20040325KEEN Direct PUC Original Scan.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO.
IDAHO POWER COMPANY
DIRECT TESTIMONY
J. LAMONT KEEN
CASE NO. IPC-E-O3-
please state your name and business address.
My name is J. LaMont Keen and my business
address is 1221 West Idaho Street, Boise, Idaho 83702.
What is your position at Idaho Power Company?
I am the President and Chief Operating
Officer.
What is your educational background?
I graduated magna cum laude in 1974 from the
College of Idaho in Caldwell, Idaho now called Albertson
College of Idaho, receiving a Bachelor of Business
Administration Degree in Accounting.In 1994 I completed
the Advanced Management Program at the Harvard University
Graduate School of Business.I have also attended many
utility management-training programs, including the Stone &
Webster Utility Management Development Program, the
University of Idaho Public Utilities Executive s Course and
the Edison Electric Institute Executive Leadership Program.
Please outline your business experience.
I have worked in the electric utility
industry at Idaho Power Company for nearly 30 years,
beginnlng my employment in 1974 in the accounting
department.I advanced through several accounting, analyst
and management positions and in July 1988, I was promoted to
Controller.In November 1991 I was appointed to Vice
President of Finance and Chief Financial Officer and served
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Idaho Power Company
in that capacity until March of 1999 when I was also given
responsibility for all of the administrative areas of the
Company as Senior Vice President of Administration and Chief
Financial Officer.In March of 2002, I was appointed
President and Chief Operating Officer where I have
responsibility for the Company s operating units.I ei ther
have or have had responsibility for virtually all aspects of
the Company s operations at some point in my career.
What are your duties as President and Chief
Operating Officer of Idaho Power Company?
I am responsible for the general oversight of
all the utility operations including all power supply and
delivery activities.
What is the purpose of your testimony?
As Idaho Power Company s president, I am
testifying as to policy matters related to the Company
filing of this request for general rate relief.
Specifically, I will address the events and circumstances
that led to this rate application, including an overview of
significant events, both regulatory and otherwise, that have
occurred over the last decade; the impact of ten years of
growth on our utility system; the Company s stewardship of
the system during the recent difficult period; the
increasing emphasis on system reliability; the critical
demand for investments in infrastructure; and the cash flow
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Idaho Power Company
and earnings implications to the Company of managing through
all of the above.
Please describe the Company s last general
ra te increase in Idaho.
The Company s las t general rate case, Case
No. IPC-94-5, concluded on January 1, 1995 when the Idaho
Public Utili ties Commission (IPUC or the Commission) issued
Order No. 25880 authorizing Idaho Power to increase its
rates by $17 177 048 or 4.19 percent.In that case, the
rate of return on common equity was established at 11
percent with an overall rate of return at 9.199 percent.
Permanent rate changes were implemented on February 1, 1995.
Shortly following the conclusion of Case No. IPC-
94-5, the Company completed its upgrade of the Twin Falls
hydroelectric power plant and filed an application with the
Commission to supplement the results of Order No. 25880 with
rate impacts of the new production facilities.
The Commission issued a bench ruling that allowed
Idaho Power to increase its revenue requirement by
$3,759,695 or .88 percent, to include the Twin Falls upgrade
on August 14, 1995.On November 13, 1995, Order No. 26236
reaffirmed the Commission s bench ruling.
Please describe the rate moratorium entered
into following the last general rate case.
On October 20, 1995, in Order No. 26216, the
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Commission approved a rate moratorium and stability of
earnings stipulation between various intervenor parties,
the Staff of the Commission, and Idaho Power Company.The
stipulation provided that in the period from 1995 through
1999, any time the Company s return on equity (ROE) fell
below 11.5 percent, the Company would be allowed to
amortize an additional amount of Accumulated Deferred
Investment Tax Credits (ADITC) in order to increase
earnings back to the 11.5 percent level.I f the Company
ROE exceeded 11.75 percent, the Company would refund
(revenue share) 50 percent of the excess earnings to the
benefit of its Idaho customers.The stipulation also
provided that Base Rates would not change prior to January
1, 2000.Because of improved operating conditions,
including hydro availability, the Company never had to use
ADITC to supplement earnings during the moratorium.On the
other hand, Idaho Power s customers were able to experience
the benefits of revenue sharing during the years 1996,
1997, 1998, and 1999.The total benefit shared with the
Idaho retail customers was approximately $28 million.
Has the corporate structure changed at Idaho
Power during the last ten years?
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Idaho Power Company
Yes.On October 1, 1998, with the formation
of IDACORP, Inc., the Company became a part of a holding
company structure.IDACORP, Inc. serves as the parent of
Idaho Power Company, a regulated utility, as well as a
number of unregulated subsidiaries.The purpose in forming
IDACORP, Inc. was two- fold.First, the structure allowed
Idaho Power to continue as a regulated utility just as it
had for the past 82 years.At the same time, the creation
of a holding company enabled present and future non-
regulated business units to compete for business in the non-
regulated arena without saddling the regulated utility with
the capital requirements and risks of those ventures.
The move to a holding company structure followed
approval by multiple regulators including the Idaho
Commission in Order No. 27348 issued on January 29, 1998 in
Case No. IPC-97 -11.
Following the rate moratorium, what impact
did the Western energy crisis have on Idaho Power?
By the summer of 2001, the West was in the
grip of the nation s worst energy crisis.
Increases in the price for natural gas, an
increasingly important fuel for thermal generation of
electricity in California, combined with the 2000-2001 water
conditions that were among the lowest ever recorded in the
Pacific Northwest region according to the u. S. Department of
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Idaho Power Company
Agricul ture, created further upward pressure on wholesale
prices emanating from the California market.Compared wi th
the first quarter 2000, wholesale power prices for 2001 peak
period transactions in the Pacific Northwest rose by almost
a factor of ten, from an average of $25 per megawatt-hour to
$240 per megawatt-hour as measured by the Dow-Jones Mid-
Price spikes took place on the hourly spotColumbia Index.
market that resulted in the price of electricity exceeding
$1000 for short periods of time.
Idaho Power s operations were also adversely
affected by the tremendous increase in prices for purchased
power, increased demand, and reduced hydroelectric
This particular combination of economic andgeneration.
natural phenomena produced substantial increases in costs
to supply power to customers not only in Idaho Power
Large andservice territory but also across the west.
small utilities throughout the west were filing for double
digit rate increases on multiple occasions during the 18-
Idaho Power was no exception as itsmonth energy crisis.
annual PCA rate applications increased to record amounts.
Please describe the severity of the current
Idaho drought.
based utility.
Drought is of particular concern to a hydro-
Reductions in the region s already limited
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water supply for extended periods of time can produce
devastating impacts in terms of reduced hydro-generation
availabili ty and correlating higher energy costs.Drought
is also a "creeping phenomenon " making its onset and end
difficul t to determine.The effects of drought accumulate
slowly over a considerable period of time and may linger for
years after the termination of the event.Current water
supply conditions for Idaho demonstrate the reality of this
phenomenon.
At its peak, the 2000 drought was as severe as any
of the major droughts of the last 40 years as measured by
temperature and moisture.This exceptionally dry summer
resul ted in low soil moisture entering into the winter.
Precipitation was much below normal over most of the Pacific
Northwest during the fall and winter of 2000-2001 and
hydrologically, the evolving 2001 drought appeared to be
similar in magnitude to the 1977 drought of record based on
streamflow and reservoir levels.
In 2001, the water supply outlook for the state of
Idaho remained much below normal and continued to be one of
the lowest years on record.May 2001 runoff was estimated
to be the second or third lowest on record for many sites
across the state.Snowpack for the same period remained low
at 30 to 55 percent of average across Idaho.The severi ty
of the 2001 drought was further exacerbated by the ongoing
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Idaho Power Company
California power problems, one result of which was that the
Federal System reservoirs were drafted to some of their
lowest levels ever.
In 2002 and 2003, the entire Columbia River Basin
experienced drought conditions.The Columbia River at The
Dalles, Oregon, is a commonly used reference point to gauge
flows in the Columbia River in the Pacific Northwest.
2002 and 2003, the April through August flows at The Dalles
averaged only 68 percent of average.These low flows
significantly reduced the amount of surplus energy available
for the Company to purchase.
In 2003, the creeping drought phenomenon continues.
Over the past four years, the April through July inflow to
Brownlee Reservoir has averaged about 60 percent of the 1960
through 2003 average.Even more telling, in southern Idaho
the April through July flows at Swan Falls Dam have declined
to 46 percent of average.In July 2003, the flow at Swan
Falls Dam was at the lowest level recorded by either the
USGS or Idaho Power.In response to these low flows, the
Idaho Department of Water Resources was prepared to take the
extreme measure of actually curtailing junior upstream
surface water diversions.
What effect does a severe drought have on the
Company?
During drought, Idaho Power must rely more
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Idaho Power Company
heavily on purchased power to meet system loads, usually at
higher market prices due to supply scarcity.At the same
time, there are obviously less "surpluses " to sell to offset
increased market purchases.The result is upward pressure
on the Company s power supply costs.
How did the combination of drought and high
market prices impact the Company s PCA requests?
Because Idaho Power relies predominantly upon
hydroelectric generation to serve its load, the Company
actual costs of providing electricity can vary dramatically
from year to year depending on changes in streamflow and
market prices.In recognition of the fluctuating power
supply costs associated with variable hydroelectric
generation, the Commission approved a "Power Cost
Adjustment" (PCA) mechanism for Idaho Power in 1993. During
the years that the PCA has been in effect, there have been
both annual credi ts and surcharges.However, as a result of
the Western energy crisis and drought conditions, the
Company s PCA application in 2001 was the largest amount
ever reques ted .Following extended hearings, the Commission
authorized the bulk of the $227.4 million requested under
the PCA mechani sm.The following year the Company s PCA
filing was even greater.The issues were complex and
required a careful balance between public policy concerns
and the need to achieve just, fair and reasonable rates for
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recovering excess power costs. As it did in 2001, the
Commission disallowed a portion of the jurisdictional power
supply-related costs contained in the 2002 PCA filing.
How did the Company view these PCA orders?
Al though the Company was concerned to see
disallowances emerge in the PCA, it generally viewed both
the 2001 and 2002 Commission decisions as a signal that the
Company was operating within the guidelines established by
the IPUC and consistent with ratemaking concepts of the PCA.
The decisions also lent valuable support to the Company
during deteriorating financial circumstances.
Please describe Idaho Power s most recent PCA
filing.
During the 2002-2003 PCA period, wholesale
energy prices had returned to pre-energy crisis levels.
However, Idaho Power continued to be impacted by diminished
precipitation levels and the resultant reduction in
hydroelectric generation.On April 14, 2003, the Company
filed a request to implement its annual PCA that would
reduce overall rates by over 18 percent.On May 13, 2003,
the Commission approved the Company s application.Despi te
the decrease, rate levels are still more than $80 million
above Base Rate levels.Wi th more normal snow pack and
current prices, another PCA decrease could occur next
spring.
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Idaho Power Company
You previously discussed the impact of the
Western energy crisis on the Company.Now, please elaborate
on the Western energy crisis s impact on the Company s PCA.
When the PCA was first developed in 1992 and
implemented in 1993, no one anticipated the types of market
prices and volatility that occurred in 2000 and 2001.
At its inception, based on historical data, the
anticipated power supply expense volatility was
approximately $116 million from best to worst condition.
During the western energy crisis, Idaho Power s power supply
expenses were $204 million over those in Base Rates in 2001
and $337 million over base in 2002.The two years in
combination were $541 million above base with the Company
shareholders absorbing over $127 million of that total
amoun t .As a resul t, Idaho Power s cus tomers and
shareholders both bore substantial power supply costs that
were of a magnitude not contemplated at the PCA's inception.
The shareholders burden came from both the sharing mechanism
and from disallowances in the 2001 and 2002 PCA orders.
What is your impression of the PCA?
I believe that the PCA is a fair ratemaking
mechanism that has recently been stress-tested under extreme
conditions.Two of the attributes that have helped the
mechanism stand the test of time are the true up and the
sharing provision.The true up provides a means for actual
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Idaho Power Company
costs to be ultimately accounted for and included.The
sharing provision ensures that the interests of both the
Company and its customers are aligned on each transaction.
Since your Company has received significant
cost recovery through the PCA in recent years,why do you
need file a general rate application?
The PCA only addresses the portion of the
Company s total annual revenue requirement that corresponds
to the variable cost of supplying energy to Idaho retail
customers.The power supply expenses that flow through the
PCA are normally limited to fuel for thermal plant
operations and purchased power.The PCA mechanism also
subtracts surplus sales revenues from these expenses.The
sheer magnitude of the power supply expenses in recent years
placed their ratemaking treatment at a higher regulatory
priority than the pursuit of general rate relief.The
Company not only had to prioritize its requests before the
Commission, but recognize rate impacts to customers as well.
Accordingly, the Company chose to postpone filing for
general rate relief.Now in 2003, with the PCA component of
our rates beginning to drop, other increasing expenses and
new investments need to be brought before the Commission for
inclusion in Base Rates.
How has the Company s investment in electric
plant grown since the last general rate case?
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Idaho Power Company
Since 1993, the test year for the last
general rate case, the Company s investment in electric
plant has grown by $856 million from nearly $2.32 billion to
slightly over $3.17 billion.The $856 million represents a
10-year 37 percent increase in Company investment in
electric plant on behalf of our customers.Put in annual
terms, Company investment in electric plant has grown at
about 3.2 percent per year since the last general rate case.
Of the $856 million of additional investment
in electric plant, please detail the growth in investment
for generation, transmission, and distribution facilities.
In the last ten years, the Company has
invested $156 million for generation additions and upgrades.
The most recent generation plant addition was the Danskin
gas-fired generation plant located in Mountain Home.The
investment in the Danskin generation facility was
approximately $50 million.In the same period of time the
Company has invested $198 million toward the construction of
transmission facilities and $366 million toward the
construction of distribution facilities.The most recent
investment in transmission facilities included in this
application is the $19.4 million Brownlee-Oxbow 230 kV
transmission upgrade.The remaining $136 million of
investment growth is attributable to general and other plant
items.
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Idaho Power Company
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Please describe the growth in Company
expenses associated with operating and maintaining a $3.
billion system.
The expenses associated with operating and
maintaining a $3.2 billion system today have grown to about
$540 million per year from the $412 million needed to
operate and maintain a $2.3 billion system in 1994.The
$128 million growth in expenses represents a 31 percent
increase in expenses from levels established 10 years ago.
Put in annual terms, Company expenses have grown at about
7 percent per year since 1993.
Please describe the growth in Company
revenues over the same 10-year period of time.
Since the las t general rate case, Company
test year operating revenues have grown only 13 percent
compared to the 37 percent growth in investment and the 31
percent growth in expenses.Clearly, growth has not paid
for itself.The incremental costs of adding, operating and
maintaining generation, transmission and distribution plant
are greater than the embedded costs associated with
generation, transmission and distribution plant that have
been the basis of Company rates over the last ten years.
How has Idaho Power managed through this
growth?
While both inflation and customer growth
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impact our expense level, the Company has actually been able
to keep expenses well below the combined growth rate of
inflation plus customer growth.I have had Exhibi t No.
prepared to demonstrate these relationships over time.
Exhibit No.1 tracks the actual operating and maintenance
(O&M) expenses from 1993 through 2002 and includes the 2003
O&M expenses that are part of the Company s general rate
request.Exhibi t No.1 also tracks the 1993 O&M expenses
over the same time period escalated by the combined impacts
of inflation and customer growth.
What is the current condition of Idaho
Power s distribution system?
The sys tem has been expanded to absorb the
growth of the past decade.As noted before, over 40 percent
of the Company s investment during this period has gone into
the distribution system, yet many of the Company '
distribution stations and lines are at or near capacity.
During this time, we have worked diligently to improve
operating efficiencies and utilization.However, there is
little room to withstand additional growth without new
construction.
Please describe the operating capaci
situation with the Company s distribution feeders.
The utilization of assets, or loading levels
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Idaho Power Company
The peak load peron feeders, has increased significantly.
Today,distribution feeder in 1987 averaged 4.9 megawatts.
this has increased to 7.0 megawatts.Approximately one
half of the retail load is served by feeders operating near
their full capacity at peak load.
The Company has carefully prioritized and scheduled
the construction of new facilities while relying heavily on
our experienced workforce to manage and operate the system
wi th these reduced margins.
How is the Company managing new growth on
its distribution system?
The Company has continued to manage
substations and feeder loadings to meet growth through
selective distribution capacity increases and the use of
This has allowed thebetter load data acquisition systems.
Company to utilize much of the reserve capacity once
However, further reductions in reserve capaci available.
would likely reduce reliability and service quality to our
Consequently, additional growth will requirecustomers.
new facilities be added to the system at full marginal
cost, rather than being able to leverage existing capacity
The Company hasin the system at the old embedded cost.
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Idaho Power Company
identified over $400 million in growth-related sub-
transmission, substation, and distribution infrastructure
additions required prior to 2010.This does not include
the ongoing costs of maintaining or replacing existing
facili ties.
Since the last rate case, has Idaho Power
Company invested in 230 kilovolt and above transmission
facilities?
Yes.Contrary to reports of other utili ties
not investing in transmission infrastructure, Idaho Power
has invested in backbone transmission facilities both to
serve load and to improve service reliability.Since 1996,
Idaho Power peak load has grown 526 megawatts.As a part of
an over-all strategy to meet this load growth, the Company
has undertaken several backbone transmission proj ects:
Brownlee-Ontario-Caldwell 230 kV Project $30.
$ 5.Boise Bench-Locust 230 kV
Brownlee 230 kV Bus Reconfiguration $ 6.
$ 7. 7MBoise Bench 230 kV Bus Reconfiguration
Brownlee-Oxbow #2 230 kV Project $19.
$ 5.Goshen 345 kV Series Capacitor
Locust-Caldwell 230 kV Project $19.
The Brownlee-Oxbow #2 Proj ect and the Goshen Proj ect
will be completed in May 2004.The Locust-Caldwell Project
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is scheduled for completion in October 2004.On a dollar
per kilowatts of capacity basis these projects cost about
$180 per kilowatt.
What are the drivers for this transmission
investment?
Other than the Goshen project, which was done
primarily for reliability purposes, the recent additions
just mentioned were focused on maximizing the capacity of
existing facilities.In other words, the Company has
focused on making relatively small incremental improvements
that increase the capacity of the system without having to
resort to building significant long distance transmission
lines.Fewer and fewer of these optimizing opportunities
remain.Future transmission additions will likely be driven
by the location of the load growth and where resource
addi tions are developed.
What are the transmission implications for
the next ten years?
A significant portion of the Company s load
growth is occurring in Ada and Canyon counties.The next
ten years will require continuing transmission system
facili ty improvements in this area.
Toward the end of this time horizon, the existing
bulk transmission system serving the Treasure Valley area
(Ontario to Mountain Home) will reach its maximum present
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capabili ties and maj or transmission additions from the
Northwest and/or areas east of Midpoint may become
necessary.
Based on recent experience, how will the cost
of these new transmission facilities compare to previous
transmission construction costs?
These future backbone expenditures will
likely cost twice the previous expenditures for a comparable
amount of load growth, about $400 per kilowatt or on average
$20 million per year.
What resource scenario was used in deriving
these cost estimates?
As mentioned earlier, a key driver for
transmission expansion is the location of future generating
resources.The estimate of future backbone transmission
expendi tures assumes the Company will be able to construct
or acquire local gas-fired combustion turbine additions in
the next few years.Other resource strategies (wind, coal,
etc.) may require significant transmission distances and
would result in greater transmission expenditures.
Will the recent east coast blackout have an
impact on Idaho Power s transmission development?
The effects of the August 14, 2003 blackout
on the east coast are not known at this time.One possible
effect is a nationwide change in reliability standards; it
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Idaho Power Company
could dramatically alter or advance transmission system
expansion of the Idaho Power system and throughout the
Western Interconnection.
How has the Company s resource planning
changed over the last ten years?
Prior to the Western energy crisis, we
planned on median water conditions and assumed that energy
would be available at reasonable prices in the wholesale
market in below normal water years.Today our generation
planning philosophy includes reducing market dependence and
building resources as required under the 2002 Integrated
Resource plan (IRP).During the 2002 IRP process, public
input supported this planning philosophy which is based upon
more stringent criteria for both loads and resources.
How does this new generation resource
planning philosophy impact costs?
By using a less than median water planning
criteria the need for additional resources will be
This applies to both peaking as well as baseaccelerated.
load facilities.
Please describe the Company s current
generating resources strategy.
Idaho Power will have to acquire a variety
of resources throughout the coming years to meet its
growing load requirement.The Company has recently
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notified Mountain View Power (MVP) that it is the
successful bidder in the Company s most recent Request for
Proposal for a generating resource.Once completed, MVP
will transfer the plant to Idaho Power ownership.Idaho
Power has decided to name this plant the Bennett Mountain
Power Plant.The Bennett Mountain Power Plant will provide
approximately 160 MW of peaking capacity.The Bennett
Mountain Power plant project will satisfy a portion of a
portfolio of resources to be acquired to meet the 2002 IRP
obj ecti ves .The Company has filed with the Idaho
Commission for a Certificate of Convenience and Necessity
for the Bennett Mountain Power Plant.In its application,
Idaho Power has provided a commitment estimate of $54
million for the generation portion of the project, which is
scheduled for completion in April 2005.
The results of the 2004 IRP will likely show
additional resource needs in the near future.
What is the current condition of the
Company s jointly owned coal-fired resources?
As the demand for electricity has grown and
the drought continues, we have relied heavily on our jointly
owned coal-fired resources.These facilities were
constructed in the 1970s through the early 1980s.As they
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age, they are in constant need of upgrading and
rehabili tation.New environmental regulations have also
added capital and maintenance requirements.We anticipate
increased capital and O&M costs for these facilities in
order to keep them reliable and compliant.
What is the status of the Company
relicensing efforts?
Utilities throughout the country have
licenses to operate hydropower projects to generate
electrici ty These licenses are granted by the Federal
Energy Regulatory Commission (FERC).Licenses are usually
granted for 30 to 50 years and define how hydropower
projects may be operated for power generation as well as
other measures that benefit the public.Idaho Power owns
and operates 17 hydropower projects on the Snake River.
2010, licenses will expire for eight Company projects
affecting 12 different power-producing facilities.The
Company has already applied, or is preparing to apply for a
new license on each proj ect.Exhibit No.2 outlines the
Relicensing Tasks Flow Chart for each proj ect in their
various stages of the FERC relicensing process.I would
like to highlight the investment the Company has made in
just one of these projects in particular, the Hells Canyon
Complex.
On July 18, 2003, Idaho Power filed a formal
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application with the FERC to relicense the Company s three-
dam Hells Canyon hydroelectric proj ect.The Hells Canyon
Complex is the largest of Idaho Power s 17 hydroelectric
proj ects on the Snake River.Currently, over 420,000
customers rely on this complex for power as it produces
nearly two-thirds of the hydroelectric generation and 40% of
the total generation of the Company in an average water
year.The final relicensing application consisted of
36, OOO-pages and was the culmination of nearly a decade of
studies conducted by the company, focused on fish, wildlife,
plants, water quality, recreation and cultural resources.
Idaho Power conducted over 100 studies and ultimately the
application process cost Idaho Power more than $50 million.
The application also includes $324 million worth of new and
continuing mitigation efforts to offset present and future
environmental impacts resulting from the operation of the
facili ty.These mitigation efforts, referred to as
protection, mitigation, and enhancement (PM&E) measures
include Water Use and Quality, Fish and Mollusc Resources,
Wildlife Resources, Botanical Resources, Cultural Resources,
Aesthetic Resources and Recreation Resources.
As the Relicensing Tasks Flow Chart shows, the
Company began work on the Hells Canyon relicensing effort in
early 1993.In September 2002 Idaho Power submitted a
25; OOO-page draft license application to the FERC and
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hundreds of stakeholders who constituted the Collaborative
Team.The Company accepted over 4,500 written comments on
its draft application through January 2003.Comments from
the different respondents were addressed and included in the
final new license application filed in July 2003.The FERC
is planning to begin their National Environmental Protection
Act process for the Hells Canyon project, with scoping
meetings scheduled for the third week of November 2003
followed by requests for additional information in December
2003.The Company expects to incur consultation and
compliance costs through 2008 followed by actual Article
Compliance costs (once the FERC has issued a new license)
that will continue well on in to the next decade.Exhibi t
No.3 charts the Hells Canyon relicensing expenses incurred
to date and the expected costs through 2010 at which time
the Company will have spent approximately $100 million.
What is the financial condition of Idaho
Power Company?
The current financial situation has developed
over a period of years.In 1999, the Company s short-term
debt was $20 million, internal cash generation was at 114
percent, and we were experiencing sales growth in our
service area.
In 2000, the combination of drought and energy
crisis that I spoke of earlier built up a huge PCA deferral
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and caused us to file our annual PCA earlier than usual.
described previously, the IPUC ultimately approved most of
the 2000-2001 PCA in two parts -- $168 million in May of
2001 and another $59 million in October of 2001.PCA
disallowances of $11 million were written off in October of
2001.During 2000, capital expenditures increased to $132
million, while short-term debt rose to almost $60 million
and internal cash generation fell to 42 percent.
By 2001 Idaho Power Company s regulated earnings per
share had dropped to $. 60 per share.2001 was characterized
by industry turmoil and continued Idaho drought.The
Perfect Storm" occurred with the combination of high market
prices, lower-than-average stream flows, and higher demand.
The PCA deferrals again grew, this time from the combined
effects of the load reduction programs for the Astaris
Special Contract and the irrigation customers.The un-
recovered portion of the PCA costs absorbed by shareholders
reached $76 million.Operating cash flow for Idaho Power
was a negative $59.6 million.The short-term debt balance
skyrocketed to $282 million.2001 construction costs
increased to $157 million, including $49 million for the
Danskin Power Plant.Net working capital declined from 2000
to 2001 by $156 million.Utili ty operating income was also
down from 2000 to 2001 by $79 million primarily due to the
PCA absorption.
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Idaho Power s earnings in 2002 were $2.24 per share,
but these were heavily supported by a one-time $.92 income
Without it, thebenefit related to a tax method change.
utili ty operation would not have earned enough to cover its
dividend payment in 2002.
In 2003 the power supply costs finally began to drop
leading to a rate decrease of 18 percent.However, cus tomer
growth and reliability requirements continue to drive the
need for investment in transmission and distribution
infrastructure.
What are the implications of the current
financial situation?
The Company needs to fund its operating and
maintenance programs at adequate levels and needs to make
additional investments in infrastructure to ensure continued
high quality and reliable service for our customers.
Looking forward, the capital expenditures are expected to
remain high for the foreseeable future.
The cash flow situation has been precarious over the
last several years.Utili ty earnings did not cover the
dividend payment in 2001 and would not have covered the
payment in 2002 except for the tax method change.
Did Idaho Power s Board of Directors (the
Board) recently vote to reduce the common stock dividend?
The Board voted on September 18, 2003Yes.
KEEN, DI
Idaho Power Company
to reduce the total common stock dividend payment for the
next quarter from $17,815,652 to $11,493,969, a reduction of
This resulted in a reduction in the IDACORP,$6,321,683.
Inc. annual dividend from $1.86 per share to $1.20 per
share.
Why did the Board take this action?
Idaho Power needs to strengthen its overall
financial position so that it will be able to fund Idaho
Power s $675 million, three-year capital expenditure program
for the years 2004 through 2006.Reducing the dividend will
improve cash flow and help maintain a strong credit rating
while balancing the level of borrowing necessary to meet the
growing capital requirements.
How does the $675 million of estimated
capi tal expendi tures over the next three years compare wi
the capital expenditures for the most recent three years?
The Company s capi tal expendi tures for the
years 2001 through 2003 are expected to total $427 million.
The forecasted growth of $675 million is a 58 percent
increase.I had Exhibi t No.4 prepared to show the
Company s actual/estimated capital expenditures for 2001
through 2006.Actual values have been included through July
of 2003.
How does the Board's decision relate to the
Company s request for rate relief?
KEEN, DI
Idaho Power Company
':-
The Board recognized the need to generate
more cash to invest in the utility infrastructure and
strengthen the balance sheet.Accordingly, the Board
decided to pay the owners less through the common stock
dividend.In a similar fashion, timely rate relief also
strongly supports increased cash flow and a stronger balance
sheet wi th its corresponding enhanced credi t worthiness.
As president of Idaho Power, where is your
focus?
My focus is the full restoration of Idaho
Power as a preeminent fully integrated utility with the
financial viability to successfully meet our customers
needs both now and in the future.
What progress have you made?
In my view, we have made remarkable progress,
particularly considering what we have been through in recent
years.The Company has managed through the energy crisis
and ongoing prolonged drought, taken steps to meet our
customers ' needs and reduce risks to them going forward, and
made difficult decisions to maintain credit quality and
financial flexibility.Running an efficient, quality
utili ty is our priority and, as detailed in Ms. Fullen
testimony, customers are recognizing our efforts.I also
believe that we have made some strides in the area of
demand-side management (DSM).Ms. Fullen s testimony notes
KEEN, DI
Idaho Power Company
our senior management support in the DSM area.I affirm her
testimony.
What is your opinion of the Company s rate
application?
Based upon the growth we have encountered
over the last ten years, sound management through the energy
crisis and ongoing drought conditions, and the system
needs going forward, I believe the Company s request for
general rate relief is fair, just, and reasonable.
Does this conclude your direct testimony in
this case?
Yes, it does.
KEEN, DI
Idaho Power Company