20140131Application.pdf

ROCKY MOUNTAIN
POWER
A DrvlSION OF PACIFICORP
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 8411l
Telephone: (80 1 ) 220-2963
Fax: [phone]
Email : ted.weston@pacifi corp. com
By E-mail (prefened):
By regular mail:
201 South Main, Suite 2300
Salt Lake City, Utah 84111':t: tr-. +n,:: ; ii-r' f. t.r
January 31,2014
VA OWRNIGHT DELIWRY
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,lD 83702
Re: Case No. PAC-E-14-01
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
FOR AUTHORITY TO DECREASE RATES BY $2.8 MILLION TO RECOYER
DEFERRED NET POWER COSTS THROUGH THE ENERGY COST
ADJUSTMENT MECHAI\ISM
Dear Ms. Jewell:
Please find enclosed an original and nine (9) copies of Rocky Mountain Power's Application in
the above referenced matter, along with Rocky Mountain Power's direct testimony and exhibits.
Also enclosed is a CD containing the Application, direct testimony, exhibits and confidential
work papers.
All formal correspondence and questions regarding this Application should be addressed to:
Yvonne Hogle
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Telephone: [phone]
Fax: [phone]
Email : Yvonne.ho [e-mail]
Communications regarding discovery matters, including data requests issued to Rocky Mountain
Power, should be addressed to the following:
datareq uest@pacifi corp. com
Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR97232
Informal inquiries may be directed to Ted Weston" Idaho Regulatory Manager at (801) 220-
2963.
[-L*w^C
Vice President, Regulation and Government Affairs
Enclosures
CC: StevenD. Spirmer
Randall C. Budge
Brian Collins
James R. Smittr
Verytuly yours,
R. JeffRichards
Yvonne R. Hogle 0SB# 8930)
201 South Main Street, Suite 2300
Salt Lake City, Utah 8411I
Telephone No. [phone]
Facsimile No. [phone]
E-mail: [e-mail]
Attorneysfor RoclE Mountain Power
ENERGY COST
MECHANISM
ADJUSTMENT )
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BEX'ORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-14-01
oF ROCr(Y MOUNTAIN POWER FOR )
AUTHORITY TO DECREASE RATES BY ) APPLICATION OF ROCKY
$2.8 MTLLTON TO RECOVER DEFERRED ) MOUNTAIN POWER
NET POWER COSTS THROUGH THE )
Rocky Mountain Power, a division of PacifiCorp ("Company" or "Rocky
Mountain Power"), in accordance with Idatro Code $61-502, $61-503, and RP 052
hereby respectfully submits this application ("Application") to the Idaho Public Utilities
Commission ("Commission") pursuant to the Company's approved energy cost
adjustment mechanism ("ECAM"). The Company is requesting approval of
approximately $12.8 million deferred net power costs from the deferral period beginning
December l, 2012 through November 30, 2013 ("Deferral Period") and proposing to
revise Electric Service Schedule No. 94, Energy Cost Adjustment, to recover
approximately $13.2 million in total deferred net power costs for the collection period
beginning April I, 2014 through March 31, 2015. The $13.2 million includes an
amortization from Monsanto's and Agrium's share of 2011,2012 and 2013 deferrals, as
further explained below. Recovery of this amount represents a decrease of approximately
$2.8 million from Schedule 94 rates currently in effect as approved in Order No. 32771 in
Case No. PAC-E-13-03. Monsanto's and Agrium's rates will increase while all other
customers' rates will be reduced. Rocky Mountain Power respectfully requests that these
changes to Idaho rate Schedule 94 become effective on April l, 2014. In support of its
Application, Rocky Mountain Power states as follows:
1. Rocky Mountain Power is a division of PacifiCorp, an Oregon
corporation, which provides electric service to retail customers through its Rocky
Mountain Power division in the states of Idaho, Wyoming, and Utah. Rocky Mountain
Power is a public utility in the state of Idaho and is subject to the Commission's
jurisdiction with respect to its prices and terms of electric service to retail customers in
Idaho. Rocky Mountain Power is authorized to do business in the state of Idaho
providing retail electric service to approximately 73,600 customers in the state.
2. Communications regarding this filing should be addressed to:
Ted Weston
Idaho Regulatory Affairs Manager
Rocky Mountain Power
201 South Main, Suite 2300
salt Lake city, utah 8411I
Telephone : [phone]
Email : ted.weston@pacifi corp. com
Yvonne R. Hogle, Senior Counsel
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Telephone: [phone]
Email : [e-mail]
3. In addition, Rocky Mountain Power requests that all data requests
regarding this Application be sent in Microsoft Word to the following:
By email (preferred) : datarequest@paci fi corp. com
By regular mail: Data Request Response Center
PacifiCorp
825 Multnomah, Suite 2000
Portland, Oregon 97232
Informal questions may be directed to Ted Weston, Idaho Regulatory Affairs
Manager at [phone].
ECAM Overview
4. The ECAM became effective July 1, 2009, pursuant to an agreement
among parties in Case No. PAC-E-08-08, as approved by the Commission September 29,
2009, in Order No. 30904. The ECAM allows the Company to collect or credit the
difference between the acfual net power costs ("NPC") incurred to serve customers in
Idaho and the NPC collected from Idaho customers through rates set in general rate cases.
5. The costs that are included in the ECAM are NPC as defined in the
Company's general rate cases and modeled by the Company's production dispatch model
GRID. Specifically, NPC include amounts booked to the following FERC accounts:
o Account 447 (sales for resale, excluding on-system wholesale sales and
other revenues not modeled in GRID),
o Account 501 (fuel, steam generation, excluding fuel handling, start-up
fueUgas, diesel fuel, residual disposal and other costs not modeled in
GRID),
o Account 503 (steam from other sources),
o Account 547 (fuel, other generation),
o Account 555 (purchased power, excluding BPA residential exchange
credit pass-through if applicable), and
o Account 565 (transmission of electricity by others).
6. On a monthly basis, the Company compares the actual system net power
costs ("Actual NPC") to the net power costs embedded in then effective rates ("Base
NPC") from the general rate case during the Defenal Period and defers the difference
into the ECAM balancing account. This comparison is on a system-wide, dollar per
megawatt-hour basis.
7. In addition to the difference between Actual NPC and Base NPC, the
ECAM includes five additional components: the Load Change Adjustment Revenues
("LCAR"), a credit for SOz allowance sales, an adjustment for load control costs, an
adjustment for the treatment of coal stripping costs, i.e., Emerging Issues Task Force
("EITF") 04-6, and a true-up of 100 percent of the incremental Renewable Energy Credit
("REC") revenues from the amount approved by Commission Order No. 32196. These
components are described in more detail below.
8. Finally, the ECAM includes a symmetrical sharing band of 90 percent
(customers) I l0 percent (Company) that shares the differential between Actual NPC and
Base NPC, LCAR, SO2 sales, load control costs, and the coal stripping costs adjustment
between the customers and the Company. The sharing band is also described in more
detail below.
Chanees to ECAM Calculation
9. In accordance with Commission Order 32910 in Case No. PAC-E-13-04,
the Company has reflected changes to the ECAM calculation ordered by the
Commission, as described in detail in Mr. Brian Dickman's Direct Testimony.
4
Proposed Deferred ECAM Rate Chanees
10. In support of this Application, Rocky Mountain Power has filed the
testimony and exhibits of Company witnesses Brian Dickman and Joelle Steward. Mr.
Dickman's testimony and exhibit describe the Actual NPC incurred by the Company to
serve retail load for the historical twelve-month period ended November 30, 2013 and
explain the main differences between Actual NPC and Base NPC. Ms. Steward's
testimony supports the new ECAM tariff surcharge rates to be effective April 1,2014
through March 31,2015.
11. Commission Order No.32432 from Case No. PAC-E-ll-l2 approved a
stipulation entered into by parties in the Company's 2011 general rate case ("2011
GRC"), to amortize the 2013 ECAM deferral over two years for Monsanto and Agrium
(*2011 GRC Stipulation"). The proposed rate change for Monsanto and Agrium in this
case covers three ECAM deferral periods: 1) the third-year amortization of the 20ll
ECAM deferral for the period of December 1, 2010 through November 30,2011; 2) the
second-year amortization of the 20I2ECAM defenal for the period of December l,20ll
through November 30, 2012; and 3) the first-year amortization from the 2013 ECAM
deferral for the period of December 1,2012 through November 30,2013. The 201I GRC
Stipulation specified that amounts owed by Monsanto and Agrium related to the Deferral
Period in this case will be amortized over a two-year period. Monsanto's and Agrium's
share of the deferral balance from this Deferral Period is approximately $5.2 million and
$0.4 million, respectively. Thus, this filing includes the first-year of amortization of those
amounts: approximately $2.6 million for Monsanto and approximately $0.2 million for
Agrium. Combined, the amortization of the amounts from the three ECAM defenal
periods result in tariff surcharge rates in this case for Monsanto and Agrium in Schedule
94 of approximately $6.0 million and $0.5 million, respectively.
12. This Application is supported by Mr. Dickman's testimony and
confidential ExhibitNo. I ("Exhibit 1") which illustrates the detailed calculation of the
ECAM deferral. During the Deferral Period, the Base NPC in rates originated from 2011
GRC which set Base NPC for calendar year 2012 at $1.205 billion and for calendar year
2013 at $1.385 billion. The combined Base NPC for the Deferral Period is $1.369
billion.
13. The NPC deferral amount is calculated on a monthly basis by subtracting
the monthly Base NPC rate from the Actual NPC rate. The NPC rate is calculated by
dividing monthly NPC by the corresponding monthly load to express the costs on a dollar
per megawatt-hour basis. On a dollar per megawatt-hour basis, the Base NPC average
was$23.47 per megawatt-hour, and the Actual NPC averaged$26.02 per megawatt-hour,
$2.55 per megawatt-hour higher. The monthly incremental difference was multiplied by
Idaho's actual load during the Deferral Period. Idaho's load is separated into three
groups-tariff customers, Monsanto and Agrium-to calculate the deferral for each
group. For the twelve-month period ended November 30,2013, the NPC differential for
deferral was approximately $9.8 million before the 90/10 percent sharing band.
14. The LCAR is a symmetrical adjustment to offset over- or under-collection
of the Company's energy-related production revenue requirement, excluding NPC, due to
variances in Idaho load. The LCAR reduced the deferral balance by approximately $1.1
million before sharing due to higher usage during the Deferral Period.
6
15. Revenues from SOz emission allowance sales received by the Company
from December l, 2012 to November 30,2013 are also included as an offset to the NPC
deferral. This adjustment reduces the deferral by approximately $3,000 before sharing.
16. A fourth component of the ECAM tracks Idaho's share of incremental
load control costs. Commission Order 32432 specified that the load control costs would
be tracked in the ECAM. This adjustment reduces the deferral by $0.2 million before
sharing.
17. The fifth component of the ECAM is the difference between including
coal stripping costs recorded on the Company's books pursuant to the guidance of the
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs
when the coal was excavated. This adjustment increases the defenal by approximately
$4 1,000 before sharing.
18. The total NPC deferral adjusted for LCAR, SO2 revenue, load control, and
EITF 04-6 is subject to the sharing band between customers and the Company such that
customers paylreceive 90 percent of the increase/decrease in Actual NPC when compared
to Base NPC, and the Company incurs/retains the remaining 10 percent.
19. In addition to the ECAM calculation components discussed above, the
deferral balance reflects 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. During the
Deferral Period actual REC revenue was approximately $5.2 million lower than the
amount in base rates on an Idaho-allocated basis.
20. The deferred ECAM balance of $24.3 million as of November 30, 2013 is
the sum of uncollected deferrals from prior ECAM filings plus the components described
above for the Deferral Period: 90% X (deferred NPC + LCAR + SOz revenues *
incremental load control * coal stripping costs adjustment) + the impact of the REC
revenue true-up. lnterest is accrued on the uncollected balance at the Commission-
approved interest rate on customer deposits, currently I percent annually. Exhibit 1
illustrates the detailed calculations for tariff customers, with an ending balance of $9.9
million; Monsanto, with an ending balance of $13.4 million; and Agrium, with an ending
balance of $1.0 million.
Allocation of Deferred ECAM Balance to Retail Tariffs
21. Ms. Joelle Steward's testimony describes the calculation of the proposed
Schedule 94 rates. Exhibit 2 of Ms. Steward's testimony illustrates this calculation based
on metered loads, the line loss adjusted loads, the allocation of the ECAM price change,
and the percentage change by rate schedule based on the present revenues ordered in
Case No. PAC-E-13-04. Exhibit 3 is a clean and legislative copy of Electric Service
Schedule No. 94 containing the proposed rates by electric service schedule based on the
customer's delivery voltage of electric service.
22. Rocky Mountain Power is notiffing its customers of this Application by
means of a press release sent to local media orgarizations and messages in customers'
bills over the course of a billing cycle. The customer bill inserts will begin on February
7, 2014, and continue through the twenty-one day billing cycle. Copies of the press
release and bill insert are provided with the Application. In addition, copies of the
Application will be made available for review at the Company's local offices in its Idaho
service territory.
WHEREFORE, Rocky Mountain Power respectfully requests that the
Commission (1) issue an order authorizing that this matter be processed by Modified
Procedure; (2) approve the $12.8 million ECAM deferral for the 2013 Deferral Period;
and (3) implement the proposed Electric Service Schedule No. 94 as filed in Exhibit 3.
DATED this 31't day of January 2014.
Respectfully submitted,
ROCKY MOUNTAIN POWER
201 South Main Street, Suite
Salt Lake City, Utah 841l I
Telephone No. [phone]
Facsimile No. [phone]
E-mail: [e-mail]
Attorneyfor RoclE Mountain Power
-ROCKYMOUNTAINYPOwER\ a orvrsror oF PAcrFrcoRP
Price reduction proposed for most customers
BOISE, Idaho, Monday, Feb. 3, 2014-Rocky Mountain Power's annual energy cost
adjustment for 2014 proposes to reduce prices for residential, commercial, and inigation
customers, with a modest increase for two large industrial customers.
The energy cost adjustment mechanism is designed to track the difference between the
company's actual expenses for fuel and other costs to provide electricity to customers and
the amount collected recently from customers through current prices. Pending
commission approval, the adjustment would take effect April 1, 2014.
Under Rocky Mountain Power's proposal, all but two large industrial customers will see
a reduction in their electric prices. The proposed adjustment will allow Rocky Mountain
Power to continue to provide safe, reliable electric service to its customers.
The company's proposal requests that the Idaho Public Utilities Commission approve
deferral of the 2013 energy related costs of $12.8 million and reduce revenues collected
through the energy cost adjustment mechanism, Schedule 94, by $2.8 million.
The proposal would have the following impacts on prices:o Residential customers - $1.5 million decrease or 2.0 percento Commercial and most industrial customers - $1.3 million decrease ranging from
2.1 percent to 3.2 percent, depending on the rate scheduleo Irrigation customers - $1.5 million decrease or 2.4 percento Industrial customer, tariff Schedule 400 - $1.4 million increase or 1.7 percento Industrial customer, Schedule 401 - $0.1 million increase or 2.1 percent
The public will have an opportunity to comment on the proposal during the coming
months as the commission studies the company's request. The commission must approve
the proposed changes before they can take effect. A copy of the company's application is
available for public review at the commission offices in Boise and at the company's
offices in Rexburg, Preston, Shelley and Montpelier.
For information contact Media Hotline: [phone]
Annual enerqv cost adiustment proposal
Idaho Public Utilities Commission
www.puc.idaho.gov
472W. Washington
Boise, lD 83702
Rocky Mountain Power officeso Rexburg - 25 East Maino Preston - 509 S. 2nd Easto Shelley -852 E. 1400 North
###
Annual energy cost
adjustment proposal
Price reduction proposed
for most customers
Rocky Mountain Power requests
recovery of power costs.
On January 31, 2014, Rocky Mountain Power asked
the Idaho Public Utilities Commission to approve the
2013 deferral of $12.8 million to the energy balancing
account and adjust the energy cost adjustment rider
down by $2.8 million. Under Rocky Mountain Power's
proposal all but two large industrial customers will
see a reduction to their prices from this adjustment.
The company is proposing to reduce all prices
with the exception of tariff contract Schedules 400
and 401. The proposed adjustment will allow
Rocky Mountain Power to continue to provide safe,
reliable electric service to its customers.
The energy cost adjustment mechanism is designed
to track the difference between the company's actual
costs to provide electricity to Idaho customers and
the amount collected from customers through current
prices. Pending commission approval, the price
change would take effect April 1,,2074.
The proposed price changes would have the
following impacts:
. Residential Schedule 1
1.9 percent decrease
. Residential Schedule 35
2.3 percent decrease
. General Service Schedule 6
2.6 percent decrease
. General Service Schedule 9
3.2 percent decrease (continued)
. Irrigation Service Schedule 10
2.4 percent decrease
. Comm & Ind. Heating Schedule 19
2.6 percent decrease
. General Service Schedule 23
2.2 percent decrease
. General Service Schedule 35
2.6 percent decrease
. Public Street Lighting
1.0 percent decrease
. Tariff Contract 400
1.7 percent increase
. Tariff Contract 401
2.1 percent increase
The public will have an opportunity to comment
on the proposal during the coming months as
the commission studies the company's request.
The commission must approve the proposed changes
before they can take effect. A copy of the company's
application is available for public review at the
commission offices in Boise and at the company's
offices in Rexburg, Prestory Shelley and Montpelier.
ldaho Public Utilities Commission
477Vf Washington
Boise,lD 83702
www.puc.idaho.gov/
Rocky Mountain Power offices
. Rexburg- 25 East Main
. Preston - 509 S. 2nd E.
. Shelley - 852 E. 1400 N.
. Montpelier - 24852U5 Hwy 89
For more information about your prices and price
schedule, go to rockymountainpowennet/rates.
ROCKY MOUNTAIN
PIOWER
@ 2014 Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOT]NTAIN POWER FOR
AUTHORITY TO DECREASE RATES BY
$2.8 MILLION TO RECOYER DEFERRED
NET POWER COSTS THROUGH TIIE
ENERGY COST ADJUSTMENT
MECHANISM
ROCKY MOUNTAIN POWER
CASE NO. PAC.E.14-01
DIRECT TESTIMOI\TY OF
BRIAN S. DICKMAN
CASE NO. PAC-E.14.0I
January 2014
I Q. Please state your name, business address and present position with
2 PacifiCorp, dba Roclry Mountain Power (the ftCompany").
3 A. My name is Brian S. Dickman. My business address is 825 NE Multnomah Street,
4 Suite 600, Portland, Oregon 97232. My title is Manager, Net Power Costs.
5 Qualifications
6 a. Briefly describe your education and business experience.
7 A. I received a Master of Business Administration from the University of Utah with
8 an emphasis in finance and a Bachelor of Science degree in accounting from Utah
9 State University. Prior to joining the Company, I was employed as an analyst for
10 Duke Energy Trading and Marketing. I have been employed by the Company
11 since 2003 including positions in revenue requirement and regulatory affairs, and
12 I assumed my current role managing the Company's net power cost group in
13 March 2012.
14 a. Have you testified in previous regulatory proceedings?
15 A. Yes. I have filed testimony in proceedings before the public service commissions
16 in California,Idaho, Oregon, Utah, and Wyoming.
17 Summary of Testimony
l8 a. What is the purpose of your testimony in this proceeding?
19 A. My testimony presents the Company's calculation of the Energy Cost Adjustment
20 Mechanism ("ECAM") balancing account for the l2-month period from
2l December l, 2012 through November 30, 2013 ("Deferral Period"). More
22 specifically, my testimony provides the following:
23 o A sunmary of the ECAM calculation, including changes made to comply
Dickman, Di - 1
Rocky Mountain Power
I with recent Commission orders.
2 r Details supporting the addition of $12.8 million ("2013 Deferral") to the
3 deferral balance, bringing the total balance of the account to $24.3
4 million as of November 30, 2013.
5 o Additional details of the ECAM calculation and a description of the
6 Company's net power costs ("NPC").
7 a. Are additional witnesses presenting testimony in this case?
8 A. Yes. Ms. Joelle R. Steward, Director, Pricing, Cost of Service & Regulatory
9 Operations, is sponsoring testimony supporting the Company's proposed ECAM
10 collection rates in Schedule 94. The Company is proposing to modifu electric
ll service Schedule 94 effective April 1,2014, so the Company would collect
12 approximately $13.2 million on an annual basis as compared to the current
13 collection rate of approximately $16.0 million.
14 Summary of the ECAM Deferral Calculation
15 a. Please briefly describe the Company's ECAM authorized by the
16 Commission.
17 A. In general, the ECAM tracks deviations between actual NPC and the NPC in base
18 rates and defers 90 percent of the difference for later recovery.r Other items, such
19 as sales of sulfur dioxide ('oSOz") emission allowances or renewable energy
20 credits ("RECs"), are also accounted for in the ECAM as a mechanism to true up
2l to actual experience. The balance that accumulates over a deferral period is then
22 passed on to customers as arate surcharge or credit. The ECAM Schedule 94 rate,
t OrderNo. 30904 in Case No. PAC-E-08-08 approved the stipulation entered into by the Commission
Stafi the Idaho lrrigation Pumpers Association, Monsanto and the Company that set up the structure and
content of the ECAM mechanism.
Dickman, Di -2
Rocky Mountain Power
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which appears as a separate line item on customer bills, collects or credits to
customers the balance of deferred costs. Schedule 94 is adjusted as needed in the
Company's annual ECAM filings. The annual defenal period for the ECAM is
December I to November 30. The Company is required to file an application with
the Commission by February 1 of each year to seek approval of the defenal
amount and to adjust the ECAM rate effective April l.
How are the 2013 ECAM deferral calculations presented in your testimony?
The 2013 ECAM deferral calculations are contained in Exhibit No. 1. A summary
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. 1.
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 in Case No. PAC-E-
13-04, the Company has modified the ECAM calculation by removing the
wholesale sales line loss adjustment from the calculation of Monsanto and
Agrium's actual load for the calculation of all deferral balances except for the
Load Change Adjustment Revenue ("LCAR"). This change applies from June l,
2013 to November 30, 2013. Starting December l, 2013, the ECAM will be
calculated on a total Idaho basis; Monsanto and Agrium's share will not be
calculated separately.
The Company also updated the LCAR calculation by using the 201I load
reported in the Annual Result of Operations report as the base load for purposes of
the ECAM deferral, consistent with the stipulation approved in Order No. 32432 in
Case No. PAC-E-ll-Iz (*2011 Rate Case").
Dickman, Di - 3
Rocky Mountain Power
a.
A.
I Beginning January 1,2015, pursuant to the stipulation in Case No. PAC-
2 E-13-04 the ECAM will include a resource adder to recover the investment in the
3 new Lake Side II generation facility until it is reflected in rates as a component of
4 rate base. The ECAM deferral will be based on the Lake Side II actual generation
5 multiplied by $1.994{WH, and capped at a total of $5.43 million or 2,729,500
6 MWh. Lake Side II is currently expected to reach commercial operation by June
7 2014.
8 Incremental2013Deferral
9 a. Please describe the ECAM components that make up the 2013 Deferral.
10 A. The 2013 Deferral is the sum of customers' 90 percent share of the following
1l items: the difference between the actual and in-rates NPC, the LCAR, the SOz
12 allowance sales, the load control cost adjustment, and the Emerging Issues Task
13 Force ("EITF") 04-6 coal cost adjustrnent. An additional true-up of 100 percent of
14 the revenue difference from the sale of RECs is also included. Detailed
15 calculations are provided in Exhibit No. 1 attached to my testimony, and Table I
16 below summarizes the various components making up the defenal.
Dickman, Di - 4
Rocky Mountain Power
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Table I
Summary of ECAM Deferral Account Balance
Please explain the calculation of the ECAM balance for the Deferral Period.
Table I above summarizes the components of the ECAM balance, broken into
three customer groups. The first section summarizes the Idaho-allocated share of
those items for which Idaho customers and the Company share responsibility:
NPC differential, LCAR, SOz sales, load control costs, and the EITF 04-6
adjustment. The next section calculates the 90 percent customer share of the
above items and adds in the Idaho-allocated REC revenue true-up, for which
customers are refunded or surcharged 100 percent of the difference. The total of
Dickman, Di - 5
Rocky Mountain Power
NPC Differential for Deferral
LCAR
Loa d Control
EITF 04-6 Adjustment
stomer Reponsibility
REC Deferral
Company Recorrery for NPC Deferral 7
Balancing Account Activity
Prior Deferral
ECAM Reven ue Col I ection
lnterest
Tariff
Customers
5,784,623
(92s,283)
(1,5ss)
(148,7s0)
38,8s2
4,747,787
4,273,O08
2,951,681
L4,O33,226
( 11,532,615)
2,624,U2
9,8s8,732
Monsanto
3,7t4,394
1264,2s41
(1,310)
(60,791)
t,737
3,389,777
3,050,799
2,t05,280
11,850,355
8,735,44L1
8,245,855
8,tr01,935
Agrium
292,377
(3,987)
(113)
(4,34t1
4t
283,977
255,579
L63,432
419,011
u5,42L
(257,27L1
s97,833
t,0t6,w
902,156
451,O78
756,424
154,4L8
Total
9,79r,394
(1,193,
40,631
8,42t,54t
7,579,387
5,230,394
12.809.781
26,729,O03
Through Norember 30, 2013
November 30, 2013 Balance For Collectlon
dule 94 Collection - Dec 2013 - March
20L4
Expected Balance as of April 1, 2014
edule 94Collection -April 2014- March
Balance as of April 1, 2015
2014 Deferral)
Amortization
2012 ECAM Balance (2011 Deferral) - 3 YrAmortization
2013 ECAM Balance (2012 Deferral) - 3 YrAmortization
14 ECAM Balance ll - 2YrAmortization
6,787,4L6 11,901,886
5,950,943
2,26L,074
2,lLs,024
1t,467,730
24,277,51L
19,591Fs9
5,4/J,2,021
2,4L7,498
2,269,442
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these items constitutes the 2013 Deferral. The 2013 Defenal of $12.8 million is
primarily a result of the $8.8 million customers' share of the NPC differential and
the $5.2 million REC revenue differential. The increase in these components is
partially offset by the $1.1 million credit for the customers' share of the LCAR
adjustnent.
The next section, Balancing Account Activity, starts with the $26.7
million balance in the ECAM deferral account as approved in Order No. 32597.
That balance is adjusted for collections and interest accrued during the Deferral
Period. When the 2013 Deferral is added, the total outstanding balance as of
November 30,2013 is $24.3 million. The final rows in Table I illustrate the
expected Schedule 94 collections between December 1,2013, ffid March 31,
2014, and then over the next collection period from April 1,2014, to March 31,
2015. Finally, the table shows the annual amount that would need to be collected
from Monsanto and Agrium according to the multi-year amortization schedules
agreed to in the settlement agreement approved by the Commission in the 2011
Rate Case.
Based on your calculations, what is the balance expected to be in the ECAM
deferral account as ofApril lr20l4?
As of April l, 2014, there will be an estimated balance of $19.6 million due for
collection-Monsanto is responsible for $l 1.9 million, Agrium is responsible for
$0.9 million, and the remaining $6.8 million will be due from other retail
customers.
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Rocky Mountain Power
1 Q. What is the proposed collection amount due from customers under Schedule
2 94 beginning April 1,2014?
3 A. As discussed by Company witness Ms. Steward, the Company proposes to collect
4 $6.8 million from retail tariff customers beginning April l, 2014. The surcharge
5 rate for Monsanto and Agrium will be set at approximately $6.4 million,
6 combined, to reflect the multiple arnortization periods outlined in the 2011 Rate
7 Case stipulation. Ms. Steward's testimony details the rate impact of the updated
8 ECAM collections.
9 a. The stipulation in the 2011 Rate Case stated the Company would track in the
l0 ECAM ldaho's share of the customer load control service credit for the
1l irrigation load control program. Have you included an adjustment to true up
12 these expenses?
13 A. Yes. The Company has included a reduction of $213,882, prior to the 90 / l0
14 sharing, as an adjustment to true up the Idaho allocated load control service costs.
l5 This reduction to the ECAM defenal calculation can be seen on line 40 of Exhibit
16 No. 1.
17 Summary of the NPC Differences
18 a. Please explain the difference between adjusted actual NPC ("Actual NPC")
19 and the NPC in base rates ('6Base NPC").
20 A. On a total Company basis, Actual NPC for the Deferral Period were
2l approximately $1.569 billion. During the Deferral Period, the Base NPC in rates
22 originated from the 2011 Rate Case. The stipulation approved in that case
23 established Base NPC for 2012 and 2013. Base NPC for 2012 were set at $1.205
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billion and the Base NPC for 2013 were set at $1.385 billion. The combined Base
NPC for the Deferral Period is $1.369 billion.
Did the Company anticipate that the actual NPC would be higher than the
NPC included in rates during the Deferral Period?
Yes. Mr. J. Ted Weston's testimony supporting the stipulation in the 2011 Rate
Case described that increasing NPC was a significant driver of the overall rate
increase sought in that case. He explained that the stipulation in 2011 Rate Case
spread the known increase in NPC over a period of two years in order to mitigate
the rate impact of the rate case.2 Mr. Weston cited that as of November 201 I the
Company expected actual NPC to be $1.35 billion in20l1 and over $1.5 billion in
2012. Actual NPC were $1.39 billion for 2011 and $1.50 billion in2012. He also
stated, "Ultimately, 90 percent of the difference between actual net power costs
and in-rates net power costs will be deferred and collected in the ECAM,
customers get the benefit of the delay in paying the higher level until the costs
become "actual" and also benefit from 10 percent of the incremental difference
not being included in the ECAM deferral."
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. 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.3 These first two items are the main
' Case No. PAC-E-l l-12, Testimony of J. Ted Weston at 7-8.
' Case No. PAC-E-13-04, Stipulation Testimony of J. Ted Weston at 3-4.
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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 enter
into the alternative rate plan.a
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.
a. 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 2012 tluolgh August 2013, projected an incremental
deferral of $10.3 million through August 2013. The final ECAM calculation
provided in Exhibit No. 1 calculates a $10.1 million deferral for the same period.
What are the major drivers that result in a difference between Actual NPC
and Base NPC?
The $200 million difference on a total company basis between the combined Base
NPC and Actual NPC in the Defenal Period is summarized in Table 2 by major
category in the NPC report.
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Rocky Mountain Power
n Case No. PAC-E-13-04, Stipulation Testimony of J. Ted Weston at 9-10.
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Table 2
Base I\PC $1,369
Inc reas e/(Dec reas e) to I\PC:
Wholesale Sales Revenue
Purchased Power Eryense
Coal Fuel Eryense
Natural Cas E>pense
Wheeling, Hydro and Other E>penses (7
Total Increase/@ecrease) $257
Setflement Adjustment (57 .
AdjustedActuat I\[PC $1569
q3
(ls4
74
Deferral Period IriPC Reconciliation millions
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
that case included a "black box" adjustment to determine Base NPC in rates
during 2012 and20l3.
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
fuel expense is partially offset by reduced purchased power and natural gas fuel
expenses. Higher load and lower hydro generation also contributed to higher costs
compared to Base NPC.
Please explain the reduction in wholesale sales revenue.
The reduction in wholesale sales revenue is driven by the expiration of four long-
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term sales contracts and reduced revenue from 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 expired prior to the end of the Defenal Period. This accounted for a $66
million reduction in wholesale sales revenue and a 1.9 million MWh reduction in
sales volume.
Revenue from market transactions (represented in GRID as short-term
firm and system balancing sales) is approximately $339 million lower than Base
NPC. The drop in revenue is due primarily to a reduction in the average price of
market sales transactions. Market sales transactions in the 2011 Rate Case were
included at an average price of $52.43llt4Wh, while actual market sales during the
Deferral Period were done at an average price of $29.36lltlWh.
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 Disfrict
("PUD"), Chelan County PUD, 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 an approximately $70 million reduction in purchased power
expense. In addition, expenses related to several qualifying facility ("QF")
contracts were reduced approximately $46 million due to the customers utilizing
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the QF generation to serve their own load.
Expenses from market transactions (represented in GRID as short-term
firm and system balancing purchases) are approximately $102 million lower than
Base NPC. The 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 four new wind qualifring facilities in Idaho that had little or no
generation in Base NPC, increasing purchased power expense approximately $26
million. These include the Power County North and South QFs which came
online at the end of 2011, and the Five Pine and North Point QFs which came
online at the end of 2012.In addition, during the Deferral Period the Company
purchased the output of the West Valley generating station under a tolling
agreement.
Please explain the change in natural gas and coal fuel expense.
Natural gas market prices were approximately 15 percent lower in the Defenal
Period compared to the prices assumed in the Base NPC. Lower market prices
contributed to an increase in natural gas generation volume of 1,910 GWh (32
percent), but the increase in generation volume is more than offset by a reduction
in the total cost per MWh of natural gas generation. Coal generation volume
increased by 1,721 GWh (four percent) contributing to an overall increase of $74
million in coal fuel expense. The average cost of coal generation increased from
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$16.60/Ir4Wh in Base NPC to $17.644{Wh in the Deferral Period.
a. How did changes in load and hydro generation impact NPC?
A. Actual system load during the deferral period was 2,071 GWh (four percent)
higher than the load in Base NPC, and hydro generation in the Defenal Period
was 608 GWh (15 percent) lower than in Base NPC. Higher load and lower hydro
generation contribute to the reduced wholesale sales revenue and increased
purchased power expenses shown in Table 2.
Description of the ECAM Calculations
a. Please describe the ECAM calculations in Exhibit No. 1.
A. The ECAM deferral 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. I details the ECAM
calculation and contains supporting information, portions of which are
confidential.
a. How are the Base NPC and Actual NPC dollar per megawatt-hour rates
calculated?
A. The monthly NPC for Base NPC in the Deferral Period are divided by the
corresponding monthly normalized load to express the costs on a dollar per
megawatt-hour basis (Exhibit No. l, line l). The Actual NPC rate on a dollar per
megawatt-hour basis is calculated by dividing the monthly Actual NPC by the
actual monthly system load (Exhibit No. l, line 8). On a dollar per megawatt-hour
basis, the Base NPC average is $23.47 per megawatt-hour, and the Actual NPC
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averaged $26.02 per megawatt-hour, $2.55 per megawatt-hour higher.
Please describe how the NPC deferral is calculated.
The defenal 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 three groups of actual Idaho retail load at
input: tariff customers, Monsanto, and Agrium (Exhibit No. 1, lines 10 through
12) to calculate the NPC differential for deferral for each customer group,
(Exhibit No. l, lines 14 through 16). For the l2-month period ended November
2013 the NPC differential was approximately $9.8 million before application of
the 90 / 10 sharing.
What costs are included in the NPC differential for deferral?
The NPC differential for defenal captures all components of NPC as defined in
the Company's general rate case proceedings and modeled by the Company's
production dispatch model ("GR[D"). 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
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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 remove
entries that are not included in the determination of the Company's Base NPC for
regulatory pulposes, such as out of period accounting entries. In addition, Actual
NPC adjustments are applied to reflect prior Commission approved adjustments,
such as the revenue imputation of the sales contract with the Sacramento
Municipal Utility District and removal of the effect of special contract customers
buying through curtailment.
What constitutes an out of period accounting entry?
Out of period accounting entries are items booked during the Deferral Period but
that pertain to an operating period prior to the inception of the ECAM on July 1,
2009.
Why is the cutoff of July 1, 2009, used to demarcate 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 sharing. As a result, 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
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inception of the ECAM should not impact the ECAM defenal.
In addition to the comparison of Actual NPC to Base NPC, what other
components are included in the ECAM?
There are five 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
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, and (v) a true-up of REC revenues as authorized by the
Commission in Order No. 32196.
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-l0-
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. 1, lines 18 through 20),
from actual Idaho load at input ("Actual Load" shown in Exhibit No. 1, lines 22
through 24). The difference (Exhibit No. 1, lines 26 through 28) is then multiplied
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by the LCAR of $5.47 per megawatt-hour in all months of the Deferral Period
(Exhibit No. l, line 30) to arrive at the LCAR adjustment (Exhibit No. l, lines 31
through 33) of ($1,193,524) before the 90 / l0 sharing.
How are SOz sales revenues included in the ECAM?
Line 35 of Exhibit No. I contains the SOz sales revenue during the Defenal
Period on a total Company basis. Line 37 of Exhibit No. 1 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 $3,078 reduction to
the NPC deferral balance before the 90 / l0 sharing.
How is the adjustment for load control costs 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 201I Rate Case established the base amount to be
tracked in the ECAM as $1,045,423. ldaho-allocated actual load contol costs
during the Deferral Period were approximately $831,540. The difference, shown
on line 40 of Exhibit No. 1, is included as a $213,882 reduction to the NPC
deferral balance before the 90 / 10 sharing.
How is the adjustment for accounting pronouncement EITF 04-6 included in
the ECAM?
Line 41 of Exhibit No. 1 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
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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
$40,631 increase to the NPC defenal balance before the 90 / l0 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. Lines 55 through 58 of Exhibit No. 1 represent the
customers' 90 percent share of the monthly deferral shown on lines 50 through 53
of Exhibit No. 1. For the Deferral Period, the customers' share of the deferred
balance is approximately $7.6 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 reyenue true-up in the current filing?
As authorizedby the Commission in Case No. PAC-E-I0-07, 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 $1.3 million, a difference
of $5.2 million (Exhibit No. 1, line 6l).
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What is the total ECAM deferred balance as calculated in Exhibit No. 1?
The total ECAM deferred balance as of November 30, 2013 is $24.3 million,
shown on line 88 of Exhibit No. l.
How is this balance divided among customers?
The ECAM deferral is divided into three customer groups based on each group's
actual load during the defenal period. Of the $24.3 million, $9.9 million is
allocated to the tariff customers (Exhibit No. 1, Line 73), $13.4 million to
Monsanto (Exhibit No. 1, Line 80) and $1.0 million to Agrium (Exhibit No. l,
Line 87). The Company will amortize and collect Monsanto's and Agrium's share
of the Commission-approved 2013 Deferral over two years pursuant to the
stipulation in the 2011 Rate Case. Beginning December 1,2013, future ECAM
defenals will be calculated on total company basis; Monsanto's and Agrium's
share will not be divided out and deferred separately. However, the existing
balances will continue 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.
Does this conclude your direct testimony?
Yes.
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CONFIDENTIAL
Case No. PAC-E-14-01
ExhibitNo. I
Witness: Brian S. Dickman
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Brian S. Dickman
Jamrary 2014
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
BEX'ORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOI]NTAIN POWER FOR
AUTHORITY TO DECREASE RATES BY
$2.8 MILLION TO RECOVER DEFERRED
NET POWER COSTS THROUGH THE
ENERGY COST ADJUSTMENT
MECHANISM
ROCKY MOUNTAIN POWER
CASE NO. PAC-E.14.01
DIRECT TESTIMOI\"Y OF
JOELLE R. STEWARI)
CASE NO. PAC-E-14.01
January 2014
1 Q. Please state your name, business address and present position with
2 PacifiCorp, dba Roclty Mountain Power ("the Company").
3 A. My name is Joelle R. Steward. My business address is 825 NE Multnomah Street,
4 Suite 2000, Portland, Oregon 97232. My present position is Director of Pricing,
5 Cost of Service, and Regulatory Operations in the Regulation Department.
6 Qualifications
7 Q. Briefly describe your education and business experience.
8 A. I have a B.A. degree in Political Science from the University of Oregon and an
9 M.A. in Public Affairs from the Hubert Humphrey Institute of Public Policy at the
10 University of Minnesota. Between 1999 and March 2007,I was employed as a
1l Regulatory Analyst with the Washington Utilities and Transportation
12 Commission. I joined the Company in March 2007 as Regulatory Manager,
13 responsible for all regulatory filings and proceedings in Oregon. I assumed my
14 current position in February 2012.
15 a. Have you appeared as a witness in previous regulatory proceedings?
16 A. Yes. I have testified in regulatory proceedings in Idaho, Oregon, Utah,
17 Washington and Wyoming.
l8 a. What is the purpose of your testimony in this proceeding?
19 A. I support the Company's proposed rates in this case.
20 Background
2l a. What level of revenues is Schedule 94, Energy Cost Adjustment, currently
22 designed to collect?
23 A. Schedule 94 is designed to collect approximately $16.0 million-$4.5 million for
Steward, Di - I
Rocky Mountain Power
1 Tariff Contract 400, $0.3 million for Tariff Contract 401, and $11.1 million for
2 the standard tariff customers-based on Idaho loads from Case No. PAC-E-I3-04.
3 Proposed Rate Change for Schedule 94
a. Please describe Roclry Mountain Power's proposed rate change in this case.
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In this 20l4Energy Cost Adjustment Mechanism ("ECAM") filing, the Company
proposes to change its current ECAM surcharge collection rates. For Tariff
Contracts 400 and 401, the Company proposes to increase the tariff surcharge
rates in Tariff Schedule 94 with a collection rate of approximately $6.0 million
and $0.5 million, respectively, on an annual basis from April l, 2014 to March 31,
2015. For standard tariff customers, the Company proposes to decrease the tariff
surcharge rates in Tariff Schedule 94 with a collection rate of approximately $6.8
million on an annual basis from April l, 2014to March 31,2015.
Why is the Company proposing to decrease the ECAM collection rates for
standard tariff customers?
Based on2012loads and the present rates authorized in Case No. PAC-E-13-04
the Company projects that the annual revenue collected from Schedule 94
surcharge for standard tariff customers would be approximately $11.1 million,
about $4.3 million more than the $6.8 million projected ECAM balance as of
March 31,2014, as supported in Table I in Mr. Brian S. Dickman's testimony,
filed concurrently with mine. Therefore, the Company proposes to decrease
Schedule 94 rates for these customers to collect approximately $6.8 million.
Please explain the proposed rate change for TariffContracts 400 and 401.
In the Company's 20ll general rate case, Case No. PAC-E-LI-L2, the parties
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stipulated and Commission Order No. 32432 approved a plan to phase-in the rate
impact from the 2011, 2012, and 2013 ECAM deferrals for these tariff contracts.
The proposed rate change for Tariff Contracts 400 and 401 covers the
amortization for the three ECAM deferral periods: The first deferral period is for
the 20ll ECAM deferral period of December 1,2010 through November 30,
2011. This defenal is being amortized over three years. This filing includes the
third year of amortization for that deferral-[2.4 million for Tariff Contract 400
and $0.2 million for Tariff Contract 401.
The second defenal period is for the 2012 ECAM deferral period of
December l,20ll through November 30,2012, and is also being amortized over
three years. This filing includes the second year of amortization for that
deferral-$2.1 million for Tariff Contract 400 and $0.1 million for Tariff Contract
40t.
The third is for the 2013 ECAM deferral period of December 1,2012
through November 30,2013. As supported in Mr. Dickman's testimony, Tariff
Contract 400 is responsible for $5.2 million and Tariff Contract 401 is responsible
for $0.4 million. Commission OrderNo.32432 approved amortization ofthe 2013
ECAM deferral amounts over two years. Therefore, this filing includes $2.6
million for TariffContract 400 and $0.2 million for Tariff Contract 401, which is
one-half of their total applicable 2013 ECAM deferral amounts.
The combined amortization of the three ECAM deferral periods for Tariff
Contracts 400 and 401 equal approximately $6.0 million and $0.5 million,
respectively on an annual basis. Schedule 94 surcharge rates have been designed
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to collect these annual amounts from these customers. The Company will track
the recovery of the three different deferral period amounts by proportioning the
collections consistent with each contract customers' annual arrortization balance.
For example, Tariff Contract 400's 201I ECAM deferral amortization amount is
30.2 percent of the total collection target of $6.0 million, so 30.2 percent of the
collections from Schedule 94 from April l, 2014 to March 31, 2015, will be
applied against the20ll ECAM defenal balance.
What is the impact from the above ECAM rate change proposals?
As summarized inmy Exhibit No. 2, these rate change proposals result in a 1.7
percent increase for Tariff Contract 400, a 2.1 percent increase for Tariff Contract
401 and a2.3 percent decrease for standard tariff customers.
Proposed Rates for Schedule 94
a. How were the proposed Schedule 94 rates developed for Tariff Contract 400
and Tariff Contract 401?
A. The proposed rates for these two customers were developed by dividing their total
collection targets identified above with their 2012 kwh consumption at the
transmission voltage level. This results in the proposed Schedule 94 rates of 0.425
cents per kWh for Tariff Contract 400, and 0.423 cents per kWh for Tariff
Contract 401.
How were the proposed Schedule 94 rates developed for standard tariff
customers?
A. The proposed rates for standard tariff customers were developed in three steps.
First, their kWh consumption at the generation level was developed by multiplying
Steward, Di - 4
Rocky Mountain Power
a.
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10 a.
their retail loads at the delivery service voltage level with the corresponding line
loss factors. Next, an overall average rate atthe generation level was developed by
dividing their total collection target identified above with their kWh consumption
at the generation level. Last, the proposed rates by delivery voltage level were
developed by multiplying the above overall average rate at the generation level
with the corresponding line loss factors. As the result, the Company proposes
Schedule 94 rates of 0.348, 0.336 and 0.327 cents per kWh for secondary, primary
and transmission delivery service voltages, respectively, for standard tariff
customers.
Please describe Exhibit No. 2.
Exhibit No. 2 illustrates the 2012 metered loads, the line loss adjusted loads, the
allocation of the ECAM price change, and the percentage change by rate schedule
based on the ordered revenues from Case No. PAC-E-13-04.
Please describe Exhibit No. 3.
Exhibit No. 3 contains clean and legislative copies of the proposed Electric Service
Schedule No. 94, Energy Cost Adjustment, designed to collect approximately
$13.2 million of the ECAM deferred balance. Consistent with the ECAM, the
Company proposes the new rates become effective April l, 2014.
Does this conclude your testimony?
Yes.
Steward, Di - 5
Rocky Mountain Power
11 A.
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Case No. PAC-E-14-01
ExhibitNo.2
Witness: Joelle R. Steward
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Jamtary 2014
Rocky Mountain Power
Exhibit No. 2 Page 1 ol 1
Case No. PAC-E-I+01
Witness: Joelle R. Stewardil il$[
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Exhibit No. 3
Witness: Joelle R. Steward
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Joelle R. Steward
January 2014
ROCKY MOUNTAIN
POWER
A OMSION OF NAC|NCOAP
Rocky Mountain Power
Exhibit No. 3 Page 1 of 2
Case No. PAC-E-'|4-01
Witness: Joelle R. Steward
Fourth Revision of Sheet No. 94.1
Cancelling Third Revision of Sheet No. 94.1LP.U.C. No. I
ROCI(Y MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO.94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the
accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power
Cost calculated on a cents per kWh basis.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bills shall have applied the following cents per kilowaff-hour rate by delivery voltage.
Deliverv Voltaee
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
Schedule
SecondaryI 0.3481 per kWh6 0.3481 per kWh6A 0.3489 per kWh7 0.3481 per kWh7A 0.3480 per kWh
9l0 0.3481, per kWh
1l 0.3480 per kWh12 0.348i per kWh19 0.348(, per kWh23 03480 per kWh23A 0.348(, per kWh24 0.3480 per kWh35 0.348( per kWh35A 0.348( per kWh36 0.348i per kWh
400
401
Primary
0.336i, per kWh
0.3360 per kWh
0.3361, per kWh
0.336i, per kWh
0.336(, per kWh
0.3360 per kWh
0.336(, per kWh
Transmission
0.3271, per kWh
0.425i, per kWh
0.423(, per kWh
Submitted Under Case No. PAC-E-14-01
ISSUED: January 31,2014 EFF'ECTIYE: April l, 2014
YffifiEXYOUNTAIN
I.P.U.C. No. I
Rocky Mountain Power
Exhibit No. 3 Page 2 of 2
Case No. PAC-E-14-01
Witness: Joelle R. Steward
+hir+FourtlL Revision of Sheet No.94.1
Cancelling Secen+ElfgLRevision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERYICE SCHEDULE NO.94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the
accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power
Cost calculated on a cents per kWh basis.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bills shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Delivery VoltaseSecondary Primarv Transmission
Schedule I 0.348+569P per kWh
Schedule 6 0.34805691 per kWh 0.336055ry per kWh
Schedule 6A 0348e'#9( per kWh 0.336055ry per kWh
Schedule 7 0343U569.d per kWh
Schedule 7A 0.34E0569P per kWh
Schedule 9
Schedule l0 0.3480$69+-per kWh
Schedule l1 0.3+8e569fper kWh
Schedule 12 OS48gS694per kWh
Schedule 19 0. j480569fper kWh
Schedule 23 0.34!10569#per kWh 0.336055efper kWh
Schedule 23A 0.34E0S69#per kWh 0.336055e#per kWh
Schedule 24 0.34EgS69#-per kWh 0.336055e#per kWh
Schedule 35 W+8e.a69fper kWh 0.3360550#per kWh
Schedule 35A W+8e569#per kWh 0.336055e#per kWh
Schedule 36 L3+805694per kWh
Schedule 400
Schedule 401
0.$ry0 per kWh
0.3?44250 per kWh
03A+423_i perkWh
Submitted Under Case No. PAC-E-14-0I4S3
ISSUED: Januarv 3 lMare'h418, X+3A14 EFFECTM: April l,20Wl