael Wilding
February 2015
Rocky Mountain Power
Exhibit No. 1 Page '1 of 1
Case No. PAC-E-15-01
Witness: Michael Wilding
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