20101116Shu Reb, Exhibits.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $27.7 )
MILLION, OR APPROXIMATELY )13.7 PERCENT )
CASE NO. PAC.E.I0.07
Rebuttal Testimony of Hui Shu
ROCKY MOUNTAIN POWER
CASE NO. PAC.E.I0.07
November 2010
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Please state your name, business address and present position with
PacitiCorp dba Rocky Mountain Power (the "Company").
My name is Hui Shu, my business address is 825 NE Multnomah, Suite 600,
Portland, Oregon 97232. My present position is Manager of Net Power Costs.
Are you the same Hui Shu that submitted direct testimony in this
proceeding?
Yes.
What is the purpose of your rebuttal testimony?
The purose of my rebuttal testimony is to respond to the adjustments proposed
by intervening paries to the Company's fied net power costs~r"NPC") in the
curent proceeding. These adjustments ar proposed by Mr. Bryan Lanspery of
the Idaho Public Utilities Commssion Staff ("Staff'), Mr. Randall J. Falenberg
of the PacifiCorp Idaho Industral Customers ("PILC"), and Mr. Mark T. Widmer
of Monsanto. In addition to my testimony, Company's witnesses Mr. Chad A.
Teply addesses the adjustments proposed by Mr. Falenberg and Mr. Widmer
regarding the Lake Side outage, Colstrp outage and Naughton outages, and Ms.
Cindy A. Crane addresses adjustment proposed by Mr. Falenberg regarding the
18 Jim Bridger fuel quality.
19 Recommendation for Company's Net Power Costs
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Has the Company made changes to its originaly tied NPC?
Yes. The Company's system NPC has decreased from $1.07 bilon in the
22 original filg to $1.063 bilon.
Shu, Di-Reb - 1
Rocky Mountan Power
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What are the reasons why the Company's NPC decreased?
This decrease of $6.5 millon reflects corrections and the Company's acceptance
of certain adjustments proposed by Staff, PILC and Monsanto.
Please summarize the changes in NPC from your direct testimony_
Exhbit No. 71 summares the cost impact of the corrections and adopted
adjustments that result in an NPC of approximately $1.063 billion on a total
Company basis, which is $69.0 millon on an Idaho-allocated basis.
Do you have a general comment regarding the level of NPC that the
Company has calculated and the adjustments proposed by other partes?
Yes. NPC and its components are volatile and inherently dificult to forecast.
Actual operation lacks the same certainty and perfect foresight as the optimzation
model used to forecast NPC in regards to the varables.and constraints, such as
hourly load and market prices, availabilty of generation and transmission
facilities, and weather conditions that impact the amount of hydro and wind
generation. As a result, the actual operation/dispatch of the Company's resources
may not necessarly achieve what the optimiation model projects. That is, the
model optized Npc tends to understate the actual Npc that would be incured
for the same period. The Company's net power costs have increase significantly
in recent year. With known changes in the Company's resource portolio in the
rate effective period, the normaled NP in a historical test period fuer
understates the costs that the Company prudently incurs to serve its customers. In
the last general rate case, Case No. PAC-E-08-07, the Company agred to Npc of
$982 milion, given the design of the test period. However, the actual Npc
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durng 2008, which was the test period in that case, was $1.121 bilion, and the
actual NPC during 2009 when the rates were in effect was $1.022 billon. In the
curent case, the Company proposed NPC of $1,070 millon that would be in
effect during 2011. The Company's recent filing in Oregon Docket No. UE 216
has shown that the projected NP in 2011 would be approximately $1,289
milion. The preliminar results indicate that the Company's actual NPC though
September are at approximately $859 millon, or $1.129 bilion for the 12-month
period ended September 2010. Given the significant differences between what
the Company proposed in this case and expected actual NPC in the rate effective
period, it is unreasonable to mae furher adjustments to reduce the modeled NPC
that wil be used to set base rates beginnng Januar 1,2011, especially when the
adjustments are as significant as the ones proposed by Staff, PIIC and Monsanto.
The Commision has authorized an Energy Cost Adjustment Mechanism
("ECAM") for the Company. Doesn't the implementation of ECAM resolve
the under. recovery risks of NPC?
No. As noted by Mr. Widmer the "review and determnation of the appropriate
Npc is very importt because it represents one of the Company's single largest
revenue requirement components and establishes the ECAM baselie."! The
amount that the Company is authoried to recover under the ECAM is based on
the diferences between actual NPC and the base NPC included in rates durng
that period. Curently the Company's ECAM has a 90/10 sharng band. Because
of the sharng band the Company is effectively limited to not recover all of the
prudently incured NP in the rate effective period when actual NPC are
1 Dit testny of Mar T Widme page 10 lines 14-16.
Shu, Di-Reb - 3
Rocky Mountan Power
1 projected to be higher than what the Company proposes in the current case.
2 Company Responses to Specific Adjustments - Overview
3 Q.How have you organized your responses to the parties' modeling adjustments
4 to NPC?
5 A.I have grouped the paries' proposed NPC modeling adjustments into thee
6 . categories. First, there are adjustments to which the Company has agreed in
7 whole. Second, there are adjustments to which the Company has agreed in par,
8 or in response to which the Company has proposed a different position. Third,
9 there are proposed modeling adjustments that the Company disputes as
10 inaccurate, unsubstantiated, or inconsistent with normalized ratemag.
11 Corrections and Adjustments Accepted in Whole
12 Q.Has the Company made any corrections since its initial filing?
13 A.Yes. After the initial fiing, the Company has identified and provided in response
14 to a Monsanto data discovery (Monsanto Data Request 2.33) thee corrections:
15 .Dunlap was modeled without reserve requirements;
16 .STF transmission from southeast Idaho to nortern Utah was not removed
17 after the inclusion of the Populus to Termal trsmission line addition;
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19 .The UAMPS Use of Facilities wheeling expense should have been
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21 Correctig these thr items increases the Company's system NPC by
22 approximtely $0.1 milion.
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Has the Company accepted any adjustments proposed by Staff, PUC or
Monsanto?
Yes. The Company has accepted the following proposed adjustments:
. Commtment Logic Screens (PILC Adjustment 1): As proposed by PIIC,
the Company agrees to modi its daily screens consistent with the
methodology set forth in the paries' stipulation in Oregon Docket UE
216. This change results in a decrease to system NPC of approximately
$1.7 millon. As discussed later in my testimony, the Company does not
agree that ths adjustment changes incremental O&M expenses included in
the test year, as these expenses were not included in the test year.
. Inter-hour Wind Integration Costs of Non-Owned Resources (corrted
PIIC Adjustment 4, and portion of Staff wind integration costs adjustment
and portion of Monsanto Adjustment 2): The Company agrees to remove
inter-hour wind integration costs associated with the wind projects that are
located in the Company's balancing areas but do not deliver generation to
the Company's system. PIle's inter-hour wind integration adjustment
needs to be corrected by removing the wind generation that the Company
recives under contract with Seattle City and Light ("SCL"). This
adjustment results in a decrease to system NPC of approximately
$1.4 millon.
. Colstrp Planned Outages (Monsanto Adjustment 8). The Company
agrees to ths adjustment that moves the ting of planed outages of the
two Colstrp units from fall to sprig. This reduces the system NPC by
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1 approximately $0.2 millon.
2 .Modeling of Mona Market (Monsanto Adjustment 14). The Company
3 does not agree to the concept and logic of this adjustment. However,
4 given the complexity around modeling all maket caps in GRID, rather
5 than selectively makng adjustments to only one market for the selected
6 time periods, the Company accepts the amount of adjustment proposed by
7 Monsanto in the current case and wil review the overall modeling of
8 market caps in the futue. This reduces the system NPC by approximately
9 $0.4 millon.
10 Adjustments Accepted in Part
11 APS Supplemental Adjustment (Staff's APS Supplemental Adjustment, Monsanto
12 Adjustment 1)
13 Q.Please explain the issue raised by Staff and Monsanto with respect to the
14 APS Supplemental contract.
15 A.Staff and Monsanto state that the Company's modeling of the APS Supplementa
16 contract causes uneconomic dispatch of the contract, and the contrct should be
17 removed. The proposed adjustment would reduce system NPC by $1.9 millon.
18 Q.Doe the Company agree with the proposal?
19 A.No. Contrar to what Sta indicates as an inconsistency, the Company's
20 modeling consistently reflects the fact that the Company has historically
21 purchased energy from APS under the terms of the contract. It is not reasonable
22 to aritrary remove this contract simply based on modeling results.
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Please describe the APS Supplemental contract.
The Company executed the Supplemental contract in 1990 with the Arona
Public Service Company ("APS") and has included it in NPC in Idao since that
time. Under the contract, APS makes available to the Company two categories of
supplemental fir energy, coal ("APS Coal") and other ("APS Other"). At
present, per the terms of contract, APS is obligated to offer the Company 219,000
megawatt-hours of fir energy on an annual basis priced at its incrementa cost of
coal generation, and 876,000 megawatt-hours of fir energy from other sources
that are primary natual gas-fired resources. The two categories of fir energy
cannot be offered at the same time. APS is obligate to offer the energy, but the
Company only takes the energy when it is economical to do so.
Has the Company modified the modelig of the APS Supplemental contract
in the current rebutta filing?
Yes. The new approach to modelig this contrct eliminates the increases to NPC
when the contract is dispatched. The Company has aligned the tig and pricing
of the deliveries with historic experience, rather than algning the volume of
17 deliveries with historic volumes, GRI now exercises the cal option on the
18 available energy when it is economical to do so. Ths change reduces the
19 Company's fied system NP by approximately $2.6 millon.
20 Non.fi Tramiion (Staff NF Transmision Adjustment, Monsanto Adjustment 3)
21 Q.Pleas explai Staffs and Monsto's positions on the modeling of non. firm
22 tramiion.
23 A.Staf and Monsanto recommend that the Company should include non-fir
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transmission in GRID. Staff and Monsanto modeled non-firm transmission using
a four-year historical average to adjust the capacity of links in the GRI model
topology and using a dollar per megawatt-hour energy charge to calculate
expenses. Staf's and Monsanto's proposed adjustments would reduce system
NPC by $2.5 millon and $2.4 millon, respectively.
What is the Company's response to Staff's and Monsto's proposal?
The Company agrees to model non-fir transmission in GRI. However, if non-
fir transmission is included in the model, it should be included on the same
basis as short-term fir transmission. There is no basis for using a different
method for non-fir transmission than for short-term trnsmission. Both tyes of
transmission should be modeled using a four-year average to adjust the capacity
links in the GRID model topology and the most curent year of expenses.
Please explain why non. firm transmission should be modeled the same as
short. term firm transmision.
In the process of reviewing how the Company has utilied non-fir trnsmission,
it is clear that the Company purchases and uses short-term fir and non-fir
transmission in the same way. The trsmission providers offer certain amount of
transmission capacity as fir products, and the rest as non-fir. The only
difference between the two products is that non-fi transmission wil be cut first
for reliabilty of the trnsmission system. For both short-term fir transmission
and non-fir transmission, the wheeling expenses are incur whether the
transmission capacity purchased is fully utiized or not. As a result, the Company
has modeled the non-firm transmission capabilty base on a four-year average of
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the historical purchases of non-fir transmission, and the expenses estimated
based on what was incured in the base period of the current filng.
What is the impact on NPC of includig non.firm transmission in GRID?
Including non-fir transmission using an approach that is consistent with the
5 modeling of short-term fir transmission decreases system NPC by
6 approximately $1.2 millon.
7 Top of the World Wind (Monsanto 6)
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Please desribe the adjustment proposed by Monsanto for the power
purchase contract with Top of the World Wind.
Monsanto proposes to reflect the actual in-service date of the contract, which is
one month earlier than what the Company has included in its original filng, but
exclude the wind integration costs related to the wind generation. This
adjustment would increase system NPC by $1.6 miion.
Does the Company agree .with thi adjustment?
Parialy. In addition to the impact of additional purchase expenses, the additional
wind generation would lead to additional wind integration costs, which is a
subject that I wil discuss later. Applying the same methodology as the Company
applied for all other wind generation, the additional energy purchased from Top
of the World Wind increases system NPC by approximate $1.9 milion, including
additional wid integration costs.
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1 Company Responses to Contested Adjustments
2 Wind Integration Costs (Staff Wind Integration Costs Adjustment, PUC
3 Adjustment 5, Monsanto Adjustment 2, 2a and 2b)
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What have Staff, PUC and Monsanto proposed with respect to the overall
wind integration costs and the wind integration costs of the OATT
customers?
Staff s proposal is to remove the entire amount of wind integration costs from the
Company's filing, which would reduce the Company's system NPC by
approximately $34.2 millon. PIIC proposes to remove the intra-hour wind
integration costs associated with integrating non-owned wind projects that are
interconnected to the Company's transmission system, which would decrease the
Company's system NPC by approximately $4.3 millon. Monsanto proposes
varous versions of adjustments to the Company's wind integration costs,
including the same proposal as the Staff to remove the $34.2 millon of the tota
wind integration costs, a similar proposal to PIIC is to remove the wind
integration costs of the non-owned wind projects that would reduce the
Company's system NPC by approximately $6.4 miion, or to include the wind
integration costs for the portion of the test period that incorporated the actual
wholesale transactions and reduce the Company's system NPC by approximately
$2.6 millon.
Do you see any basis to the proposls made by Staff and Monsanto to exclude
the entire wind integration costs?
No. The proposals seem to be made based on thee general arguments. First, the
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wind integration charge that the Company used is for setting avoided costs rates
and not for setting retail rates. Second, the wind integration costs "are neither
paid under contract or to any other utility." Third, the costs should be captued in
the Company's ECAM. Their arguments to support their adjustments are
contradictory and ilogicaL.
Please explain.
In Case No. PAC-E-09-07, after considerig the Company's proposed wind
integration costs and paries' positions on such costs, the Commssion adopted a
wind integration charge that was lower than what the Company proposed and
authorized the Company to use $6.50 per megawatt-hour charge in determning its
avoided costs for wind qualifying facilities in Idaho. Neither Staff nor Monsanto
provides any evidence that would explain why this charge is appropriate to apply
to wind qualifying facilities, but not appropriate to apply to Company-owned
facilities or non-qualifying facilty purchased power agreements. It is also unclear
whether Staff or Monsanto is suggesting that by applying this charge, the prices
for wind qualifying facilties located in Idao ar understated and whether the
reta customers should pay more for the two qualying facilty contracts that are
listed in Mr. Lanspery's testiony. Whe implying that the Company's wind
integration costs are not real ("neither paid under contract or to any other utilty"),
Staf states that the Company's wind integration costs are captued in actual test
period expenses and reflected in a number of accounts? In adtion, if the
proposal of removing the wind integration costs from the Company's filing is
2 Stafs testimny on page 5, lines 20 thugh 22 suggest that the reference to 200 may nee to be 2010.
Oterse, the discussion on a 200 test period would be irlevant in the curent proceeng.
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based on the fact that the wind integration costs are of significant size, diffcult to
calculate, and the Company may capture such costs in its ECAM filings, then the
same argument may be made to the wholesale sales revenues: the Company's
wholesale revenues are large, the actual amount of revenues in a year never
matches the amount that has been projected, and as a result, the Company could
use the ECAM filings to capture such revenues.
Staff indicates that in the testimony requesting the ECAM, the Company
stated that the ECAM was designed to capture the volatilty, including the
wind variabilty. How do you respond?
It is correct that the ECAM is designed to captue the volatility in NPC that
occurs in relation to a properly set base NPC. However, the wind integration
costs are not the same as the varation in NPC that the ECAM is designed to
captue. Instead of addressing the varation between normlized and actual wind
generation as the ECAM is designed for, wind integration costs are costs incured
due to additional reserve requirments to integrate the intermttent generation
from the wind projects into the Company's portfolio of resources. The addtional
reserve requirements include regulatig services that deal with wind variabilty in
ten-miute interval, and load following services that deal with wind varabilty
over hourly time intervals. Both services should respond to the up and down
varations inerent in wind facilties. That is, the additional reserve requirements
to integrate wind generation into the Company's resource portfolio taes on the
form of regulation up, regulation down, load followig up and load following
down.
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In proposing to remove the wind integration costs, Staff never explained
why such costs, which are reflected in a number of accounts, simply should not be
par of the normlized studies, or at least not "explicitly". The Company could
have modeled the wind integration costs "implicitly" by incorporating the
additional reserve requirements in GRID, which would certainly lead to a value
that is higher than $6.50 per megawatt-hour. The Company applied a simplified
calculation using a Commssion-authorized value that is lower than what the
Company believes it to be in an attempt to minimize the controversy. In addition,
since the ECAM is designed to capture the differences between actual NPC and
the base NP, the base NPC should reasonably account for all components,
including the wind integration costs.
Staff stated that the Commission has never expressly approved wind
integrtion costs in any utilty's general rate case. Do you believe that thi is
a precedent to follow?
No. The fact that the Commssion has never expressly approved such costs does
not mean that the costs do not exist or are not prudently incured. The Company's
wind resoures have increased significantly in recent years. The subject of wind
integration costs has received more and more attention in recent years. The
Company is not the only utilty that has recognized the cost impact of integrating
wind generation into its resource portolio. By allowing the wind integration
costs charged by the Bonnevile Power Admstration ("BPA"), Staf and
Monsanto agree that the Company prudently incured wind integration costs in
serving its customers at approximately $5.89 per megawatt-hour.
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One of Monsanto's arguments for removing wind integration costs seems to
be the fact that the Company is unable to calculate its actual wind
integration costs, and without knowing the actual costs "it is very dificult to
determine the reasonableness of Company's requested recovery." How do
you respond?
First of all, as Mr. Widmer is aware, the Company operates its resource portfolio
to serve all its obligations, and does not differentiate what resources are used for
serving which obligations. As such, the Company can only estimate the impact of
wind integration costs. Second, if Mr. Widmer is looking for references to check
if the Company's wind integration costs are within reasonableness, he only needs
to look at the wind integration charge that BPA imposes, the wind integration
study that the Company used in proposing wind integration costs for avoided
costs, wind integration costs that he quoted in his testimony from the Company's
last Integrated Resource Plan ("IRP"), and the wind integration costs of $6.63 per
megawatt.,hour that were approved by the Public Service Commssion of Uta in
the Company's last general rate case Docket No. 09~035-23.
Why do PUC and Monsanto propose disllowing intra.hour wid integration
chares assoiate with non.owned wind facilities in the Company's
balncing areas?
PIIC argues that the Company should not include the wind integration costs
incurd by providing wid integration services to the non-owned wind projects
beause the Company does not have a trsmission taf to recover the costs from
those customers. The proposal would reduce system NPC by $4.3 mion. As a
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secondar proposal, Monsanto also proposed the same adjustment, which would
reduce system NPC by $6.4 millon.
Are there any errors in the adjustments by PUC and Monsanto?
Yes. The adjustments proposed by PIIC and Monsanto are both incorrectly
calculated because, in addition to generation from the non-owned wind projects,
their adjustments exclude the generation under the contract between the Company
and SCL. Per the terms of the contract, the Company receives wind generation
from the portion of the Stateline wind project owned by SCL and then retus
fir and shaped energy to SCL. In addition, Monsanto's adjustment also includes
an adjustment for inter-hour wind integration for the wind projects that are located
in the Company's balancing areas that the Company has interconnected.
Why doesn't the Company charge wind generators for wind integation costs
that are located in the Company's balancing area but do not provide
generation to the Company?
The Company could not charge wholesale transmission customers for this type of
service without FERC approval of a rate application proposing a new wind
integration charge. The Company is required by federa law to interconnect with
new facilities under the term of its Open Access Transmission Tarff ("OATT").
Once the Company interconnects a new facilty to its trnsmission system, it is
responsible for integratig it into the system.
Are there barrers to chang non.owned wind facilities for wind integration
costs?
Yes. Modfyig the Company's OA TT to impose wind integration charges on
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only non-owned wind facilties would violate the federal statutory mandate that
the Company treat all transmission customers, affilated and non-affiliated, on a
not unduly discriminatory basis. In addition, there is little regulatory guidance
from PERC in this area with respect to what FERC wil ultimately consider to be
an adequate proposal for a wind integration charge. Although PERC
conditionally accepted a proposal by We star to add a new Schedule 3A charge,
whereby all varable generators located within Westar's balancing area pay a
regulatory service fee for power exported outside of the balancing area, recently,
FERC rejected Puget Sound Energy's proposed revision to its OAIT to add a new
charge applicable to all wind generators for wind integration within-hour
generation following service. In each case, wind industr advocates vigorously
protested the proposed tarff revisions because, among other issues, the proposed
charges' constituted significantly higher regulatory service fees to intermttent
resources than for dispatch able resources.
Does the Company plan to raise this issue in its next FERC rate cae?
Yes. The Company plans to fie a rate case with PERC no later than June 1,2011,
in which the Company wil include a proposed wind integration charge in its
transmission tarrates pendig any PERC guidance on the issue. The Company
completed a wind integration study in conjunction with its 2010 Integrated
Resource Plan and is in the process of reviewing comments from paries regarding
the study. It is hoped that the study can be use in the development of a wind
integration charge proposed to be added to the OA IT, however, no determation
has yet been made. The Company is closely trackig al developments at PERC
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related to wind integration and is bound to follow any guidance FERC may issue
in this regard.
Are the costs associated with wind integrtion a prudent expense?
Yes. As a balancing area authority, the Company must operate its balancing areas
by matching system resources to actual load and generation fluctuations on a
moment-to-moment basis though automatic generation control. Maintaining
system balance is one of the key functions of a balancing area authority who is
required to mantain system reliabilty, including maintaining system frequency.
Load fluctuations, outages, and generation output fluctuations all contrbute to the
need for balancing resources. The addition of renewable resources such as wind
has the tendency to increase the need for balancing resources.
What are the benefits to the Company's retail customers of providing such
services to the non.owned generation?
As a balancing area authority, the Company owns and operates an extensive
transmission network that it is required to operate safely and reliably for all of its
customers, keeping all resources and loads in balance on a moment-to-moment
basis. By providing wind integration services in addition to other transmission
related services as a balancing area authority, the Company ensures that its
customers are served by a reliable system with diverse resources. Moreover, any
transmission revenues received from non-owned generation, which pays wheelig
to the Company, ar credted agaist retal rates and therefore have the effect of
lowerig retal rates.
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What adjustment does Monsanto propose to the Company's inter.hour wind
integration costs?
If the Commssion does not agree with Monsanto's proposal to remove the entire
wind integration costs from the Company's filng then Monsanto proposes a
secondar adjustment. Monsanto claims that the inter-hour wind integration costs
for balancing purposes have already been included in the Company's fiing
though. the inclusion of actual short term fir transactions, and by calculating the
inter-hour wind integration costs for the period from Januar 1 to May 4, 2010,
the Company double counted the wind integration costs. The adjustment would
reduce Company's system NPC by $2.6 millon for inter-hour wind integration
costs from Januar to Apri.
What is your response to the propos?
I don't agree with the proposal. Monsanto's own arguments present
contradictions. On one hand, Mr. Widmer claims that the inter-hour wind
integration costs have been included for the first four months of the test period
because the Company has included actual short term fir transactions though
that period. Then on the other hand, Mr. Widmer also agrees that "(t)he Company
has a varety of options for balancing," and these options include redispatch of all
flexible resources, fir and non-fir wholesale contracts, generation and wid
curlment. The Company has included actual short term fir transactions in its
filing. However, those transactions are only a smal porton, if any, of the
resources that the Company utilizes to integrte generation from wind facilties
into its system. In its filing, the Company has included wind generation at the
Shu, Di-Reb - 18
Rocky Mounta Power
1
2
3
4
5 Q.
6 A.
7
8
9
10
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12
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18 Q.
19
20
21 A.
22
23
expected level that lacks the significant varabilty as in actual generation. As
such, the generation from all other flexible resources is also at the level that does
not reflect the impact of the significant varabilty in actual wind generation and
the costs of integrating such generation into its system.
Are there other problems with Monsanto's proposal?
Yes. While not accepting the Company's wind integration costs at $6.50 per
megawatt-hour, Mr. Widmer uses the Company's wind integration at $6.92 per
megawatt-hour as a reasonable approximation to split the intra-hour and inter-
hour wind integration costs. In addition, it is unclear what Mr. Widmer implies
by stating that fuer adjustment could be made to what he has proposed in
relation to varous other means. If the reference were to the flexible resoure
indicated above, the Company's NPC in the proceeding has not considered the
impact of significant fluctuation in wind generation on other resources because
they are all modeled on a normized basis. If the reference were to the additional
sales transactions that the Company could mae, Mr. Widmer would be double
countig the presumed impact that he calculated based on short term fir
transactions, which wo~ld have included both sales and purchases.
What do you recommend the Commision do regarding various proposals to
remove all or porton of the wind integration costs that the Company has
included in the case?
With the exception of inter-hour wind integration costs discussed earlier in my
testiony that the Company agrees to remove, the Commssion should reject all
other adjustments proposed by Staff, PUC and Monsanto.
Shu, Di-Reb - 19
Rocky Mountan Power
1 Bear River Hydro Normalization (Staff Bear River Hydro Generation Adjustment,
2 Monsanto Adjustment 12)
3 Q.
4 A.
5
6
7
8
9
10 Q.
11 A.
12
13
14
15
16 Q.
17
18 A.
19
20
21
22
23
What was the issue on the Bear River normalization?
The Company modeled the normalized generation from the Bear River system
based on history, excluding the flood control years. Staf and Monsanto argued
. that the Company should not have reduced hydro generation from the Bear River
system based on long-term drought conditions on the Bear River, and recommend
using the historical average generation from the Bear River system. The
adjustments would reduce the Company's system NPC by $2.2 milion.
Does the Company agree with Staff and Monsanto's argument?
No. The water available for generation at the Bear River facilties is dependent
on contractually specified irgation and flood control releases from Bear Lake.
Flood control on the Bear River is an operational constrt and releases of water
for flood control have not been avaiable to the Company since 2001. The usual
manner of normalizing hydro requires adjustments for operating constraits.
Pleas explain the contractual controls over dishages of water from Bear
Lake.
Those contractual controls include: (1) The 1958 Bear River Compact approved
by the United States Congress which prohibits the release of water from Bear
Lae solely for power generation below the irgation reserve level of elevation
5,914.61 feet; (2) the 2000 "Operations Agreement for PacifiCorp's Bear River
System," which requirs that the Company operate Bear Lake primaly for
irgation and flood control. This agrement was required by Idao, Wyomig,
Shu, Di-Reb - 20
Rocky Mountan Power
1
2
3
4
5
6
7
8
9
10 Q.
11
12 A.
13
14
15
16
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18
19
20
21
22
23
and Utah as a condition for approving MidAmerican Energy Holdings Company's
acquisition of PacifiCorp; and (3) recently, the Company began modeling the
impact of the new operating constraints required by the 2003 license for FERC
Project #20, including the Grace Plant on the Bear River system, which mandates
increased bypass flows below Grace dam for ameliorating fisheries and aquatic
issues and to provide recreation opportnities (e.g., white water boating). Water
released into. the river channel below the dam bypasses the turbine and cannot be
used for generation. This alone reduces total generation available from the Bear
River by an estimated 19,000 megawatt-hours.
Please provide background on how the Company modeled Bear River
generation in the last case.
The dams on the Bear River have thee potential sources of water for generation:
natural inflow, water withdrawn from Bear Lake to supply downstream irgators,
and water withdrawn from Bear Lake for flood control puroses. The Company's
operating agreements for the Bear River system referred to above prohibit the
Company from withdrawing water from Bear Lake for generation and flood
control puroses unless the lake elevation exceeds a certin leveL. For the past 10
years, and for the foreseeable futue assumig median streamow into Bear Lake,
ths operational constrait has and wil prevent the Company from operating the
Bear River system with flood control releases. The lake elevation is projected to
drop to about 5,910 feet at present, which is 11 feet below the 5,921 feet elevation
level that allows the Company to release flood contrl storage.
The Company previously modeled the Bear River system using historical
Shu, Di-Reb - 21
Rocky Mounta Power
1
2
3
4
5
6
7
8
9 Q.
10
11 A.
12
13
14
15
16
normlized hydro generation for al the operational modes that included water
supply from natual run-off, irgation deliveries, and flood control releases,
without considering the operational constraints around flood control operations.
After a careful review, the Company concluded that the floòd control mode of
operation has now effectively become unavailable, and the Company has begun
accounting for this operational constraint in its rate filngs and operations
planning by excluding the generation using the flood control water in its
normlized hydro generation.
What has been the generation from the Bear River system in the recent
history?
Figure 1 below shows the actual generation from the Bear River system from
1979 to 2009 water year (October of the previous calendar year to September of
the curnt year), which is the base period applied in the curent proceeding. The
un shaded bars identify the flood control years. It is clear that the generation
durng the flood control years is significantly higher than the non-flood control
years. The actual generation through 2010 is also added to the Figure.
Shu, Di-Reb - 22
Rocky Mounta Power
1 Figure 1. Actual Generation from Bear River
2
3
4
5
6
7
8
9
------------------------------------------------------------------ --------'"
800,000 ..---------------------------~--~-------------------------------------------------------------------- il~ t1¡ ~ ~ :, 'I lll!700,00 .+----- II --------------------------~ ~"~~ r~
~ ~ ~ ;:;: ~ !~ ~~ ~š ~
600,000 -l.---------------ll~~---------------------------T'l~------------~------------ ¡~ ~~ ~~ .~~ ~~ ~'1l 11 11 d II ii _~ ;: ~ š § ~ ~ š š š š
500,000 ~Ln.~~~~~...............lJ..il........tl...........................................................................i..l.J.l........................................................................1 ~~. ~ š ~ i ~ i ~ ~ ~\ ~~~šš~šš ~~š..~šI: ~i ~i I~i~ t'~ ~i i~ ii. š š Š ~ ~ š š .. š Š š š š š š400,000 -r....rT.~...l.....llll1lllnlr........................................,...........lllllr'iï......................................................
300,000 .t....-rt'r 'lnrtn'" -¡.......................................................~raTt'r...................................................
¡ n n~ H n n !l n ~ q d L i ¡200,000 ll"H'n'l..tntlt--l~lH"I"'I"'"'I''''''''~'''l-:'''l''~'''1''1''' .1--llltll...I.;;-...~...............I......I...l-..-.........I....
~ ~ ~ .~ ~ ~ ~ ~ ~ ¡ ~ § ~ ~ i I ~ ~ ~ ~ ¡ ~ š ~ ¡ ~ ¡ i I l
100,000 .~ ..¡.§..¡_k..~...g.*.q.l.. 4..H.. .. ... ... ... "'~"'~"'lR"'¡j~.. *"r4..¡'.¡..¡'*.. ...~... ...1.. .. .. .. .. ..~ ~~ ¡li~¡¡SU ~i¡ ~ ~ ~- š! ~~¡¡¡ ~
~ ¡ ~ I ~ ~ ~ ~ ~ š ~ š ~ ~ ~ .~ ~ ~ i ~ l ~ Š ~ I~ ~ ¡ š ~ ~ ~ ~ i i ¡ ~ ~ ~ ~ ~ I ~ ~ ~ ~ ~ ~. ~ ~
o .i~~~:i..,s.:.""..~t.~"rw~~~~ 1:~ ~~,~~.~, ':' .:' 't' "r' ~u~.1us:'1:uis,~,~~~:~ ~T~':.Æ..~t'~~" ~:''''~~' 1:' ~' 'Or ':' 't"" 't' ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~¡
I September 2010 is preliminary. I
L............~..........................................................................................._.............................._..._..............................................................................
Q.How does the normalized hydro generation from the Bear River system
compare with actual generation?
A.Figure 2 below shows the comparson of historical generation that is unadjusted
for any known and measurable changes, such as rules and regulations, over the
years, normalized generation in the curent proceeding as proposed by the
Company and by Staff and Monsanto, and the most recent actual generation. It is
clea that the normed generation in the Company's filing is more
representative of the expected generation from the Bear River system.
Shu, Di-Reb - 23
Rocky Mountai Power
1 Figure 2 Bear River Generation Comparison
350,000 r.....................................................................................................................................................................................
300,000 .+.- -.------.----.- .--.-.----.-
250,000 .1....... ...........................................................~ 200,001--
150,000 +--.
50,000
100,000
1979-2008 1979-2008 1979-2008
Average Median Median, wlo
Flood Control
IOGRC Staff and Water Year Water Year
Monsanto 2009 Actual 2010 Actual
September 2010 is preliminary.
:...........................................................................................................................................n.........~........................................."............................................................................
2 Q.What then is the consquence of adopting Staff and Monsanto's proposed
3 adjustment for Bear River normalization?
4 A.Adopting Staff and Monsanto's proposal would lead to overstating hydro
5 generation, and understating NPC as a result of not incorporating this operational
6 constraint in normalizing historical generation. I recommend the Commssion
7 reject the adjustment proposed by Sta and Monsanto.
8 Start Up Energy (PUC Adjustment 2)
9 Q.Pleas explain PUC's proposal for the value of sta.up energy.
10 A.PILC proposed that the Company include the energy associated with staing up
11 Cuant Creek, Lae Side, and Chehalis in NPC because the fuel costs of sta-ups
12 are included in NPC. The adjustment would decrease the Company's system
13 NPC by $1.7 milion.
Shu, Di-Reb - 24
Rocky Mounta Power
1 Q.
2 A.
3
4
5
6
7
8
9 Q.
10 A.
11
12
13
14
15
16
17
18
19
20
What other costs are incurred when starting up the gas. tied plants?
Star-up costs are not limited to fueL. In order to accommodate the star-ups of a
500 to 600-megawatt gas unit, the Company must re-dispatch the system. In
doing so, the Company incurs costs beyond what it would have incured had the
star-ups not occured. These costs could result from ramping down the lower~
costs hydro and thermal units to lower efficiency levels, and increasing generation
from higher-cost units prior to when they are needed. None of these costs are
included in GRID.
Did PUC's proposal contain technical errors?
Yes. In calculating the value for the sta-up energy, PILC violated the
requirement of the minimum down time required for units to stay offine before
retung to service. This is due to the fact that GRID allows units to star
instantaneously. However, if sta-up energy is to be considered, the multi-hour
star-up sequence must also be considered. The end result is that the units would
need to stay offlne and be unavailable for a longer time in order for PIIC' s
adjustment to be even applicable. The prolonged downtime would lead to
increases in NPC by approximately $4.7 millon from what the Company included
in its original filg on a total Company basis, which offsets the $1.7 millon
assumed value of the sta..up energy. As a result, I recommend the Commssion
reject PIlC's adjustment.
Shu, Di-Reb - 25
Rocky Mounta Power
1 Normalation of Call Option Contracts (PUC Adjustment 3, Monsanto Adjustment
2 13)
3 Q.
4
5
6 A.
7
8
9
10
11 Q.
12 A.
13
14
15
16
17
18
19
20
21
22
23
What were the adjustments that PUC proposes to the modeling of the SMUD
sales contract and Monsanto proposes to the modeling of the Black Hils sales
contract?
PIlC proposes to substitute actual data for normlized data for the sales contrct
with the Sacramento Municipal Utilty Distrct ("SMUD"), and Monsanto
proposes simlar adjustment for the sales contract with Black Hils Power ("Black
Hils"). The adjustmnts would reduce the Company's system NPC by $1.6
milion and $1.3 millon, respectively.
Do you have any general comments about the two proposals?
Yes. For normalized purposes, the GRID assumes that the counterparies - who
control the call options on these two contracts - wil maximize the value of the
contracts and take power at the most economical time. GRI assumes
optimiation of all flexible resources, while PIIC's and Monsanto's proposals
embody an approach of optimiing flexible resources when it lowers NPC and not
optimizing flexible resources when it raises NPC. It was based on the assumption
that the Company acts rationally and other companies act irationally. PIIC's and
Monsanto's proposals violate any reasonable principles of consistency and
faiess. If NPC are to be set using an optiation model, then all resources and
contracts that ar subject to being optied should be optimid. This is the same
argument used by Staff and Monsanto in their proposed treatment of the APS
Supplementa contract where they propose that actual historic energy take under
Shu, Di-Reb - 26
Rocky Mountain Power
1
2 Q.
3 A.
4
5
6
7
8
9
10
11
12
13 Q.
14
15 A.
16
17
18
19
the contract should be rejected in favor of optimiing the contract in GRID.
Please explain.
The proposed adjustments depar from modeling power costs on a normalized
basis. If this type of modeling adjustments were adopted, then consistency and
fairess require its application to all other flexible purchase or sale contracts that
are modeled in a similar fashion to the SMUD and Black Hils contracts. For that
matter, it should also be applied to flexible generating resources. Optimation of
the Company's system operations decreases NPC on a net basis. PIIC and
Monsanto have not proposed "de-optimiation" across the board, which would
increase NPC. Nor have PIlC and Monsanto provided any justifcation for
selective "de-optimization" of only two call option sales contrcts, rather than all
purchase and sale contracts and flexible generating units.
Why is it importnt to treat third party contracts the same whether the
Company is sellng or purchasing energy?
Use of any delivery patterns other than the optimied delivery patterns wil
always lower net power costs for wholesale sales contracts with flexibilty such as
the SMUD and Black Hils contracts. The opposite is tre for purchased power
contracts that give the Company flexibilty in how the power is taken. It is not
fai or consistent to normale dierent contracts using diferent rules.
Shu, Di-Reb - 27
Rocky Mounta Power
1 Q.
2
3
4
5 A.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
How do you respond to the arguments made by PUC and Monsanto that
flexible wholesale sales contracts should not be optimized because the
Company has not modeled any of the loads, constraints, or forward price
curves used by the counterparties?
It is correct that the Company does not model the counterparies' systems due to
the impossibilty of obtaining the data that are proprietar to those counterparies.
However, given that the Company is only one of the may parcipants in the
market, the only assumption is to assume that all the paricipants in the same
market are rational and wil exercise their rights to the flexible contract to lower
their costs. Ths is confired by Black Hils as presented on page 2 of Exhibit
No. 72, which was an exhibit to Mr. Falkenberg's testimony in the Company's
2009 Wyoming general rate case, Docket No. 20000-352-ER-093, where it states:
"BHP wil captue the maximum contract value by takig delivery of the contract
energy to serve load or faciltate market sales." This is exactly what the
Company's method of optimization captues, and what is demonstrated in Exhbit
Nos. 73-75. Exhibit No. 73 shows the actual delivery taen as a whole, and that
the pattern of this energy delivery may appear to be flat. However, lookig at the
same data, but by HLH and LLH and by location where the energy was delivered
in Exhibit Nos. 74 and 75, it is clear that Black Hils exercised their rights based
on price signals from the maket, takng more energy when and where market
prices were relatively higher.
3 Both Mr. Falnbeg and Mr. Widmer wer contats to Wyomig Inustral Energy Consumers
("WIEC") in that preeding.
Shu, Di-Reb - 28
Rocky Mountan Power
1 Q.
2 A.
3
4
5
6
7 Q.
8
9 A.
10
11
12
13
14
15
16
17
How is the SMUD contract structured?
In addition to the fir energy component that is modeled in GRID explicitly,
SMUD also has the right to take provisional power from the Company under the
terms of the same contract, which wil be retued in full to the Company next
year. For the normalized calculation, the Company assumes the take and return of
the provisional power are equal and matching in the test period.
Does the historical data display SMUD's preference on when to take energy
under the contract?
Yes. When both of these are taken together, it is clear that SMUD intends to take
energy with preferences by season. Figure 3 below shows the monthly pattern of
the total fir and provisional sales in a four-year period. Based on the historical
pattern, it would be reasonable to assume that without the flexibilty of the
provisional porton of the contract, SMUD would shape their take of the fir
portion with a similar seasonal pattern. PIIC's proposal only considers the fir
porton of the contract, and suggests that SMUD would tae more energy in
sprig than in fall as if SMUD would not have considered their rights to the
provisional energy.
Shu, Di-Reb - 29
Rocky Mounta Power
1 Figure 3 Historical Shape of Energy Take by SMUD
80,000
70,000
60,000
50,000
40,000
.c;:30,000:5
20,000
10,000
0
2 Q.
3 A.
----------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------:--------------------------------------------
:
:~
:
:
::
:
---:------------------------------------------------------:::.
:'.
:
,
:
~'.~
::::
-----------------------------
:
:,
:,
::
:
:
:.'
~co "-"-~~9 §:r 9 :ri:~i:~i:~i:~.!.!.!.!
I &:Finn II Provisional I
Does the Company model any contracts based on actual historical data?
Yes. The Company models non-flexible contracts, such as the ones with GP
4 Camas, Biomass, and smal purchases, base on historical information because
5 none of these contracts provide the Company the kind of flexibilties that are
6 provided for under the terms of the cal option sales contracts. Base on the
7 priciple of known and measurable information, the only information known to
8 the Company is the history of those contrcts. I recommend the Commssion
9 reject the adjustments proposed by PIIC and Monsanto on the basis that the
10 adjustments violate the faiess in the optiation of all flexible resources to
11 reduce NP.
Shu, Di-Reb - 30
Rocky Mountain Power
1 Heat Rate Deration (PUC Adjustment 10)
2 Q.
3 A.
4
5
6 Q.
7 A.
8
9
10 Q.
11 A.
12
13
14
15
16
17 Q.
18 A.
19
20
21
22
23
What does PUC's propose in this adjustment?
PILC claims that the Company's application of outages biases the availabilty and
average heat rates of the units. The adjustment proposed by PILC would reduce
Company's system NPC by $1.8 millon.
How does the Company apply the deration method?
The Company's approach derates the maximum capacity of the unit in every hour
of the year by an equal percent based on historic forced outage rates, which
constitutes a "haircut" in unit availabilty.
How would PUC's discussion change this method?
The discussion presented by PILC would alter thermal units' heat rate cures to
arificially increase their effciency as compar with the heat rate cures that are
developed from actual plant operating data. The discussion on the "other aspect"
of the problem.that PIlC presents is to reduce therml plant mimum generation
levels so GRID can run therml units at levels they are physically incapable of
reaching.
Would PUC's method significantly understate the heat rates?
Yes. The only time when the derate adjustment to the heat rate may be applicable
is when the unit is dispatched at one paricular level of generation - its derated
maxmum capacity, with the assumption that the unit may be dispatched at its
state mamum capacity in GRI if there were not the availabilty "haicut".
When the unit is dispatched at any level below its derated maximum capacity,
GRI has made the optial decision to dispatch that unit at a lower and less
Shu, Di-Reb - 31
Rock:Y Mounta Power
1 efficient generation level, whether it has been derated or not. Therefore, derating
2 the entie heat rate cure overstates the efficiency of the unit and understates the
3 heat inputs.
4 Figure 4 and Figure 5 below show the heat rate cures that would be under
5 the methods modeled by the Company and modeled by Mr. Falkenberg in the
6 Company's previous cases in other jursdctions for a coal-fied unit and gas-fired
7 unit, from minimum to maximum generation level, with the assumed generation
8 levels superimposed on the heat rate cures that would be dispatched under the
9 Company's methods. The graphs clearly demonstrate that heat input required for
10 varous levels of generation is understated using the derate-adjusted heat rate. In
11 both cases, there are many hours of dispatch below the derated maxmum
12 capacity, which are the generating levels at which PIle's proposal would
13 understate the heat rate, and subsequently understate NPC.
Shu, Di-Reb - 32
Rocky Mountan Power
1 Figure 4 Heat Rate Curve (Coal Unit)
-:iii
.5
'lai:i
;
i Minimum Capacity
1/:H~-~l ."im"mc_\i
'j~ .! ..
"71' \J~ ',,,.. ìi~", "'''~ ,i ""'-._ . ~~ ; IPIIC Adjusted Hèat Rate Curve ---____.~..~!..~
I
. Derated Capacity
..._--------1
Generation Level
2 Figure 5 Heat Rate Curve (Gas Unit)
I
Heat Rate cuieI i
I
!,
I
/I_m"mc~
Deraed Capcity
'5Q,S
\;:i ~PIIC Adjuste Heat '"
Rate Curve "-"-,,~-I -""",~r- MinimumCapacit j -~____I j --~~ I
Genel't1n Level
Shu, Di-Reb - 33
Rocky Mounta Power
1 Q.
2
3 A.
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16 Q.
17
18 A.
19
20
21
22
23
Hasn't the Company agreed to adjust the heat rates at leat to the derated
maximum capacities of the units as claimed by PUC?
No. The Company believes that the only adjustment that may be valid is at units'
derated maximum, assuming that the unit could generate at a slightly more
efficient level, but the Company does not believe such adjustment should be
made. After the Company's application of the "haicut," the units' capacities are
stil at relatively efficient levels. In actual operations, a unit can be derated to any
level between its minimum and maximum capacities, and from Figure 4 and
Figure 5, the heat rate at lower levels are significantly less efficient than at the
derated maximum.
Do you agree with PUC's discussion that the minimum generation level
should be derated becaus the maximum generating level is derated?
No. The purose of the "haicut" to the maximum generatig capabilty is to
reflect the amount of generation no longer available due to outages. That is fully
accomplished though the "haicut" to the maximum generatig capacity.
PUC relates the proposal of making duration adjustment to the Company's
modeling of fractionally owned units. Do you have comments on that?
Yes. PIlC seems to suggest that the porton of the units that would not be
available due to outages may be considered to be owned by other entities. Such
concept would require the modelig of al aspects of the unts in the same maner,
includig the reserve capabilties of the units. In addition, in the case of outages,
it is not correct to assume that another entity owns the porton of the units that are
forced out. When GRID determes certin amount of generation from a unit, it
Shu, Di-Reb - 34
Rocky Mountan Power
1
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
16
17
18
19 Q.
20 A.
21
22
23
does not make the decision based on whether or how much the unit has been
derated. That is, for basis that no purchases are modeled at the Nevada-Oregon
Border ("NOB"), the point from which the agreement provides wheeling. The
two adjustments proposed by PIIC would result in a $4.8 millon decrease to
system NPC.
Please provide some background on the DC Intertie contract.
The DC Intertie contract was executed 16 years ago on May 26, 1994, to provide
deliveries of 200 megawatts of power from Southern California Edison at NOB
under Amendment 1 to the Winter Power Sales Agreement ("WPSA"). The
WPSAwas executed on December 14, 1993 and provided up to 422 MW of
power to be delivered to the Company's west control area. At the time the WPSA
was executed, the Company had sufficient transmission rights to import 222
megawatts of power into the west control area. The agreement provided that if the
Company procured additional transmission rights by June 1, 1993, then it could
import the remaining 200 megawatts to its system. The Company secured the
remaining 200 megawatts of transmission rights by acquirng 200 megawatts of
transmission capacity on the DC intertie. The Company termated the WPSA
effective Januar 1,2002, but kept its 200 megawatts of DC Intertie import rights.
How doe the DC Intertie contract benefit the Company's customers toy?
The agreement taes advantage of the load diversity between summer-peakg
Californa and the winter-peag Pacifc Nortwest. The contract provides a
valuable means of securng capacity and energy from Californa entities to meet
retal loads. Loads in Calorna ar relatively low in the winter when loads in the
Shu, Di-Reb - 35
Rocky Mounta Power
1 Company's west control area and the rest of the Pacific Northwest are at their
2 highest.
3 Existing Long Term Contracts (PUC Adjustments 11 and 13 regarding DC Intertie
4 Costs, and Idaho Power PTP Contract)
5 Q.
6
7 A.
8
9
10
11
12 Q.
13 A.
14
15
16
17 Q.
18
19
20 A.
21
22
23
Please explain PUC's proposed adjustment to costs associated with the DC
Intertie.
PIle argues that costs associated with the DC Interte and Network Transmission
Agreement between BPA and the Company should be removed from NPC on the
basis that no purchases are modeled atthe NOB, the point from which the
agreement provides wheeling. The two adjustments proposed by PIlC would
result in a $4.8 millon decrease to NPC.
How should the Commission judge the prudence of this contrct?
Prdence should always be judged based on the information that was known at
the time the contract was executed. It would not be reasonable to judge a 16-year
old contract based on inormation that is available today that was not available 16
years ago.
But there are no transctions modeled at NOB in the test period in this
proceeding. Why is it appropriate to include costs related to the DC Intertie
agreement in this proceeding?
In makg their proposal, PILC focuses on energy deliveries under the contrct
rather than the capacity and diversity benefits of the contract. It would be
inappropnate to penalze the Company for prudently acquirng transmission rights
16 years ago by disallowing costs tody basd on hindsight and only lookig at
Shu, Di-Reb - 36
Rocky Mounta Power
1
2
3
4
5
6
7
8
9 Q.
10
11 A.
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
the energy value of a resource that can facilitate the delivery of both capacity and
energy. By purchasing these transmission rights, the Company has purchased
assurance that it can reliabilty serve its load obligations. PIlC's proposals based
on the limited energy-only view of this contract is simlar to arguing that the
Company should only be able to recover insurance premiums when it receives
proceeds under an insurance policy. The costs associated with this contract are
modest in light of the benefit to the Company's overall transmission strategy and
hedge against changes in the market.
What does PUC propose to adjust for the expenses of the. contract between
the Company and the Idaho Power Company ("IPC")?
PILC claims that the contract that the Company has with !PC would no longer be
needed after the Populus to Termnal section of transmission line goes into
service.. As a result, the expenses related to the contract should be removed,
which would reduce the Company's system NPC by $0.8 millon.
Why doe the Company disagree with this adjustment?
The notion that an existing contract should be termnated simply because a new
resource may replace the function of that contract is unfounded. The 'referenced
contract is a two-year contract that the Company entered into in 2009 to serve
reta load, given the information at the time about the resources available to the
Company to meet its obligation in the next two years. Ths contract is not the
same as the short term fir contracts that the Company enters into from time to
tie and for a short duration, such as the ones listed as a correction earlier in my
testiony. The capabilty of those short term fir transmission is modeled in
Shu, Di-Reb - 37
Rocky Mountain Power
1 GRI at the assumed level based on what the Company has experienced
2 historically, and the assumption should be modified when the Populus to Termnal
3 line can provide the needed transmission capacity. The Company entered into
4 that paricular contract based on expected in-service date of the Populus to
5 Termnal line and with the option of annual contracts only. As the result, the
6 terms of the contract could not perfectly match the in-service date of the new
7 transmission line, and the Company should not be required to time the contract
8 terms precisely with resources that become available subsequently. Had the
9 Company entered into a shorter contract, there would have ben a potential gap
10 prior to the new transmission line being in service to the detrment of customers.
11 I recommend the Commssion reject PIlC's adjustment.
12 Reserve Shutdown (Monsanto Adjustment 5)
13 Q.Please describe Monsanto's adjustment for reserve shutdowns.
14 A.Monsanto claims that the Company's forced outage rates and the rates used in
15 GRID are calculated inconsistently and proposes that reserve shutdown hours
16 should be added to the denominator of the force outage rate calculations. The
17 proposed adjustment would reduce the Company's system NPC about $0.8
18 milion.
19 Q.Do you agree with this adjustment?
20 A.No. This adjustment has the effect of arificially lowering the forced outage rates
21 by stating that the units would be available 100 percent of the time if they were to
22 be called upon to run durng the hours when they were on reserve shutdown for
23 economic reasons.
Shu, Di-Reb - 38
Rocky Mountain Power
1 Q.Please explain.
2 A.Contrar to what Monsanto claims, the Company's calculation of forced outage
3 rates is consistent with how GRI applies them. Monsanto agrees that the
4 planned outage hours should be excluded from the denominator in the calculation
5 of forced outages. Removing the reserve shutdown hours are based on the same
6 fact that no forced outage events are collected durng either the planned outage
7 hours or the reserve shutdown hours. Monsanto's proposal is the same as stating
8 that if the units were to run durg the hours when they were shutdown for
9 economic reason, the units would not encounter any forced outage events. The
10 proposal is not supported by logical or analytical reasoning. In addition, given the
11 fact that GRI models reserve shutdowns, the rates are only applied to the hours
12 when they are scheduled to run, which is a fact even supported by Mr. Widmer in
13 his testimony stating that "(tlhe Company's daily screen modeling in GRI
14 specifcally identifies when CCCTs are available but are not economic to run an
.15 essentially placed them on reserve shutdown so they cannot run." I recommend
16 the Commssion reject Monsanto's proposal.
17 Cal iso (Monsnto Adjustment 7)
18 Q.Please desribe Monsanto's adjustment to the Cal iso Fee.
19 A.Monsanto reommends removal of the Cal ISO fees that are base on 2009 actual
20 costs incurred by the Company, and replace them with a lower amount.
21 Monsato's recommendation is based on the assumption that a signicant porton
22 of the fees are not matched by electrcity trsactions that the Company included
23 in the case and could incur the fees. This adjustment results in a $4.0 mion
Shu, Di-Reb - 39
Rocky Mounta Power
1
2 Q.
3 A.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18 Q.
19
20 A.
decrease to the Company's system NPC.
How do you respond to this adjustment?
I urge the Commssion to reject this adjustment. Cal iso fees are incured for
transactions at market points of SPI5, NP15, and when the Cal iso is the
counterpary.4 The bulk of these transactions are short term transactions made
close to the time of delivery. Cal iso is a major counterpar in the Company's
activities to balance its system, which is a fact that Monsanto doesn't dispute
according to Mr. Widmer's testimony stating "(h)istorical records reveal that most
of the transactions with the Cal iso as a counter pary ar incured shortly before
or on the actual day of delivery." Such activities are reflected in GRID as par of
the system balancing sales and purhases, which are transactions computed by
GRID representing the types of transactions that would be consummated shortly
before or on the actual day of delivery. The Company continues to do business
with the CalISO and continues to incur Cal iso fees. There is no reason to
arbitrarly elimiate expenses that are required to be incured when doing
business with the Cal iso simply because the data in the Company's filing does
not explicitly include those applicable transactions.
Would removing the Cal iso as a counterparty affect the operations of the
Company's power system?
Yes. The Company enters into transactions with the Cal iso in order to
4 Mr. Widm quoed an excerpt presumably frm the testiony by Company's witness Mr. Duval frm
the Wyomg Doket No. 200-352-ER-09. Mr. Duval's testimony in that case did not conta the
quoted excet. However, Mr. Duval did testiy to content simlar to the excerpt as the Secnd
Supplemnta testiny in the Company's Utah gener rae cae Docket No. 08-035-38, where the
dicussion was about the reason why the Comany enter into trsactions that had delivery points in
SP 15 when it did not have fin trsmission nghts.
Shu, Di-Reb - 40
Rocky Mounta Power
1
2
3
4
5
6
7 Q.
8
9 A.
10
11
12
13
14 Q.
15 A.
16
17
18
19
20
21
22
23
economically balance the system. In doing so, the Company incurs Cal ISO fees.
Not allowing the Cal iso fees is the same as makng the assumption that the
Company would not do business with the Cal ISO. Removing Cal ISO as
counterpary would limit the options that the Company may use to balance its
system economically. As aresult, NPC would go up due to those limitations and
constraints.
Does the Company expet that it wm continue to do business with the Cal
iso in2010?
Yes. The Company expects to do business with the Cal ISO in 2010 and the
futu and incur varous fees in the markets governed by the Cal ISO. Costs such
as wheeling costs are typically quantified for ratemakg puroses by using the
most recent historic data, absent any known and measurable changes. This is
exactly how the Company has normalized Cal ISO costs in ths proceeding.
Do you see other problems in Monsanto's proposal?
Yes. Despite the fact that the Company requested Monsanto to provide all
workpapers supporting their adjustments, the workpapers for this adjustment is
among the ones that do not support the amount of the adjustments. Given the
magnitude of the adjustment, it seems that Monsanto proposes to remove the
entire amount of the Cal ISO fees that the Company included in the case,
replacing it with only a fraction of the actual Cal ISO fees that the Company has
incurd durg the period that is claied to match the actual short term fir
transactions that the Company included in the case. However, though September
2010, the Company has incur approximately $3.2 millon of Cal ISO fees, both
Shu, Di-Reb - 41
Rocky Mountan Power
1 wheeling fees and service fees, which are only $66,265, lower than what the
2 Company included in the filng for the corresponding period. Accordingly, the
3 Commssion should reject Monsanto's argument that the Company would not
4 incur Cal iso fees in the test period, as well as rejecting the proposed adjustment,
5 which would replace what the Company has included in the case with a fraction
6 of the actual fees.
7 Cholla 4 Capacity (Monsanto Adjustment 10)
8 Q.
9 A.
10
11
12
13
14 Q.
15 A.
16
17
18
19
20
21
22
What was the issue regarding the capacity of Cholla unit 4?
As the result of a major overhaul in 2008 the capacity at Cholla Unit 4 was
upgraded. However, due to trnsmission constraints, the generation from the
Cholla unit 4 to the Company's system has remained at the previous leveL.
Monsanto argues that the upgrade should be reflected in GRI. The adjustment
would reduce the Company's system NPC by $1.1 millon.
Do you agree with Monsanto's argument?
No. Firt, the argument ignores the physical transmission constrts on delivery
of power from Cholla. Second, Monsanto has increased transmission capacity to
accommodate the increased generation from Cholla unit 4 without increasing any
other costs related to that capacity. Thid, the purose of derating the units for
forced outages is to captue the lost generation due to such outages, whie
Monsanto's proposal would suggest the lost generation due to outages could be
supplemented by the possible generation from the unit that cannot be delivered to
the system.
Shu, Di-Reb - 42
Rocky Mounta Power
1 Morgan Stanly Call Premiums (Monsanto Adjustment 11)
2 Q.
3 A.
4
5
6
7 Q.
8 A.
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
Please explai the Monsanto's proposed adjustment.
Monsanto proposes to remove the capacity payments related to two of the
Company's call option contracts because those contracts are not dispatched durng
the test period. The adjustment would reduce the Company's system NPC by
$3.1 millon.
Do you agree with Monsanto's proposed adjustment?
No. Monsanto is seeking to disallow the capacity payments that the Compaily
pays on cal option contracts without demonstrating the imprudence of these
costs. The Company executed these call option contracts to meet demand and
ensure reliable service by providing physical delivery of energy durig periods of
increased demad and/or transmission constraints when prices are higher. So
even if the contracts are not dispatched in GRI, they can provide customers a
real benefit in the event of a change in the Company's system.
What would you recommend the Commission do in the current case?
The Commssion should reject Monsanto's proposal to remove the capacity
payment of the cal option contracts. As state above, the contrcts were entered
into to meet demand and ensure reliable service by providig physical delivery of
energy durng periods of increased demad and/or transmission constraits when
prices are higher. Monsanto's adjustment is simar to requestig a refund of your
auto insurance payment every year when you have not been involved in an
accident.
Shu, Di-Reb - 43
Rocky Mountain Power
1 Other Proposals
2 Combined Cycle O&M Adjustment (PUC Adjustment 14)
3 Q.
4 A.
5
6 Q.
7 A.
8
9
10
11 Q.
12 A.
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
Please explain PUC's adjustment to O&M costs of combined cycle plants.
PIlC states that the proposed daiy screening adjustment reduces the O&M costs
associated with combined cycle plants.
What is the basis for PUC's adjustment?
Based on Mr. Falkenberg's testimony on this issue in prior cases and the reference
to Mr. McDougal's exhbit, PILC seems to be referrng to the O&M that the
Company might have added to fixed O&M for each sta-up of a combined cycle
plant.
Is PUC's adjustment reasonable?
No. The Company has not included any incrementa O&M to reflect the
additional costs of combined cycle plant sta-ups. Therefore, there are no costs
to remove.
Do both Staff and Monsanto oppose updates to the Company's filed NPC?
Yes. The Company believes that updated information would provide the
Commssion with the most recent and more accurate information for the test
period. While opposing updates to the Company's NPC, Monsanto proposes to
selectively update components of the NPC, such as the recommendation to
replace the Cal iso fees that the Company included in the filig with actual Cal
iso fees that the Company has incured for period pnor to May 4,2010. If the
Company were to update the NPC to reflect all actual information that is avaiable
for the test period though September, the NP for the twelve-month period
Shu, Di-Reb - 44
Rocky Mounta Power
1
2
3
4
5
6 Q.
7 A.
8
9
10
11 Q.
12 A.
13
14
15
16
17
18
19
20
21
22 Q.
23 A.
endig December 2010 would be approximately $53.7 millon higher than what
was contained in the Company's original fiing. If the Company were to update
all NPC for actual information though May 4, 2010, as Monsanto recommended
for the Cal iso fees, the test period NPC would be $25.0 millon higher than
fied.
Has the Company updated its NPC in this rebuttal?
No. However the Company believes updates improve the accuracy of NPC
forecasts and reserves the right to propose updates in futue fiings Staf, PILC and
Monsanto proposed and the Company accepts adjustments to NPC, which total to
an approximate $6.5 millon reduction from what the Company originally filed.
Please summarize your testimony.
In its diect filing, the Company proposed NPC of $1.07 billon on a total
Company basis for the 12-month test period ending December 2010. In this
curent filng, the Company has revised its projected NPC to $1.063 bilon on a
tota Company basis. The revised NPC incorporate corrctions and positions that
Staf, PIlC and Monsanto proposed and the Company accepts, which total to an
approximte $6.5 millon reduction from what the Company originally fied. For
the adjustments that the Company does not agree with, I have provided
explanations and evidence to support the Company's positions. I believe the
revised NP has reflected more accurate inormtion and presented a reasonable
compromise to positions proposed by Staf, PILC and Monsanto.
Do this conclude your rebutt testimony?
Yes, it does.
Shu, Di-Reb - 45
Rocky Mountan Power
Case No. PAC-E-I0-07
Exhbit No. 71
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhbit Accompanying Rebuttl Testimony of Hui Shu
NP Summar
November 2010
Rocky Mountain Power
Exhibit No. 71 Page 1 of 1
case No. PAC-E-10-07
Witness: Hui Shu
Idaho GRC 2010, Inital Filng NPC ($) =
$/MWh = $
1,069,701,315
18.62
Idaho GRC 2010, Rebuttal Filng
Corrections, one-off
1
2
3
Adopted, one-off
4
5
6
7
8
9
10
Dunlap Reserve Contrbutor
Path C STF Transmission
UAMPS Use of Facilties
Commitment logic screens
Non-owned wind interhour
Colstrip planned outage moved to Spring
Mona market
APS Supplemental
Non-firm transmission
Top of the World Commercial Operaion Date
System balancing impact of all changes
Total Changes from initial filng =
Idaho GRC 2010, rebuttal filng
Impact ($)
121,389
(25874.30)
(700.00)
(1684408.33)
(1367358.97)
(215922.22)
(438529.00)
(2640717.11)
(1232943.93)
1,90,544
(884,467)
(6,471,288)
NPC($)
1,069,822,704
1,069,675,44
1,069,694,315
1 ,068,016,906
1 ,068,333,956
1 ,069,48,393
1,069,262,786
1,067,060,598
1,068,468,371
1,071 ,605,859
1,063,23,027
Case No. PAC-E-I0-07
Exhibit No. 72
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttl Testimony of Hui Shu
Black Hils Power
November 2010
BLACK IDLLSPOWER, INC.
SD PUC DOCKET: EL-09-018
Rocky Mountain Power
Exhibit No. 72 Page 1 of 2
Case No. PAC-E-10-Q7
Witness: Hui Shu
REQUEST DATE November 5. 2009
RESPONSE DATE Decembe 8, 2009
REQUESTING PARTY:Black Hils Industral Intervenors
BHIRequestNo.I-68: Pleasë:explain the markets, in terms of liquid trdig
bubs~ where tbeCompany mak transactions. (e.g. Mid
Columbia, 4 Corners, Palo Verde, etc.) Identify each hub
where the Com.panytrades, and the test year sales and
purcha.e v:ølumeš, costs aìdrë:veniies by hub or market.
:Rsponse to BHIIReguest No. 1-68:
Black HilsPower(BHP) trades at the following liquid trding hubs,
· Mid-Columbia (Md-C)
. Four Comers 345
. Mona
. Midwest Indepen.dent System Operator (MSO)
TIiese pointS of delivery ate considered liquid trading hubs because there are established
markets with published prices from vàrous recognzed sources.
See Attchment 68.1 for test year sales and purchase volumes, costs and revenues by hub
or market
Legend for Attachment:
.¡ HE ~ the tradingterm for Hout Endig, 0100-0200 would be FI02 and so on
./ PHE ~ the trdig term for Price f~r Hour Endîg
.¡ Trasaction Type- is the tye of ener transaction that occurred, whether it is
a puche or a sale wi a third par
.¡ Zone - the trading point of receipt or point of delivery for energy, for example,
the liquid trading hub
.¡ Market - the trmission provide location code (P ACW - PacifiCor West,
PACE - PacifiCorp East, AZS - Arizona Public Serice, PNM - Public SerVice
of New Mexico, MISO - Midwest Independent System Operator)
BHP-BHII-OO72
BLACK HILS POWER, mc.
SD PUC DOCKET: EL-09-018
Rocky Mountain Ppwer
Exhibit No. 72 Page 2 of 2
Case No. PAC-E-10-07
Witness: Hui Shu
REQUEST DATE
RESPONSE DATE
REQUESTING PARTY:
November 5, 2009
Decei:her 8, 2009
Black Hill Industral IntervenorS
BHRReguest No. 1-58: Please explain why the Company's delivery pattern of
power from the Colstripcontrad appears, to have a flatter
protile than might be su.ggested by shaping thecontra-ct to
optini~einarketreveiiue. Pleaseexp,iain any constraints that
the Company encountes that liits its abili to maximize the
contrct revenue. Demonstrate that the methodology use is
prudent.
Response to BHII Request 1-58: Firt and foremost, the lowest cost resouces avaiable
to BHP are allowed to serve BHP's Customers. Black Hìls Power (B:H), on a mont1y
basis, maximzes the use ofthe Colstrip contrct based upOn contractual pareters.
The contract detals are below:
Second Restated and Amended Power Sales Agreement
between P,acifiCorp .and Black Hils Corporation
"'Colstrip Contract"
Hourlv MaximumEnrp;Deliverv::50MW
Hourlv MaxumChag;e::ì25 MW
HourlvMinimum Energy Deliverv:OMW
Week1v Maximum Energy Delivery:6,700MWh
Monthy Maximum Energy Delivery
based upo numbe of days in the 30.day Month 28,710MW
ìndividual month:31...day Month 29,610MWh
BHP wil captue the maxum contract value by tag delivery of the contrct energy
to serve load or faciltate market sales. Typically this contract isutied in the Day
Ahead Energy Market where stadard energy market products are traded in 25 MW
blocks exrcised in stdad utility products - On-Peak hour equte to Monday though
Saturday (0700-2300 MPT), Off-Pea hours equte to Monday through Saturday (0000-
0700,2300-2400) plus Sunda and Holidays (0000-2400). Ifmaxum vaue is
detered to be utiliZed for load, then the contrct energy will be scheduled to BBP
load, with a shapig pattern. BHP,as a practice; utiles the maxum energy delivery
on a monthy basis, if the maket support such.
BHP-BHIi.
Case No. PAC-E-10-07
Exhibit No. 73
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttl Testimony of Hui Shu
Black Hils Average Energy
November 2010
Rocky Mountain Power
Exhibit No. 73 Page 1 of 1
Case No. PAC-E-10-07
Witness: Hui Shu
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Case No. PAC-E-1O-07
Exhibit No. 74
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhbit Accompanying Rebuttl Testiony of Hui Shu
Black Hils HLH
November 2010
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Rocky Mountain Power
Exhibit No. 74 Page 1 of 1
Case No. PAC.E-10-07
Witness: Hui Shu
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Case No. PAC-E-1O-07
Exhibit No. 75
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttl Testimony of Hui Shu
Black Hils LLH
November 2010
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