20071026Duvall rebuttal.pdf

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2007 OCT 26 AM 10=
I JQAHO PUBUCU I ,LIliES COMM1SSfOi
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR APPROV AL )
OF CHANGES TO ITS ELECTRIC SERVICE SCHEDULES
CASE NO. PAC-07-
Rebuttal Testimony
of Gregory N. Duvall
ROCKY MOUNTAIN POWER
CASE NO. PAC-O7-
October 2007
Please state your name, business address and present position with the
Company (also referred to as Rocky Mountain Power).
My name is Gregory N. Duvall. My business address is 825 NE Multnomah, Suite
600, Portland, Oregon, 97232. My present position is Director, Integrated
Resource Planning and Regulatory Strategy.
How long have you been in your present position?
I have been in my present position since December 2005.
Please describe your education and business experience.
I received a degree in Mathematics from the University of Washington in 1976
and a Masters of Business Administration from the University of Portland in
1979. I was first employed by Pacific Power in 1976 and have held various
positions in resource and transmission planning, regulation, resource acquisitions
and trading. From 1997 through 2000 I lived in Australia where I managed the
Energy Trading Department for Powercor, a PacifiCorp subsidiary at that time.
After returning to Portland, I was involved in direct access issues in Oregon, was
responsible for directing the analytical effort for the Multi-State Process ("MSP"
and currently direct the work of the integrated resource planning group, the load
forecasting group, and the market assessment group in PacifiCorp Energy. Both
Rocky Mountain Power and PacifiCorp Energy are divisions ofPacifiCorp (the
Company
Purpose and Summary of Testimony
What is the purpose of your testimony?
The purpose of my testimony is to respond to issues raised in the pre-filed direct
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testimony of the Commission Staff and the Idaho Irrigation Pumpers Association
lIP A") regarding the Company s irrigation load control program in Idaho.
Specifically, I will address the proper inter-jurisdictional allocation treatment of
program costs and the appropriate value of incentives paid to irrigation customers
in exchange for participation in this program. I am adopting the Supplemental
Testimony of Company Witness Mr. Mark T. Widmer on issues relating to the
irrigation load control program.
Please summarize your testimony.
My testimony establishes the following:
Inter-jurisdictional Cost Allocation
Situs assignment of the irrigation load control program credit is required
under the Revised Protocol.
Situs assignment provides over $1 million in reduced revenue requirement to
Idaho.
Staffs claim that the Revised Protocol did not address Class 1 DSM load
control based on "loosely defined" language is incorrect and has no basis.
The Idaho irrigation load control program is significantly different than the
Monsanto contract in that it does not provide ancillary services, it is not
contractually as firm, it is not separately metered, and it is integrated into the
local Idaho distribution system.
The proposal of Mr. Bryan Lanspery and Mr. Anthony Yankel to allocate the
Idaho irrigation credit system-wide double counts the benefits of the
interruptions and is inconsistent with the treatment of Monsanto in that it does
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not adjust loads as if the curtailment had not taken place. In addition, it is
inconsistent as it does not propose the same treatment for Class 1 DSM
programs in other states.
Product Valuation
The current value ascribed to the scheduled firm irrigation load control
program is $27 per kilowatt-year which is inclusive of a customer incentive of
$11.19 per kilowatt-year.
The recently completed potential study conducted by Quantec identified
demand-side resource availability, type, location and cost. The report did not
determine avoided cost as alleged by Mr. Yankel.
Mr. Yankel's contention that the Quantec study identified $98 per kilowatt-
year as the avoided cost for the Idaho irrigation load control program is a
gross misrepresentation of the report.
The $98 per kilowatt-year value was used by Quantec as a screening
mechanism to determine demand-side resource availability, type , location, and
cost, and was never intended to represent an avoided cost for Idaho irrigation
load control.
Recommendations
What is the Company s recommendation regarding the inter-jurisdictional
allocation of the irrigation load control program credit?
The Company recommends that the Commission continue situs assignment ofthe
irrigation load control program credit as dictated by the Revised Protocol.
respond to the change in allocation approaches suggested by Staff and lIP A, the
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Company recommends that the Commission order the parties to take this issue to
the Multi-State Process Standing Committee. A more thorough description and
the rationale for my recommendations are provided below.
What is the Company s recommendation regarding the level of the irrigation
load control program credit?
The Company recommends that the Commission not adjust the credit at $11.
per kilowatt-year for the scheduled firm product (Schedule 72) in this rate case.
Moreover, any change made to the price would need to be reflected in the
Company s revenue requirement in this case. The Company expects to continue
the scheduled firm product as well as the dispatchable program launched in 2007.
The Company will make a separate filing with the Commission before the end of
2007 to determine the load control incentive credit level and operating criteria for
both products in the 2008 season. A more thorough description and the rationale
for my recommendations are provided below.
Inter-Jurisdictional Cost Allocation
Please describe the irrigation load control demand side management
program offered by the Company in Idaho.
Since 2003 the Company has offered an optional irrigation load control program
Schedule 72, which allows customers to agree to restrict, through the use of
timers, the use of electricity during peak hours in exchange for a dollar credit on
their bill. Under this program, load control is scheduled in advance for the entire
irrigation season and executed automatically according to the prescribed schedule.
In 2007, the Company launched a pilot program utilizing new technology that
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allows the Company to control participating load on a day-ahead basis, subject to
certain constraints. The pilot program was for the 2007 irrigation season, and the
results of its operation are currently being analyzed. A report of the pilot
program s outcome and plans regarding the program s expected operation in 2008
will be provided to the Commission later this year.
Do you agree with the proposal advocated by Staff witness Mr. Lanspery and
lIP A witness Mr. Yankel that the incentive credits paid to irrigation
customers who participate in the load control demand side management
program should be system allocated?
No. Their proposals violate the Revised Protocol and double count the benefits of
the load control incentive credit. Both witnesses claim that the payments made to
Idaho irrigation customers as an incentive to participate in the load control
demand side management program should be allocated system wide and paid for
by customers in all of the Company s jurisdictions. Yet neither witness adds the
irrigation loads back into the inter-jurisdictional allocation factors, thereby
enjoying the benefit of a lower allocation of system costs, and only paying a
fraction of the incentive credit. Situs treatment of the load control incentive credit
is required under the Revised Protocol allocation methodology approved and
implemented by this Commission, and provides a reasonable matching of the cost
and benefits related to load management within a particular state. Indeed, Mr.
Yankel acknowledges at pages 6 and 7 of his testimony that his proposal requires
the Commission to "ignore" the Revised Protocol:
I recommend that for purposes of this case that this portion of the
Revised Protocol be ignored and a more appropriate "system" treatment of
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these costs be utilized. Over the long-term, this defect in the Revised
Protocol should be corrected, such that it reflects the treatment of the
benefit of the Irrigation Load Curtailment program in a manner similar to
the treatment of the benefit of the Monsanto interruptible program.
On Page 7 of his testimony, Mr. Yankel states that the Revised Protocol has
never been used to establish rates in Idaho. Is this true?
No. The Company has now filed three rate adjustments since the Commission
approved the Revised Protocol. Case No. PAC-05-, a general rate case filed
by the Company in January 2005, was settled by way of a stipulation approved by
the Commission in Order No. 29833. All parties signing the settlement
agreement, including the Commission Staff and lIP A, stipulated that the Revised
Protocol was then implemented for setting rates in Idaho. In each of these cases,
the Company s filing allocated the irrigation load control program on a situs
basis-without objection from any party.
What facilitated the introduction of Idaho s current irrigation load
management program?
Two factors led to the development of the Company s program: opportunity and a
Company commitment implemented through a Commission order. The
opportunity is created by Idaho having the greatest irrigation energy requirements
of any of the six state territories served by PacifiCorp, which is approximately 18
percent of all the energy consumed in Idaho. The vast majority of the energy
consumed by irrigators occurs within a six month period each year with the
greatest system impacts occurring in July and August. The timing and magnitude
of the irrigation loads present the opportunity for acquisition of a demand-side
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resource.
The second factor leading to the current Idaho irrigation program was a
Company commitment whereby the Company worked with irrigators to develop
an optional load control program for the 2003 irrigation season. Since program
approval and implementation in 2003 in Commission Order No. 29034, the
Company has continued working with irrigators and the Commission staff to
evolve the program and increase program participation.
What is demand-side management ("DSM"
Demand-side management refers to utility programs intended to affect the timing
or amount of customer electricity use. These include conservation programs
aimed at reducing the energy required to serve customer needs either through
improved end-use efficiency or changes in behavior, and programs that shift
electricity demand away from peak load hours, which in turn improves the
efficiency of the system.
As a utility, PacifiCorp looks at demand-side resources as distributed
resource acquisitions made possible through capturing and managing customer
usage that can improve system efficiency. Opportunities for demand-side
resource acquisitions differ by market sector, end-use equipment, load usage
patterns, and jurisdiction, which led to the Company recently conducting a six-
state demand-side management potential assessment to help identify demand-side
resource availability, type, location, and cost.
Does Idaho s irrigation load management program fall into this definition?
Yes. The irrigation load control program s primary objective is to improve the
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management of Idaho irrigation loads through working with irrigators to reduce
their contribution to system and local peak loads, shifting a portion of their
demand to non-peak hours. As a result, costs are reduced reflecting more
efficient use of resources and potential reduction in distribution investment.
Mr. Lanspery states that Idaho s irrigation load management program does
not fall into the definition of Demand Side Management in the Revised
Protocol. Do you agree?
No. As one of the Company s lead participants in the Multi-State Process (the
MSP") and the Revised Protocol, I strongly disagree with Mr. Lanspery
conclusion. In the context of the MSP discussions and the Revised Protocol
document, all classes of DSM were considered to be State Resources. One only
needs to look at the Company s integrated resource plans or the Quantec potential
study to understand what is considered to be DSM by the Company and its
stakeholders. Class 1 DSM is fully dispatchable or scheduled firm load control
programs, Class 2 is non-dispatchable, firm energy efficiency programs, Class 3 is
price responsive programs, and Class 4 is customer education programs. They all
fall under the category of Demand-Side Management Programs in the Revised
Protocol and are therefore considered State Resources and their costs are assigned
situs.
The sole basis of Mr. Lanspery s claim that load control programs
referred to as Class 1 DSM, are not DSM under the Revised Protocol is that DSM
programs are "loosely defined" in the Revised Protocol. The exact wording
contained in Appendix A of the Revised Protocol is:
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"Demand-Side Management Programs" means programs intended to
improve the efficiency of electricity use by PacifiCorp s retail customers.
Without any basis, Mr. Lanspery suggests that some programs like "See ya later
refrigerator" fit this definition, while others, such as the Idaho load control
program, do not. He gives no explanation for his claim, other than "loosely
defined" language. Rather than calling it "loose" language, I would characterize
it as a definition that is broad enough to capture all four classes ofDSM. For
example, load control improves the efficiency of electricity used by PacifiCorp
retail customers at a system level. The most inefficient resources run at times of
highest load. By shifting load away from peak times, efficiency is improved.
Is there additional support for situs allocation of the irrigation load control
program under the Revised Protocol?
Yes. First, the understanding of what constitutes DSM under the Revised
Protocol is evidenced by the treatment of Class 1 DSM under the Revised
Protocol by other states: all assign it situs. Additionally, the MSP studies
reflected situs treatment of Class 1 DSM program costs. Lastly, MSP legislative
history indicates a clear policy decision to maintain situs assignment of the costs
of all DSM programs on the basis that "the benefits from these programs, in the
form of reduced consumption, (would be) reflected through time in each State
Load-Based Dynamic Allocation Factors.
Is this irrigation program fundamentally the same as the Company
agreement to purchase ancillary services from Monsanto?
No. Unlike the Monsanto contract, the irrigation load control program falls
outside of the definition of "Special Contract with Ancillary Services " described
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. 3
in Appendices A and D of the Revised Protocol, for several reasons. First, unlike
Monsanto, the irrigation program does not provide the Company with any
ancillary services and is not available throughout the entire year. As described in
detail by Company witness Mr. Paul H. Clements, the Company purchases three
types of products from Monsanto: economic curtailment, operating reserves, and
system integrity. All are provided to the Company pursuant to the terms of a
negotiated contract over a specified number of years and provide the Company
the option of curtailing Monsanto load for economic or operational reasons
throughout the year, not just during the irrigation season. Otherwise, Monsanto is
a high load factor customer taking service at transmission level voltage whose
load does not pose significant operational challenges to the Company
distribution system.
Second, irrigation load control, unlike Monsanto, is not a contractually
firm resource that can be counted on for multiple years or even one irrigation
season. The purpose of the irrigation load control program is to manage a
significant summer peak load by shifting usage away from on-peak periods.
Participation in the program is determined not by a negotiated contract, but by
each individual customer electing to participate at the beginning of each irrigation
season under a tariffed offer with no commitment for participating in any
subsequent irrigation season. Furthermore, if any customer elects to remove
themselves from participation during the irrigation season, they may do so with
no other penalty other than reimbursing the Company for costs associated with
participation in the program, not including replacement power.
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Third, irrigation load control, unlike Monsanto, is not separately metered.
This makes it difficult to be as precise in valuing the irrigation load control
discount as it is for Monsanto.
Finally, irrigation load control, unlike Monsanto, has the potential to avoid
local distribution costs that are assigned directly to the state of Idaho. This
provides one example of a basis to situs assign the costs of the program which is
not the case for Monsanto.
When the Commission initially approved the irrigation load control
program, it expressly recognized that it was a DSM program, not a purchase
contract. See Commission Order No. 29034 (The Company s irrigation load
control program "is essentially a time-of-use proposal and not a curtailment or
buy-out proposaL"
Is it true that the cost of the program outweighs any benefits received in
Idaho based on reduced load as purported by Mr. Yankel on pages 6 and 7 of
his testimony?
No. If all impacts of this program are removed from this case, the Idaho revenue
requirement would increase over $1 million. To properly remove the program
from this case, the cost for incentives must be removed and the peak demand used
for jurisdictional allocation must be adjusted (increased) to remove the effects of
shifted load, increasing the total embedded costs allocated to Idaho.
The same load adjustment is required if the Idaho irrigation load control
program is to be treated similar to the negotiated contract between the Company
and Monsanto, i.e. system allocated. System allocation of the Idaho irrigation
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load control program would also increase Idaho revenue requirement over $1
million.
If the Commission concludes the incentive costs should be system allocated,
does the Company agree with the adjustments proposed by Mr. Lanspery
and Mr. Yankel?
No. Their arguments indicate that system treatment would be merited because the
product is similar to Monsanto s curtailment, and that it should be similarly
system allocated. However, while Mr. Yankel admits the cost of service loads
should be increased to reflect the irrigators as having been served as full
requirements customers, both he and Mr. Lanspery neglect to increase the peak
load used for inter-jurisdictional cost allocation purposes. Consistent with the
Revised Protocol allocation methodology, because the Company s purchase of
Monsanto curtailment is system-allocated, Monsanto s load is adjusted for both
jurisdictional and class cost allocation as if the curtailment had not taken place.
With the adjustment to allocation factors as described above, would the
Company agree to the adjustments proposed by Mr. Lanspery and Mr.
Yankel?
No. Ifload control programs (DSM Class 1) are deemed to be system resources
then all states' programs should be treated consistently and be system allocated.
Neither Mr. Lanspery nor Mr. Yankel made this adjustment. Currently the
Company offers both a Cool Keeper air conditioning load control program and
irrigation load control program in Utah. The Utah Commission interprets DSM
Class 1 load control programs as State Resources under the Revised Protocol and
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assigns all costs and incentives of the Utah Cool Keeper and irrigation load
control programs situs to the state of Utah. In addition, the cost of any future
programs implemented in other states would necessarily be system allocated and
partially charged to Idaho ratepayers.
Are there other possible consequences if these costs are system-allocated?
Yes. The Company believes these proposals are a deviation from the Revised
Protocol and believes other states would agree with the Company. This would
likely raise questions about the allocation of all DSM, since arguably if Class
DSM is allocated as a system resource, then arguably all DSM should likewise be
allocated as a system resource. If deviation from the approved methodology is
needed, the issue is appropriately addressed in committees established for just this
purpose. Ms. Carlock mentions that other issues affecting states and cost
allocation are currently under consideration at the MSP Standing Committee and
workgroup. To respond to the allocation issues raised by Staff and the lIP A, the
Company recommends that the Commission order the parties to take this issue to
the Multi-State Process Standing Committee.
Product Valuation
What is the cost of the Idaho irrigation load control program?
The total cost of providing the irrigation load control program varies year to year
depending on participation, dispatch option selected, field and equipment costs.
The average total cost for the 2006 scheduled firm program was approximately
$27 per kilowatt-year, including all operational and administrative costs and an
$11.19 per kilowatt-year credit to participating customers. Because this general
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rate case is based on a historical test year, the credit to be recovered in rates is
based on the scheduled firm program costs from calendar year 2006 and is set at
$11.19 per kilowatt-year.
What's the value of the program to PacifiCorp?
The value that can best be ascribed to the scheduled firm program based on
current modeling available is $27 per kilowatt-year. The historical program cost
of $27 per kilowatt-year (incentive and delivery costs inclusive) was modeled
within the 2007 IRP against supply-side alternatives and was selected at this cost
as a least cost alternative within the IRP base case economics.
Is there a difference in value to the Company between the traditional
scheduled firm product and the new dispatch able product?
It is possible that there is; however, the Company has not yet finalized its analysis
that provides a value estimate for the pilot dispatchable program. As I will
describe later in my testimony, generic DSM programs with varying
characteristics and cost structures have been analyzed using the Company s IRP
models. A fully dispatchable summer product that had costs higher than those of
the Company s current scheduled firm program was accepted by the Company
IRP models.
Unfortunately, none ofthe modeled generic programs had the same
characteristics and constraints as the Company s new dispatchable program, and
as a result, the values derived from the studies cannot be directly ascribed to the
Company s program. In addition, the dispatchable program has higher initial
operational and administrative costs than the scheduled firm program, due mainly
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to the change over of required equipment. The Company is committed to fairly
valuing this program and is working to incorporate the results of the 2007 pilot
program into a study that will allow the Company, lIP A, and this Commission to
analyze the value of this program and set a price for the 2008 irrigation season.
Is Mr. Yankel correct that the recently released DSM potential assessment,
developed by Quantec, indicates that capacity-focused programs on the east
side of PacifiCorp s system would be cost effective if they cost less than $98
per kilowatt-year?
No. Mr. Yankel misrepresents the numbers from the Quantec potential
assessment study in his testimony. The Quantec study did not determine an
avoided cost for DSM programs. The $98 per kilowatt-year value referenced in
the study was a gross estimate for the purpose of an initial screen for Class
DSM programs, such that programs that exceeded that amount would not be
considered any further. It has no implication as to the value of the Idaho
irrigation load control program. The analysis was designed to have virtually no
chance of constraining what might be cost-effective in the study s results ahead of
the modeling of the products in PacifiCorp s next integrated resource plan update
or planning process. Further evidence of this fact is that the $98 per kilowatt-year
value was used to screen all Class 1 DSM programs, regardless of their hours of
availability, firmness, dispatch characteristics, size, and contractual firmness.
How was the $98 per kilowatt-year value derived?
During the 2007 integrated resource planning process, PacifiCorp had limited
information on demand-side management resource potentials and costs from
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which to derive comprehensive supply curves for demand-side resources. To
address this information gap while the demand-side potential assessment was
being completed, PacifiCorp commissioned Quantec to develop a generic sample
set of capacity program potentials and their costs for the purpose of modeling
them in a comparable manner to supply-side resources. The modeling of these
generic sample resources and the results were the basis for arriving at the $98 per
kilowatt-year screening values.
What generic sample capacity resource programs were modeled in the 2007
plan?
Five Class 1 generic sample load management products were modeled within the
2007 integrated resource plan. The generic sample products had varying dispatch
characteristics, hours of availability, assumed costs, and they varied in size. The
intent was to create specific supply curve data for each generic sample product
between control areas (east or west) and under different economic assumptions
regarding electricity prices. The five generic sample products modeled in the east
were:
. A fully dispatchable winter product that could be dispatched within 10
minutes or less and was available up to 87 hours annually. Program
costs ranged from $57-$83 per kilowatt-year.
A fully dispatchable summer product dispatchable within 10 minutes
or less and available up to 87 hours each season. Program costs
ranged from $52-$71 per kilowatt-year.
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. A fully dispatchable large commercial and industrial customer summer
product dispatchable within 10 minutes or less and available up to 87
hours each season. Program costs ranged from $82-$159 per kilowatt-
year.
. A scheduled firm irrigation product (no dispatch capabilities) available
336 hours each season. Program costs ranged from $27 to $36 per
kilowatt-year.
. A scheduled firm product (no dispatch capabilities) available 1 437
hours each season. Program costs ranged from $115 to $118 per
kilowatt-year (thermal energy storage).
For modeling purposes, each of these generic sample products were assumed to
be available on a firm basis over the entire planning horizon.
What generic sample resources were selected under the base case within the
2007 integrated resource plan modeling?
In the east under the base case assumptions the model accepted the fully
dispatchable summer product at an assumed cost of$71 per kilowatt-year, the
fully dispatchable commercial and industrial product at an assumed cost of $82
per kilowatt-year, and the scheduled firm irrigation product at an assumed cost of
$27 per kilowatt-year.
Does the dispatchable irrigation program provide the same value to the
Company as the dispatchable air conditioning program selected in the IRP?
No. It has less value to the Company since it offers fewer hours of interruption
and requires a full days notice rather than the 10 minute notice required under the
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air conditioning program and therefore can not be used to provide non-spinning
reserves.
Y 00 said that scheduled firm irrigation programs with costs ranging from
$27 to $36 per kilowatt-year were made available to the model, but only the
$27 per kilowatt-year programs were selected?
That is correct. The higher cost scheduled firm irrigation programs were not
selected in the high demand-side potential scenario under which it was modeled;
however, the $36 per kilowatt-year cost wasn t modeled within the base case set
of assumptions which were used in the development of the preferred portfolio.
How were these results used to arrive at the $98 per kilowatt value?
The Company factored in the results of the modeling selections to arrive at the
proxy value of $98 per kilowatt-year as the preliminary economic screen within
the study. The east side load management resources with certain dispatch
characteristics and hours of availability were accepted by the model in the base
case at a price of $82 per kilowatt-year (summer focused commercial and
industrial dispatchable product) but the next highest priced product (summer
focused thermal energy storage) was rejected at a price of$117 per kilowatt-year.
Ignoring the differences in dispatch characteristics and hours of availability, and
not having specific values for the products identified in the potential study, the
Company averaged the $82 and $117 to come up with the $98 per kilowatt-year.
Based on the understanding of how the $98 per kilowatt-year was derived and
what it was intended to be used for, it should be clear that Mr. Yankel'
characterization of the $98 per kilowatt-year as the Company s avoided cost for
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Idaho irrigation load control, or any other resource, is simply incorrect.
Are any of the values cited in the Quantec potential study applicable for
purposes of determining the amount of credit that should be provided to
customers under the Idaho irrigation load control program?
No. As mentioned above, the values determined by using the integrated resource
planning models were based on generic sample resources, and were intended for
use in screening and planning. Even if one were to assume that the resource
acquired under the Idaho irrigation load control were firm over the entire 20-year
planning horizon, the highest value that could be ascribed to the program is $27
per kilowatt-year based on the IRP studies. None of the other costs cited in the
Quantec study or in the Company s IRP are applicable to the Idaho irrigation load
control program.
Was the purpose of the Quantec potential study to determine the avoided
cost of DSM programs?
No. Mr. Yankel has quoted the primary goal ofthe Quantec study on page 21 of
his testimony. The goal of the study was to provide data to the Company on the
magnitude, timing and cost of DSM resources, inclusive of Class 1 , Class 2, Class
3 and Class 4. Nowhere does Quantec state that one of their goals is to determine
the avoided cost ofDSM programs, nor were they asked to do so.
Mr. Yankel bases much of his analysis on the comparison ofthe level of
program incentives and the size of the BP A credit passed on to the
Company s irrigation customers. Is this comparison appropriate?
No. The outcome of the BPA credit issue is uncertain. As described by Company
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witness Mr. A. Richard Walje, the Company is conscious of the impact of the
BP A credit on the irrigators and is doing all it can to restore a portion of this
benefit. A remedy based on artificially raising the irrigation load control credit
and then allocating it away from Idaho customers in violation of the Revised
Protocol is not the right solution. Following Mr. Yankel's proposal to its ultimate
conclusion would result in about a $16 million disallowance for shareholders if
other jurisdictions did not agree with this proposed treatment of the irrigation load
control credit, which could then lead to additional states deviating from the
guidelines that have been established in the Revised Protocol and the MSP work
groups. A more reasonable approach would be for the Commission to allow the
Company to complete its analysis regarding an appropriate level of incentive
credits and to order the parties to take the allocation issue up with the MSP
Standing Committee and report back to the Commission as recommended by the
Company.
Does this conclude your testimony?
Yes.
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