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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF P ACIFICORP
FOR A VOIDED COST
METHODOLOGY FOR QUALIFYING
FACILITIES LARGER THAN 1 MW
Case No. IPC-95-
Direct Testimony
Laren Hale
On Behalf of PacifiCorp
June 14 , 1996
Q. Please state your name, business address and present position
with PacifiCorp dba Utah Power & Light Company (PacifiCorp or
the Company).
A. My name is Laren Hale, my business address is 825 NW
Multnomah, Suite 625, Portland, Oregon 97232, and my present
position is Senior Power Planner.
Qualifications
Q. Briefly describe your education and business experience.
A. I received an undergraduate degree in Business Finance and a
Masters of Business Administration from the University of Utah.
I began working for Utah Power & Light Company in 1979.
During my 17 years with the Company I have held a variety of
positions including Senior Cost of Service Analyst, Senior Pricing
Analyst and Marketing Specialist. I assumed my current position
in April of 1993.
Q. Please describe your current duties.
A. I am part of a team that prepares the Company s integrated
resource plan (IRP). The Company s IRP is called Resource and
Market Planning Program (RAMPP). The Company filed its
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Laren Hale - Di
PacifiCorp
fourth RAMPP report (RAMPP-4) with the Idaho Public Utilities
Commission and other commissions in November, 1995. My
specific duties include developing computer models of
PacifiCorp s service territory including customer loads
transmission constraints, and existing and potential resources to
serve customer needs.
Q. What is the purpose of your testimony?
A. The purpose of my testimony is to discuss the method developed
by the Company to calculate IRP-based avoided costs. In
addition I will discuss the updates that have been made to the
RAMPP-4 computer model to bring the model current with
existing market conditions.
Q. Would you describe the computer model that is used to calculate
avoided costs.
A. The Integrated Planning Model (IPM) is a capacity expansion
linear programming model that selects future resources and
dispatches all resources to minimize the present value of total
resource costs. The model uses a 20-year planning horizon. An
additional 30 years is also studied to incorporate the impact of
end effects when selecting new resources. The additional 30
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Laren Hale - Di
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years is included to recognize the financial benefits of
investments made in the last few years of the planning period.
Q. Was the IPM model used in the Company s most recent IRP
process?
A. Yes. The Company licensed the IPM model in 1993 and has used
it in the last two RAMPPs. However, the inputs used by the IPM
model have been updated since the completion of RAMPP-
Updates to the RAMPP-4 Model
Q. Would you describe the updates that have been made to the
RAMPP-4 model since the completion of RAMPP-
A. The updates are summarized in Exhibit 303 (LJH-
Q. Please describe Exhibit 303 (LJH-l).
A. The exhibit was prepared to demonstrate the changes that were
necessary to update the RAMPP-4 model for use in the avoided
cost study.
The exhibit has six columns. The second column describes the
necessary update.The third and fourth columns identify the
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Laren Hale - Di
PacifiCorp
difference between RAMPP-4 and the avoided cost treatment.
The fifth column identifies whether the update was mentioned in
RAMPP-4 as an area that had changed since the inputs into
RAMPP-4 had been established in early 1995. The RAMPP-
report included a section in the Inputs Chapter called uRevisions
to Inputs." This section reviewed known changes in input
assumptions since the inputs were frozen for modeling purposes
in early 1995. The sixth column provides useful information
about the necessary change.
Q. Were these updates made in accordance with the settlement
stipulation in this case?
A. Yes. All of the changes fall into one or more of the following
categories:
(1) the changes were discussed as part of the settlement
stipula tion
(2) the changes were needed to permit an IRP model to
calculate avoided costs, or
(3) the changes were specifically discussed in RAMPP-4 as an
update to the inputs.
Q. Would you describe Exhibit 304 (LJH-
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A. Exhibit 304 (LJH-2) is comprised of pages 100 to 105 taken from
the RAMPP-4 report, the uRevisions to Inputs" section of the
Inputs Chapter. These pages discuss the changes that were
known to have occurred since the RAMPP-4 inputs were frozen
in early 1995. Most of the updates made to the RAMPP-4 model
are described in these pages.
Q. Why weren t these known changes included in the RAMPP-
model?
A. The RAMPP process progresses in stages. First, model inputs are
determined, then model runs are developed, followed by analysis
of the model runs. The inputs need to be frozen in order to have a
consistent database through the completion of model analysis.
Q. The first change described in Exhibit 303 (LJH-l) is the number of
run years. Why was this change necessary?
A. To keep model run times manageable, the Company required the
model to select new resources for only 14 of the years in the 50-
year period. The 14 years are called run years. In between run
years, the model interpolates results to approximate the impact of
resource selection. In the avoided cost study, the Company
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determined that the level of detail provided by only 14 run years
was not sufficient. To calculate avoided costs using the IPM
model, the Company included 25 run years, one run year for each
of the first 21 years, then 4 run years during the 30 end effect
years.
Q. If a QF wanted a twenty year contract to start in 1997 rather than
1996, would the model still require 25 run years?
A. No. The model would require 26 run years, 1996, the twenty
years of the QF's contract 1997 to 2016, the year after the contract
expires 2017, and four run years to calculate the end effects.
Corresponding extensions would be required for any QF with an
on-line year after 1996. Since the RAMPP-4 study period ends in
2015, the model would require extensive modeling revisions to
extend the study years into the end effect years. These revisions
are difficult and complicated to prepare. The Company will make
its best effort to respond to a QF request in the 30 day period
discussed in the settlement document in this case.
Q. The second item in Exhibit 303 (LJH-l) is the reduction of reserve
margin from 12% to 100/0. Why was this change needed?
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A. 10% is consistent with the planning reserve margins the Company
intends to use in RAMPP-
Planning reserve margins have declined since the 1980s when
planning reserve margins were typically 20%. This decline is due
to reduced construction lead time for supply-side resources
reduced rate of customer load growth, greater availability of low
cost resources in the market place and ample surpluses available
in WSCC.
Q. Item 3 of Exhibit 303 (LJH-l) states that DSM resources could be
selected but DSM amounts have been locked for the avoided cost
filing. Why was this done?
A. As part of the RAMPP process, representatives from various state
commissions, agencies, intervenors and the Company discussed
the appropriate DSM acquisition levels. The Company has
committed to achieve 23 MWa of installed cost-effective savings
by 1996; 25 MWa by 1997; and 28 MWa by 1998 as part of the
RAMPP-4 action plan. Since the Company has committed to
these DSM acquisitions, we do not feel it is correct to allow the
model to select different DSM levels.
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Q. The fourth item in Exhibit 303 (LJH-l) is Hermiston. Wasn
Hermiston included in the RAMPP-4 modeling?
A. Yes, Hermiston was included in RAMPP-4 modeling. In RAMPP-
4 the Company assumed that Hermiston would not be completed
in time for the Summer 1996 season. Current estimates are that
Hermiston will be available for the Summer 1996 season and
therefore should be included in the 1996 resources.
Hermiston is expected to go commercial on July 1 of this year.
Hermiston began generating on March 31; April generation was
554 MWH, May was 69 662 MWH, and June is expected to be
105,000 MWH.
Q. The fifth, sixth and seventh items in Exhibit 303 (LJH-l) relate to
natural gas. Are these the same prices discussed in Exhibit 304
(LJH-2) and on page 103 of RAMPP-
A. Yes. For RAMPP-4 the Company used the medium escalation
rate. Since then, gas prices have declined. Therefore, for the
avoided cost analysis work the Company used the low escalation
rate and price discussed in RAMPP-
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Q. Items eight and nine of Exhibit 303 (LJH-l) relate to non-firm
wholesale power prices and price escalation rates. Would you
describe these changes.
A. Wholesale power prices have declined significantly from the
levels used in RAMPP-4 and have declined even more than the
mills/kWh on-peak / 14 mills/kWh off-peak that was described
in Exhibit 304 (LJH-2). The Company s wholesale marketing
department has provided updated prices. The Company
determined three index prices, namely a COB (California Oregon
Border), Mid-Columbia and a Palo Verde price. The prices in
mills/kWh are for an annual average delivery, based upon
months of future index values and provide for peak and off peak
deliveries.
One year Wholesale Spot Power Prices
RAMPP -Current Prices
On-peak Off-peak On-peak Off-peak
COB 19.16.12.10.
Mid Columbia 19.16.12.
Palo Verde 19.16.13.8.3
As mentioned above, the Company has selected the low gas price
escalation rate as an estimate of future gas price escalation. As in
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RAMPP-, the Company escalated wholesale market prices at
80% of the natural gas price escalation rate.
Q. Items ten and eleven of Exhibit 303 (LJH-l) relate to existing
purchases and sales. Please describe these updates.
A. Since the inputs into RAMPP-4 were frozen in early 1995, the
Company has entered into one new wholesale purchase, two
seasonal exchanges and six new wholesale sales. For computer
modeling purposes, each seasonal exchange requires a purchase
to model the energy taken and a sale to model the energy
delivered to the customer. Thus the IPM model has three new
purchases and eight new sales since the RAMPP-4 inputs were
frozen.
Two new purchases and seven new sales are discussed in Exhibit
304 (LJH-2). The third new purchase and the eighth new sale
occurred because of a seasonal exchange with Black Hills which
occurred after RAMPP-4 went to press.
An additional purchase has been added titled the Avoided Cost
Unit.' The Avoided Cost Unit is the zero cost purchase used to
calculate avoided costs. The size and delivery characteristics will
vary with each QF project to be modeled.
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In addition to the introduction of new purchases and sales, the
Company has updated known changes to existing contracts. For
example, the Company has notified BP A of our intent to reduce
purchases under the BP A Peaking contract. The BP A Peaking
purchase was reduced by 175 MW in the year 2000 consistent
with this change.
Q. Item 12 of Exhibit 303 (LJH-l) relates to a potential market
purchase. Is this an update of a resource in RAMPP-
A. Yes. The Company included a capacity purchase from the
wholesale market in the RAMPP-4 portfolio of new resources. In
RAMPP-, the Market Purchase was priced like a simple cycle CT
available at simple cycle fuel prices and with the natural gas fuel
price escalation rate. In the avoided cost analysis, the Market
Purchase has the same market price and price escalation rate as
all of the other wholesale market short-term purchases. During
the period 2003 to 2015, the model's selection of the Market
Purchase has been constrained such that it represents no more
than 50% of the total new supply side resources selected.
Q. There are three other updates mentioned in your Exhibit 303
(LJH-l). Please explain each update.
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A. Item thirteen was the Arizona Public Service (APS) Sales. As
mentioned in Exhibit 304 (LJH-2), the timing and availability of
APS resources were under review by the Company when
RAMPP-4 went to press. An APS simple cycle resource that was
expected to be available in 1998 was eliminated. The APS
Seasonal Sale and APS Seasonal Exchange were also adjusted to
reflect current expected capacity, energy and timing. These
changes in available resources would tend to increase avoided
costs.
Item fourteen is Plant Re-rates. In RAMPP-4 the Company found
that turbine upgrades were a cost effective method of providing
more resources to the company. The timing and size of these
turbine upgrades have been revised to current planning levels.
The final item in Exhibit 303 (LJH-l) is the Gadsby Repowering
option. The Company has excluded the Gadsby Repowering
option from the portfolio of new resources. The Gadsby
Repowering option made calculation of avoided cost problematic.
Repowering requires the conversion of an existing resource to
become part of a new potential resource. The IPM model does
not have an effective way to account for existing (sunk) costs.
The elimination of this option has the impact of increasing
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Laren Hale - Di
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avoided costs slightly since Gadsby costs were slightly lower than
those for a cogeneration unit or a CCCT.
Q. Exhibit 304 (LJH-2) lists other items that have changed since
RAMPP-4 inputs were frozen. Why were these items not updated
in the model?
A. Two items were not updated: (1) Existing System: Wind Plants
and (2) New Resources: Renewables. In each instance, the
reference in Exhibit 304 (LJH-2) was informative in nature and
did not require changes to the model.
Q. Were there any other items that the Company considered
updating?
A. Yes. In RAMPP-4 the Company proposed that all new
combustion turbines would be F" technology. F" technology
turbines have been replaced by the newer G" technology. The
newer combustion turbines use advanced turbine blades to
extract more energy during the first stage of the combined cycle.
In addition to a superior heat rate, the newer combustion turbines
have declined in cost primarily due to international competition
and market conditions.
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Although the Company did not make this update for this filing,
we feel that keeping technology current is consistent with one of
the goals of avoided cost. Quoting from the Idaho Staff's
proposal If One of the goals of this avoided cost methodology is to
achieve a dynamic resource evaluation process that recognizes
changes in loads, technologies, costs, availabilities, and economic
conditions so that utilities' avoided costs are accurately
determined." This item would not have had any noticeable
impact on avoided cost rates.
Avoided Cost Calculation
Q. Please describe how avoided costs were calculated.
A. The development of the avoided costs follows the methodology in
the settlement stipulation. The Company started with RAMPP-
Case 13 which is the case used by the Company to determine the
amount of DSM in the RAMPP-4 action plan. The Company
developed a base case and an avoided cost case by making the
updates mentioned above. The only modeling difference between
the base case and the avoided cost case is the If Avoided Cost
Unit." The Avoided Cost Unit is the zero cost purchase used to
calculate avoided costs. Its characteristics will vary with each
being priced. After completion of the two runs, relevant financial
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Laren Hale - Di
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results are extracted from run outputs and read into an Excel
spreadsheet to calculate the avoided costs.
Q. Please describe Exhibit 305 (LJH-3).
A. This Exhibit was prepared by me and consists of three pages
showing the avoided cost calculation for 10 20 and 40 MW, 100%
capacity factor avoided costs units. The number in the bold box
in the lower right hand corner is the Nominal Levelized Avoided
Costs in $/MWH. For example in the 10 MW case, the nominal
levelized avoided cost is $24.74 /MWH. Columns (A) and (B) are
the Base Case and Avoided Cost Case annual expenses in
thousands of dollars. Column (C) is the annual savings resulting
from the avoided cost case. Column (D) is the nominal annual
avoided costs in $ /MWH.
Q. Why does Exhibit 305 (LJH-3) have results that continue past the
20 years which Staff has proposed as a standard QF contract
term?
A. The avoided cost calculation includes end effect years in order to
capture all of the impacts of the QF. Note that the IPM model
shows negative avoided costs in the end effect years. The
negative avoided costs is the result of a variety of offsetting
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Laren Hale - Di
PacifiCorp
savings and costs associated with the avoided cost unit. It should
be noted that not all runs will have negative avoided costs
savings in the end effects years.
Q. Does this conclude your testimony?
A. Yes.
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Laren Hale - Di
PacifiCorp
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RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)
Case # IPC-E-95-9
Laren Hale, PacifiCo
Page 1 of
Revisions to Inputs
PacifiCorp determined all of the key inputs to the model in early 1995,
and then did the modelingJor the 39 cases. Between early 1995 and late
1995 some of those inputs may have changed. This section identifies
the changes that have occurred, and how each would affect the
modeling results. The following discussion addresses updates in the
following areas:
Existing system: APS CTs
Existing system: Hermiston
Existing system: wind plants
Existing system: plant re-rates
Existing system: wholesale sales
. New resource: gas prices
. New Resources: renew abies
. Non-firm market prices
Existin1LSystem: APS CTs
RAMPP-4 modeling included the APS CTs in the existing system
begiIming in 1998. They were part of the portfolio because they are part
of an extensive agreement with Arizona Public Service company that
includes many other components. The company is re-evaluating the
timing for those CTs, discussing the issue with APS, and now expects
delays in the timing of those projects. If the delay is 2-3 years, it would
not affect the modeling results that peaking needs don t begin until
2002. Therefore, the company does not believe that this presents
problem for RAMPP-4 model results.
Existin2: System: Hermis
As of May 1995, 60 percent of the engineering efforts were complete and
93 percent of the project purchase orders placed for the Hermiston
RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)Case # IPC-E-95-9
Laren Hale, PacifiCorp
Page 2 of
project. PacifiCorp has initiated discussions with U,S. Generating
Company regarding potential cost savings that may be available,
Existing System: Wind Plants
Both the Foote Creek and Columbia Hills wind projects are on track for
completion and on-line status in 1996. Recent agreements with BPA
and Kenetech clear significant hurdles in siting and building the
projects. With both projects, PacifiCorp will be the majority owner and
Kenetech will be the developer.
The United States House of Representatives Ways and Means
Committee s latest budget proposal includes cutting the wind tax credit.
PacifiCorp is working to keep the credit in effect, The company
appreciates the importance of the credit to keep the current cost of wind
power more competitive with alternative power sources. If the budget
proposal without the credit is approved, it could threaten the viability
of current and new wind projects. The company will be carefully
watching the Committee s activities.
Existing System: Plant Re-Rates
Plant re-rates occur on an ongoing basis as plants undergo
maintenance. Often different sources will report slight! y different
capacities; typically this is due to the use of different measurementstandards, For example, the measurement may be on potential
capacity, on a 30-minute output, or averaged over a longer time period,
Any changes since early 1995 are small and would not affect the
RAMPP-4 modeling results,
Existing System: Wholesale Sales
The company has made some new wholesale sales since performing
the modeling for RAMPP-4. The significant fact for RAMPP modeling
is that they all expire before the date of expected resource deficiency
(2003), except for one 50 MW sale. New purchases of 71 MW help
balance the sale and neutralize its impact on resource needs. Thus,recent wholesale activity should have no impact on the date of the
company s need for new resources. Recent sales are listed below:
RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)
Case # IPC-E-95-9
Laren Hale, PacifiCorp
Page 3 of
City of Anaheim for 25 MW from 5/1995 to 10/1997
Black Hills Power and Light for up to 60 MW from 10/1996 to
3/2002
. BPA for 100 MW from 8/1995 to 7/1998
. Cheyenne Light Fuel and Power for 145 MW from 6/1997 to
5/2000
Eugene Water and Electric Board for 50 MW from 8/1995
7/2000
Hinson Power for 140 MW from 4/1996 to 3/2001
Springfield Utility Board for 50 MW from 10/1995 to 9/2015
In addition, the company has made two new wholesale purchases:
. BPA for 50 MW from 8/1995 to 7/1998
City of Redding for 21 MW from 5/1995 to 5/2014
Information about the prudency of these contracts will be part of future
rate case filings, Until the state public utility commissions decide the
transactions are prudent in a rate case, there will be no price impact to
customers.
New Resource Costs: Gas Prices
Current gas prices have declined from 155.1 to 124.5 ~/MMBtu in the
Mountain region and 131.6 c/MMBtu in the Pacific Northwest region.
The medium gas price escalation rate has declined from 2.11 percent
used in RAMPP-4 modeling to about 1.55 percent. Although lower, itis not as low as the low escalation rate used -- zero percent real
escalation. However, the starting price has declined by about 19 percent
in the Mountain region and by about 15 percent in the Pacific
Northwest region. Table 3-25 shows the differences in assumptions
used in the RAMPP-4 modeling and current market conditions. Since
gas-fired resources were the least-cost supply-side resource under the
original assumptions, lowering their cost does not change the ranking
of resources.
RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)
Case # IPC-E-95-9
Laren Hale, PacifiCorp
Page 4 of
Comparison between RAMPP-4 Forecast
and Current Prices for Natural Gas
Table 3-
Current RAMPP-Difference
Market Forecast
Raw Gas Price Including 1,5% Shrinkage
Low Gas Price Pacific NW 124.5 151.9 (27.4) ~/MMBtu
Medium Gas Price Pacific NW 124.5 155.(30,6) ~/MMBtu
High Gas Price Pacific NW 124.5 157.(33.1) aMMBtu
Low Gas Price Mountain 131.6 151.9 (20.3) ~/MMBtu
Medium Gas Price Mountain 131.6 155.(23.5) ~/MMBtu
High Gas Price Mountain 131.6 157.(26.0) ~ /MMBtu
Transport & Stora
Simple Cycle (1)Pacific NW 12.48 35,(23.43) /kW-year
Mountain 19.21.51 (1.60) /kW-year
Pacific NW 10,11.(1.09) ~/MMBtu
Mountain 17 ~/MMBtu
Combined Cycle Pacific NW 35.46.50 (11.20) ~/MMBtu
Mountain 23.50 20.80 (t/MMBtu
Real Gas Price Escalation Rate
Low Gas Escalation 66%00%66% / year
Medium Gas Escalation 1.55%11%0.56% / year
High Gas Escalation 84%78%94% / year
Real Transport & Stora~e Escalation Rate
00%00%00% / year
(1) Simple Cycle assumes 15% capacity factor, 11,300 BTU /kWh average heat rate.
Ijh N3.25 Gas Comparison Calculations 11/9/95 8:33 AM
RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)Case # IPC-E-95-9
Laren Hale, PacifiCor
Page 5 of 6
A comparison between the low gas price case and the base case shows
the major impacts of a decrease in the gas price and gas price escalation,
Lower gas prices make gas-fired resources cheaper relative to other
resources, which would result in the model's selection of more gas-
fired resources and less DSM. Many of the DSM bundles would not be
cost-effective at a 125 or a 131 It/MMbtu gas price. The model would
also make fewer non-firm sales, and make more non-firm purchases.
In spite of these changes in gas prices, and their expected impacts on
modeling results , the company is not changing the amount of DSM in
the RAMPP-4 action plan.
Coal prices have shown no significant change since early 1995.
New Resources: Renewables
A recent announcement by PacifiCorp is not directly related to the
RAMPP-4 inputs, but is a significant development for the company
knowledge and experience with renewable technologies. PacifiCorp
recently announced a joint venture with Bechtel to develop, own, and
operate small renewable and distributed energy system projects in
international markets as well as in the U.s. EnergyWorks will focus on
specific markets for commercially available technologies: wind power
biomass-fueled power and cogeneration, small hydro, hybrid energy
systems for remote and distributed power applications such as solar
and industrial energy efficiency services, The World Energy Council
projects that approximately 145,000 MW of new electric generating
capacity using renewable resources will be added to the global energy
supply between 1991 and 2010. The initial focus of EnergyWorks is
likely to be selected developing countries where the benefits of grid-
supplied power are not readily secured, that have attractive business
environments, and where growth in demand for power are greatest.
The initiative will work with strong local partners in each country,
PacifiCorp sees this type of business arrangement as best addressing
customer needs , accelerating the company s understanding of the
technology of PV and its economics, and developing the capability to
provide such services in the U.s. when a viable business can be
sustained.
Non-Firm Market Prices
Wholesale prices have declined slightly since early 1995. The company
believes they maybe one to two mills lower than the levels used in
RAMPP-4 PacifiCorp
Exhibit 304 (LJH-2)
Case # IPC-E-95-9
Laren Hale, PacifiCor~
Page 6 of
RAMPP-4 modeling, or around 18 mills on-peak and 14 mills off-peak,
The reader can look at the case with 25 percent lower non-firm market
prices for an estimate of the impact of lower non-firm market prices.
The primary impact would be lower revenues for the company and
higher retail customer prices. It would have very little impact on
resource choices.
The company has concluded that, in spite of some changes in inputs
since the RAMPP-4 modeling, none of the changes warrant changing
the action plan,
The next chapter covers the modeling results for RAMPP-4, It reviews
the input assumptions and results for each of the individual cases,
PacifiCorp Exhibit 305 (LJH-
Case # IPC-95-
Laren Hale, PacifiCorp
Page 1 of 3
Idaho Avoided Cost Filing
10 MW Avoided Cost Unit
Annual Expense $000 $/MWh
Base Case with AC Unit Savings Annual
(A)(B)(C)(D)
(A)-(B)(C)/8,76/10
1996 044 540 043,279 261 14.
1997 088,558 087 205 354 15.
1998 130 265 128,916 350 15.
1999 204 550 203,157 393 15.
2000 306,315 304 057 258 25.
2001 370 028 367 658 370 27.
2002 1,482 374 1,479,881 2,492 28.
2003 603,997 601,615 382 27.
2004 708,525 706 075 450 27.
2005 811,825 809,300 526 28.
2006 956,485 953,891 594 29.
2007 072 007 069 288 719 31.
2008 225,637 222 811 826 32.
2009 383 987 381 175 812 32.
2010 583,156 580,140 015 34.
2011 765 912 762 877 034 34.
2012 929,033 925 890 143 35.
2013 095 108 091 852 256 37.
2014 293,159 289 792 367 38.
2015 502 895 3,499,409 3,486 39.
2016 661 147 661 240 (92)
2020 187 221 187 345 (124)
2024 771 352 771,493 (140)
2031 990,363 990,539 (177)
2038 520,812 521 034 (222)- 2.
2045 439,892 440 170 (278)
Nominal Levelized Avoided Cost at 8.24.
Ijh 10.rnw _ac.xls -06/10/96 5:44 PM
PacifiCorp Exhibit 305 (LJH-
Case # IPC-95-
Laren Hale, PacifiCorp
Page 2 of 3
Idaho Avoided Cost Filing
20 MW Avoided Cost Unit
Annual Expense $000 $/MWh
Base Case with A C Unit Savings Annual
(A)(B)(C)(D)
(A)-(B)(C)/8.76/20
1996 044 540 042 018 522 14.
1997 088 558 085,851 707 15.
1998 130,265 127 567 698 15.
1999 204 550 201 761 789 15.
2000 306 315 301 798 517 25.
2001 370 028 365,337 691 26.
2002 1,482 374 1,477 389 984 28.
2003 603 997 599 233 764 27.
2004 708 525 703,624 901 27.
2005 811 825 806,766 059 28.
2006 956,485 951 296 189 29.
2007 072 007 066 585 421 30.
2008 225,637 219 987 650 32.
2009 383,987 378,362 625 32.
2010 583,156 577 135 021 34.
2011 765,912 759,843 069 34.
2012 929 033 922 747 287 35.
2013 095,108 088,596 512 37.
2014 293,159 286,425 734 38.
2015 502 895 3,495 923 972 39.
2016 661 147 661 332 (185)
2020 187 221 187,462 (241)
2024 771 352 771 633 (281)
2031 990,363 990,716 (353)
2038 520 812 521 255 (443)
2045 9,439 892 440 448 (556)
Nominal Levelized Avoided Cost at 8.24.
Ijh 20.rnw _ac.xls -06/10/96 5:45 PM
PacifiCorp Exhibit 305 (LJH-
Case # IPC-95-
Laren Hale, PacifiCorp
Page 3 of 3
Idaho Avoided Cost Filing
40 MW Avoided Cost Unit
Annual Expense $000 $/MWh
Base Case with A C Unit Savings Annual
(A)(B)(C)(D)
(A)-(B)(C)/8.76/40
1996 044 540 039,496 045 14.
1997 088,558 083,143 5,415 15.45
1998 130,265 124 908 358 15.
1999 204 550 199,045 505 15.
2000 306 315 297 293 022 25.
2001 370,028 360 695 332 26.
2002 1,482 374 1,472,405 969 28.
2003 603 997 594,466 530 27.
2004 708 525 698,738 787 27.
2005 811 825 801,717 10,108 28.
2006 956,485 946,107 377 29.
2007 072 007 061 208 799 30.
2008 225 637 214 339 298 32.
2009 383,987 372 736 251 32.
2010 583,156 571 114 041 34.
2011 765,912 753 774 138 34.
2012 929 033 916,459 574 35.
2013 095,108 082 098 13,010 37.
2014 293 159 279,692 13,467 38.
2015 502 895 3,488,950 945 39.
2016 661 147 661 558 (411)
2020 187 221 187 673 (452)
2024 771 352 771 873 (521)
2031 990 363 991 016 (654)
2038 520 812 521 633 (821)
2045 9,439,892 9,440,922 030)
Nominal Levelized Avoided Cost at 24.
Ijh 40,mw _ac.xls -06/10/96 5:44 PM
CERTIFICATE OF SERVICE
I hereby certify that on the/~-Iltday of June, 1996, a true and correct copy of the
foregoing Direct Testimony ofLaren Hale was sent via Federal Express to the following:
Larry D, Ripley
Idaho Power Company
O. Box 70
Boise, Idaho 83707-0070
Barton L. Kline
Idaho Power Company
O. Box 70
Boise, Idaho 83707-0070
Brad Purdy
Deputy Attorney General
Idaho Public Utilities Commission
O. Box 83720
Boise, Idaho 83720-0074
Thomas Dukich, Manager
Washington Water Power Co.
O. Box 3727
Spokane, Washington 99220
R. Blair Strong
Paine, Hamblen, et al.
717 W. Sprague Avenue, #1200
Spokane, Washington 99204
Gregory N. Duvall
PacifiCorp
825 NE Multnomah, Suite 485
Portland, Oregon 97202
Peter J Richardson
Davis Wright Tremain
999 Main Street, Suite 911
Boise, Idaho 83702
Carl Myers
Myers Engineering, P.
750 Warm Springs Avenue
Boise, Idaho 83712
Ronald C. Barr
Earth Power Resources, Inc.
2534 East 53rd Street
Tulsa, Oklahoma 74105
Richard B. Burleigh
Don Olowinski
Stephanie Walter Gillette
Hawley Troxell Ennis & Hawley
O. Box 1617
Boise, Idaho 83701-1617
Owen H. Orndorff
Orndorff Peterson & Hawley
1087 West River Street, Suite 230
Boise, Idaho 83702-7035
~~/