20030930Taylor Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATIER OF THE
INVESTIGATION OF INTER-
JURISDICTIONAL ISSUES
AFFECTING P ACIFICORP DBA
UTAH POWER & LIGHT CO.
CASE NO. P AC-O2-
DIRECT TESTIMONY
OF DA VID L. TAYLOR
SEPTEMBER 2003
Please State your name, business address and position with PacifiCorp ("the
Company.
My name is David L. Taylor. My business address is 825 NE Multnomah Street
Suite 800, Portland, Oregon 97232. I am employed by PacifiCorp as Director
Revenue Requirement and Cost of Service.
Qualifications
Please summarize your education and business experience.
I received a Bachelor of Science degree in Accounting from Weber State College
in 1979 and a M.A. from Brigham Young University in 1986. I have been
employed by PacifiCorp since the merger with Utah Power in 1989 ("Merger
Prior to the Merger I was employed by Utah Power, beginning in 1979. At the
Company I have worked in the Accounting, Budgeting, and Pricing and
Regulatory areas. From 1987 to the present I have held several supervision and
management positions in Pricing and Regulation.
Have you appeared as a witness in previous regulatory proceedings?
Yes. I have testified on numerous occasions in California, Idaho, Montana,
Oregon, Utah, Washington and Wyoming.
Purpose
What is the purpose of your direct testimony in these proceedings?
My direct testimony is in support of the Company s request that the Commission
ratify the PacifiCorp Inter-Jurisdictional Cost Allocation Protocol ("Protocol"
contained in Exhibit No.3. Appendix A to the protocol is a list of defined terms.
For purposes of greater clarity and consistency, when I capitalize terms in my
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direct testimony, and do not otherwise define them, it is intended that those terms
have the same meaning as provided for in Appendix A to the Protocol.
My direct testimony covers three areas. First, it provides the basis for the
allocation procedures used in the Company s proposed inter-jurisdictional cost
allocation method, which was identified as the "MSP Solution" in Ms. Kelly
direct testimony. This portion of my direct testimony discusses the classification
and allocation of generation and transmission costs, the treatment of non-tariff
Special Contracts and the treatment of the Hydro and Coal Endowments and
certain new baseload Resources.Second, my testimony considers the
implications of disproportionate load growth in one State on the revenue
requirements of other States. Finally, my testimony estimates the impact of the
MSP Solution on the overall revenue requirements in each State.
Allocation Procedures
Please summarize the procedures that the Company proposes to follow in
allocating the costs of generation Resources.
The allocation of a utility's costs employs a three-step process generally referred
to as "functionalization
, "
classification , and "allocation . The use of these three
steps recognizes the way a utility provides electrical service and attempts to
assign cost responsibility to the groups of customers for whom those costs were
incurred.
Functionalization, the process of separating expenses and rate base items
between the generation, transmission, and distribution functions, is generally not
at issue in MSP.
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Classification is the process of separating costs between those which are
Demand-Related, Energy-Related, or Customer-Related. Demand-Related costs
are the capital and other fixed costs incurred by the Company in order to be
prepared to meet the maximum Demand imposed on generating units
transmission lines, and distribution facilities. Energy-Related costs are costs
(such as fuel costs) that vary with the amount of Energy actually generated plus
any portion of Fixed Costs that have been classified as Energy-Related.
Customer-Related costs are those that are primarily driven by the number of
customers served.
Allocation is the process of assigning Demand, Energy, and Customer-
Related costs among States or customer groups. This is achieved by the use
allocation factors that specify each State s share of a particular cost driver such as
system peak demand, energy consumed, or number of customers. The appropriate
allocation factor determines each State s share of cost.
With the exceptions that I will describe later, the MSP Solution is an
integrated system methodology pursuant to which customer loads are deemed to
be served from a common Resource portfolio. The MSP Solution only deals with
the allocation of costs among States. The procedures for allocation of costs
among customer classes will continue to be determined independently by each
State.
How is your testimony concerning the allocation procedures relied upon in
the MSP Solution organized?
First, I will discuss the Company analysis and conclusions on general
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classification and allocation procedures.Then, I will detail the specific
classification and allocation procedures for each type of Resource identified in the
MSP Solution.
Classification of Generation Costs
Does the Company propose to continue to classify the majority of generation
fIXed costs and Wholesale Contracts as 75 percent Demand-Related and 25
percent Energy-Related?
Yes.With the exception of Simple-cycle Combustion Turbines (SCCTs),
PacifiCorp found no compelling reason to change from the currently employed 75
percent Demand / 25 percent Energy classification of generation fixed costs. We
also propose to continue the practice of allocating Energy-Related Costs based
upon energy usage. Commissions have generally found that these methods have a
reasonable basis in cost causation and changing them would have unwarranted
impacts on State revenue requirements.
discussion paper on the topic of Classification and Allocation of
Generation Fixed Costs is presented as Exhibit No. 12. The paper reviews some
of the classification and allocation history at PacifiCorp and its predecessor
companies. It also draws from the 1992 NARUC Electric Utility Cost Allocation
Manual which catalogues a number of classification methods commonly
employed by utilities.
It is not uncommon to classify all Fixed Costs as Demand-Related since
in general, system capacity must be sufficient to meet maximum demand and thus
costs are said not to vary with respect to energy output. On the other hand
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engineering analyses employing system reliability criteria in system planning
might reveal that the Fixed Costs of generation plant production are both Demand
and Energy-Related, as would analyses showing that peak demand should be met
with peaking plant while additional energy loads should be met with intermediate
and baseload plant. This is said to justify the inclusion of some portion of energy
in the allocation factor to be applied to production plant costs.
Exhibit No. 12 applied the methods discussed in the NARUC Manual
PacifiCorp s State peak and energy load data and produced a range of results.
Demand-Related production costs could vary from 100 percent, to a low end of27
percent using the "Average and Excess Demand" method. The Company also
surveyed a number of electric utilities serving in other states, finding wide
classification differences among them.
The choice of the 75 percent Demand/25 percent Energy classification for
generation and transmission plant was the final allocation decision made by the
PacifiCorp Inter-Jurisdictional Taskforce on Allocations ("PITA"after the
Merger. The PITA analysis also indicated that a wide range of demand and
energy classification methods could be supported on a technical basis. The
demand/energy classification was the means ultimately used to balance the
sharing of merger benefits among all the States. The 75 percent Demand/25
percent Energy classification method was selected because it produced an overall
cost allocation result that was acceptable to all the States.
Because no clearly superior demand/energy classification split has
emerged from analyses conducted during the Multi-State Process ("MSP"), and
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because the 75 percent Demand/25 percent Energy classification of generation
Fixed Costs currently used by PacifiCorp falls in the middle of the range
reasonable approaches, we propose to continue to use it for all System and
Regional Resources and most Seasonal Resources.System and Regional
Resources are primarily baseload plants and purchases. The Cholla Unit IV plant
which is identified as a Seasonal Resource, is also a baseload plant and will be
classified consistent with the System and Regional Resources.
However, PacifiCorp does propose to change the classification for Simple-
cycle Combustion Turbines to 100 percent Demand-Related.
Why does PacifiCorp propose to classify the cost of SCCTs differently from
the remainder of the Company s Resources?
SCCTs are typically peaking Resources that are used differently from base load
Resources, so it is reasonable to employ a classification method that better
matches how customers benefit from their use. One of the justifications for
classifying the fixed costs of base load plants as both Demand and Energy-Related
is to recognize their design capability to meet both peak demand and to generate
lower cost energy all hours of the day and during all seasons of the year. Because
SCCTs are designed and operated to run during peak-load periods, rather than
produce sustained, low cost energy, we propose to classify their Fixed Costs as
100 percent Demand-Related.
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Allocation of Generation Plant
How does the Company propose to allocate the Demand-Related component
of generation costs?
As with the issue of the demand/energy classification, the Company found no
compelling evidence to support a change from the current 12 Coincident Peak
12 CP") allocation factor for the demand component of System and Regional
Resources. We did, however, determine that certain Resources, identified as
Seasonal Resources " were acquired and dispatched to meet customer needs
during either the winter or summer periods. To match the cost of these Resources
with their use, costs are apportioned across the months of the year consistent with
their dispatch. I will discuss this in greater detail later in my testimony as I
review each Resource type.
How did the Company decide to use a 12 CP method to allocate the demand
component of System and Regional Resources?
Since the time of the Merger, PacifiCorp s Demand-Related Costs of generation
Resources have been allocated using the12 CP Factor, pursuant to which all
months of the year are deemed to play an equal role in Demand-Related cost
causation. To determine if a smaller subset of monthly peaks might form a better
basis for Demand-Related Cost allocation, PacifiCorp revisited the stress factor
analysis that was employed at the time of the Merger.
What is stress factor analysis?
Stress factor analysis is a tool used to identify particular months for inclusion in
the capacity allocation factor by examining, month by month, the key elements
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that stress the ability of the system to meet its peak load requirements and
therefore drive the need for investment in new capacity. PacifiCorp examined
monthly historical and forecast data for three specific stress factors: a) monthly
retail peak demand, b) probability of loads in any hour to contribute to the system
peak, and c) the cost to bring the reserve margin to 15 percent.
Please briefly explain the basis for each of these stress factors and how it is
calculated.
Monthly retail peak, also referred to as the monthly Coincident Peak, is one of the
most common stress factors. It is the simplest to calculate and perhaps the easiest
to understand.It is single highest combined demand measurement of all
PacifiCorp retail customers during each month. The Company needs enough
available generating capacity to meet this level of load. Months with higher peak
loads are viewed to place more stress on the system than months with lower peak
loads.
The probability of contribution to the system peak indicates the number of
hours in each month with loads that exceed a threshold demand level.The
criterion for our analysis was the average available energy from PacifiCorp
owned and long-term purchased resources divided by the maximum peak capacity
of those same resources, or approximately 83%. If the load in any hour of the
year exceeds 83% of the annual system peak it is considered to contribute to the
system peak. Months where more hours contribute to the system peak are
considered to place more stress on the system than months where fewer hours
contribute to the peak.
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The cost to bring the reserve margin to 15 percent identifies months where
the Company s owned plus long-term purchased resources are insufficient to meet
the reserve adjusted peak load and captures the magnitude of that shortfall.
Months where the cost to achieve the reserve margin is greater are considered to
be more stressful on the system than months where the cost is less, or even zero.
The cost is calculated by subtracting the available generating capacity from the
reserve adjusted monthly peak load, or peak load plus 15 percent. When this
value is positive, it is multiplied by the monthly cost of capacity. For our
purposes, the monthly capacity cost of a simple cycle combustion turbine was
used.
What did the stress factor analysis indicate?
To enable a common comparison between the three stress factors and to make
comparisons between months of a given year and between different years several
techniques were used. A method, termed "rationalizing , where the peak demand
or other measured value, of a given month is stated as a percentage of the
maximum measurement for the year, seemed to be the favored approach.
Exhibit No. 13 summarizes the results of the stress factor analysis for the
forecast years 2004 through 2008. The monthly-rationalized percents for each
stress factor are shown in columns (A) through (C). Column (D) shows the
simple average of the three factors and column (E) shows a weighted average
with the monthly peak value given double weight.
As shown in column (A), the monthly retail peak is generally the greatest
in July or August. The peaks for all months of the year, however, are within 80
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percent of the annual peak with eight months of the year, June through September
and November through February, within 90 percent of the annual peak. Only the
April peak is less than 85 percent of the annual peak.
The probability of contribution to system peak summarized in column (B).
While the probability of summer hours contributing to the peak is the greatest, the
analysis also shows strong probabilities during the winter months.It also
suggests that, with the exception of April, there are hours in all months of the year
that contribute to the system peak.
The analysis summarized in column (C) indicates that the cost to bring
reserve margin to 15 percent is again greater in the summer with the winter costs
only about half of that in the summer.
The stress factor analyses suggest that winter and summer loads may be
more significant Demand-Related cost drivers than spring and fall loads. We
have addressed this by segregating Seasonal Resources from other Resources.
mentioned earlier, and as will be discussed in greater detail later in my testimony,
the costs of Seasonal Resources will be assigned to the months those Resources
are dispatched to meet retail load. The seasonal weighting will assign a larger
portion of the Demand-Related costs to the summer and winter months. With this
adjustment for Seasonal Resources, the continued use of the 12 CP Factor for the
remaining Resources appears even more reasonable.
How does the 12 CP Factor work?
The 12 CP Factor determines the proportional share of annual Demand-Related
costs that are allocated to each State. For each month of the year, the Coincident
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Peak, or the hour during which the combined demand of all PacifiCorp retail
customers is the greatest, is identified. For that hour, each State s contribution to
the Coincident Peak, the combined demand of all retail customers in that State, is
measured in megawatts. Each State s contributions to the twelve monthly system
peaks are summed to establish the State s 12 CP measurement. The 12 CP Factor
is calculated by dividing each State s 12 CP by the sum of the twelve monthly
total system Coincident Peaks, or in the case of Regional Resources by the
aggregate sum of the twelve monthly Coincident Peaks of the participating States.
How is the process different for Seasonal Resources?
For Seasonal Resources, the process is very similar. The only difference is that
prior to summing the twelve monthly Coincident Peaks, each monthly
measurement is weighted by the monthly portion of the total annual energy
generated by the Seasonal Resource. For example, if 30 percent of the annual
generation of a particular Seasonal Resource occurs in July, the monthly
Coincident Peak for July would be weighted by 30 percent in the calculation of
the allocation factor. This, in essence, allocates 30 percent of the Demand-
Related Cost for that Resource among States based upon their contribution to the
July Coincident Peak.
Why does PacifiCorp propose to allocate the cost of Seasonal Resources
differently from the remainder of its Resources?
Seasonal Resources are designed to be used more intensively at certain times of
year. The proposed allocation method captures this aspect of cost causation. The
weighted CP method allocates the costs of Seasonal Resources more heavily to
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States that contribute most to system peaks in months in which the Resource
operates.
How is the hour of system peak for each month determined?
In the case of an historical test period, the hour of system peak is based on
metered load data. For each hour of the month, all inputs into the system such as
Company owned generation, purchases or interchanges are measured. From that
measurement, all deliveries outside the system or to non-retail customers are
deducted to arrive at total retail load. The Coincident Peak is the hour of each
month during which the combined demand of all retail customers is the greatest.
Each State s contribution to hourly loads is determined in essentially the
same way. Each State s hourly load consists of the Company owned generation
within that State, purchases or interchanges delivered into the State, plus metered
flows of energy into the State from other parts of the PacifiCorp system. From
that measurement, metered energy flows out of the State and deliveries to non-
retail customers are deducted to arrive at that State s retail load.
In the case of a forecast test period, the system Coincident Peak and each
State s contribution to that peak are forecasted along with retail Energy usage.
Allocation of Energy Costs
How does the Company propose to allocate fuel and other Energy-Related
costs?
For System and Regional Resources, fuel and other Energy-Related Costs are
allocated using each participating State s share of annual system energy usage.
For each type of Seasonal Resource, other than Seasonal Contracts, Energy-
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Related Costs are allocated using weighted monthly energy usage. Similar to the
weighting of Demand-Related costs, each State s monthly energy usage
weighted by that month's portion of annual energy generation for the particular
Resource. The annual fuel costs for that Resource are then allocated using its
seasonally weighted energy factor.
Cost Allocation for Regional Resources
Are the costs of Regional Resources allocated differently than the costs of
System Resources?
Yes. Regional Resources consist of: a) the Hydro Endowment, b) the Coal
Endowment, and c) the First Major New Coal Resource. Costs of Regional
Resources are, in the first instance, assigned to fewer than all States, depending
upon the nature of the Regional Resource. Once this assignment is made, costs
are allocated among the assigned States using the same methods that apply to
System Resources.
Hydro-Electric Resources
Please explain how the costs of Hydro-Electric Resources are assigned and
allocated.
The MSP Solution assigns the existing and future investment and operating costs
of Hydro-Electric Resources, including those associated with relicensing, to the
former Pacific Power States.Participating States are then allocated their
proportional share of the Hydro-Electric Resource costs using the Divisional 75
percent 12 CP / 25 percent annual Energy allocation method, or DGP (Divisional
Generation - Pacific) factor. The DGP factor is calculated using the classification
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and allocation procedures described above for System and Regional Resources.
However, because this is a Regional Resource, only the loads of the former
Pacific Power States are included in calculating the allocation factors.
Huntington Resource
Please explain how the costs of the Huntington Resource are assigned and
allocated.
The MSP Solution assigns the existing and future investment and operating costs
of the Huntington Resource, including those associated with clean air initiatives
to the former Utah Power States. Participating States are then allocated their
proportional share of the Huntington Resource Fixed Costs using the Divisional
75 percent 12 CP / 25 percent annual Energy allocation method, or DGU
(Divisional Generation - Utah) factor. The DGU factor is calculated using the
classification and allocation procedures described above for System and Regional
Resources. However, because this is a Regional Resource, only the loads for the
former Utah Power States are included in calculating the allocation factors. The
former Utah Power States are also allocated their proportional share of the
Huntington Resource Energy-Related Costs using the Divisional Energy, or DEU
(Divisional Energy - Utah) factor.
First New Major Coal Resource
How does the proposal to permit Oregon to "opt-out" of the First New Major
Coal Resource affect the allocation of generation costs?
If the Oregon Commission elects this option, costs of the First New Major Coal
Resource would be assigned to the remaining States. The costs of the Resource
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would then be allocated among those remaining States using the classification and
allocation procedures described above for System Resources. Fixed costs will be
classified as 75 percent Demand--Related and 25 percent Energy--Related with
the demand component allocated using the 12 CP Factor. Energy costs will be
allocated using the Annual Energy Factor.
Also, should Oregon choose not to participate in the First New Major Coal
Resource, an alternate baseload Resource of equivalent vintage and size to
Oregon s proportional share of the coal Resource would be assigned to Oregon in
its place. Otherwise, Oregon would be avoiding the cost associated with a new
undepreciated Resource and replacing it with a disproportionate share of lower-
cost resources from the largely depreciated embedded portfolio (which consists
largely of coal-fired Resources). Assigning Oregon the cost of an alternate non-
coal-fired matching Resource matches more closely the economic effects of
Oregon s policy decision.
Should Oregon choose not to opt out of participation in the First Major
New Coal Resource, costs of the Resource would be treated as a System
Resource.
Cost Allocation for Seasonal Resources
Are the costs of Seasonal Resources allocated differently than the costs
System Resources?
Yes.Somewhat different procedures are used for simple-cycle combustion
turbines, Seasonal Contracts and the costs of Cholla Unit IV.
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Simple Cycle Combustion Turbines
How does the Company propose to classify and allocate the costs of Simple.-
Cycle Combustion Turbines?
As described earlier in my testimony, the fixed costs of SCCTs are classified as
100 percent Demand-Related. Both the Demand-Related and Energy-Related
Costs are then assigned to the individual months of the year on the proportional
basis of the annual dispatch hours for the given month in which those resources
are dispatched to meet retail load. Mr. Duvall describes how these values are
determined.. The aggregate Demand-Related Costs of the turbines are allocated
to States using the Simple-Cycle Combustion Turbine dispatch weighted 12 CP
(Seasonal System Capacity Combustion Turbine or SSCCT) allocation factor and
the Energy-Related Costs are allocated using the Simple-cycle Combustion
Turbine dispatch weighted Energy (Seasonal System Energy Combustion Turbine
or SSECT) allocation factor. This process was described earlier in my testimony.
Because existing SCCTs are dispatched more heavily during the summer
months, the majority of their costs are allocated using summer loads.
Seasonal Contracts
Does Pacificorp propose to allocate the cost of Seasonal Contracts in the
same way as SCCTs?
Generally, yes. As with the Simple-Cycle Combustion Turbines, the cost of
Seasonal Contracts will be allocated on a weighted monthly basis according to
their monthly delivered megawatt h9urs. Because some of the contracts do not
have explicit Demand and Energy components, however, the entire contracts will
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be classified as 75 percent Demand and 25 percent Energy-Related and allocated
to States using the seasonally weighted (Seasonal System Generation Purchases or
SSGP) allocation factor.
Cholla Unit IV
Are there any other Resources that are more heavily used in one season of
the year?
Yes. The Cholla plant is considered a winter Seasonal Resource. Although the
Cholla Unit IV is operated all year except for times of required maintenance, a
substantial portion of the summer output is delivered to Arizona Pubic Service
Company ("APS") and an equivalent amount of capacity and energy is returned to
PacifiCorp during the winter months.
How are the costs of the Cholla Unit IV to be allocated under the MSP
Solution?
The costs of the Cholla plant are allocated using a similar monthly weighting
methodology as used for SCCTs with an adjustment for the megawatt hours
delivered to and received from APS. Both the demand and energy components of
plant costs are assigned to months on the basis of monthly megawatt hours
dispatched from Cholla plus megawatt hours received from APS less megawatt
hours delivered to APS. This assigns the majority of the Cholla costs to five
winter months, October through February.
Because Cholla is a baseload plant, fixed costs are classified as 75 percent
Demand/25 percent Energy. The Fixed Costs are allocated using the Seasonal
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System Generation Cholla (SSGCH) allocation factor and fuel costs are allocated
using the Seasonal System Energy Cholla (SSECH) allocation factor.
System Resources
What is the allocation procedure for the remaining System Resources?
The Fixed Costs of System Resources are allocated using the 75 percent Demand
25 percent Energy 12 CP (System Generation or SG) allocation factor. Variable
Costs for System Resources are allocated using the Annual Energy (System
Energy or SG) allocation factor. The basis for these allocation factors and a
description of how they are calculated were discussed earlier in my testimony.
Transmission Costs
How does the MSP Solution propose to classify and allocate transmission
costs?
Costs associated with transmission assets and firm wheeling expense are
classified as 75 percent Demand/25 percent Energy-Related and allocated using
the SG allocation factor. Non-firm wheeling expense and revenues are classified
as Energy-Related and allocated among the States based upon the SE Factor.
Would this allocation change with the implementation of an RTO?
In the future, should PacifiCorp become a participant in an RTO, charges from
the RTO will be allocated among the States based upon the same billing
determinants relied upon by the FERC in setting the RTO's rates.
What would be the revenue requirement allocation implication of FERC
requires that certain current transmission assets be refunctionalized?
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Those that are refunctionalized as generation assets will be allocated consistent
with the allocation of the fixed costs of the Resource with which they are
associated. Those refunctionalized as distribution assets will be direct assigned to
the State where they are physically located.
Distribution Costs
Does the MSP Solution propose any change to the allocation of distribution
costs?
No.Distribution costs are all directly assigned to individual States and no
jurisdictional allocation is required.
Administrative and General (A&G) Costs
With the change in the allocation of some of the generation plant costs, have
you looked at the impact that these new allocation procedures have on the
sharing of A&G and other infrastructure costs?
Yes, and the impacts appear to be minimal. Historically PacifiCorp has allocated
the bulk of A&G expenses, the costs of General Plant and Intangible Plant, and
other common costs using a System Overhead (SO) factor. The SO factor is
calculated using each State s proportional share of allocated and assigned plant
investment. With a change in the allocation for some of the generation assets
there will be a corresponding shift in the allocation of these common costs.
test whether that shift was significant enough to warrant development of a new
allocation procedure, the Company compared the allocation of all costs using the
SO factor under the proposed method with the allocation of those same costs
under the rolled-in allocation method. The impact of the change in the SO factor
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was approximately plus or minus one percent of system overhead costs and less
than 0.15 percent of total State revenue requirements. We did not consider this
impact to be large enough to warrant a change in methodology for the allocation
of system overhead costs.
Special Contracts
What is the Company s proposal regarding the treatment of Special
Contracts?
As described in the direct testimony of Ms. Kelly, the Company proposes that if a
Commission makes a decision for reasons of local or State interest that increases
costs to customers in other States, the costs of the decision should be borne
entirely within the State making the decision. As applied to Special Contracts, the
cost of serving contract customer loads, and their State approved retail service
revenues, will be included in the local State s revenue requirement on the same
basis as would apply to the cost of serving any other retail customer. Any
payments made (or discounts provided) for the Customer Ancillary Service
Contract attributes, such as operating reserves, system integrity interruption, or
economic curtailment, will be treated as a Resource acquisition by the Company
and included as a purchased power costs allocated among all States. If a buy-
through option is provided with economic curtailment, both the cost and the
revenue associated with the buy- through will be assigned situs to the host
jurisdiction.This removes the effect of the buy-through from non-host
jurisdictions and from all other customers in the host jurisdiction.
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As with the establishment of retail tariff prices, the Commission with
jurisdiction over a Special Contract will, within the context of the State revenue
requirement, have authority to establish the retail service price for the contract.
This includes the application of State-specific public policy preferences that may
allow Commissions to consider other issues, in addition to costs, when setting
retail prices.
Exhibit No. 14 shows an example of the impact of the proposed treatment
of Special Contracts on State revenue requirements. This example assumes a
three-jurisdiction system. Jurisdictions two and three each have Special Contracts
and Jurisdiction one does not. Jurisdictional loads and potential resources are
shown on lines 1 through 6. Allocation factors based on total State loads are
shown on lines 8 through 11. The "No Ancillary Service Contracts" example
lines 16 through 23 show the resource cost of service and associated revenues
assuming no ancillary services are acquired from the two Special Contracts. The
second example, lines 28 through 48 show the resource cost of service and
associated revenues assuming there are ancillary service components to each
the contracts.
In the "With Ancillary Service Contracts" example, Contract A has retail
service revenue of $40 million and receives a $4 million discount for providing
100 MW of operating reserves. Contract B has retail service revenue of $20
million and receives a $3 million discount for allowing 75 MW of economic
curtailment for up to 500 hours per year.
The $4 million discount, or payment, for reserves is identified as a
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Resource acquisition and is shown on line 41 as part of the cost of service.
Likewise the $3 million discount, or payment, for economic curtailment is also
identified as a Resource acquisition and shown on lines 42 and 43. Because these
Resources are obtained from the two customers rather than other sources, the
Energy-Related and Demand-Related costs, shown on lines 39 and 40, are $7
million less than in the first example, lines 17 and 18, where there were no
ancillary services contracts. Comparing line 19 with line 44, total cost of service
both total system and by jurisdiction, are equal whether or not the ancillary
services are acquired from the contract customers.
As with total cost of service, jurisdictional revenues are also unchanged.
The $40 million associated Contract A and the $20 million associated with
Contract B continue to be identified as jurisdictional revenues and the revenues to
be collected from all other customers, as shown on lines 23 and 48, remain
unchanged.
Load Growth
You testified that the MSP Solution allocates costs dynamically and, with the
exceptions identified above, all States share in the cost of new Resources.
Does this provision cause slow-growing States to subsidize fast-growing
States?
As Mr. Duvall has testified, we do not believe this occurs to a material degree.
During the MSP, PacifiCorp prepared an example that identified the implications
of disproportionate load growth in one State and the Resources added to meet that
growth. In the example, Utah's load was increased an additional 200 MW above
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the MSP forecast starting in 2010. Concurrently a 200 MW combined cycle gas
plant was added to meet the additional load. Exhibit No. 15 shows the revenue
requirement impacts of meeting the additional 200 MW. In this example, Utah
picks up 94 percent in the total revenue requirement increase. While the example
shows an impact of the other States, that impact was minimal.
Why aren t more of the costs of the additional Resource passed on to other
States?
While all States pick up their proportional share of the higher than system average
costs of the new additional Resource, Utah, the faster growing State in this
example, picks up a larger share of all other allocated costs. As a result of its now
larger allocation factors, Utah picks up a larger share of the costs of the remaining
generation Resources, a larger share of the system s transmission costs, a larger
share of A&G expenses and all other allocated costs.
Revenue Requirement Impacts
Have you prepared an exhibit showing the impact of the MSP Solution on
revenue requirements?
Yes. Exhibit No. 16 presents estimates of impacts of the MSP Solution on each
State s revenue requirement. Estimated MSP Solution revenue requirements for
California, Oregon, Washington, and Wyoming are compared to the Modified
Accord methodology. Estimated MSP Solution revenue requirements for Idaho
and Utah are compared to the Rolled-In methodology.A positive percent
indicates the States revenue requirement for a given year under the MSP Solution
is higher and a negative percent indicates the revenue requirement under the MSP
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PacifiCorp
Solution is lower. The year-by-year revenue requirement impacts are shown for
the period 2005 thorough 2018 as well as the Net Present Value of the difference
in revenue requirements over the 14-year period. For each State, the percent
change in revenue requirement associated with the Hydro and Coal Endowments
is shown first followed by the impact of the full MSP Solution.
What do you conclude from Exhibit No.16?
I conclude that the revenue requirement impacts are within an acceptable range.
The Net Present Value of the change in revenue requirement over the 14-year
period is less than one percent for every State and single year impacts never
exceed plus or minus 2.5 percent. While the MSP Solution produces somewhat
lower revenue requirements for California, Oregon, Washington, and Wyoming in
the early years, the trend reverses and those States see larger revenue
requirements in the later years. The higher MSP Solution revenue requirements
seen by Utah and Idaho in the early years are offset by lower revenue
requirements in the later years.
Have you prepared an exhibit that identifies how all cost components of the
revenue requirement are allocated among States?
Yes.Exhibit No. 17, which is Appendix B of the Protocol, identifies the
allocation factor applied to each component of the revenue requirement
calculation. Exhibit No. 18, which is Appendix C of the Protocol, gives a detailed
explanation and the algebraic formula for each allocation factor.
Does this conclude your Direct Testimony?
Yes.
Taylor, Di - 24
PacifiCorp