20120201Application.pdf

~~OUNTAIN c \..::J
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M~ Q; sgt\. i J -201 South Main, Suite 2300
Salt Lake City, Utah 84111
Febru 1,2012
VI OVERNIGHT DELIVERY
Jean D. Jewell
Commssion Secreta
Idaho Public Utilities Commssion
472 W. Washigton
Boise, ID 83702
Re: Case No. PAC-E-12-03
In the Matter of the Application of Rocky Mountain Power for Authority to Increase
Rates by $2.6 Milion to Recover Deferred Net Power Costs Though the Energy Cost
Adjustment Mechansm
Dear Ms. Jewell:
Please find enclosed an original and nine copies of Rocky Mountain Power's Application in the
above referenced matter, along with Rocky Mounta Power's direct testimony and exhbits.
Also enclosed is a CD contaning the Application, direct testimony, exhbits and confdential
work papers.
All formal correspondence and questions regarding ths Application should be addrssed to:
Ted Weston
Rocky Mounta Power
201 South Main, Suite 2300
Salt Lake City, Uta 84111
Telephone: [phone]
Fax: [phone]
Email: ted.weston(ßpacificom.com
Yvonne Hogle
Rocky Mounta Power
201 South Main Street, Suite 2300
Salt Lake City, Uta 84111
Telephone: (801) 220~4050
Fax: [phone]
Email: Yvonne.hogle(ßacificorp.com
Communcations regarding discovery matters, including data requests issued to Rocky Mountan
Power, should be addressed to the following:
By E-mail (preferred):dataequest(ßpacificorp.com
By reguar mail:Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR 97232
Idaho Public Utilties Company
Febru 1,2012
Page 2
Inform inquies may be dircted to Ted Weston, Idaho Reguatory Manager at (801) 220-
2963.
Very trly your,
~&It~/~
Vice President, Reguation
Enclosures
R EIVED
Mark C. Moench
Yvonne R. Hogle (pro hac vice application pending)
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Telephone No. [phone]
Facsimle No. [phone]
E-mail: yvonne.hogle(ßpacificorp.com
2Ui2 rEB -1 AM \0: 04
Richard R. Hall
Local Counsel
Stoel Rives LLP
101 S. Capitol Boulevard, Suite 1900
Boise, iD 83702-7705
Telephone No. [phone]
Facsimile No. [phone]
E-mail: rrhall(ßstoel.com
Attorneys/or Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-12-03
OF ROCKY MOUNAIN POWER FOR )
AUTHORI TO INCREASE RATES BY ) APPLICATION OF ROCKY
$2.6 MILLION TO RECOVER DEFERRD ) MOUNAIN POWER
NET POWER COSTS THROUGH THE )
ENERGY COST ADJUSTMENT )MECHASM )
Rocky Mounta Power, a division of PacifiCorp ("Company" or "Rocky
Mounta Power"), in accordance with Idaho Code §61-502, §61-503, and RP 052,
hereby respectflly submits ths application ("Application") to the Idaho Public Utilities
Commission ("Commission") pursuat to its approved energy cost adjustment
mechansm ("ECAM"), requesting approval to adjust Schedule 94, Energy Cost
Adjustment, and establish the ECAM rate for all customer classes includig Monsanto
Company ("Monsato") and Agrum, Inc. ("Agrum") based on the deferr period
beginng December 1, 2010 though November 30, 2011 ("Deferral Period"). The
Company is requesting approval to add $18.1 millon into the ECAM balancing account
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for the Deferrl Period. Ths addition would brig the tota balance of the account to
$24.1 million as of November 30, 2011. The Company is also proposing to adjust
Schedule 94 to collect approximately $13.0 millon over the period beginnng April 1,
2012 through March 31, 2013, representing an increase of $2.6 milion over Schedule 94
rates curently in effect as approved in Order No. 32216 of Case No. PAC-E-11-07.
Rocky Mountan Power respectfuly requests that this increase in Idaho rates become
effective on April 1, 2012, pursuat to Schedule 94. In support of its Application, Rocky
Mountan Power states as follows:
1. Rocky Mountan Power is a division of PacifiCorp, an Oregon
corporation, which provides electrc service to retail customers through its Rocky
Mounta Power division in the states of Idaho, Wyoming, and Uta. Rocky Mountan
Power is a public utilty in the state of Idaho and is subject to the Commission's
jursdiction with respect to its prices and terms of electrc service to retal customers in.
Idaho. Rocky Mountan Power is authorized to do and is doing business in the state of
Idaho providig retal electrc service to approximately 73,000 customers in the stte.
2. Communcations regarding ths filing should be addressed to:
Ted Weston
Idaho Reguatory Affairs Manager
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lae City, Uta 84111
Telephone: [phone]
Email: ted.weston(ßpacificorp.com
Yvonne R. Hogle, Senior Counsel
Rocky Mountai Power
201 South Mai Suite 2300
Salt Lake City, Uta 84111
Telephone: [phone]
Email: Yvonne.hogle(ßpacificorp.com
2
3. In addition, Rocky Mountan Power requests that all data requests
regarding ths Application should be sent in Microsoft Word or plain text format to the
followig:
By email (preferred):datarequest(ßpacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 Multnomah Suite 2000
Portland, Oregon 97232
Informal questions may. be diected to Ted Weston, Idaho Reguatory Affairs
Manager at [phone].
Brief Overview of the ECAM
4. On October 23, 2008, Rocky Mounta Power filed an application with the
Commssion, Case No. PAC-E-08-08, seeking approval of an ECAM. After meeting with
sta and other .paries over a period of approximately four months, the Company and the
paries entered into a stipulation agreeing to the type of ECAM that would be acceptable
to all the paries. On June 29, 2009, the paries filed said ECAM Stipulation with the
Commssion.
5. On September 29, 2009, by Order No. 30904 issued in Case No. PAC-E-
08-08, the Commssion approved the implementation of an anual ECAM.
6. By agreement, the costs that are to be included in the ECAM are net
power costs ("NPC") that are defied in the Company's general rate cases and modeled
by the Company's production dispatch model GRI. Specifically, base and actu NPC
include amounts booked to the followig FERC accounts:
· Account 447 (sales for resale, excludig on-system wholesale sales and
other revenues not modeled in GRID),
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9. In addition to the comparson of Actu NPC to Base NPC, the ECAM
includes five additional components: the Load Growt Adjustment Rate ("LGAR") or
Load Change Adjustment Rate ("LCAR")i, a credit for SOi allowance sales, an
adjustment for the treatment of coal strpping costs, a renewable resource adder for
1 The LGAR was changed to the "LCAR", puruat to the Commission's Order No. 32206.
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renewable resources that are not yet in rate base and a tre-up of Renewable Energy
Credit ("REC") revenues, as authorized by the Commission in Order No. 32196. These
components.are described in more detal below.
10. Finally, the ECAM includes a symetrcal sharg band of 90 percent
(customers) / 10 percent (Company) that shas the NPC differential between Actual
NPC and Base NPC, LCAR, SOi sales, and the coal strpping costs adjustment between
the customers and the Company. The sharg band is also described in more detal below.
Proposed Deferred ECAM Rate Increase
1 1 . In support of this Application, Rocky Mountain Power has fied the
testimony and exhbits of Company witnesses Gregory N. Duvall and Willam R.
Grffth. Mr. Duvall's testimony and exhbit describes the Actu NPC incured by the
Company to serve retal load for the historical twelve-month period ended November 30,
2011 and explains the main increases between Actul NPC and Base NPC. Mr. Griffth's
testimony supports the new ECAM taff surcharge rates to be effective April 1, 2012
through March 31, 2013 for Monsato and Agrium.
12. Effective Janua 1,2011, Monsanto's and Agrum's loads are included in
the calculation of the ECAM balances in ths ECAM filing. As of December 31, 2010,
Monsanto's and Agrum's taff contrts expired and, pursuat to a stipulation entered
into and approved in Order No. 30904, Case No. PAC-E-08-08, the two customers' loads
were to be included as par of the ECAM calculation in ths case, along with all other
retal customers' loads. In addition, as indicated in the stipulation approved by the
Commission in Order No. 32432 in Case No. PAC-E-11-12, the Company will amortize
and collect Monsanto's and Agrum's share of the Commssion-approved 2011 ECAM
balances over three year.
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13. In ths Application, confdential Exhibit 1 ("Exhbit 1") to Mr. Duvall's
testimony ilustrtes the detaled calculation of the deferred NPC adjustment. Stag
with the bas NPC in the amount of approximtely $1.02 bilion, previously approved by
the Commssion in its Order 32196, the Company taes the monthy NPC from that
amount and divides it by the monthy normalized load used to determne NPC to express
the costs on a dollar per megawatt-hour basis (line 1 of Exhibit if The actul NPC rate
on a dollar per megawatt-hour basis is then calculated by tang the monthy actu NPC
and dividing it by the actu monthy system load (line 4 of Exhibit 1).
14. Next, the deferral amount is calculated on a monthly basis by subtracting
the monthy base NPC rate from the actu NPC rate. Ths results in a monthly NPC rate
differential (line 5 of Exhibit 1) which is then multiplied by thee groups of actu Idao
retal load at input: taff customers, Monsanto and Agrum (lines 6 though 8, Exhibit
1,) to calculate the NPC differential for deferral for each group (lines 10-13, Exhibit 1).
For the 12-month period ended November 30,2011, the NPC differential for deferral was
approxiately $18.6 millon before the 90/10 shag (line 13 of Exhibit 1).
15. As described in Mr. Duvall's testimony, the LCAR is a symetrcal
adjustment to offset over or under collection of the Company's production energy related
revenue requiement, excluding NPC, due to varances in Idaho load. Puruat to
Commssion Order No. 30904, the intial Commssion-approved symetrcal LGAR was
$17.48 per megawatt-hour. Ths was updated by Commission approval to $21.89 per
megawatt-hour beging December 28, 2010, and fuer updated by Commssion
approval beginng in April 2011, to $5.47 per megawatt-hour. Lines 23 though 26 of
2 Base NPC Rate and Load from Case No. PAC-E-08-07 in the amount of $987 millon were used though
12/27/10. Base NPC Rate and Load from Case No. PAC-E-1O-07 in the amount of$L.02 bilion were used
since 12/28/11.
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Exhibit 1 in Mr. Duvall's testiony ilustrte the tota LCAR adjustment used in ths
case.
16. Under ths Application, credits for SOi allowance sales revenues received
by the Company from December 1,2010 to November 30,2011 are included as an offset
to the NPC deferral. Mr. Duvall's testimony describes how the SOi sales revenues were
offset agaist deferred NPC in ths docket. Line 29 of Exhibit 1 in Mr. Duvall's
testimony contans the SOi sales revenues that are credited against the NPC differential
for deferral.
17. Line 30 of Exhibit 1 reflects Idaho's allocated differences between
excludig coal strpping costs incurd by the Company and recorded on the Company's
books puruat to the guidance of the accounting pronouncement EITF 04-6, and the
amortization of the coal strpping costs when the coal was excavated. The EITF 04-6
deferral adjustment on line 30 of Exhibit 1 is added to the NPC differential for deferr.
18. Lines 39 though 41 of Exhibit 1 show the tota NPC deferral adjusted for
LCAR revenue, S02 revenue, and EITP 04-6 deferral for taff customers, Monsanto and
Agrum.
19. A sharg band between customers and the Company is included such that
customers pay/receive the increas/decrease in Actu NPC when compared to Base
NPC, and the Company incurs/retas the remaig 10 percent. The sharing bands also
apply to the SOi, the LCAR and the coal strpping costs. Lines 44 though Line 47 of
Exhibit 1 in Mr. Duvall's testimony sumarze by customer groups the cusomers'
(taff customers', Monsanto's and Agrum's) share of these components
20. As approved in Case No. P AC-E-08-08, the ECAM includes a renewable
resource adder which has been usèd in prior ECAM filings but which ended on the
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+ LCAR + SOi revenues+ coal strpping costs adjustent) + the renewable resource
adder + interest charges + REC revenues. Lines 64 though 70 of Exhibit 1 in Mr.
Duvall's testimony ilustrate the detaled calculations for stadad tarff customers, with
an endig balance of$16.3 millon; lines 72 though77 ilustrate the detaled calculations
for Monsanto, with an endig balance of $7.2 milion; and lines 79 though 84 ilustrate
the detailed calculations for Agrum, with an ending balance of $.5 millon. The sum of
the three groups' ending balances validates the total ending balance of $24.1 millon. The
Company will amortize and collect Monsanto's and. Agrum's share of the deferral
balance, as approved by the Commission in ths case, over thee years pursuant to the
stipulation approved by the Commssion in Order No. 32432.
23. The Company is not requesting a change in the ECAM surchage rate to
recover the full $24.1 millon deferral at this time. The Company estimates that
approximately $3.0 millon of the balance will be recovered though Schedule 94 rates
from December 1,2011 to March 31, 2012. Any over or under collection of ths amount
will be addressed in future ECAM fiings. In addition, the Company is not requesting a
change to existing Schedule 94 rates for stadard taff customers at ths time as it
anticipates that an increase in the collection rate ths year would be followed by a
decrease in the rate next year.
Allocation of Deferred ECAMto Retail Tariffs
24. As previously stated, Mr. Grffth's testimony describes in greater detal
the calculation of the proposed Schedule 94 rates for Monsanto and Agrum. Exhibit 2 of
Mr. Grffith's testiony ilustrates the allocation of the intial collection rate for each of
the two customers and the biling determants used. Exhibit 3 is taff Schedule 94
contang the proposed rates by electric service schedule.
9
25. Rocky Mountan Power is notifyg its customers of ths Application by,
among other means, issuing a press releas sent to local media organzations and
messages in customer bils over the coure of a biling cycle. In addition, copies of ths
Application will be made available for review at the Company's local offces in its Idaho
sece terrtory.
26. WHREFORE, Rocky MountRin Power respectfuly requests that the
Commssion issue an order (l) authoriing that ths matter be processed by Modified
Procedure; (2) approve the ECAM deferred balance; and (3) implement the proposed
electrc service Schedule 94 as filed in Exhibit 3.
DATED ths 1 st day of Febru 2012.
Respectflly submitted,
ROCKY MOUNTAI POWER
dlML t dirl!f
Mark C. Moench
Yvonne R. Hogle
201 South Mai Street, Suite 2300
Salt Lake City, Uta 84111
Telephone No. [phone]
Facsime No. [phone]
E-mail: yyonne.hogle(ßpacificorp.com
Richard R. Hall
Local Counsel
Stoel Rives LLP
101 S. Capitol Boulevard, Suite 1900
Boise, il 83702-7705
Telephone No. [phone]
Facsimile No. [phone]
E-mail: rrhall(ßstoel.com
Attorneys for Rocky Mountain Power
10
~
~2t~~OUNTAIN
For information contact: Media Hotline: [phone]
No change proposed for residential and commercial customers
in Rocky Mountain Power's annual energy cost adjustment
request
BOISE, ID Wednesday, Feb. 1,2012- Rocky Mountain Power's anual energy cost
adjustment for 2012 proposes no increase for residential or commercial customers, and a
modest increase for two large industrial customers.
The energy cost adjustment mechanism is designed to track the difference between the
company's actual costs to provide electricity to customers and the amount collected from
customers through current prices. If the commission approves, the adjustment would take
effect April 1,2012.
Because of increases in fuel and other costs to produce and purchase the electricity
customers need, the proposed adjustment wil 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 2011 energy related costs of $18.1 milion and adjust the energy cost
adjustment rider, Schedule 94, by $2.6 milion. Those costs wil be collected from two
large industrial customers who previously were not covered by Schedule 94. The
company is proposing no change to stadard taiff customer prices.
The proposed increase would have the following impacts:
. Residential, commercial and most industrial customers - no change to curent
rates
. Industrial customer served on taiff Schedule 400 - $2.4 milion increase or 3.3
percent
. Industrial customer served on taiff Schedule 401 - $0.2 milion increase or 3.2
percent
The public will have an opportunty to comment on the proposal durng 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.
Idaho Public Utilities Commission
ww.puc.idaho.gov/
472 W. Washington
Boise, ID 83702
Rocky Mountain Power offces
. Rexburg - 25 East Main
. Preston - 509 S. 2nd East
. Shelley - 852 E. 1400 Nort
###
Keeping you
informed
Rocky Mountain Power requests
recovery of power costs.
On February 1, 2012, Rocky Mountain Power asked
the Idaho Public Utilities Commission to approve
the 2011 deferral of $18.1 million to the energy
balancing account and adjust the energy cost
adjustment rider by $2.6 million. The company is
proposing no change to tariff customer prices with
the exception of tariff contract Schedules 400 and 401.
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. If the commission approves, the rider
would take effect April 1, 2012.
Because of increases in fuel and other costs
to produce and purchase the electricity Idaho
customers need, the proposed adjustment
will allow Rocky Mountain Power to continue
to provide safe, reliable electric service to its
customers.
The proposed increase would have the following
impacts:
· Tariff customers Schedules 1 through 36 -
no change to current r'Jtes
· Addition of tariff contract Schedule 400 -
$2.4 million increase or 3.3 percent
· Addition of tariff contract Schedule 401 -
$0.2 milion increase or 3.2 percent
(continued)
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.
Idaho Public Utilties Commission
www.puc.idaho.gov
472 W Washington
Boise, 10 83702
Rocky Mountain Power offices
· Rexburg - 25 East Main
· Preston - 509 S. 2nd E.
· Shelley - 852 E. 1400 N.
· Montpelier - 24852 US Hwy 89
..ROCKY MOUNTAIN~POWER
(Ç 2012 Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE RATES )
BY $2.6 MILLION TO RECOVER )
DEFERRD NET POWER COSTS )
THROUGH THE ENERGY COST )
ADJUSTMENT MECHANISM )
CASE NO. PAC-E-12-03
Direct Testimony of Gregory N. Duvall
Redacted
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-12-03
February 2012
1 Q.Please state your name, business address and present position with
2 PacifiCorp, dba Rocky Mountain Power (the "Company").
3 A.My name is Gregory N. Duvall. My business address is 825 NE Multnomah St.,
4 Suite 600, Portland, Oregon 97232. My title is Director, Net Power Costs.
5 Qualifcations
6 Q.
7 A.
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Briefly describe your education and business experience.
I received a degree in Mathematics from the University of Washington in 1976
and a Master of Business Administration degree from University of Portland in
1979. I was first employed by Pacific Power in 1976 and have held varous
positions in resource and transmission planning, regulation, resource acquisitions
and trading. From 1997 though 2000 I lived in Australia where I managed the
Energy Trading Deparment for Powercor, a PacifiCorp subsidiar at that time.
After returning to Portland, I was involved in direct access issues in Oregon and
was responsible for diecting the analytical effort for the Multi-State Process
("MSP"). Currently, I direct the work of the net power cost group, the load
forecasting group, and the renewable compliance area.
1 7 Summry of Testimony
18 Q.Wil you please summarize your testimony?
19 A.My testimony provides evidence justifying the need to add $ 1 8.1 milion ("201 1
20 Deferral") into the Energy Cost Adjustment Mechanism ("ECAM") balancing
21 account for the 12-month period from December 1, 2010 through November 30,
22 2011 ("Deferral Period"). This would bring the total balance of the account to
23 $24.1 millon as of November 30, 2011. In addition, my testimony presents the
REDACTED
Duvall, Di - 1
Rocky Mountain Power
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background and calculation of the Company's ECAM and describes the actual net
power. costs ("NPC") incured by the Company to serve retail load durig the
Deferral Period.
Are additional witnesses presnting testimony in this case?
Yes. Mr. Wiliam R. Griffith, Director, Pricing, Cost of Service & Regulatory
Operations, is sponsoring testimony supporting new tariff surcharge rates for
Monsanto and Agrium for inclusion in Tarff Schedule 94 with an initial
collection rate of approximately $2.6 millon. The existing surcharge for other
customers wil. remain unchanged. 1 When combined with the existing surcharge
rate for other customers, the Company anticipates that Schedule 94 wil collect
approximately $13.0 millon on an annual basis as compared to the curent
collection rate of $10.4 millon.
What are the components of the $18.1 millon 2011 Deferral?
The components of the 2011 Deferral are the customers' 90 percent share of the
difference between the actual and in-rates NPC, the load growth adjustment
revenue and load change adjustment revenue ("LGAR/LCAR"), the sulfur dioxide
("SOz") allowance sales adjustment, the Emerging Issues Task Force ("EITF")
04-6 adjustment, and the renewable resource adder adjustment. Also included is
100 percent of the true-up of renewable energy credit ("REC") revenues. More
specifically, the $18.1 millon is made up of the following:
1 The Company was authorized to set present Schedule 94. rates that were designed to recover
approximately $12.8 millon in the 2011 ECAM adjustment, Case No. PAC-E-1l-07 using the Company's
then-most recent general rate case test period, forecasted 12 months ending December 2010. In this curent
docket, the Company is using the test period, historic 12 months ending December 2010 from its most
recent general rate case, Case No. PAC-E-l1-12. Using ths most recent test period, present Schedule 94
wil collect approximately $10.4 millon.
REDACTED
Duvall, Di - 2
Rocky Mountain Power
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· $16.6 milion is the customers' share of the NPC differential, net of the
LGARICAR, SOz sales, and EITF 04-6 deferral balance,
. $0.3 millon is the renewable resource adder, and
. $1.2 millon is the REC revenue adjustment.
What is included in the remaining $6 millon of the ECAM deferral balance
that brings the total to $24.1 millon?
The remaining $6 millon of the ECAM deferral balance is made up of the
following:
· $2.4 millon as the seond year amortization of the 2010 LGAR deferral,
. $3.6 milion of uncollected balance from the Company's ECAM filing in
2011, plus interest, most of which is expected to be recovered before April 1,
2012 under the existing Schedule 94 collection rate.
Based on your calculations, what is'the potential amount that would be
required to be collected from customers under Schedule 94 beginning April
1,2012?
The combined total for potential collection from customers beginning April 1,
2012 is estimated to be $21. 1 millon, of which retail customers other than
Monsanto and Agrium are responsible for $13.4 millon, Monsanto is responsible
for $7.2 millon and Agrium is responsible for $0.5 millon.
Is the Company proposing to collect this full amount?
No.
REDACTED
Duvall, Di - 3
Rocky Mounta Power
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10 A.
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How much does the Company propose to collect from customers under
Schedule 94 beginning April 1, 2012?
The Company proposes to collect $10.4 millon from retail customers other than
Monsanto and Agrium beginning April 1,2012. This wil require no change to the
ECAM surcharge rate for theses customers. The surcharge rate for Monsanto and
Agrium wil be set at approximately $2.6 millon to reflect the three year
amortization outlned in the stipulation agreed to by the paries and approved by
the Commssion in the 2011 general rate case.
Do you have a summary of your calculations and proposal?
Yes. Table 1 summarzes the Company's calculations of the ECAM balance and
the proposal in this case.
REDACTED
Duvall, Di - 4
Rocky Mountain Power
Table 1
Tariff
Customers Monsanto Agrium Total
NPC Differential for Deferral 10,532,075 7,460,738 576,204 18,569,017
LGARILCAR (237,317)105,158 (44,888)(177,047)S02 (5,722)(4,420)(331)(10,474)
EI1F-06 Adjustment 68,315 21,620 2,145 92,079
10,357,350 7,583,095 533,130 18,473,575
90%90%90%90%
Customer Responsibilty 9,321,615 6,824,785 479,817 16,626,217
Renewable Resource Adder 282,851 °°282,851
RE C Deferrl 821,390 371,539 31,817 1,224,746
Total Company Recovery for NPC Deferral 10425,857 7,196 325 511,633 18133,815
Year 2 of LGAR ordered Amortization 2378,721 0 0 2378,721
Balancing Account Actility
Prior Deferral 11,181,331 --11,181,331
ECAM Revenue Collection (7,821,058)--(7,821,058)Interest 189,858 --189,858
Estimated Undercollection (911/30/11 3,550,131 --3,550,131
Balance Subject to Surcharge Collection 16,354,709 7,196,325 511,633 24,062,667
Tarff 94 Collection - April 2012 to March 2013 (10,450,734)(2,409,685)(171,269)(13,031,688)
Tarff 94 Collection - Dec 2011 to March 2012 13,000,000)--13,000,000
Balance After Esimated Collection 2,903,975 4,786,64 340,36 803,979
Proposed Schedule 94 Changes (Monsanto /
Agrium 3 Year Amortization)2,409,685 171,269 2,580,954
1 The first section of Table 1 shows the components of the $18.1 millon which is
2 summarzed on the line labeled "Total Company Recovery for NPC Deferral."
3 The next section of Table 1 shows the components of the total balance of $24.1
4 millon as of November 30, 2011 and is labeled "Balance Subject to Surcharge
5 Collections." The third portion of Table 1 is summarzed on the line labeled
6 "Tarff 94 Collection - April 2012 to March 2013" and shows the Company's
7 proposed initial surcharge to Monsanto of $2.4 millon, an initial surcharge to
8 Agrium of $171,000, and a surcharge for the remaining tarff customers of $10.4
9 millon, which represents no change to the surcharge for these tarff customers.
10 The final section of Table 1 labeled "Balance After Estimated Collection" shows
REDACTED
Duvall, Di - 5
Rocky Mountain Power
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19 A.
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the estimated remaining balance of the $24.1 millon afer the 12-month collection
period ending March 31, 2013 jf the Company's proposed surcharge was
approved.
It appears the primary driver of the $18.1 millon 2011 Deferral is a result of
the difference between the in-rates NPC and the actual NPC for the Deferral
Period. Please explain the causes of this difference.
The in-rates NPC for the Deferral Period were $1.025 billon, were based on 2008
and 2010 test periods and excluded wind integration costs of about $34 millon.
Actual NPC for the Deferral Period were $1.344 bilion, or $319 millon higher
than the in-rates NPC. The difference is primarly drven by a 29 percent drop in
wholesale sales prices and a reduction in the volume of wholesale sales of 9.3
millon megawatt-hour, or nearly 50 percent as compared to what was included
in the in-rates amount. This caused a reduction in wholesale sales revenues of
$505 milion, offset parially by a reduction in purchased power expense of $60
millon and a reduction in natual gas fuel expense of $ 118 millon for a net
increase in NPC from these three components of $327 millon. Small changes in
coal and wheeling expenses make up the difference.
Why did sales volumes drop by 9.3 millon megawatt-hours?
The loss of sales volume reflects the impact that low power prices had on the
economics of the Company's coal and natural gas units.. The Company generated
7.9 millon fewer megawatt-hours from its thermal fleet than were included in
rates. Table 2 shows wholesale power prices for low load hours at the Mid-
Columbia and Palo Verde trading hubs as compared to the Company's average
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coal costs.
Table 2
~~~"',............~..~................35.00 I -::CAMA:~~~p,;æ -'=~CLLH
30.00 ~~-\---.~-_._-------.- -----.~~-----~.-------.- jI \ .~ ~ Ii *". '\ . ~~~,~,,,,,,,... ~", ¡
25.00 .¡..........~\,,~~~~~~~~...........................................................................¡......................./...............~ ...~~~~......I¡ '\ '\ ¡ I ¡: '\ \ . $ :20.00 I.--\~.\/---fli: Ji ,:R:;~ I I :i 'm'i *.q¡ ,V~ ¡Wi 0i ' iim / i,q-: !Iii .: K~ m ~~ ~i-g-"'-I- -. ........ ~..-I-'
~ 10.00 llllí....~..~II~ -'-1-111-1
5.00 .:....:::,:m..........:';:L'........II~--l-I#- -ll--l'
Il.~l.:-l-~ -.~f~.-~.~.~-~~~: ~~') ,y.$ ",\~') ~~') '?~ 'o\~') '\\~ t¡\~') q\~'" .s~ ..~.$ j
(5.00) .:...................................................................................................................................................................................................¡
E'~
:E
~ 15.00
Table 2 shows that for six months in 2011, the average low load hour wholesale
power prices at Mid-C were below the average coal price of the Company's coal
fleet. Palo Verde low load hour wholesale power prices were below the average
coal prices three months of the year. In June, the monthly average low load price
was negative. These low price conditions make it uneconomic at times to run coal
an~ gas units.
Did the Company anticipate that the actual NPC for the Deferral Period
would be $319 millon higher than the NPC included in rates during the
Deferral Period?
Yes. In the 2011 general rate case, I testified that NPC for calendar year 2011
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would be $1.312 bilion. This was not a true forecast of 2011 NPC since it used
2010 temperature adjusted loads. In Company witness Mr. J. Ted Weston's
testimony fied on November 2, 2011 in support of the stipulation in the 2011 rate
case, he indicated that the Company expected actual NPC for 2011 to be $1.35
billon and that the expected ECAM deferral would be in the range of $15 to $ 1 8
millon. These estimates compare well to the $1.344 billon actual NPC for the
Deferral Period.
Why is the 2011 Deferral $18.1 millon when the 2010 deferral was only $12.8
millon?
The increase in the 2011 Deferral over the 2010 deferred amount is mainly
attributable to the inclusion of Monsanto and Agrium for the first time in 2011.
Their share of the deferral is $7.7 millon, or 43 percent; the remaining $10.4
millon is the responsibilty of all other tarff customers and is actually less than
the 2010 deferral for these customers.
Are you sponsoring an exhibit that details the calculations of the ECAM?
Yes. Exhibit NO.1 presents thecalculation of the ECAM.
17 ECAM Background
18 Q.Please briefly describe the Company's ECAM authorized by the
19 Commission.
20 A.Order No. 30904 dated September 29, 2009, from Case No. PAC-E-08-08,
21 approved the stipulation entered into by the Commssion Staff, the Idaho
22 Irgation Pumpers Association, Monsanto and the Company that set up the
23 strcture and content of the ECAM mechanism.
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1 In general, power cost adjustment mechanisms track and defer deviations
2 between actual NPC and the NPC in rates. The deferred costs that accumulate
3 over a one-year period are then passed on to customers as a rate surcharge or
4 credit.
5 The ECAM Schedule 94 charge, which appears as a separate line item on
6 customer bils, defers the difference between actual NPC incured by the
7 Company to serve Idaho customers over a specified period ("Actual NPC") and a
8 base NPC level established through a general rate case proceeding ("Base NPC").
9 When Actual NPC is greater than Base NPC, the difference is charged to
10 customers; conversely, where Base NPC is greater than Actual NPC, the
11 difference is credited to customers through the ECAM.
12 In addition to the varance between Actual and Base NPC, the ECAM
13 reflects the impact of the LCAR applied to the differences in actual and base
14 period retail load, a credit for SOz revenues, an adjustment for the treatment of
15 EITF 4-06 coal strpping costs and a renewable resource adder that reflects
16 generation from new renewable resources that were not included in rates durig
17 the deferral period. Pursuant to Order No. 32196, 100 percent of the difference
18 between base REC revenues established in a general rate case and actual REC
19 revenues are also tracked in the ECAM. The annual deferral period for the ECAM
20 is December 1 to November 30. The Company is required to file an application
21 with the Commssion by February 1 of each year to seek approval of the deferral
22 amount and to adjust the ECAM rate effective April 1.
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Has the ECAM calculation changed from the calculation used in the prior
ECAM?
Yes. In the current filing, Monsanto's and Agrum's loads are included in the
calculation of the ECAMbalances. In the 2007 general rate case, Case No. PAC-
E-07 -05, the Commssion approved a stipulation including electrc service
agreements with specific planned rate increases for Monsanto and Agrium
through December 31,2010. Beginning on Januar 1,2011, those tarff contracts
expired and the two customers' loads are included in the ECAM calculation in the
same way as all other retail customers. However, as indicated in the stipulation
Order No. 32432 in the 2011 rate case, the Company wil amortize and collect
Monsanto's and Agrium's share of the Commission approved 2011 ECAM
balances over three years. As a result, the ECAM balances for the two customers
wil be tracked separately through the amortization periods.
Please describe the ECAM as calculate in Exhibit No.1.
This Application includes deferred amounts from December 1, 2010 to November
30, 2011. The deferral was calculated by comparng the Actual NPC to the Base
NPC on a monthly basis and deferrng the differences into an ECAM balancing
account. During the Deferral Period, the Base NPC in rates were from two rate
cases: Case No. PAC-E-08-07 ("2008 Rate Case") from December 1 to December
27, 2010, and Case No.PAC-E-10-07 ("2010 Rate Case") from December 28,
2010 through November 30, 2011. The calculation is made by utilzing the system
dollar per megawatt-hour rate applied to the Idaho retail load. Exhibit No. 1
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details the ECAM calculation and contais supporting information, portions of
which are confidential.
How are the Base NPC and Actual NPC dollar per megawatt-hour rates
calculated?
With respect to the Base NPC rate, the Company staed with the NPC of $982
millon and $1,025 millon approved by the Commssion in Order No. 30783 from
the 2008 Rate Case and Order No. 32224 from the 2010 Rate Case, respectively.
Prorating the December value included in the $982 millon for 27 days in
December 2010 and applying corresponding months from the $1,025 millon for
the rest of the Deferral Period, the Base NPC for the Deferral Period are $1,028
millon. The Company then divided the monthly NPC dollar amount by the
monthly normalized load of the corresponding months to express the costs on a
dollar per megawatt-hour basis (Exhibit No.1, line 1). The Actual NPC rate on a
dollar per megawatt-hour basis is calculated by dividing the monthly Actual NPC
dollar amount by the actual monthly system load (Exhibit No.1, line 4).
Please describe how the NPC deferral is determined.
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 5) is then multiplied by three groups of actual Idaho retail load at
input: taff customers, Monsanto, and Agrium (Exhibit No.1, lines 6 through 8)
to calculate the NPC differential for deferral for each customer group (Exhibit No.
1, lines 10 though 13). For the 12-month period ended November 2011 the NPC
differential for deferral was approximately $18.6 millon before the 90 / 10
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sharng.
What types of costs are included in the NPC differential for deferral?
The NPC differential for deferral captures all components of NPC as defined in
the Company's general rate case proceedings and modeled by the Company's
production dispatch model ("GRID"). Specifically, Base NPC and Actual NPC
include amounts booked to the following Federal Energy Regulatory Commssion
("PERC") 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, star up
fueF (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 Bonnevile Power
Administration ("BP A") residential exchange credit pass-
though if applicable
Account 565 - Transmission of electrcity by others
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)
LGAR revenues, which have been changed to LCAR revenues beginning April 1,
2 Starup fuel is accounted for separately from the prima fuel for steam power generation plants. Star up
costs are not accounted for separately for natural gas plants, and therefore all fuel for natural gas plants is
included in the determination of both Base NPC and Actual NPC.
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2011, as authorized by the Commssion in Order No. 32206, (ii) credit for any
SOz allowance sales varances, (iii) adjustment for deferred costs associated with
coal mine stripping activities recorded under the Financial Accounting Standads
Board ("FASB") EITF 04-6, (iv) a renewable resource adder for 27 days in
December 2010, and (v) true-up of REC revenues as authorized by the
Commssion in Order No. 32196.
Please describe the LGAR and LCAR revenues.
The calculation of both LGAR and LCAR revenues is a symetrcal adjustment
for any over or under collection of the Company's production related revenue
requirement, excluding NPC, due to varances in Idaho load. In Order No. 32206
of Case No. GNR-E-10-03, the Commssion revisited the load growth adjustment
in ECAMs.
The Commssion order specified five LGAR items; (1) to only include the
energy classified portion of embedded production revenue requirement in the
calculation, (2) that a symetrical approach for growing and declining loads
continued to be just and reasonable to both the utilty and its customers, (3) to
change the termnology from Load Growth Adjustment Rate to. Load Change
Adjustment Rate, (4) compute the LCAR based on the most recent Commssion-
approved cost of service results, and (5) the newly-calculated LCAR shall be used
in ECAM calculations beginning on April 1, 2011.
How are the LGAR and LCAR calculated and what is their impact on the
2011 Deferral?
In Commssion Order No. 30904, the Commssion approved a symetrical
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LGAR of $17.48 per megawatt-hour, which was updated to $21.89 per megawatt-
hour beginning on December 28, 2010 as authorized by the Commssion in the
2010 Rate Case. Beginning in April 2011, the Commssion approved the LCAR,
at $5.47 per megawatt-hour, which replaced the LGAR. Both the LGAR and
LCAR revenues are calculated in the same manner by stang with subtracting
Idaho's load at input established in rates ("Base Load" shown in Exhibit No.1,
lines 14 through 17), from actual Idaho load at input ("Actual Load" shown in
Exhibit No.1, lines 6 through 9). The difference (Exhibit No.1, lines 18 though
21) is then multiplied by the LGAR of $17.48 per megawatt-hour for 27 days in
December 2010 (Order No. 30783), $21.89 per megawatt-hour (Order No. 32196
and 32224) though March 31, 2011, and $5.47 per megawatt-hour (Order No.
32206) from April 1 through November 30, 2011 (Exhibit No.1, line 22) to arve
at the WAR and LCAR credits (Exhibit No.1, lines 23 though 26) of $177,047
for the Deferral Period before the 90 /10 sharng.
How are S02 sales revenues included in the ECAM?
Line 27 of Exhibit NO.1 contains the total Company SOl sales revenue during the
Deferral Period on a total Company basis., Line 29 of Exhibit NO.1 is Idaho's
allocated share of the SOl sales revenue which is calculated using Idaho's System
Energy ("SE") allocation factor authonzed by the Commssion from the 2008
Rate Case and 2010 Rate Case. The SOl sales revenue on line 29 of Exhibit NO.1
is credited against the NPC differential for deferrL. For the Deferral Period, the
total SOl sales revenue credit is a $10,474 reduction to the NPC deferral balance
before the 90/10 sharng.
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How is the adjustment for the accounting pronouncement EITF 04-6
included in the ECAM?
Line 30 of Exhibit NO.1 reflects Idaho's allocated differences between excluding
coal stripping costs incured 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. The EITF
04-6 deferral adjustment on line 30 of Exhibit No. 1 is added to the NPC
differential for deferral. For the Deferral Period, the total EITF 04-6 coal stripping
deferral adjustment is a $92,079 increase to the NPC deferral balance before the
90/10 sharng.
What is the total amount of the NPC differential and the adjustments
described above?
Lines 39 through 41 of Exhibit No.1 show the total NPC deferral adjusted for
LGAR/CAR revenue, S02 revenue, and EITF 04-6 deferral for tarff customers,
Monsanto and Agrum, which is approximately $18.5 millon for the Deferral
Period before the 90 /10 sharng.
Is the deferral subject to a sharing ratio between the Company and
customers in the ECAM?
Yes. The ECAM includes a symetrical sharng ratio where customers payor
receive 90 percent of the ECAM deferral balance and the Company is responsible
for the remaining 10 percent. Lines 44 though 47 of Exhibit NO.1 reflect the
customers' 90 percent share of the monthly deferral shown on lines 39 through 42
of Exhibit No. 1. For the Deferral Period, the customers' share of the deferred
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balance is approximately $16.6 millon. The remaining balance of approximately
$1.8 millon is not included in the deferral calculation and is not recoverable from
customers.
Is the deferred balance adjusted for a renewable resource adder?
Yes. However, the adder was only applicable to the first 27 days in December
2010 prior to the time the rates from the 2010 Rate Case went in effect. The
renewable resource adder was implemented to recognize that the cost of the
renewable generation resources that were not yet being recovered in Idao rates
were providing benefits to customers through the near-zero cost energy generation
included in the Actual NPC. The adjustment is calculated by multiplying the
authorized amount of $55.00 per megawatt-hour by the prorated actual megawatt-
hour output generated in the first 27 days of December 2010 from those
renewable resources that were not included in rates during the Deferral Period
(Exhibit No.1, line 48). Line 50 of Exhibit NO.1 reflects this adjustment on a
total Company basis. The total Company amouni is allocated to Idaho (Exhibit
No.1, line 52) based on the System Generation allocation factor ("SG"), which is
furher prorated to include only the tarff customers load (Exhibit No.1, line 54).
The renewable resource adder adjustment is $282,851 for the 27 days in
December 2010.
What is the amount of REC revenue true-up in the current filing?
As authorized by the Commssion in Docket No. PAC-E-10-07, Order No. 32196,
the Company included the difference between actual REC revenues durng the
Deferral Period and the amount of REC revenues included in base rates. The REC
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revenue true-up included in the ECAM is symmetrcal but no sharng band is
applied. Thus, 100 percent of the difference between base and actual REC
revenues is either refunded or surcharged to customers. Case No. PAC-10-07
established an annual level of REC revenue in base rates of $7,031,166. In the
curent filing, the REC revenues are prorated beginning on December 28, 2010,
27 days less than the full 12-month Deferral Period, so the amount included in
base rates durg the deferral period was $6.5 millon. Idaho's actual REC
revenues for that same time period were approximately $5.3 milion, a difference
of approximately $1.2 millon (Exhibit No.1, line 61).
What is the total ECAM deferred balance as calculated in Exhibit No.1?
The total ECAM deferred balance as of November 30, 2011 is 24.1 millon and is
shown on line 85 of Exhibit No. 1.
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 deferral period. Of the $24.1 million, $16.3 millon is
allocated to the tariff customers (Exhibit No.1, Line 70), $7.2 millon to
Monsanto (Exhibit No.1, Line 77) and $0.5 milion to Agrium (Exhibit No.1,
Line 84). The Company wil amortize and collect Monsanto's and Agrum's share
of the Commssion approved 201 1 ECAM balance over three years pursuant to
the stipulation approved by the Commssion in Order No. 32432.
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In your opinion does the calculation of the deferred NPC adjustment in this
application comply with the parameters of the Idaho ECAM as approved by
the Commssion?
Yes.
Is the Company requestiiig a rate increase to recover the. full $24.1 millon
deferral?
No. The Company estimates that approximately $3.0 millon of the under
collection wil be recovered through Schedule 94 rates from December 1, 2011 to
March 31, 2012. Any over or under collection of this amount wil be addressed in
future ECAM fiings. Additionally, the Company is not requesting a change to the
existing Schedule 94 rates for tarff standard customers at this time as it anticipates
that an increase in the collection rate this year would be followed by a decrease in
the rate next year. The Company is recommending that the rate be held constant
for these customers in order to achieve rate stabilty potentially over the next two
15 years.
16 Actual NPC - Base NPC Comparison
17 Q.
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How do the Actual NPC differ from the Base NPC for this Deferral Period?
The Base NPCapproved by the Commssion and included in rates is $1,028
19 millon on a total Company basis. Total adjusted Actual NPC during the Deferral
20 Period is $ 1 ,344 millon, which is $316 milion higher than what was included in
21 rates during the Deferral Period. On a dollar per megawatt-hour basis, the Base
22 NPC average is $17.83 per megawatt-hour, and the Actual NPC averages to
23 $22.92 per megawatt-hour, $5.09 per megawatt-hour higher.
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Please explain why Actual NPC are adjusted.
The Actual NPC recorded on the Company's books are adjusted to remove entres
that are not included in the determnation of the Company's Base NPC for
regulatory puroses, such as adjustments made to remove entres in months
outside the curent Deferral Period. In addition, Actual NPC ar adjusted to reflect
prior Commssion approved adjustments, such as the revenue imputation of the
sales contract with the Sacramento Municipal Utilty District.
In your summary, you indicated that several power contracts have expired.
Please provide some examples of these expiring power contracts?
Some examples include:
· On June 30, 2011, the exchange contract between the Company and the Alcoa
Power Generating Inc. for approximately 100 megawatts of capacity from the
Rocky Reach project expired. Under this contract, the Company received
energy durng peak periods and returns energy during off-peak periods.
· On October 31, 2011, the contract between the Company and the Chelan
Public Utility District for generation from the Rocky Reach project expired.
Power purchased by the Company under this contract was. priced at the
embedded cost of the project.
· On August 31, 2011, the contract between the Company and BPA for 575
MW of capacity expired. Under this contract, the Company received energy
durg peak periods and returns energy durng off-peak periods. In addition,
power received under this contract was delivered directly to a varety of the
Company's load pockets in the western area at the Company's discretion.
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· On September 30, 2011, the contract between the Company and the Grant
Public Utility Distrct for displacement generation expird, which was priced
at BP A's Priority Fir Power rate.
. On Januar 1, 201 1, the amount of sales to the Public Service Company of
Colorado reduces per the. contract terms, which was a legacy sales contract at
relatively high contract prices.
You also mentioned in your summary that coal prices had increased. What
are the primary drivers of the coal price increases?
Both third pary coal purchase expense and captive mine costs have increased.
The primar factors are:
· Naughton - approximately $4 millon increase. Subsequent to the filing of
2010 Idaho General Rate Case, the Company amended the Naughton coal
supply agreement with Chevron Mining Company. The amended coal supply
agreement included advancement of the January 2011 price reopener to July
2010, changes to the contract strcture and a lump sum prepayment by the
Company of. millon. The prepayment which is being amortized to fuel
expense over the primar term of the agreement resulted in a $1.4 millon
increase in actual net power costs. Additionally, the contract incorporates a
two-tiered pricing structure. The Base NPC included 395 thousand tons of
Tier 2 coal, the lower priced tier; actual net power costs included only 337
thousand tons of Tier 2 coal. The reduction of 58 thousand tons of Tier 2
resulted in an approximately. millon increase. Finally, a change in the
contract price structure as well as escalation of the producer price indices
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1 contrbuted to the remainder of the increase.
2 · Dave Johnston - approximately $6 millon increase. Though 2011, the Dave
3 Johnston plant was supplied by three mines under multi-year agreements:
4 Peabody's Rawhide mine, Western Fuels' Dry Fork mine and Wyodak
5 Resources' Wyoda mine. Approximately. millon of the price increase at
6 Dave Johnston plant is due to annual increases in fixed prices from the base
7 year to 2011 with almost. millon attrbutable to the Dry Fork mine itself.
8 Increased rail rates durng 2011 relative to what was in Base NPC have also
9 contrbuted approximately. millon of the total price increase at the plant.
10 . Hunter - approximately $14 millon increase. The majority of the Hunter plant
11 requirements are supplied under a long-term coal supply agreement with Arch
12 Coal Sales. Arch supplied approximately 90 percent of the plant deliveries
13 assumed in the Base NPC and approximately 75 percent durng the 12 months
14 ending November 30, 2011. Approximately. millon of the $14 millon
15 increase is a result of the Januar 2011 price reopener under the Arch contract.
16 As a result of the reopener, the contract price increased by almost. per ton
17 between 2010 and 2011. The remainder of the increase at the Hunter plant is
18 due to increased Deer Creek operating costs and a new long-term coal supply
19 agreement with WestRidge that commenced Januar 2011. The reduction in
20 Sufco delivenes from the levels included in Base NPC was offset by increase
21 in deliveries from the West Ridge mine under the new coal supply agreement.
22 · Huntington - approximately $7 millon increase. The majority of the
23 Huntington plant is supplied by the Deer Creek mine. The increase is
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predominantly the result of higher operating costs associated with movement
of longwall operations from the Blind Canyon seam to the lower Hiawatha
seam in December 2010 and reduced longwall production due to adverse
geological conditions associated with elevated levels of ash and sulfur
encountered in the Hiawatha seam.
· Bridger - approximately $26 millon increase. The price increase at the
Bridger Plant is the result of higher Bridger Coal Company production costs,
. milion, and increased Black Butte costs, . millon. The inclusion of
378 thousand tons of Black Butte 2009 contract at a Freight-On-Board
("F.O.B") mine price of _ per ton in the Base NPC versus an
approximate. per ton F.O.B mine price in the actual results accounts for
approximately. millon of the Black Butte increase. Escalation of producer
price indices under the Black Butte contract account for the remaining .
millon of the Black Butte increase. Higher operating costs of approximately
. millon at the Bridger mine in 2011 are a result of reductions in the Jim
Bridger plant bum and poor underground mining conditions.
Does this conclude your direct testimony?
Yes.
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Case No. PAC-E-12-03
Exhibit NO.1
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhbit Accompanying Direct Testimony of Gregory N. Duvall
Februar 2012
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNAIN POWER FOR
AUTHORITY TO INCREASE RATES
BY $2.6 MILLION TO RECOVER
DEFERRD NET POWER COSTS
THROUGH THE ENERGY COST
ADJUSTMENT MECHANISM
)
) CASE NO. P AC-E-12-03
)
) Direct Testimony of Wiliam R. Griffith
)
)
)
)
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-12-03
February 2012
1 Q.Please state your name, business address and present position with the
2 Company (also referred to as Rocky Mountain Power).
3 A.My name is Wiliam R. Griffith. My business address is 825 NE Multnomah
4 Street, Suite 2000, Portand, Oregon 97232. My present position is Director,
5 Pricing, Cost of Service & Regulatory Operations in the Regulation Deparment.
6 Qualifcations
7 Q.
8 A.
9
10
11
12
13
14
15 Q.
16 A.
17
18 Q.
19 A.
Briefly describe your educational and professional background.
I have a B.A. degree with High Honors and distinction in Political Science and
Economics from San Diego State University and an M.A. in Political Science
from that same institution; I was subsequently employed on the faculty. I attended
the University of Oregon and completed all course work towards a Ph.D. in
Political Science. I joined the Company in the Rates & Regulation Deparment in
December 1983. In June 1989, I became Manager, Pricing in the Regulation
Deparent. In Februar 2001, I was promoted to my current position.
Have you appeared as a witness in previous regulatory proceedings?
Yes. I have testified for the Company in regulatory proceedings in Idaho, Utah,
Oregon, Wyoming, Washington, and California.
What are your responsibilties in this proceeding?
I am responsible for the Company's proposed rates in this case.
20 Background
21 Q.
22 A.
What level of revenues is Schedule 94 currently designed to collect?
Order No. 32216 authorized the Company to collect $10.4 millon on an annual
23 basis from April 1,2011 to March 31, 2012. Currently Schedule 94 is designed to
Griffith, Di - 1
Rocky Mountain Power
1 collect that level of revenues based on Idaho actual loads from Case No. PAC-E-
2 11-07. However, Idaho's actual loads were slightly lower during the collection
3 period and the Company anticipates that it wil collect approximately $10.2
4 millon over that collection period.
5 Proposed Rate Change for Schedule 94
6 Q.
7 A.
Please describe Rocky Mountain Power's proposed rate change in this case.
As stated in the direct testimony of the Company's witness Mr. Gregory N.
8 Duvall, in this annual ECAM filing the Company proposes no change to its
9 current ECAM surcharge collection rates, equal to $10.4 millon, from retail
10 customers other than Monsanto and Agrum. For Monsanto and Agrium, the
11 Company proposes to implement new tarff surcharge rates for inclusion in Tarff
12 Schedule 94 with an initial collection rate of approximately $2.6 milion.
13 Including Monsanto's and Agrium's tarff schedules in with the curent energy
14 cost adjustment tarff Schedule 94 surcharge rates wil increase the annual
15 collection level to $13.0 millon.
16 Q.
17 A.
Please explain the proposed rate change for Monsanto and Agrium.
As indicated by Mr. Duvall, Monsanto's Schedule 400 service is responsible for
$7.2 millon and Agrum's Schedule 401 service is responsible for $0.5 millon of18
19
20
21
22
23
the current ECAM deferral. The Company proposes to amortize these amounts for
Monsanto and Agrium, respectively, over three years to reflect the three year
amortization outlned in the Stipulation, agreed to by the paries, and approved by
the Commssion, Order No. 32432, in the Company's 2011 general rate case. This
amortization results in new tarff surcharge rates for Monsanto and Agrum for
Griffith, Di - 2
Rocky Mountain Power
1 inclusion in Tarff Schedule 94 equal to an initial collection rate of approximately
2 $2.6 millon.
3 Q.
4 A.
What is the impact from the above ECAM rate change proposals?
These rate change proposals result in a 3.3 percent increase for Monsanto and 3.2
5 percent increase for Agrium. As indicated above, the Company proposes no
6 changes for other retail tarff customers.
7 Proposed Rate Design for Schedule 94
How were the proposed Schedule 94 rates developed for Monsanto (Schedule8Q.
9
10 A.
11
12
13
14
15 Q.
16 A.
17
18
19
20 Q.
21 A.
22
23
400) and Agrium (Schedule 401)?
The proposed rates for these two customers were developed by dividing their
November 30, 2011, ECAM balance by three (to reflect the three year
amortization) and then dividing that amount by their kWh consumption at the
transmission voltage leveL. As a result, a proposed Schedule 94 rate of 0.175 cents
per kWh is indicated for Monsanto and 0.164 cents per kWh for Agrum.
Please describe Exhibit No.2.
Exhibit No. 2 ilustrates the metered loads, the line loss adjusted loads, the
allocation of the ECAM price change, and the percentage change by rate schedule
based on present revenues from Order No. 32432, PAC-E-11-12, the Company's
2011 general rate case.
Please describe Exhibit No.3.
Exhibit No. 3 is the proposed tarff Schedule 94, Energy Cost Adjustment,
designed to collect approximately $13.0 millon of the ECAM deferred balance.
The only revisions to the Schedule 94 surcharge proposed in this case are the
Griffith, Di - 3
Rocky Mountain Power
1
2
3
4
5 Q.
6 A.
proposed rates for Monsanto (Schedule 400) and Agrium (Schedule 401) discussed
above. Rates for other customers are unchanged. Consistent with the ECAM
mechanism, the Company proposes that these rate changes become effective on
April i, 2012.
Does this conclude youi: testimony?
Yes, it does.
Griffth, Di - 4
Rocky Mountain Power
Case No. PAC-E-12-03
Exhibit NO.2
Witness: Wiliam R. Griffith
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Wiliam R. Griffth
February 2012
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::
Case No. PAC-E-12-03
Exhbit NO.3
Witness: Wiliam R. Griffith
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Willam R. Griffth
Februar 2012
"~ROCKY MOUNTAIN
POWER
A DIVISION OF PAFlCORP
I.P.U.C. No.1
Rocky Mountain Power
Exhibit NO.3 Page 1 of 3
Case No. Pac-E-12-03
Witness: Willam R. Griffit
Second Revision of Sheet No. 94.1
Cancellng First Revision of Sheet No. 94.1
ROCKY 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 bils shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Secondar
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
Schedule 1
Schedule 6
Schedule 6A
Schedule 7
Schedule 7A
Schedule 9
Schedule 10
Schedule 11
Schedule 12
Schedule 19
Schedule 23
Schedule 23A
Schedule 24
Schedule 35
Schedule 35A
Schedule 36
Schedule 400
Schedule 401
Submitted Under Case No. PAC-E-12-03
ISSUED: Februar 1,2012
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
O.569Ø per kWh
0.569Ø per kWh
0.569Ø per kWh
O.569Ø per kWh
0.569Ø per kWh
Delivery Voltage
Primar Transmission
0.550Ø per kWh
O.550Ø per kWh
0.535Ø per kWh
0.550Ø per kWh
O.550Ø per kWh
O.550Ø per kWh
0.550Ø per kWh
0.550Ø per kWh
0.175Ø per kWh
0.164Ø per kWh
EFFECTIVE: April 1, 2012
"~ROCKY MOUNTAINPOER
A OIVSiON OF PAIFlCORP
Rocky Mountain Power
Exhibit No.3 Page 2 of 3
Case No. Pac-E-12-03
Witness: Willam R. Griffth
I I.P.U.C. No.1
FiSecond Revision of Sheet No. 94.1
Cancellng OFigiROl First Revision of Sheet No. 94.1
ROCKY 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 bils shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Submitted Under Case No. PAC E I I 07 PAC-E-12-03
ISSUED: Mareli 31, 201 1Februar 1, 2012 EFFECTIV: Aprill,201~+
~2t~~OUNTAIN
Rocky Mountain Power
Exhibit NO.3 Page 3 of 3
Case No. Pac-E-12-03
Witness: Willam R. Griffth
Submitted Under Case No. PAC E I I 07 PAC-E-12-03
ISSUED: March 31, 20 II February 1, 2012 EFFECTIVE: April 1, 201i+