pace2.1rl.pdf

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Q. Please state your name and business address
for the record.
A. My name is Randy Lobb and my business
address is 472 West Washington Street, Boise, Idaho.
Q. By whom are you employed?
A. I am employed by the Idaho Public Utilities
Commission as Utilities Division Administrator.
Q. What is your educational and professional
background?
A. I received a Bachelor of Science Degree in
Agricultural Engineering from the University of Idaho in
1980 and worked for the Idaho Department of Water
Resources from June of 1980 to November of 1987. I
received my Idaho license as a registered professional
Civil Engineer in 1985 and began work at the Idaho Public
Utilities Commission in December of 1987. My duties at
the Commission currently include case management and
oversight of all technical staff assigned to Commission
filings. I have conducted analysis of utility rate
applications, rate design, tariff analysis and customer
petitions. I have testified in numerous proceedings
before the Commission including cases dealing with rate
structure, cost of service, power supply, line extensions
and facility acquisitions.
Q. What is the purpose of your testimony in this
CASE NO. PAC-E-02-1 R. LOBB (Di) 1
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case?
A. The purpose of my testimony is to describe the
provisions of the Stipulated Settlement presented to the
Commission in this case and attached as Staff Exhibit No.
101. I will also discuss the issues considered in
negotiating and developing the agreement and support
Staff’s recommendation for Settlement approval.
Q. Would you please summarize your testimony?
A. Yes. The tendered Stipulation is the end
result of comprehensive negotiations by the parties to
this case. The Stipulation incorporates implementation
of the BPA credit, reasonable recovery of extraordinary
power supply costs with mitigation, modified revenue
requirement across customer classes and changes in
irrigation rate design. The Settlement package
incorporates an extraordinary BPA credit agreement and
allows reasonable recovery of extraordinary power supply
costs. The Settlement utilizes a modified irrigation
class revenue requirement that more accurately reflects
cost of service to significantly reduce rate increases in
other classes that would otherwise occur due to power
supply cost recovery.
The Settlement negotiations focused on three
main areas: 1) power supply cost recovery amount, 2)
customer class revenue requirement, and 3) rate design.
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The primary issues addressed by the parties in the cost
recovery negotiations centered around those issues
identified by the Commission including the Idaho
jurisdictional revenue requirement, the merger condition
prohibiting a rate increase for two years, the Hunter
generating plant outage and the effect of wholesale sales
contracts and load growth on power supply costs. After
evaluation of these issues and numerous discussions with
all parties, Staff believes that a 65% recovery of the
deferred power supply costs is appropriate and fair to
both the Company and its Idaho customers.
The second phase of the negotiations dealt with
the determination of the appropriate annual revenue
requirement for each customer class. Staff believes that
the Settlement properly incorporates the previously
approved BPA credit and reasonably adjusts the irrigation
revenue requirement to better reflect cost of service.
More importantly, the Settlement effectively reduces the
impact of power supply cost recovery by applying a
revenue (rate) mitigation adjustment to various customer
classes and spreading recovery over two years. The net
change in annual revenue requirement (as compared to
2001) ranges between a 34% decrease in one customer class
to a maximum 4% increase in other classes.
Finally, Staff supports adjusting the energy
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component of rates in each class (where appropriate) to
reflect a combination of BPA credit, a power supply
surcharge and a rate mitigation adjustment. Staff
further supports modification of the rate structure in
the irrigation class to establish a single low cost firm
rate and a declining block energy rate for large
irrigators.
POWER SUPPLY COSTS
Q. What issues did Staff consider in evaluating
the Company’s request to recover deferred extraordinary
power supply costs?
A. Staff focused on four main issues in its
evaluation of the Company’s request. They included: 1)
a determination of the appropriate Idaho jurisdictional
power supply costs on a normalized basis; 2) an
evaluation and audit of Idaho jurisdictional power supply
costs during the deferral period; 3) the economic impact
and propriety of wholesale power sales contracts, and 4)
the economic impact and circumstances surrounding the
failure of the Hunter coal fire generating station.
Q. How did Staff determine what issues to address?
A. Staff issues were identified during its case
review and audit and established by the Commission in its
Notice of Issues and Scheduling in this case. The nature
of the extraordinary system power supply costs that the
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Company is seeking to recover and the methodology used to
allocate those costs to Idaho were main factors
considered when framing the issues. For example, higher
than normal power purchase costs and lower than normal
surplus sales comprised the vast majority of the
extraordinary system costs. Therefore, Staff focused on
resource availability and load obligations.
Resource availability was diminished by
abnormally low water conditions and the loss of the
Hunter generating plant. Replacement resources were
essentially limited to energy purchases from the market
at extraordinarily high prices. Load obligations
included normalized native load, growth in native load
and long-term firm wholesale sales contracts. Hunter
operation and the magnitude of wholesale sales are under
the direct control of the Company. During the audit,
these areas were identified as the main focus of Staff’s
investigation. Once the level of system costs was
established, methods used to allocate those costs to
Idaho were reviewed and compared to past practices to
assure consistency.
Q. Why didn’t Staff oppose recovery based on
Scottish Power/PacifiCorp Merger Approval Condition No. 2
that prohibited rate increases for two years?
A. Staff believed that the merger language was
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clear. It stated: “As a minimum, Scottish Power shall
not seek a general rate increase for its Idaho service
territory effective prior to January 1, 2002.”
Based on this language, Staff believed that
rates could increase after January 1, 2002. Staff
further understood as part of its participation in the
merger negotiations that rate stability through 2001 was
the objective of the condition and the use of costs
incurred during 2001 to establish rates after January 1,
2002, was not prohibited. Staff also considered the
extraordinary market conditions and the fact that
PacifiCorp does not control the market as a legitimate
reason for power cost deferral and recovery.
The Commission has subsequently issued Order
No. 28998 establishing that the merger condition does not
prohibit recovery of deferred power supply costs after
January 2, 2002.
Q. Based on its review of the main issues cited
above, what cost recovery adjustment did Staff believe
was justified prior to Settlement negotiations?
A. As a starting point to the negotiations, Staff
originally proposed that approximately $21 million in
deferred power supply costs be recovered from the Idaho
jurisdiction. This represents a reduction of about $17
million in the amount requested for recovery by the
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Company.
Q. What adjustments were specifically identified?
A. As shown on Staff Exhibit No. 102, Staff
adjustments specifically included a reduction in the base
jurisdictional allocation to Idaho of $3.2 million in
1998 net power costs consistent with previous Staff
recommendations in Case No. PAC-E-00-5. Staff also
maintained that interest of about $900,000 on the
deferral balance should be removed in addition to removal
of $600,000 to reflect the additional costs of normal
load growth included by the Company as an extraordinary
power supply cost.
Staff proposed that $1.5 million for two
wholesale power contracts be remove from the total
deferred power costs based on contract charges. Nine
other wholesale sales contracts signed after 1994 were
considered under priced. Consistent with prior audit
adjustments, one contract has 100% of the revenue imputed
for an adjustment of $400,000. Imputation of revenue for
the remaining contracts at the 1998 marginal cost of
service resulted in an adjustment of approximately $15.2
million. Staff believed that a 50% sharing of the
imputed revenue reflected a reasonable sharing of costs
and risk associated with the contracts. A 50% sharing of
the $1 million costs and risks associated with wheeling
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for non-native load contracts was also believed to be a
reasonable sharing of cost risk associated with
discretionary transactions.
Q. Did Staff propose any adjustment in cost
recovery associated with the outage at the Hunter coal
fired generating station?
A. Yes. Staff determined that the cost associated
with the Hunter outage represented approximately $11.9
million of the total $38.3 million in extraordinary power
supply costs requested for recovery by the Company.
Based on a review of expert testimony filed in other
jurisdictions regarding this issue, it is unclear exactly
what role, if any, maintenance schedules, monitoring
equipment and operating protocols had in the failure of
the Hunter generator. Based on its review, Staff
believed that the Company had some responsibility in the
failure and should share responsibility for a portion of
the extraordinary costs. Therefore, Staff proposed that
the Hunter cost recovery be reduced by 25% or $3 million.
Q. What costs were included in the Hunter outage
total?
A. The costs included were essentially the net
costs above and beyond what would have occurred had
Hunter operated normally. While fuel costs to operate
Hunter were obviously eliminated, the Company was forced
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to buy replacement energy from the market at a time when
prices were extraordinarily high. The costs do not
include the costs to repair the plant.
Q. What amount of extraordinary power supply
expense did the parties ultimately agree to?
A. The parties ultimately agreed to allow recovery
of $25 million in extraordinary power supply costs or
approximately 65% of the original request.
Q. How did Staff determine what adjustments to
propose and what level constituted a reasonable
settlement?
A. Staff reviewed filed testimony and orders
issued in other jurisdictions that dealt with wholesale
contracts and the Hunter outage. Staff also carefully
reviewed past Company filings and Staff recommendations
to establish a reasonable level of normalized power
supply costs allocated to Idaho. Staff then evaluated
the components of the deferred power supply costs to
identify what costs were extraordinary, to determine what
events caused the extraordinary costs and to establish
responsibility for cost recovery.
The determination of what constituted a
reasonable adjustment for each power supply issue and
what constituted a reasonable overall settlement was made
based primarily upon Staff’s evaluation of how successful
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it would be in presenting and defending its positions at
hearing. Discussing the merits of the various issues
with other parties to the negotiation and evaluating the
resources required to litigate in Idaho the same issues
already addressed in other jurisdiction also shaped
Staff’s position. Finally, Staff saw an opportunity to
significantly reduce the impact of power supply cost
recovery for customers by packaging the recovery with the
BPA credit and movement in irrigator revenue requirement
to more closely reflect cost of service.
Q. Does the Settlement specifically establish the
exact adjustment required for each issue?
A. No. The Settlement establishes an overall
adjustment to the Company’s request. The cost
responsibility for the Hunter outage or any of the other
issues was not specifically identified as part of the
Stipulation.
Q. Why were the remaining two years of the merger
credit accelerated and included in the Stipulated
Settlement?
A. The remaining two years of the merger credit,
valued at $2.3 million, was included to further reduce
the impact of power supply cost recovery and eliminate
the need for a rate increase when the merger credit
expires at the end of 2003.
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CASE NO. PAC-E-02-1 R. LOBB (Di) 11
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CLASS REVENUE REQUIREMENT
Q. Once an agreement was reached on a reasonable
level of power supply cost recovery, how did Staff and
the other parties establish an equitable spreading of
revenue requirement among the customer classes?
A. Staff’s objective was to create a package that
appropriately applied the BPA credit, equitably
distributed the power supply cost recovery responsibility
and ultimately moved the irrigation class closer to cost
of service. Most importantly, Staff’s objective was to
achieve this result with the smallest possible increase
in customer rates.
Q. Was Staff able to achieve its desired result?
A. Yes, we believe that we have. All of the
objectives were reasonably achieved and no customer class
received a rate increase greater than 4% over the two-
year period. While Staff does not wish to minimize the
impact of a 4% increase, we also recognize that rate
increases due to recent extraordinary events have been
much higher for many other electric customers throughout
the region. In addition, without the class rate
mitigation provided by the Stipulation, the rate impact
resulting from what we believe is reasonable power supply
cost recovery could have exceeded 17% for some customers
over a two-year period.

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Q. What do you mean by rate mitigation and how was
it achieved?
A. Rate mitigation is simply a credit used to
reduce the energy rate of a given customer class that
would otherwise experience a larger rate increase.
Increasing the revenue requirement assigned to the
irrigation class and distributing the savings to classes
that experience an increase during the power supply cost
recovery period provided rate mitigation. Rate
mitigation was also provided in year two to assure that
no customer class experiences any rate increase as
compared to the prior year.
Q. Why did you increase the revenue requirement
assigned to the irrigation class?
A. Based on the last cost of service study
approved by the Commission in 1990 and several cost of
service studies submitted since then including the one
submitted by the Company in this case, the irrigation
class has generated revenues significantly below that
required to cover cost of service. The result is a
subsidy of the irrigation class by other customer
classes. The extraordinarily large BPA credit provided a
valuable opportunity to modify the irrigation class
revenue requirement without increasing average irrigation
rates. Modifying the revenue requirement at this time
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reduces the subsidy, reduces the effect on irrigation
rates that would have occurred without the BPA credit and
provides an opportunity to provide rate mitigation to
reduce the effects on other classes of extraordinary
power supply cost recovery.
Because movement in class revenue requirement
must be revenue neutral outside of a general rate case,
the level of mitigation had to exactly equal the $4
million increase in irrigation revenue requirement.
After power supply costs are recovered in full, rate
mitigation will continue to reflect a continuation of
class revenue requirement that more closely reflects
costs of service.
Q. Does Staff agree with the cost of service study
submitted by the Company in this case?
A. No. Staff did not accept the specific details
of the cost of service study submitted by the Company and
required that the position be so stated in the
Stipulation. Staff did agree that an increase in
irrigation revenue requirement at this time represents a
reasonable step toward what will ultimately be accepted
as cost of service. Staff will evaluate specific cost of
service issues and make its recommendations to the
Commission in conjunction with Case No. PAC-E-01-19 (The
Monsanto/PacifiCorp Service Contract Case). The cost of
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service study ultimately approved by the Commission may
result in an irrigation class revenue requirement that is
different than that established in this case. The
Commission will decide at that time whether it is
necessary or appropriate to further modify irrigation
class revenue requirement.
Q. Why didn’t Staff support using the BPA credits
or an alternative spread of power supply cost recovery
among the classes to fully mitigate the rate increase?
A. BPA credits, as required by BPA rules, must go
only to qualifying customers. Therefore, the credit may
not be used to offset rate increases in other customer
classes. With respect to recovery of extraordinary power
supply costs, Staff believed that these costs were
incurred based on energy consumption and should be
recovered based on energy consumption. Any shifting of
responsibility for cost recovery from one class to
another would be inappropriate.
Q. After all of the revenue components are added,
what is the revenue requirement for each customer class
and how does it compare to the revenue requirement in
2001?
A. Staff Exhibit No. 103 shows the various revenue
components for each class and compares the revenue
requirement agreed to under the stipulation to last
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year’s revenue requirement.
RATE DESIGN
Q. What rate structure is recommended for the
various customer classes under the Stipulation?
A. The parties to the Stipulation agreed that rate
structure should remain unchanged for all classes except
the irrigation class. The proposal is to reflect the
change in revenue requirement for each class by modifying
the energy component of the rate either up or down as
necessary. Increasing the energy component was
determined by the parties to be most appropriate given
the nature of the extraordinary power supply costs
subject to recovery. These variable costs were incurred
based on energy consumption and are equitably recovered
based on energy consumption. BPA credits are already
provided on the basis of energy consumption and the rate
mitigation component had to be applied based on energy
consumption to be effective. Staff Exhibit No. 104 shows
the new energy rates recommended for the Residential,
General service and irrigation classes and a provides a
comparison to rates in 2001.
Q. What is recommended for the irrigation class?
A. The parties agreed to eliminate the separate A,
B and C firm and interruptible schedules in favor of a
single firm rate. The parties also agreed to modify the
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energy rate component from a two block, declining rate to
a three block, declining rate.
Q. Why was the interruptible rate eliminated for
irrigators?
A. Most of the irrigation customers currently take
service under Schedule C because it is the lowest price
of the three service schedules available. Therefore
these customers generate most of the revenue in the
class. However, irrigators indicated that significant
economic hardship was suffered in 2001 due to the
numerous interruptions that occurred. Consequently, the
Company and the parties agreed that a single non-
interruptible rate at a price previously offered for
interruptible service should be provided.
Q. Will irrigators be able to obtain further rate
discounts for interruptible service?
A. Some of the larger irrigation customers on a
case-by-case basis may be able to take interruptible
service for a discounted rate. The Company agreed to
discuss this type of service with irrigators that use
energy at levels not subject to the BPA credit.
Q. Why was the energy rate changed from a two-
tiered structure to a three-tiered structure?
A. The rate structure was modified to recognize
that the BPA credit is applied to a limited amount of
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CASE NO. PAC-E-02-1 R. LOBB (Di) 17
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energy consumed during a given month. Establishing a
third block at a lower price will help to mitigate rate
impacts that will occur for usage not eligible for a BPA
credit.
Q. Does that conclude your direct testimony in
this proceeding?
A. Yes, it does.