20101124Shu Errata Reb.pdf

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-10-07
Errata Testimony of Hui Shu
ROCKY MOUNTAIN POWER
RECE
iuiu NOV 24 AMIO:43
CASE NO. PAC-E-10-07
November 2010
Q.Please state your name, business address and present position with
2 PacifiCorp dba Rocky Mountain Power (the "Company").
3 A.My name is Hui Shu, my business address is 825 NE Multnomah, Suite 600,
4 Portland, Oregon 97232. My present position is Manager of Net Power Costs.
5 Q.Are you the same Hui Shu that submitted direct testimony in this
6 proceeding?
7 A.Yes.
8 Q.What is the purpose of your rebuttal testimony?
9 A.The purpose of my rebuttal testimony is to respond to the adjustments proposed
10 by intervening parties to the Company's fied net power costs ("NPC") in the
1 1 current proceeding. These adjustments are proposed by Mr. Bryan Lanspery of
12 the Idaho Public Utilities Commission Staff("Staff'), Mr. Randall J. Falkenberg
13 ofthe PacifiCorp Idaho Industrial Customers ("PIIC"), and Mr. Mark T. Widmer
14 of Monsanto. In addition to my testimony, Company's witnesses Mr. Chad A.
15 Teply addresses the adjustments proposed by Mr. Falkenberg and Mr. Widmer
16 regarding the Lake Side outage, Colstrip outage and Naughton outages, and Ms.
17 Cindy A. Crane addresses adjustment proposed by Mr. Falkenberg regarding the
18 Jim Bridger fuel quality.
i 9 Recommendation for Company's Net Power Costs
20 Q.Has the Company made changes to its originally fied NPC?
21 A.Yes. The Company's system NPC has decreased from $1.07 billion in the
22 original filing to $1.063 bilion.
Shu, Di-Reb - 1
Rocky Mountain Power
Q.
2 A.
3
4 Q.
5 A.
6
7
8 Q.
9
10 A.
1 I
12
13
14
15
16
17
18
19
20
21
22
23
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, PIIC and Monsanto.
Please summarize the changes in NPC from your direct testimony.
Exhibit No. 71 summarizes the cost impact of the corrections and adopted
adjustments that result in an NPC of approximately $ 1.063 bilion on a total
Company basis, which is $69.0 milion 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 parties?
Yes. NPC and its components are volatile and inherently difficult to forecast.
Actual operation lacks the same certinty and perfect foresight as the optimization
model used to forecast NPC in regards to the variables and constraints, such as
hourly load and market prices, availability 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 necessarily achieve what the optimization model projects. That is, the
model optimized NPC tends to understate the actual NPC that would be incurred
for the same period. The Company's net power costs have increased significantly
in recent years. With known changes in the Company's resource portfolio in the
rate effective period, the normalized NPC in a historical test period further
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 agreed to NPC of
$982 millon, given the design of the test period. However, the actual NPC
Shu, Di-Reb - 2
Rocky Mountain Power
2
3
4
5
6
7
8
9
10
11
12
13 Q.
14
15
16 A.
17
18
19
20
21
22
23
during 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 bilion. In the
current case, the Company proposed NPC of $ 1 ,070 milion that would be in
effect during 2011. The Company's recent filing in Oregon Docket No. UE 216
has shown that the projected NPC in 20 I 1 would be approximately $ I ,289
milion. The preliminary results indicate that the Company's actual NPC through
September are at approximately $859 millon, or $ I. I 29 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 make further adjustments to reduce the modeled NPC
that wil be used to set base rates beginning January I, 201 1, especially when the
adjustments are as significant as the ones proposed by Staff, PIIC and Monsanto.
The Commission 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 determination ofthe appropriate
NPC is very important because it represents one of the Company's single largest
revenue requirement components and establishes the ECAM baseline."¡ The
amount that the Company is authorized to recover under the ECAM is based on
the differences between actual NPC and the base NPC included in rates during
that period. Currently the Company's ECAM has a 90/10 sharing band. Because
of the sharing band the Company is effectively limited to not recover all of the
prudently incurred NPC in the rate effective period when actual NPC are
i Direct testimony of Mark T Widmer page 10 lines i 4- i 6.
Shu, Di-Reb - 3
Rocky Mountain Power
1 projected to be higher than what the Company proposes in the current case.
2 Company Responses to Specifc Adjustments - Overview
3 Q.How have you organized your responses to the parties' modeling adjustments
4 to NPC?
5 A.I have grouped the parties' proposed NPC modeling adjustments into three
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 part,
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 ratemaking.
1 1 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) three corrections:
15 .Dunlap was modeled without reserve requirements;
16 .STF transmission from southeast Idaho to northern Utah was not removed
17 after the inclusion ofthe Populus to Terminal transmission line addition;
18 and
19 .The UAMPS Use of Facilties wheeling expense should have been
20 excluded
21 Correcting these three items increases the Company's system NPC by
22 approximately $0.1 milion.
Shu, Di-Reb - 4
Rocky Mountain Power
Q.
2
3 A.
4
5
6
7
8
9
10
1 1
12
13
14
15
16
17
18
19
20
21
22
23
Has the Company accepted any adjustments proposed by Staff, PUC or
Monsanto?
Yes. The Company has accepted the following proposed adjustments:
. Commitment Logic Screens (PIIC Adjustment 1): As proposed by PIIC,
the Company agrees to modify its daily screens consistent with the
methodology set forth in the parties' stipulation in Oregon Docket UE
216. This change results in a decrease to system NPC of approximately
$ 1.7 milion. As discussed later in my testimony, the Company does not
agree that this 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 (corrected
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. PIIC's inter-hour wind integration adjustment
needs to be corrected by removing the wind generation that the Company
receives under contract with Seattle City and Light ("SCL"). This
adjustment results in a decrease to system NPC of approximately
$ 1.4 milion.
. Colstrip Planned Outages (Monsanto Adjustment 8). The Company
agrees to this adjustment that moves the timing of planned outages of the
two Colstrip units from fall to spring. This reduces the system NPC by
Shu, Di-Reb - 5
Rocky Mountain Power
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 market caps in GRID, rather
5 than selectively making 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 future. This reduces the system NPC by approximately
9 $0.4 millon.
10 Adjustments Accepted in Part
i i APS Supplemental Adjustment (Staffs 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 Supplemental
16 contract causes uneconomic dispatch of the contract, and the contract should be
17 removed. The proposed adjustment would reduce system NPC by $ 1.9 milion.
18 Q.Does the Company agree with the proposal?
19 A.No. Contrary to what Staff 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 arbitrarily remove this contract simply based on modeling results.
Shu, Di-Reb - 6
Rocky Mountain Power
Q.
2 A.
3
4
5
6
7
8
9
10
1 1
12 Q.
13
14 A.
15
16
17
18
19
Please describe the APS Supplemental contract.
The Company executed the Supplemental contract in 1990 with the Arizona
Public Service Company ("APS") and has included it in NPC in Idaho since that
time. Under the contract, APS makes available to the Company two categories of
supplemental firm 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 firm energy on an annual basis priced at its incremental cost of
coal generation, and 876,000 megawatt-hours of firm energy from other sources
that are primarily natural gas-fired resources. The two categories of firm energy
cannot be offered at the same time. APS is obligated to offer the energy, but the
Company only takes the energy when it is economical to do so.
Has the Company modified the modeling of the APS Supplemental contract
in the current rebuttal filing?
Yes. The new approach to modeling this contract eliminates the increases to NPC
when the contract is dispatched. The Company has aligned the timing and pricing
of the deliveries with historic experience, rather than aligning the volume of
deliveries with historic volumes, GRID now exercises the call option on the
available energy when it is economical to do so. This change reduces the
Company's fied system NPC by approximately $2.6 million.
20 Non-firm Transmission (Staff NF Transmission Adjustment, Monsanto Adjustment 3)
21 Q.
22
23 A.
Please explain Staffs and Monsanto's positions on the modeling of non-firm
transmission.
Staff and Monsanto recommend that the Company should include non-firm
Shu, Di-Reb - 7
Rocky Mountain Power
1
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13 Q.
14
15 A.
16
17
18
19
20
21
22
23
transmission in GRID. Staff and Monsanto modeled non-firm transmission using
a four-year historical average to adjust the capacity of links in the GRID model
topology and using a dollar per megawatt-hour energy charge to calculate
expenses. Staffs and Monsanto's proposed adjustments would reduce system
NPC by $2.5 milion and $2.4 milion, respectively.
What is the Company's response to Staffs and Monsanto's proposal?
The Company agrees to model non-firm transmission in GRID. However, ifnon-
firm transmission is included in the model, it should be included on the same
basis as short-term firm transmission. There is no basis for using a different
method for non-firm transmission than for short-term transmission. Both types of
transmission should be modeled using a four-year average to adjust the capacity
links in the GRID model topology and the most current year of expenses.
Please explain why non-firm transmission should be modeled the same as
short-term firm transmission.
In the process of reviewing how the Company has utilized non-firm transmission,
it is clear that the Company purchases and uses short-term firm and non-firm
transmission in the same way. The transmission providers offer certin amount of
transmission capacity as firm products, and the rest as non-firm. The only
difference between the two products is that non-firm transmission wil be cut first
for reliabilty of the transmission system. For both short-term firm transmission
and non-firm transmission, the wheeling expenses are incurred whether the
transmission capacity purchased is fully utilzed or not. As a result, the Company
has modeled the non-firm transmission capabilty based on a four-year average of
Shu, Di-Reb - 8
Rocky Mountain Power
the historical purchases of non-firm transmission, and the expenses estimated
2 based on what was incurred in the base period of the current filing.
3 Q.What is the impact on NPC of including non-firm transmission in GRID?
4 A.Including non-firm transmission using an approach that is consistent with the
5 modeling of short-term firm transmission decreases system NPC by
6 approximately $ 1.2 milion.
7 Top of the World Wind (Monsanto 6)
8 Q.Please describe the adjustment proposed by Monsanto for the power
9 purchase contract with Top of the World Wind.
10 A.Monsanto proposes to reflect the actual in-service date of the contract, which is
1 I one month earlier than what the Company has included in its original fiing, but
12 exclude the wind integration costs related to the wind generation. This
13 adjustment would increase system NPC by $1.6 milion.
14 Q.Does the Company agree with this adjustment?
15 A.Partially. In addition to the impact of additional purchase expenses, the additional
16 wind generation would lead to additional wind integration costs, which is a
17 subject that I wil discuss later. Applying the same methodology as the Company
18 applied for all other wind gèneration, the additional energy purchased from Top
19 of the World Wind increases system NPC by approximate $ 1.9 milion, including
20 additional wind integration costs.
Shu, Di-Reb - 9
Rocky Mountain Power
Company Responses to Contested Adjustments
2 Wind Integration Costs (Staff Wind Integration Costs Adjustment, PUC
3 Adjustment 5, Monsanto Adjustment 2, 2a and 2b)
4 Q.
5
6
7 A.
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Q.
22
23 A.
What have Staff, PUC and Monsanto proposed with respect to the overall
wind integration costs and the wind integration costs of the OA TT
customers?
Staff s proposal is to remove the entire amount of wind integration costs from the
Company's fiing, which would reduce the Company's system NPC by
approximately $34.2 million. 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 milion. Monsanto proposes
various versions of adjustments to the Company's wind integration costs,
including the same proposal as the Staff to remove the $34.2 milion of the total
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 milion, 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 milion.
Do you see any basis to the proposals made by Staff and Monsanto to exclude
the entire wind integration costs?
No. The proposals seem to be made based on three general arguments. First, the
Shu, Di-Reb - 10
Rocky Mountain Power
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
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 utilty." Third, the costs should be captured 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 considering the Company's proposed wind
integration costs and parties' positions on such costs, the Commission 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 determining.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 facilities located in Idaho are understated and whether the
retail customers should pay more for the two qualifying facility contracts that are
listed in Mr. Lanspery's testimony. While implying that the Company's wind
integration costs are not real ("neither paid under contract or to any other utilty"),
Staff states that the Company's wind integration costs are captured in actual test
period expenses and reflected in a number ofaccounts.2 In addition, if the
proposal of removing the wind integration costs from the Company's fiing is
2 Staffs testimony on page 5, lines 20 through 22 suggest that the reference to 2009 may need to be 2010.
Otherwise, the discussion on a 2009 test period would be irrelevant in the current proceeding.
Shu, Di-Reb - 11
Rocky Mountain Power
2
3
4
5
6
7 Q.
8
9
10 A.
1 I
12
13
14
15
16
17
18
19
20
21
22
23
based on the fact that the wind integration costs are of signifcant 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 fiings 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 capture 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 variation in NPC that the ECAM is designed to
capture. Instead of addressing the variation between normalized and actual wind
generation as the ECAM is designed for, wind integration costs are costs incurred
due to additional reserve requirements to integrate the intermittent generation
from the wind projects into the Company's portfolio of resources. The additional
reserve requirements include regulating services that deal with wind variabilty in
ten-minute interval, and load following services that deal with wind variability
over hourly time intervals. Both services should respond to the up and down
variations inherent in wind facilities. That is, the additional reserve requirements
to integrate wind generation into the Company's resource portfolio takes on the
forms of regulation up, regulation down, load following up and load following
down.
Shu, Di-Reb - 12
Rocky Mountain Power
2
3
4
5
6
7
8
9
10
11
12 Q.
13
14
15 A.
16
17
18
19
20
21
22
23
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
part of the normalized 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 Commission-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 NPC, the base NPC should reasonably account for all components,
including the wind integration costs.
Staff stated that the Commission has never expressly approved wind
integration costs in any utilty's general rate case. Do you believe that this is
a precedent to follow?
No. The fact that the Commission has never expressly approved such costs does
not mean that the costs do not exist or are not prudently incurred. The Company's
wind resources 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 portfolio. By allowing the wind integration
costs charged by the Bonnevile Power Administration ("BPA"), Staff and
Monsanto agree that the Company prudently incurred wind integration costs in
serving its customers at approximately $5.89 per megawatt-hour.
Shu, Di-Reb - 13
Rocky Mountain Power
Q.
2
3
4
5
6 A.
7
8
9
10
11
12
13
14
15
16
17 Q.
18
19
20 A.
21
22
23
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 diffcult 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
ifthe 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 Commission of Utah in
the Company's last general rate case Docket No. 09-035-23.
Why do PUC and Monsanto propose disallowing intra-hour wind integration
charges associated with non-owned wind facilties in the Company's
balancing areas?
PIIC argues that the Company should not include the wind integration costs
incurred by providing wind integration services to the non-owned wind projects
because the Company does not have a transmission tariff to recover the costs from
those customers. The proposal would reduce system NPC by $4.3 millon. As a
Shu, Di-Reb - 14
Rocky Mountain Power
2
3 Q.
4 A.
5
6
7
8
9
10
1 I
12 Q.
13
14
15 A.
16
17
18
19
20
21 Q.
22
23 A.
secondary proposal, Monsanto also proposed the same adjustment, which would
reduce system NPC by $6.4 milion.
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 ofthe Stateline wind project owned by SCL and then returns
firm 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 integration costs
that are located in the Company's balancing areas 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 federal law to interconnect with
new facilities under the terms of its Open Access Transmission Tariff ("OA TT").
Once the Company interconnects a new facilty to its transmission system, it is
responsible for integrating it into the system.
Are there barriers to charging non-owned wind facilties for wind integration
costs?
Yes. Modifying the Company's OA IT to impose wind integration charges on
Shu, Di-Reb - 15
Rocky Mountain Power
2
3
4
5
6
7
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
only non-owned wind facilties would violate the federal statutory mandate that
the Company treat all transmission customers, affiliated and non-affiliated, on a
not unduly discriminatory basis. In addition, there is little regulatory guidance
from FERC in this area with respect to what FERC wil ultimately consider to be
an adequate proposal for a wind integration charge. Although FERC
conditionally accepted a proposal by Westar to add a new Schedule 3A charge,
whereby all variable 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 OATT to add a new
charge applicable to all wind generators for wind integration within-hour
generation following service. In each case, wind industry advocates vigorously
protested the proposed tariff revisions because, among other issues, the proposed
charges constituted significantly higher regulatory service fees to intermittent
resources than for dispatchable resources.
Does the Company plan to raise this issue in its next FERC rate case?
Yes. The Company plans to fie a rate case with FERC no later than June 1, 201 1,
in which the Company wil include a proposed wind integration charge in its
transmission tariff rates pending any FERC 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 parties regarding
the study. It is hoped that the study can be used in the development of a wind
integration charge proposed to be added to the OAIT, however, no determination
has yet been made. The Company is closely tracking all developments at FERC
Shu, Di-Reb - 16
Rocky Mountain Power
2
3 Q.
4 A.
5
6
7
8
9
10
11
12 Q.
13
14 A.
15
16
17
18
19
20
21
22
related to wind integration and is bound to follow any guidance FERC may issue
in this regard.
Are the costs associated with wind integration 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 through automatic generation control. Maintaining
system balance is one of the key functions of a balancing area authority who is
required to maintain system reliabilty, including maintaining system frequency.
Load fluctuations, outages, and generation output fluctuations all contribute 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 wheeling
to the Company, are credited against retail rates and therefore have the effect of
lowering retail rates.
Shu, Di-Reb - 17
Rocky Mountain Power
Q.
2
3 A.
4
5
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
23
What adjustment does Monsanto propose to the Company's inter-hour wind
integration costs?
If the Commission does not agree with Monsanto's proposal to remove the entire
wind integration costs from the Company's fiing then Monsanto proposes a
secondary adjustment. Monsanto claims that the inter-hour wind integration costs
for balancing purposes have already been included in the Company's fiing
through the inclusion of actual short term firm transactions, and by calculating the
inter-hour wind integration costs for the period from January 1 to May 4, 2010,
the Company double counted the wind integration costs. The adjustment would
reduce Company's system NPC by $2.6 milion for inter-hour wind integration
costs from January to ApriL.
What is your response to the proposal?
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 firm transactions through
that period. Then on the other hand, Mr. Widmer also agrees that "(t)he Company
has a variety of options for balancing," and these options include redispatch of all
flexible resources, firm and non-firm wholesale contracts, generation and wind
curtailment. The Company has included actual short term firm transactions in its
fiing. However, those transactions are only a small portion, if any, of the
resources that the Company utilizes to integrate generation from wind facilities
into its system. In its fiing, the Company has included wind generation at the
Shu, Di-Reb - 18
Rocky Mountain Power
2
3
4
5 Q.
6 A.
7
8
9
10
11
12
13
14
15
16
17
18 Q.
19
20
21 A.
22
23
expected level that lacks the significant variabilty 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 variabilty 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 further adjustment could be made to what he has proposed in
relation to various other means. If the reference were to the flexible resource
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 normalized basis. Ifthe reference were to the additional
sales transactions that the Company could make, Mr. Widmer would be double
counting the presumed impact that he calculated based on short term firm
transactions, which would have included both sales and purchases.
What do you recommend the Commission do regarding various proposals to
remove all or portion 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
testimony that the Company agrees to remove, the Commission should reject all
other adjustments proposed by Staff, PIIC and Monsanto.
Shu, Di-Reb - 19
Rocky Mountain Power
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.
1 1 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. Staff 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 irrigation and flood control releases from Bear Lake.
Flood control on the Bear River is an operational constraint and releases of water
for flood control have not been available to the Company since 2001. The usual
manner of normalizing hydro requires adjustments for operating constraints.
Please explain the contractual controls over discharges 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
Lake solely for power generation below the irrigation reserve level of elevation
5,914.61 feet; (2) the 2000 "Operations Agreement for PacifiCorp's Bear River
System," which requires that the Company operate Bear Lake primarily for
irrigation and flood control. This agreement was required by Idaho, Wyoming,
Shu, Di-Reb - 20
Rocky Mountain Power
2
3
4
5
6
7
8
9
10 Q.
11
12 A.
13
14
15
16
17
18
19
20
21
22
23
and Utah as a condition for approving MidAmerican Energy Holdings Company's
acquisition ofPacifiCorp; 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 opportunities (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 three potential sources of water for generation:
natural inflow, water withdrawn from Bear Lake to supply downstream irrigators,
and water withdrawn from Bear Lake for flood control purposes. 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 purposes unless the lake elevation exceeds a certain leveL. For the past 10
years, and for the foreseeable future assuming median streamflow into Bear Lake,
this operational constraint 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 control storage.
The Company previously modeled the Bear River system using historical
Shu, Di-Reb - 21
Rocky Mountain Power
normalized hydro generation for all three operational modes that included water
2 supply from natural run-off, irrigation deliveries, and flood control releases,
3 without considering the operational constraints around flood control operations.
4 After a careful review, the Company concluded that the flood control mode of
5 operation has now effectively become unavailable, and the Company has begun
6 accounting for this operational constraint in its rate filings and operations
7 planning by excluding the generation using the flood control water in its
8 normalized hydro generation.
9 Q.What has been the generation from the Bear River system in the recent
10 history?
11 A.Figure 1 below shows the actual generation from the Bear River system from
12 1979 to 2009 water year (October of the previous calendar year to September of
13 the current year), which is the base period applied in the current proceeding. The
14 un shaded bars identify the flood control years. It is clear that the generation
15 during the flood control years is significantly higher than the non-flood control
i 6 years. The actual generation through 2010 is also added to the Figure.
Shu, Di-Reb - 22
Rocky Mountain Power
2 Q.
3
4 A.
5
6
7
8
9
Figure 1 Actual Generation from Bear River
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
o
-l.9~ -l.9 -l,9 -lJ! -l,9 -l,9 -l.o -l,9 -lJ! -l,9 -l,9 ~a ~I'_ ~a ~a ~a~~~~~~~~~~~~~~~~
September 2010 is preliminary.
How does the normalized hydro generation from the Bear River system
compare with actual generation?
Figure 2 below shows the comparison of historical generation that is unadjusted
for any known and measurable changes, such as rules and regulations, over the
years, normalized generation in the current proceeding as proposed by the
Company and by Staff and Monsanto, and the most recent actual generation. It is
clear that the normalized generation in the Company's fiing is more
representative ofthe expected generation from the Bear River system.
Shu, Di-Reb - 23
Rocky Mountain Power
Figure 2 Bear River Generation Comparison
350,000
300,000
250,000
.c 200,000
~150,000
100,000
50,000
o
1979-2008 1979-2008 1979-2008 ID GRC
Average Median Median, w/o
Flood Control
Staff and Water Year Water Year
Monsanto 2009 Actual 2010 Actual
September2010is preliminary.
2 Q.What then is the consequence 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 Commission
7 reject the adjustment proposed by Staff and Monsanto.
8 Start Up Energy (pUC Adjustment 2)
9 Q.Please explain PUC's proposal for the value of start-up energy.
10 A.PIIC proposed that the Company include the energy associated with starting up
1 1 Currant Creek, Lake Side, and Chehalis in NPC because the fuel costs of start-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 Mountain Power
Q.
2 A.
3
4
5
6
7
8
9 Q.
10 A.
1 1
12
13
14
15
16
17
18
19
20
What other costs are incurred when starting up the gas-fired plants?
Start-up costs are not limited to fueL. In order to accommodate the start-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 incurred had the
start-ups not occurred. 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 ofthese costs are
included in GRID.
Did PUC's proposal contain technical errors?
Yes. In calculating the value for the start-up energy, PIIC violated the
requirement of the minimum down time required for units to stay offine before
returning to service. This is due to the fact that GRID allows units to start
instantaneously. However, if start-up energy is to be considered, the multi-hour
start-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 milion from what the Company included
in its original filing on a total Company basis, which offsets the $ 1.7 milion
assumed value of the start-up energy. As a result, I recommend the Commission
reject PIIC's adjustment.
Shu, Di-Reb - 25
Rocky Mountain Power
Normalization of Call Option Contracts (pUC Adjustment 3, Monsanto Adjustment
2 13)
3 Q.
4
5
6 A.
7
8
9
10
1 I 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?
PIIC proposes to substitute actual data for normalized data for the sales contract
with the Sacramento Municipal Utility District ("SMUD"), and Monsanto
proposes similar adjustment for the sales contract with Black Hils Power ("Black
Hils"). The adjustments would reduce the Company's system NPC by $1.6
milion and $ 1.3 milion, respectively.
Do you have any general comments about the two proposals?
Yes. For normalized purposes, the GRID assumes that the counterparties - who
control the call options on these two contracts - wil maximize the value ofthe
contracts and take power at the most economical time. GRID assumes
optimization of all flexible resources, while PIIC's and Monsanto's proposals
embody an approach of optimizing 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 irrationally. PIIC's and
Monsanto's proposals violate any reasonable principles of consistency and
fairness. IfNPC are to be set using an optimization model, then all resources and
contracts that are subject to being optimized should be optimized. This is the same
argument used by Staff and Monsanto in their proposed treatment of the APS
Supplemental contract where they propose that actual historic energy take under
Shu, Di-Reb - 26
Rocky Mountain Power
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 optimizing the contract in GRID.
Please explain.
The proposed adjustments depart from modeling power costs on a normalized
basis. If this type of modeling adjustments were adopted, then consistency and
fairness require its application to all other flexible purchase or sale contracts that
are modeled in a similar fashion to the SMUD and Black Hills contracts. For that
matter, it should also be applied to flexible generating resources. Optimization of
the Company's system operations decreases NPC on a net basis. PIIC and
Monsanto have not proposed "de-optimization" across the board, which would
increase NPC. Nor have PIIC and Monsanto provided any justification for
selective "de-optimization" of only two call option sales contracts, rather than all
purchase and sale contracts and flexible generating units.
Why is it important to treat third part contracts the same whether the
Company is sellng or purchasing energy?
Use of any delivery patterns other than the optimized delivery patterns will
always lower net power costs for wholesale sales contracts with flexibilty such as
the SMUD and Black Hils contracts. The opposite is true for purchased power
contracts that give the Company flexibilty in how the power is taken. It is not
fair or consistent to normalize different contracts using different rules.
Shu, Di-Reb - 27
Rocky Mountain Power
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 counterparties' systems due to
the impossibility of obtaining the data that are proprietary to those counterparties.
However, given that the Company is only one ofthe many participants in the
market, the only assumption is to assume that all the participants in the same
market are rational and wil exercise their rights to the flexible contract to lower
their costs. This is confirmed 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 capture the maximum contract value by taking delivery of the contract
energy to serve load or faciltate market sales." This is exactly what the
Company's method of optimization captures, and what is demonstrated in Exhibit
Nos. 73-75. Exhibit No. 73 shows the actual delivery taken as a whole, and that
the pattern ofthis energy delivery may appear to be flat. However, looking 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 Hills exercised their rights based
on price signals from the market, taking more energy when and where market
prices were relatively higher.
3 Both Mr. Falkenberg and Mr. Widmer were consultants to Wyoming Industrial Energy Consumers
("WIEC") in that proceeding.
Shu, Di-Reb - 28
Rocky Mountain 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 SMU contract structured?
In addition to the firm 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 returned 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 firm 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 portion of the contract, SMUD would shape their take of the firm
portion with a similar seasonal pattern. PIIC's proposal only considers the firm
portion of the contract, and suggests that SMUD would take more energy in
spring than in fall as if SMUD would not have considered their rights to the
provisional energy.
Shu, Di-Reb - 29
Rocky Mountain Power
Figure 3 Historical Shape of Energy Take by SMU
80,000
70,000
60,000
50,000
40,000
~30,000
20,000
10.000
0
2 Q.
3 A.
4
5
6
7
8
9
10
11
----------------------------------------------------------------------------------------------------------------------------
---------------------------- - -- - --- ---- --------------------------------------------------------------------
-----------------------------------------------------------
--------------------------------
co §'"'"
/N §~0)9 9 :r :rc:.a c:.a c:.a c:.a.!.!.!.!
I I~ Firm . 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
Camas, Biomass, and small purchases, based on historical information because
none of these contracts provide the Company the kind offlexibilities that are
provided for under the terms of the call option sales contracts. Based on the
principle of known and measurable information, the only information known to
the Company is the history of those contracts. I recommend the Commission
reject the adjustments proposed by PIIC and Monsanto on the basis that the
adjustments violate the fairness in the optimization of all flexible resources to
reduce NPC.
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.
1 1 A.
12
13
14
15
16
17 Q.
18 A.
19
20
21
22
23
What does PUC's propose in this adjustment?
PIIC claims that the Company's application of outages biases the availability and
average heat rates of the units. The adjustment proposed by PIle would reduce
Company's system NPC by $1.8 milion.
How does the Company apply the deration method?
The Company's approach derates the maximum capacity of the unit in every hour
ofthe year by an equal percent based on historic forced outage rates, which
constitutes a "haircut" in unit availability.
How would PUC's discussion change this method?
The discussion presented by PIIC would alter thermal units' heat rate curves to
artificially increase their efficiency as compared with the heat rate curves that are
developed from actual plant operating data. The discussion on the "other aspect"
of the problem that PIIC presents is to reduce thermal plant minimum generation
levels so GRID can run thermal units at levels they are physically incapable of
reaching.
Would PUC's method signifcantly 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 particular level of generation - its derated
maximum capacity, with the assumption that the unit may be dispatched at its
stated maximum capacity in GRID if there were not the availability "haircut".
When the unit is dispatched at any level below its derated maximum capacity,
GRID has made the optimal decision to dispatch that unit at a lower and less
Shu, Di-Reb - 31
Rocky Mountain Power
efficient generation level, whether it has been derated or not. Therefore, derating
2 the entire heat rate curve overstates the effciency of the unit and understates the
3 heat inputs.
4 Figure 4 and Figure 5 below show the heat rate curves 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 jurisdictions for a coal-fired unit and gas-fired
7 unit, from minimum to maximum generation level, with the assumed generation
8 levels superimposed on the heat rate curves that would be dispatched under the
9 Company's methods. The graphs clearly demonstrate that heat input required for
10 various levels of generation is understated using the derate-adjusted heat rate. In
1 1 both cases, there are many hours of dispatch below the derated maximum
12 capacity, which are the generating levels at which PIIC's proposal would
13 understate the heat rate, and subsequently understate NPC.
Shu, Di-Reb - 32
Rocky Mountain Power
Figure 4 Heat Rate Curve (Coal Unit)
Minimum Capacity/
I
Heat Rate curvel
J
"'
Maximum Capacity\
'$Q.
.5::i
Derated Capacity
/ I
PIIC Adjusted H~at Rate Curve
Generatin Level
2 Figure 5 Heat Rate Curve (Gas Unit)
..::Q.c
¡:i
Maximum Ca acity
Derated Capacity
Minimum Capacity
Generation Level
Shu, Di-Reb - 33
Rocky Mountain Power
Q.
2
3 A.
4
5
6
7
8
9
10
1 1 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 least 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
effcient level, but the Company does not believe such adjustment should be
made. After the Company's application ofthe "haircut," 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 because the maximum generating level is derated?
No. The purpose of the "haircut" to the maximum generating capability is to
reflect the amount of generation no longer available due to outages. That is fully
accomplished through the "haircut" to the maximum generating 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. PIIC seems to suggest that the portion 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 modeling of all aspects of the units in the same manner,
including the reserve capabilties of the units. In addition, in the case of outages,
it is not correct to assume that another entity owns the portion of the units that are
forced out. When GRID determines certain amount of generation from a unit, it
Shu, Di-Reb - 34
Rocky Mountain Power
does not make the decision based on whether or how much the unit has been
2 derated. That is, for a unit with a capacity of 100 megawatts, when GRID
3 dispatches the unit at 70 megawatts, it does not matter whether the unit has been
4 derated by 20 percent or not. The Commission should reject PIIC's adjustment.
5 Existing Long Term Contracts (PUC Adjustments 11 and 13 regarding DC Intertie
6 Costs, and Idaho Power PTP Contract)
7 Q.
8
9 A.
10
11
12
13
14 Q.
15 A.
16
17
18
19
20
21
22
23
Please explain PUC's proposed adjustment to costs associated with the DC
Intertie.
PIIC argues that costs associated with the DC Intertie and Network Transmission
Agreement between BPA and the Company should be removed from NPC on the
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 milion 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 of200 megawatts of power from Southern California Edison at NOB
under Amendment 1 to the Winter Power Sales Agreement ("WPSA"). The
WPSA was 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 suffcient 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
Shu, Di-Reb - 35
Rocky Mountain Power
remaining 200 megawatts oftransmission rights by acquiring 200 megawatts of
2 transmission capacity on the DC intertie. The Company terminated the WPSA
3 effective January 1,2002, but kept its 200 megawatts of DC Intertie import rights.
4 Q.How does the DC Intertie contract benefit the Company's customers today?
5 A.The agreement takes advantage of the load diversity between summer-peaking
6 California and the winter-peaking Pacific Northwest. The contract provides a
7 valuable means of securing capacity and energy from California entities to meet
8 retail loads. Loads in California are relatively low in the winter when loads in the
9 Company's west control area and the rest of the Pacific Northwest are at their
10 highest.
1 1 Existing Long Term Contracts (pUC Adjustments 11 and 13 regarding DC Intertie
12 Costs, and Idaho Power PTP Contract)
13 Q.Please explain PUC's proposed adjustment to costs associated with the DC
14 Intertie.
15 A.PIIC argues that costs associated with the DC Intertie and Network Transmission
16 Agreement between BPA and the Company should be removed from NPC on the
17 basis that no purchases are modeled at the NOB, the point from which the
18 agreement provides wheeling. The two adjustments proposed by PIIC would
19 result in a $4.8 milion decrease to NPC.
20 Q.How should the Commission judge the prudence of this contract?
21 A.Prudence should always be judged based on the information that was known at
22 the time the contract was executed. It would not be reasonable to judge a 16-year
23 old contract based on information that is available today that was not available 16
Shu, Di-Reb - 36
Rocky Mountain Power
2 Q.
3
4
5 A.
6
7
8
9
10
i 1
12
13
14
15
16
17 Q.
18
19 A.
20
21
22
years ago.
But there are no transactions 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 making their proposal, PIIC focuses on energy deliveries under the contract
rather than the capacity and diversity benefits ofthe contract. It would be
inappropriate to penalize the Company for prudently acquiring transmission rights
16 years ago by disallowing costs today based on hindsight and only looking at
the energy value ofa resource that can faciltate 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. PIIC's proposals based
on the limited energy-only view of this contract is similar 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 ofthe 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")?
PIIC claims that the contract that the Company has with IPC would no longer be
needed after the Populus to Terminal 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 milion.
Shu, Di-Reb - 37
Rocky Mountain Power
Q. Why does the Company disagree with this adjustment?
2 A.The notion that an existing contract should be terminated simply because a new
3 resource may replace the function ofthat contract is unfounded. The referenced
4 contract is a two-year contract that the Company entered into in 2009 to serve
5 retail load, given the information at the time about the resources available to the
6 Company to meet its obligation in the next two years. This contract is not the
7 same as the short term firm contracts that the Company enters into from time to
8 time and for a short duration, such as the ones listed as a correction earlier in my
9 testimony. The capabilty ofthose short term firm transmission is modeled in
10 GRID at the assumed level based on what the Company has experienced
11 historically, and the assumption should be modified when the Populus to Terminal
12 line can provide the needed transmission capacity. The Company entered into
13 that particular contract based on expected in-service date of the Populus to
14 Terminal line and with the option of annual contracts only. As the result, the
15 terms ofthe contract could not perfectly match the in-service date of the new
16 transmission line, and the Company should not be required to time the contract
17 terms precisely with resources that become available subsequently. Had the
18 Company entered into a shorter contract, there would have been a potential gap
19 prior to the new transmission line being in service to the detriment of customers.
20 I recommend the Commission reject PIIC's adjustment.
21 Reserve Shutdown (Monsanto Adjustment 5)
22 Q.Please describe Monsanto's adjustment for reserve shutdowns.
23 A.Monsanto claims that the Company's forced outage rates and the rates used in
Shu, Di-Reb - 38
Rocky Mountain Power
2
3
4
5 Q.
6 A.
7
8
9
10 Q.
1 1 A.
12
13
14
15
16
17
18
19
20
21
22
23
GRID are calculated inconsistently and proposes that reserve shutdown hours
should be added to the denominator of the forced outage rate calculations. The
proposed adjustment would reduce the Company's system NPC about $0.8
milion.
Do you agree with this adjustment?
No. This adjustment has the effect of artificially lowering the forced outage rates
by stating that the units would be available 100 percent of the time if they were to
be called upon to run during the hours when they were on reserve shutdown for
economic reasons.
Please explain.
Contrary to what Monsanto claims, the Company's calculation of forced outage
rates is consistent with how GRID applies them. Monsanto agrees that the
planned outage hours should be excluded from the denominator in the calculation
of forced outages. Removing the reserve shutdown hours are based on the same
fact that no forced outage events are collected during either the planned outage
hours or the reserve shutdown hours. Monsanto's proposal is the same as stating
that if the units were to run during the hours when they were shutdown for
economic reason, the units would not encounter any forced outage events. The
proposal is not supported by logical or analytical reasoning. In addition, given the
fact that GRID models reserve shutdowns, the rates are only applied to the hours
when they are scheduled to run, which is a fact even supported by Mr. Widmer in
his testimony stating that "(t)he Company's daily screen modeling in GRID
specifically identifies when CCCTs are available but are not economic to run and
Shu, Di-Reb - 39
Rocky Mountain Power
essentially placed them on reserve shutdown so they cannot run." I recommend
2 the Commission reject Monsanto's proposaL.
3 Cal iso (Monsanto Adjustment 7)
4 Q.Please describe Monsanto's adjustment to the Cal iso Fees.
5 A.Monsanto recommends removal of the Cal iso fees that are based on 2009 actual
6 costs incurred by the Company, and replace them with a lower amount.
7 Monsanto's recommendation is based on the assumption that a significant portion
8 of the fees are not matched by electricity transactions that the Company included
9 in the case and could incur the fees. This adjustment results in a $4.0 milion
10 decrease to the Company's system NPC.
11 Q.How do you respond to this adjustment?
12 A.I urge the Commission to reject this adjustment. Cal iso fees are incurred for
13 transactions at market points ofSP15, NPI5, and when the Cal iso is the
14 counterpart.4 The bulk of these transactions are short term transactions made
15 close to the time of delivery. Cal iso is a major counterpart in the Company's
16 activities to balance its system, which is a fact that Monsanto doesn't dispute
17 according to Mr. Widmer's testimony stating "(h)istorical records reveal that most
18 of the transactions with the Cal iso as a counter part are incurred shortly before
1 9 or on the actual day of delivery." Such activities are reflected in GRID as part of
20 the system balancing sales and purchases, which are transactions computed by
4 Mr. Widmer quoted an excerpt presumably from the testimony by Company's witness Mr. Duvall from
the Wyoming Docket No. 20000-352-ER-09. Mr. Duvall's testimony in that case did not contain the
quoted excerpt. However, Mr. Duvall did testifY to content similar to the excerpt as the Second
Supplemental testimony in the Company's Utah general rate case Docket No. 08-035-38, where the
discussion was about the reason why the Company entered into transactions that had delivery points in
SPI5 when it did not have firm transmission rights.
Shu, Di-Reb - 40
Rocky Mountain Power
2
3
4
5
6
7 Q.
8
9 A.
10
11
12
13
14
15
16 Q.
17
18 A.
19
20
21
22
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 Cal iso and continues to incur Cal iso fees. There is no reason to
arbitrarily eliminate expenses that are required to be incurred when doing
business with the Cal iso simply because the data in the Company's fiing does
not explicitly include those applicable transactions.
Would removing the Cal iso as a counterparty affect the operations ofthe
Company's power system?
Yes. The Company enters into transactions with the Cal iso in order to
economically balance the system. In doing so, the Company incurs Cal iso fees.
Not allowing the Cal iso fees is the same as making the assumption that the
Company would not do business with the Cal iso. Removing Cal iso as
counterpart would limit the options that the Company may use to balance its
system economically. As a result, NPC would go up due to those limitations and
constraints.
Does the Company expect that it wil continue to do business with the Cal
iso in 2010?
Yes. The Company expects to do business with the Cal iso in 2010 and the
future and incur various fees in the markets governed by the Cal iso. Costs such
as wheeling costs are typically quantified for ratemaking purposes 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 this proceeding.
Shu, Di-Reb - 41
Rocky Mountain Power
Q. Do you see other problems in Monsanto's proposal?
2 A.Yes. Despite the fact that the Company requested Monsanto to provide all
3 workpapers supporting their adjustments, the workpapers for this adjustment is
4 among the ones that do not support the amount ofthe adjustments. Given the
5 magnitude of the adjustment, it seems that Monsanto proposes to remove the
6 entire amount of the Cal iso fees that the Company included in the case,
7 replacing it with only a fraction of the actual Cal iso fees that the Company has
8 incurred during the period that is claimed to match the actual short term firm
9 transactions that the Company included in the case. However, through September
10 2010, the Company has incurred approximately $3.2 milion of Cal iso fees, both
11 wheeling fees and service fees, which are only $66,265, lower than what the
12 Company included in the filing for the corresponding period. Accordingly, the
13 Commission should reject Monsanto's argument that the Company would not
14 incur Cal iso fees in the test period, as well as rejecting the proposed adjustment,
15 which would replace what the Company has included in the case with a fraction
16 of the actual fees.
17 Cholla 4 Capacity (Monsanto Adjustment 10)
18 Q.What was the issue regarding the capacity ofCholla unit 4?
19 A.As the result of a major overhaul in 2008 the capacity at Cholla Unit 4 was
20 upgraded. However, due to transmission constraints, the generation from the
21 Cholla unit 4 to the Company's system has remained at the previous leveL.
22 Monsanto argues that the upgrade should be reflected in GRID. The adjustment
23 would reduce the Company's system NPC by $1.1 milion.
Shu, Di-Reb - 42
Rocky Mountain Power
Q. Do you agree with Monsanto's argument?
2 A.No. First, the argument ignores the physical transmission constraints on delivery
3 of power from Cholla. Second, Monsanto has increased transmission capacity to
4 accommodate the increased generation from Cholla unit 4 without increasing any
5 other costs related to that capacity. Third, the purpose of derating the units for
6 forced outages is to capture the lost generation due to such outages, while
7 Monsanto's proposal would suggest the lost generation due to outages could be
8 supplemented by the possible generation from the unit that cannot be delivered to
9 the system.
10 Morgan Stanley Call Premiums (Monsanto Adjustment 11)
11 Q.Please explain the Monsanto's proposed adjustment.
12 A.Monsanto proposes to remove the capacity payments related to two of the
13 Company's call option contracts because those contracts are not dispatched during
14 the test period. The adjustment would reduce the Company's system NPC by
15 $3.1 milion.
16 Q.Do you agree with Monsanto's proposed adjustment?
17 A.No. Monsanto is seeking to disallow the capacity payments that the Company
18 pays on call option contracts without demonstrating the imprudence of these
19 costs. The Company executed these call option contracts to meet demand and
20 ensure reliable service by providing physical delivery of energy during periods of
21 increased demand and/or transmission constraints when prices are higher. So
22 even if the contracts are not dispatched in GRID, they can provide customers a
23 real benefit in the event of a change in the Company's system.
Shu, Di-Reb - 43
Rocky Mountain Power
Q. What would you recommend the Commission do in the current case?
2 A.The Commission should reject Monsanto's proposal to remove the capacity
3 payment of the call option contracts. As stated above, the contracts were entered
4 into to meet demand and ensure reliable service by providing physical delivery of
5 energy during periods of increased demand and/or transmission constraints when
6 prices are higher. Monsanto's adjustment is similar to requesting a refund of your
7 auto insurance payment every year when you have not been involved in an
8 accident.
9 Other Proposals
10 Combined Cycle O&M Adjustment (PUC Adjustment 14)
11 Q.Please explain PUC's adjustment to O&M costs of combined cycle plants.
12 A.PUC states that the proposed daily screening adjustment reduces the O&M costs
13 associated with combined cycle plants.
14 Q.What is the basis for PUC's adjustment?
15 A.Based on Mr. Falkenberg's testimony on this issue in prior cases and the reference
16 to Mr. Steven R. McDougal's exhibit, PUC seems to be referring to the O&M that
17 the Company might have added to fixed O&M for each start-up of a combined
18 cycle plant.
19 Q.Is PUC's adjustment reasonable?
20 A.No. The Company has not included any incremental O&M to reflect the
21 additional costs of combined cycle plant start-ups. Therefore, there are no costs
22 to remove.
Shu, Di-Reb - 44
Rocky Mountain Power
Q.Do both Staff and Monsanto oppose updates to the Company's fied NPC?
2 A.Yes. The Company believes that updated information would provide the
3 Commission with the most recent and more accurate information for the test
4 period. While opposing updates to the Company's NPC, Monsanto proposes to
5 selectively update components ofthe NPC, such as the recommendation to
6 replace the Cal iso fees that the Company included in the fiing with actual Cal
7 iso fees that the Company has incurred for period prior to May 4, 2010.If the
8 Company were to update the NPC to reflect all actual information that is available
9 for the test period through September, the NPC for the twelve-month period
10 ending December 2010 would be approximately $53.7 millon higher than what
1 1 was contained in the Company's original filing. If the Company were to update
12 all NPC for actual information through May 4, 2010, as Monsanto recommended
13 for the Cal iso fees, the test period NPC would be $25.0 milion higher than
14 fied.
15 Q.Has the Company updated its NPC in this rebuttal?
16 A.No. However the Company believes updates improve the accuracy ofNPC
17 forecasts and reserves the right to propose updates in future fiings Staff, PIIC and
18 Monsanto proposed and the Company accepts adjustments to NPC, which total to
19 an approximate $6.5 millon reduction from what the Company originally fied.
20 Q.Please summarize your testimony.
21 A.In its direct filing, the Company proposed NPC of $ 1.07 bilion on a total
22 Company basis for the 12-month test period ending December 2010. In this
23 current fiing, the Company has revised its projected NPC to $ 1.063 bilion on a
Shu, Di-Reb - 45
Rocky Mountain Power
total Company basis. The revised NPC incorporate corrections and positions that
2 Staff, PUC and Monsanto proposed and the Company accepts, which total to an
3 approximate $6.5 milion reduction from what the Company originally fied. For
4 the adjustments that the Company does not agree with, I have provided
5 explanations and evidence to support the Company's positions. I believe the
6 revised NPC has reflected more accurate information and presented a reasonable
7 compromise to positions proposed by Staff, PIIC and Monsanto.
8 Q.Does this conclude your rebuttal testimony?
9 A.Yes, it does.
Shu, Di-Reb - 46
Rocky Mountain Power