electric.pdf

Electrical Power in Idaho
Idaho residents consistently enjoy some of the least expensive electric service in the nation, according to
surveys conducted by the National Association of Regulatory Utility Commissioners (NARUC), the
Edison Electric Institute and the Energy Information Administration of the U.S. Department of Energy.

Idaho Power Company
2006 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
374,527 Residential Customers/$0.0594
71,472 Commercial Customers/$0.0429
122 Industrial Customers/$0.0295

Avista Utilities
2006 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
99,653 Residential Customers/$0.0650
15,753 Commercial Customers/$0.0656
494 Industrial Customers/$0.0415

2006 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
53,148 Residential Customers/$0.0487
7,460 Commercial Customer/$0.0632
3,441 Industrial Customer/$0.0360

--PAGE 16--

Rate adjustments

Rocky Mountain Power was granted an average 6.4 percent rate increase that became effective Jan. 1.
2008. For residential and irrigation customers, the increase was 4.89 percent. The case was settled. Rocky
Mountain Power had originally requested an average 10.3 percent rate increase.

Another settlement in the Idaho Power Co. rate case was pending at year’s end. That utility also
proposed a 10.3 percent rate case, but a settlement of all parties involved proposed an average 5.2 percent
rate increase. The residential increase proposed is 4.7 percent, while all other customers classes would get
a 5.65 percent increase if the settlement is eventually approved.

Avista Utilities’ Power Cost Adjustment (PGA) resulted in a 2.2 percent overall increase (1.5 percent for
residential customers) that became effective Oct. 1, 2007. A dry winter and spring resulted in a more
dramatic PCA increase for Idaho Power customers. An average 14.5 percent increase became effective on
June 1.

Rocky Mountain Power granted 6.4 percent increase
Case No. PAC-E-07-05, Order No. 30482
December 28, 2007

Electric rates for customers of Rocky Mountain Power in eastern Idaho increased by an average 6.4
percent on Jan. 1, 2008. The size of the increases varied by customer class. For residential and irrigation
customers, the increase was 4.89 percent.

The Idaho Public Utilities Commission approved a settlement between the utility and customer groups to
increase Rocky Mountain Power’s annual revenue by $11.5 million. Rocky Mountain Power originally
sought an average 10.3 percent increase and $18.5 million in additional annual revenue.

The settlement was signed by all the parties in the case including Rocky Mountain Power, commission
staff, the Idaho Irrigation Pumpers Association, the Community Action Partnership of Idaho, a consumer
group that fights the causes of poverty, and two large customers of Rocky Mountain Power: Monsanto
and Agrium. Timothy Shurtz, a Firth resident representing himself, also signed the settlement.

The company said the rate increase was needed to meet the demands of higher costs for fuel, labor and
transmission wheeling as well as to cover additional investment in generation, transmission and
distribution plants.

In actual cents per kilowatt-hour, the rate for residential customers (average summer rates and winter
rates) increases from 8.36 cents to 8.76 cents. For those customers on the company’s residential time-of-
day program, the rate increases from 6.77 cents to 7.10 cents. For irrigation customers, the average rate
increase is from 6.68 cents per kWh to 7 cents.

--PAGE 17 --

The company was authorized to earn a rate of return up to 8.27 percent. The commission approved a
return on equity of 10.25 percent. The company requested 10.75 percent. Rocky Mountain Power is
currently earning on ROE of 5.3 percent and said a higher ROE is warranted to attract the capital
necessary to maintain its utility infrastructure.

Highlights of the settlement included:

An agreement with irrigators that those who participate in the company’s Dispatchable Irrigation
Load Control Program will get nearly twice as large a credit – from $11.19 to $23 – for every
kilowatt of peak demand reduced. That can be increased to $26 per kilowatt if total participation
reduces more than 150 megawatts of peak demand and $28 if total participation reduces more than
175 MW of peak demand. The program allows the company to remotely interrupt irrigation
service during peak times.
Agreements with Monsanto Corporation, the utility’s largest customer and Agrium, both based in
Soda Springs, that spread rate increases over three years and increase the amount of an
interruption credit granted Monsanto. Rocky Mountain originally proposed a 24.1 percent increase
for Monsanto and 14.5 percent increase for Agrium. The settlement allows a 13.5 percent increase
for Monsanto on Jan. 1, 2008, another 3 percent on Jan. 1, 2009 and 5 percent on Jan. 1, 2010.
Agrium will get a 6.25 percent increase on Jan. 1, 2008, another 3 percent on Jan. 1, 2009 and
another 7 percent on Jan. 1, 2010. Rocky Mountain further agrees to not increase rates for
Monsanto and Agrium beyond what is proposed even if the cost to serve those classes increases
before Dec. 31, 2010. If there are increases in cost of service to Monsanto and Agrium, Rocky
Mountain Power agrees to assume those losses and not propose they be assigned to other customer
classes.
An increase in the credit paid Monsanto for agreeing to have its electrical load reduced by the
company during peak operating times. Monsanto, an elemental phosphorous plant, consumes
about 1.4 million megawatt-hours of electricity, roughly 42 percent of Rocky Mountain’s Idaho
electrical load. Monsanto can provide up to 162 MW of electricity for the company by having
service to its three furnaces curtailed. Interruptions can occur within seconds to meet system
emergencies to provide operating reserves for the utility. For non-emergency curtailments, such as
economic curtailments, two hours notice to Monsanto is required.
The commission acknowledged that the percentage increases for street-lighting customers,
primarily cities, of about 75 percent is high, but the actual dollar amount is not excessive and is
needed to meet the cost of service to that customer class. Some city officials testified at hearings
and workshops in eastern Idaho, expressing concern about the street lighting increase. The
commission noted the actual dollar increase is not excessive, especially when considering that the
costs to serve the street lighting classes have increased by 80.7 percent since the last rate case.
“Cost of service results have historically fluctuated for the street lighting classes, more so than
larger customer classes,” the commission said, but noted this is the first proposed revenue increase
for street lighting classes in many years. “We find that moving the street lighting classes to full
cost of service is justified on equity principles. Should the increase not be borne by these
particular classes, the revenue shortfall would be shifted to those classes already receiving a rate
increase,” the commission said. “For street lighting customers, it is a large percentage increase, but
the related dollar amount, we find, is not likely to impose undue economic hardship.”
--PAGE 18--

What is the power cost surcharge (PCA)?
Customer rates are divided into two components, the base rate
and the power cost adjustment or PCA. (In the case of gas
utilities, this same mechanism is called the “purchased gas cost
adjustment” or PGA.) The normal costs for supplying power
are recovered in the utility’s base rates. However, a utility may
incur higher than normal costs from unusual circumstances,
such as low water conditions or higher than anticipated market
conditions. The PCA annually increases (through a one-year
surcharge) or decreases (with a credit) customer rates to
account for above-normal or below-normal power supply costs.
Yearly PCA adjustments, up or down, do not affect the utility’s
earnings. The money collected from the PCA is essentially a
pass-through, passing directly from the utility to its power
suppliers.
Simpler de inition: The base rate includes the cost of everyday
operations. The power cost adjustment includes the variable
costs of energy.

Dry year means higher PCA for Idaho Power customers
Case No. IPC-E-07-10, Order No. 30325
May 31, 2007

A dry winter and spring resulted in customers
of Idaho Power Co. paying more for power
supply. The Idaho Public Utilities
Commission approved Idaho Power Co.’s
application to implement a 0.24-cent per kWh
surcharge to pay for extraordinary power
supply costs not already covered in base rates.

The increase varied in size according to
customer class. Residential customers
received an 11 percent increase; small
commercial, 8.8 percent; large commercial,
16.6 percent; irrigation, 14.6 percent and
industrial, 22.5 percent. The average increase
for all customer classes was 14.5 percent.

Due to low water, the company’s hydroelectric dams cannot generate enough electricity to meet customer
demand, so the company must acquire power from other sources. The revenues from the one-year
surcharge go directly to pay for power supply and do not enhance company earnings.

In 2006, customers received an average 19.34 percent reduction in rates due to favorable water
conditions. Due to dry conditions in 2006-07, the company calculated its annual power costs were $77.5
million more than what was collected in 2005-06 PCA rates.

For an average customer who uses 1,050 kWh per month, the monthly increase was $6.41, according to
the company’s figures. Customers were getting a credit of 0.37 cents per KWh. Thus, the increase from a
negative 0.37 cents to a positive 0.24 results in customers paying a surcharge, an additional 0.61 cents
per kWh. Adding in the proposed PCA, the non-summer residential rate increased from 5.05 cents per
kWh to 5.66 cents.

The forecasted runoff from the mountains upstream of Brownlee Reservoir was 3.3 million acre-feet.
During 2005-06, the runoff was 8.4 maf. During an average year, the runoff is 6.3 maf.

The Industrial Customers of Idaho Power (ICIP) filed comments, agreeing with the company’s
calculations and stating the PCA be approved. However, ICIP wanted the PCA to be subject to refund
while the commission initiates a proceeding to modify the mechanism that calculates the PCA. ICIP
proposed a “balancing account” be left in the PCA that would reduce the volatility of the increases and
decreases to the PCA. Last year, industrial customers got a 27 percent reduction, while this year they are
getting a 22.5 percent increase.

Commissioners opposed the ICIP proposal. “The existing PCA methodology contains a true-up
mechanism so that customers will pay no more or no less than the PCA requires,” the commission said.

--PAGE 19 --

Commission OKs permanent PCA
mechanism for Avista

Case No. AVU-E-07-01, Order No. 30361
July 6, 2007

The Idaho Public Utilities Commission
approved a yearly adjustment to rates for
Avista Corporation that will allow the utility to
recover extraordinary power supply expenses
not already included in base rates. The yearly
Power Cost Adjustment (PCA) mechanism is
similar to one that has been in place for
Idaho Power Co. customers since 1993.

The yearly adjustment will increase or
decrease rates depending on conditions
outside the company’s control that can
dramatically alter power supply expense.
Those conditions include variations in hydroelectric generation cause by lack of
streamflows or unanticipated changes in fuel
costs or wholesale market prices for energy.

The updated PCA will be effective Oct. 1 of
each year. Each year when Avista files its
PCA, the commission will review the
application to make sure the power supply
and fuel expenses incurred by Avista were
necessary to serve customers and were the
most reasonably priced available to the
company at the time.

The true-up mechanism aligns Idaho Power’s year-ahead forecast of power supply costs with the actual
costs incurred during the year. If actual costs are higher than forecast, customers get a surcharge. If actual
power supply costs are less than forecast, customers get a credit. “We further find that the current PCA
methodology with its true-up mechanism provides customers with timely ‘price signals’ so that customers
have the opportunity to adjust their usage given higher PCA rates,” the commission said.

Avista allowed recovery of extraordinary expenses
Case No. AVU-E-07-07, Order No. 30429
September 14, 2007

The portion of Avista Utilities’ customer bills that goes
to pay for extraordinary power supply costs increased
by about 1.5 percent for residential customers – and 2.2
percent overall – beginning Oct. 1. For an average
residential customer who uses 1,000 kWh per month,
the increase is about $1.04 per month.

The surcharge was 2.45 percent, or about 0.163 cents
per kWh, and increased to about 0.267 cents per kWh.
The surcharge has been as high as 19.4 percent when
the Western energy crisis of 2000-01 caused
unprecedented increases in wholesale power prices. It
has been dropping steadily until 2007.

The surcharge does NOT affect company earnings and
does not go to pay salaries or finance any company
operations. The surcharge is essentially a “pass-
through,” collected from ratepayers, kept in a deferred
account, and then passed directly to wholesale power
and fuel suppliers. The commission’s job is to review
the surcharge request to make sure the power supply
and fuel expenses incurred by Avista were necessary to
serve customers and were the most reasonably priced
available to the company at the time. State statutes
require that regulated utilities recover all prudently
incurred expenses and earn a reasonable rate of return.

-- PAGE 20 --

Idaho Power rate case pending at year’s end
Case No. IPC-E-07-08

At year’s end, parties to an Idaho Power Company rate case were asking state regulators to approve a
settlement that increases rates for residential customers by about 4.7 percent and by about 5.65 percent for
all other customers. The annual revenue increase to the company, under the settlement, would be 5.2
percent.

When Idaho Power filed the case in June, it asked for an increase in annual revenue of $63.9 million, or
10.35 percent. The proposed settlement would allow the company an annual revenue increase of $32.1
million or 5.2 percent.

Idaho Power, commission staff and intervenors began participating in settlement discussions in late
October. Intervenors in the case include the Idaho Irrigation Pumpers Association, the Industrial
Customers of Idaho Power, Micron Technology, Inc, the U.S. Department of Energy and Kroger
Company. All the parties, with the exception of Kroger, signed the settlement. Kroger, which represents
the Fred Meyer and Smith’s Food King stores in Idaho, agreed with the majority of the settlement, but
wanted large commercial customers like itself to be afforded a Time of Use rate similar to that allowed
industrial customers.

The proposed increase for residential customers of 4.7 percent is very close to the company’s original 4.5
percent proposal. The company originally proposed a 15 percent increase for small commercial, 13.1
percent for large commercial, 15 percent for industrial and 20 percent for irrigation customers. Instead,
the settlement proposes a 5.65 percent increase for all those customer classes. The parties requested a
March 1, 2008, effective date for new rates.

The settlement proposed that issues not resolved in the case be addressed in discussions with commission
staff and interested parties before the company files its next rate case. Those issues include:

Deciding on whether to include actual, historical financial information during a 12-month “test
year” to determine a future rate or whether to use forecasted data. Historically, the commission has
approved only the use of historical data or a blend of historical and forecasted data. Idaho Power
favors using forecast data, arguing that continued load growth and infrastructure additions during
the pendency of a rate case results in the company being already revenue deficient when a new
rate is finally implemented.
Devising a mechanism that will either adjust or replace the current Load Growth Adjustment Rate.
The load growth rate is intended to compensate for additional revenues attributable to load growth
between rate cases. An amount related to load growth is subtracted from the company’s power
supply expenses during the Power Cost Adjustment (PCA) process, resulting in a lower PCA for
customers.
Updating Idaho Power’s “Irrigation Peak Rewards Program,” to encourage more participation
from irrigators. Currently, only about 10 percent of Idaho Power irrigation customers participate in
the program, which gives irrigators financial credits for agreeing to curtail their use during times
of peak demand. Irrigators want a larger credit and want to be able to participate in a dispatchable
program as well as scheduled curtailments.

--PAGE 21 --

What is the Bonneville Power
Administration?

The BPA is a federally owned wholesale power
marketer, selling electricity at cost to customers in
Oregon, Washington, Idaho and Montana. The
electricity is generated from a number of hydroelectric
facilities along the Columbia River and its tributaries.

Ninth Circuit Court decision suspends BPA credit

The biggest impact to electric rates during 2007,
particularly to Rocky Mountain Power customers in eastern
Idaho was not even tied to a rate case.

A panel of three judges on the Ninth Circuit Court of
Appeals in May declared that the Bonneville Power
Administration did not act in accordance with the law when
it negotiated a settlement regarding the distribution of
wholesale power and credits to electric utilities and customers in the Northwest. Because of the court’s
decision, BPA suspended the Residential Exchange Program (REP) credit to customers of investor-owned
utilities in four Northwest states.

For Rocky Mountain Power, suspending the credit resulted in an average 28 percent rate increase for
residential customers and a 51 percent increase for irrigation customers. To soften the blow for irrigation
customers, the company proposed and the commission agreed to immediately end the residential credit
and to use the remaining amount in the REP fund balance to carry irrigators through until the balance
zeroed out in about mid-July. The company maintained that residential customers had already received
the benefit during 2007 during the winter heating season, but irrigators had not received any benefit by
May’s end since the season was just beginning.

For Idaho Power, the result was a 9.3 percent increase for average residential customers or about $5.35
per month. For Avista customers, the residential increase was an average 9.5 percent.

The Idaho commission joined commissions in Oregon, Washington and Montana asking the Ninth Circuit
for a re-hearing on the issue. Re-hearings are granted in cases of “exceptional importance.” The
commissioners said this case easily meets that standard. “Indeed, it is difficult to imagine decisions that
would have more direct impact on such a large number of people,” the commissioners said.

The Northwest Power Act of 1980 requires that residential and small-farm customers in the Northwest
share in the benefits of the region’s federal hydroelectric projects. Customers of public utility districts,
such as rural co-ops and municipalities, typically benefit from the federal hydroelectric system with
preferential access to low-cost federal power provided by BPA. Customers of the region’s investor-owned
utilities, such as Idaho Power, receive their share of the benefit through a Residential Exchange Program
(REP) that results in financial credits on the electric bills of residential and small-farm customers.

The amount of the credit is determined by formulas using various factors, including a utility’s average
system cost for producing power. In 2000, BPA offered the region’s investor-owned utilities the option of
entering into a settlement in lieu of a more traditional REP calculation. Several public utility districts
challenged the settlement, alleging BPA had overstepped its authority under the Northwest Power Act and
that the result was too small a benefit to publicly owned utilities and too large a benefit to customers of
investor-owned utilities. The court ruled in favor of the public utility districts, eliminating the REP for the
first time in nearly 30 years until a new settlement can be reached.

--PAGE 22--

Wind issues continue to dominate
As was the case during 2005 and 2006, the increasing development of wind as an energy source posed
new questions for the commission, regulated utilities and wind developers.
IPC-E-07-03, AVU-E-07-02, PAC-E-07-07
A case that began in 2005 to determine the cost
to utilities to integrate wind transmission into
their respective electric grids was nearing
resolution at the end of 2007. Idaho Power, later
joined by PacifiCorp and Avista, received and
sought commission approval to suspend the
company’s federal obligation to buy wind
power from independent developers of small
wind projects to allow time to further examine a
fair price for wind given its unpredictable
output. The commission temporarily lowered
the size of non-firm wind projects that can
qualify for a published government rate from 10
megawatts to 100 kilowatts. (See definition of PURPA rate at right.)
Since then, Idaho Power Co., as well as the two other major electric utilities that serve the state, Avista
Corporation and PacifiCorp, completed studies to determine wind integration costs and later proposed that
the published rate for wind be discounted and that the size limit of projects that can qualify for the rate be
brought back up to 10 MW.

The three utilities differ on exactly how much the discount for wind integration should be, but the
proposals are in the $5 to $10 per megawatt-hour range. The current posted rate for generation from
renewable small-power projects, absent a discount rate, is about $64 per MWh.

The utilities also propose that wind developers reimburse them for the cost of state-of-the-art wind
forecasting services and, further, that developers provide guarantees that their wind projects are
mechanically able to generate at full output during 85 percent of the hours during a month. If the wind
developers agree to these provisions, the utilities would agree to support removal of the "90/110
performance band" now required in wind contracts. That requirement stipulated that when output was less
than 90 percent of projections or more than 110 percent of projections, that Idaho Power could pay
developers a market-based rate rather than the posted rate.

Commission staff conducted two workshops to explore whether the utilities and wind developers could
agree to a generic wind integration adjustment, but the parties were unable to settle. With the parties
unable to agree, the matter was before the commission for a decision at year’s end.

--PAGE 23--
What is PURPA?
Congress passed the Public Utility Regulatory Policies Act
during the energy crisis of the late 1970s. One of its stated
goals is to encourage development of renewable energy
technologies as alternatives to burning fossil fuels or
constructing new power plants. The federal act requires that
electric utilities offer to buy power produced by small power
producers or co-generators who obtain Qualifying Facility (QF)
status. The published rate to be paid project developers is set by
state commissions and is to be equal to the cost the electric
utility avoids if it would have had to generate the power itself
or purchase it from another source.

Cassia ‘redispatch’ process negates need for major transmission upgrade
Case No. IPC-E-06-21, Order No. 30414
August 29, 2007

The commission approved a negotiated settlement between wind developers and Idaho Power Co. on who
should pay for transmission upgrades required to accommodate about 200 megawatts of new wind
generation planned in the Twin Falls area.

A complaint filed by Cassia Gulch Wind Park and Cassia Wind Farm alleged that an Idaho Power plan to
require small-power producers to pay for nearly $60 million in transmission upgrades to accommodate
new generation threatened the economic viability of a number of wind projects and would stifle further
development of renewable energy in Idaho. The developer, Jared Grover, asked the commission to
determine that costs to upgrade the 138-kV transmission system in the Magic Valley be borne by all Idaho
Power ratepayers, not just small-power producers.

The settlement significantly reduced the amount needed to invest in transmission upgrade from $60
million to $11 million. Cassia agreed to install, at its expense, equipment and communication facilities
that will allow it to reduce its energy output to a predetermined point within 10 minutes of when Idaho
Power asks for a reduction. Under the proposed settlement, Idaho Power would issue a “redispatch”
notice to Cassia and other wind developers when it needs to act quickly to reduce transmission over-loads.

Idaho Power has the transmission capability to handle the anticipated 200 MW in new generation under
normal circumstances. However, existing transmission capacity is not sufficient to meet the company’s
required reliability standards during times of emergency, such as when transmission lines are out of
service. The willingness of Cassia and future wind generators in the area to be able to reduce output when
Idaho Power issues a redispatch notice will obviate the need to install major transmission upgrades.

The parties also proposed, and the commission accepted, a formula to pay for the $11 million in
transmission upgrades required to accommodate generation from Cassia and other anticipated wind
projects in the Magic Valley. Idaho Power will pay 100 percent of the costs for the first phase of the five-
phased upgrade. For the remaining four phases, 25 percent of costs will be provided by the developer and
25 percent by Idaho Power Co. The 25 percent provided by the company will be included in rate base for
future recovery from customers systemwide. The remaining 50 percent would be advanced by the
developer, but refunded over a term not to exceed 10 years after the projects are commercially viable. The
refunded amounts would then be included in rate base.

The transmission upgrades, Idaho Power said, will provide the company with a more robust transmission
system serving the Magic Valley and the Wood River Valley. Further, the generation Idaho Power
anticipates from other wind projects in the area, about 60 to 80 MWs, would satisfy a major portion of
future generation identified as necessary in the company’s Integrated Resource Plan.

-PAGE 24--

Commission allows daily adjustment to prices paid generators
Case No. IPC-E-07-04, PAC-E-07-07, PAC-E-07-13, AVU-E-07-02, Order No. 30415
September 11, 2007

The commission granted a request by utilities to adjust rates paid small-power producers so they more
closely match the actual value of energy at the point of time it is delivered.

The value of energy increases during peak demand times and decreases during light-load hours, yet
utilities maintain they must pay the same price to the small-power generator during light load hours as it
pays when the energy is delivered during heavy load hours.

In a related matter, the commission denied a request by utilities to place further restrictions on the
distance allowed between wind projects, or other small-power generation projects, which are owned by
the same entity.

Under the federal Public Utility Regulatory Policies Act of 1978 (PURPA), regulated utilities must buy
power from generators of renewable energy at a rate that is published by state utility commissions. That
rate, about $62.40 per megawatt-hour at the case’s filing, is called the avoided-cost rate and is typically
more attractive than market rates. The rate is to be based on the cost the utility avoids when it buys from a
PURPA project and thus does not have to generate the power itself or buy it from another source.

Utilities are already allowed a seasonable adjustment to account for the changing value of energy between
the various seasons of the year. But because the value of energy fluctuates hourly, Idaho Power Company
and Rocky Mountain Power petitioned the commission for a daily load shape adjustment, similar to one
granted Avista Utilities in northern Idaho. The revision does not change the computation of the avoided-
cost rate but could change the revenues received by small-power producers depending on the times during
the day they deliver their energy.

Idaho Power proposed a daily load shape adjustment of $11.63, as the weighted difference between light-
load hours and heavy-load hours. However, commission staff proposed and the commission adopted an
adjustment of $7.28. For Rocky Mountain Power, the difference, on average, is $7.18.

Idaho Power and Avista also asked the commission to adopt a rule, similar to one approved in Oregon,
which prevents utilities from having to pay the published avoided-cost rate when the same
owner/developer has small-power projects located within five miles of each other. Current federal
regulations state that projects must be at least one mile apart.

The utilities allege some wind developers build their projects at or near the size limit to qualify for the
published PURPA rate and then locate another similar-sized project close by and still qualify for the
published rate simply by creating a separate legal entity, although ownership does not change.

But the commission said the public interest would not be served by the more restrictive rule. “It is a
change that we find would encourage and might actually promote gamesmanship,” the commission said.

--PAGE 25 --

PUC modifies method to calculate rates paid small-power developers
Case No. IPC-E-06-29, Order No. 30220
December 28, 2007

Beginning Jan. 1, 2008, the amount utilities must pay small-power producers under provisions of the
federal PURPA act will be calculated under a different formula that is a compromise to an alternative
proposed by Idaho Power Co. and the view of wind advocates that the formula should be left alone.

In September, Idaho Power petitioned the commission to modify the method it uses to calculate the fuel
component of the avoided-cost rate. The fuel component, which accounts for more than half of the total
avoided-cost rate, varies as wholesale prices for natural gas fluctuate.

The fuel component was determined by using a 20-year forecast of natural gas prices issued by the
Northwest Power and Conservation Council (NWPC). The Idaho PUC averages the first three years of
that forecast and also includes a fixed 20-year escalation rate.

Idaho Power maintained that by using an average of the first three years of the NWPC forecast and a fixed
escalation rate over 20 years, the downward trend in natural gas prices forecast in future years was not
taken into account. The result is a rate that is higher than avoided cost, Idaho Power contended. A rate
higher than avoided cost negatively impacts customers, Idaho Power said, because costs for PURPA
contracts are passed on to customers.

Instead, Idaho Power proposed using an average of the entire 20-year forecast and eliminating the
escalation rate. Under Idaho Power’s proposal, a small-power producer who signed a 20-year contract in
2007 would be paid $67.77 per MWh, compared to $72.22 per MWh under the commission’s formula.

Wind groups and developers argued the formula should not be changed because Idaho Power’s proposed
method has never been tested. Wind developers said the commission should adopt a reasonable
methodology that produces the best rate for wind developers to restart PURPA development here and put
renewable projects at the top of the list of new generation in Idaho. Idaho Power said establishing an
avoided-cost rate to make wind projects profitable and stimulate PURPA wind industry is inconsistent
with the letter and spirit of PURPA.

The commission ultimately adopted a proposal offered by commission staff and supported by Avista
Utilities and Rocky Mountain Power to use each year of the council’s 20-year forecast “as is”, rather than
an escalated average of the first three years. Under that method, a 2007 contract would result in a payment
of $66.88 per MWh, compared to Idaho Power’s formula, which results in a $67.77 per MWh payment to
developers.

The commission agreed with Idaho Power that workshops should be scheduled to determine whether
other variables used to calculate avoided-cost other than just the fuel component need to be updated as
well.

--PAGE 26--

Idaho Power signs 20-year agreement with 100-MW wind project
IPC-E-06-31, Order No. 30259
February 27, 2007

The commission approved a major wind agreement between Idaho Power Company and Houston-based
Telocaset Wind Power Producers LLC. The agreement for 100 megawatts of wind energy generated from
a wind farm in eastern Oregon is needed to meet Idaho Power’s growing demand, the commission said.

“Moreover, the addition of wind generation to the western side of the company’s service territory adds
some geographic diversity to its growing portfolio of wind resources,” the commission said. Most of
Idaho Power’s wind projects are on the company’s eastern side, in south-central Idaho. Telocaset’s wind
farm is in eastern Oregon’s Union County near North Powder. Energy will be delivered to a point on the
La Grande-Brownlee 230 kV transmission line.

The 20-year sales agreement with Telocaset, sometimes referred to as the Horizon project, starts at a base
rate of $48 per megawatt-hour with an annual escalation rate of 3 percent. The levelized cost of the
contract over the entire 20 years is estimated at $62.38 per MWh.

The agreement has provisions similar to those included in the company’s agreements with small wind
projects that penalize Telocaset if output does not meet projections. The agreement provides that
Telocaset will deliver detailed forecasting data, including forecasts of energy to be delivered during the
next hour, day and week. The data will assist Idaho Power to integrate the wind power into the utility’s
resource supply mix. The project, scheduled to be operating by March 21, 2008, is expected to generate
its most output during those times of winter and summer when there is peak demand on Idaho Power’s
overall generating system.

The estimated cost of transmission upgrades and interconnection to Idaho Power’s transmission system is
$3.6 million. Of that, an estimated $2.3 million is the expense required to allow Telocaset to interconnect
with Idaho Power’s transmission system. Telocaset will pay all the costs related to interconnection. The
remaining $1.3 million is the estimated expense for upgrades to the company’s general transmission
system. Because those upgrades benefit all customers, Telocaset will be eligible to have that amount
refunded by Idaho Power after it makes the initial investment for those upgrades.

Idaho Power’s 2004 growth plan, called an Integrated Resource Plan, said the company would solicit bids
for 200 MW of wind energy. In September 2005, the request-for-proposals was revised downward to ask
for 100 MW because of the quantity of wind the company was getting from small-wind projects in the
state. Telocaset was selected as the preferred bidder from among seven bids representing 19 projects
between 45 MW and 200 MW. In its findings, the commission said the RFP process was “conducted in a
fair and reasonable manner” that resulted in the selection of the best proposal.

Three organizations, the Northwest Energy Coalition, the Renewable Northwest Project and the Idaho
Farm Energy Association submitted comments for the case record.

The Northwest Energy Coalition and the Renewable Northwest Project said the agreement would be
beneficial to both Idaho Power and ratepayers and furthers renewable energy in Idaho Power’s mix of

--PAGE 27--

energy resources. The rate is one of the most cost-effective of all generation sources identified in Idaho
Power’s long-range plan, the groups said.

The Idaho Farm Energy Association said the contract is a wise investment for ratepayers, but noted that
the project is a $160 million investment in a rural Oregon county while Idaho customers pay for the
energy. The organization said projects similar to this, which typically generate more than $1 million per
year in local economic benefits, are desperately needed in rural Idaho.

Commission approves delay for two wind projects
IPC-E-06-34 and –35, Order Nos. 30398, 30399
August 15, 2007

A wind developer was given another year to get two projects online before having to pay Idaho Power
Company damages.

The commission approved changes in two contracts with Hot Springs Wind Farm LLC and Bennett Creek
Wind Farm LLC that originally required the projects to be online by Dec. 31, 2007. The developer of the
projects, Energy Vision LLC, said unanticipated upgrades to Idaho Power’s transmission network are
needed before the Elmore County projects can be built. More time is needed to conduct the necessary
studies and built the interconnection facilities to accommodate the projects, Energy Vision claimed.

The delay in interconnection caused the projects’ investor and wind turbine supplier to reallocate the
turbines to other projects, forcing Bennett Creek and Hot Springs to wait for the next available turbines.
One of the contract amendments requires a modification of the type and size of wind turbines.

Both Bennett Creek and Hot Springs have agreed to provide Idaho Power with liquid security in an
amount sufficient to cover the delay liquidated damages in the event the projects do not meet new
deadlines. Idaho Power said it is aware of other wind projects facing similar delays and proposed that the
agreement with these wind farms be a template for similar resolution to other projects. However, the
commission declined that request, although it did accept the liquid security provisions for these two
projects.

Both projects will include 12 wind turbines that will deliver an average 10 megawatts per month. The
developer of both projects is Glenn Ikemoto of Energy Vision LLC, based in Piedmont, Calif.

Idaho Power-Alkali wind agreement approved
IPC-E-06-36, Order No. 30253
February 27, 2007

Idaho Winds LLC plans to build a wind generation project six miles northwest of Glenns Ferry. Its sales
agreement with Idaho Power Co. was approved by the commission.

The Alkali Wind Farm includes 12 turbines that will be operating by Dec. 31. Even though the maximum
output of the project is 18 megawatts, Idaho Winds will not generate more than 10 average megawatts on

--PAGE 28--

a monthly basis. Energy delivered in excess of that amount may be accepted but Idaho Power will not be
obligated to pay for it. The president of Idaho Winds LLC is Rick Koebbe of Boise.

The project is a Qualified Facility under the provisions of the federal Public Utility Regulatory Policies
Act.
The agreement does include provisions that require the project to pay Idaho Power damages if the project
comes on-line after Dec. 31. The delay damages will accrue for up to 90 days.
The project is also one of the first to come under changes in company’s interconnection tariff, including a
requirement that small-power producers enter into an interconnection agreement as well as a sales
agreement with the utility.
Idaho Winds has not yet signed an interconnection agreement with Idaho Power, but anticipates doing so
by year’s end. A feasibility study indicates that upgrades to both Idaho Power’s local distribution system
and transmission system are necessary. Costs associated with those upgrades could be reduced if other
projects in the area will use some of the same transmission facilities, although cost-sharing arrangements
have yet to be worked out.

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IRPs: Planning for the future
The commission requires regulated utilities to file an Integrated Resource Plan (IRP) every two years.
The 10-year growth plan projects future load requirements and how utilities plan to deliver low-cost,
reliable energy to its customers. The document is only a guide and not a commitment to resource
acquisition.
Idaho Power Company
Case No. IPC-E-06-24, Order No. 30281

Idaho Power Company’s 20-year growth plan calls for 1,300 MW of added generation from wind,
geothermal, coal and nuclear resources to meet the demands of its growing customer base.

The plan also calls for 187 megawatts of demand reduction through conservation and energy efficiency
measures referred to in the industry as demand-side management (DSM) programs. Idaho Power also
plans to gain access to an additional 285 megawatts as a result of transmission expansion and upgrades
that will bring in more power from the Pacific Northwest.

The commission said Idaho Power’s 2006 IRP is an improvement from prior filings, particularly in its
inclusion of transmission upgrade and expansion as a method to acquire new sources of energy supply.
“We are also pleased that the company is expanding its DSM programs and increasing the amount of
renewable energy resources in its portfolio,” the commission said.

The commission asked that Idaho Power and the two other major regulated utilities that serve the state –
Avista and PacifiCorp – consider jointly filing their IRPs in order to provide the commission with a more
regional view for resource planning.

Idaho Power projects its customer base will increase from 455,000 to more than 680,000 over the next 20
years.

The company recently entered into an agreement with the developers of an eastern Oregon wind farm for
100 megawatts to add to its growing wind portfolio. The company has increased its wind portfolio from
2.61 megawatts in 2004 to nearly 400 MW scheduled to be online by the end of 2008.

The plan includes a 250-megawatt coal addition in 2013. Idaho Power said it does not know specifically
where this addition will be located, but states that one of its best near-term alternatives is an expansion at
the Jim Bridger coal plant near Rock Springs, Wyoming. The plan also anticipates a possible 250
megawatts from a regional facility that would use an advanced clean-coal technology called Integrated
Gasification Combined Cycle. IGCC developers have expressed interest in Pocatello and Soda Springs as
possible sites for the advanced coal technology. Preliminary results indicate IGCC technology may be
viable, but the high initial capital expenditure and unproven technology may be barriers.

Idaho Power recently named U.S. Geothermal Inc. as the successful bidder for an approximate 45.5 MW

--PAGE 30--

of geothermal resources from a plant in eastern Oregon and one under construction near Raft River,
Idaho. Idaho Power is seeking to add a total of 100 MW of geothermal resources over the next 20 years.

The company also plans to acquire 150 megawatts through the use of combined heat and power, or
industrial cogeneration. Many manufacturers, such as lumber plants, produce steam as a byproduct of
their manufacturing process and can sell that steam generation to electric utilities.

In 2023, Idaho Power may be able to acquire 250 MW from an anticipated nuclear facility at the Idaho
National Laboratory in eastern Idaho.

Several organizations submitted comments for the commission to consider regarding Idaho Power’s IRP.

Citizens Protecting Resources, an organization formed in response to the proposed siting of a large coal
plant near Jerome, said the IRP did not include a strong DSM plan and didn’t place enough emphasis on
non-hydro renewable resources.

The Northwest Energy Coalition commended the company’s increase use of DSM programs, but
expressed concern about the amount of thermal resources that are proposed, such as coal. The coalition
said the company should consider more transmission improvements in southern Idaho to accommodate
additional wind energy.

The Industrial Customers of Idaho Power urged the commission to reject the plan because of its
inclusion of the Evander Andrews natural gas-fired plant near Mountain Home. ICIP said the company
should use emergency back-up generators during times of peak demand rather than building additional
plants. It also said the company focuses on transmission upgrades in the northwest but does not consider
more transmission access to markets east of its service territory.

The Idaho Irrigation Pumpers Association commended the company for a realistic plan and one that
included a diverse resource base. It urged the company to continue with its DSM programs for irrigators
and other customer classes.

Exergy Development Group of Idaho LLC, which develops wind generation, criticized the plan for
focusing too strongly on transmission upgrades to the Pacific Northwest, ignoring development to the east
and south. Idaho Power said transmission upgrades to the east have been proposed, but are not finalized.

Rocky Mountain Power
Case No. PAC-E-07-11
October 22, 2007

PacifiCorp, a six-state electric utility that operates as Rocky Mountain Power in eastern Idaho, plans to
serve its growing customer load in future years by adding about 2,000 megawatts of renewable power,
most from wind, over the next 10 years. PacifiCorp also plans additions to gas and coal facilities, though
none of those expansions are planned in Idaho.

--PAGE 31--

PacifiCorp, with about 68,000 customers in eastern Idaho, expects to grow at an annual rate of 2.5 percent
in its six states. Growth on the east side of the company’s territory, which includes Wyoming, Utah and
Idaho, is expected to be 3.2 percent. PacifiCorp anticipates 0.8 percent growth on its western side, which
includes Washington, Oregon and northern California. The company anticipates a 1.3 percent growth rate
in Idaho alone.

Of the 2,000 MW in renewable resources, the company plans 1,600 MW of that to come from wind farms
planned in Wyoming, Washington and Oregon.

Other sources include: 340 MW from a Utah coal plant in 2012 and 527 MW from a Wyoming coal
source in 2014; 548 MW from a natural gas combined cycle combustion turbine (CCCT) added in 2012
and another 357 MW from a gas CCCT added in 2016, both to be built on the eastern side of the
company’s territory. Another 602 MW would come from a CCCT natural gas combustion turbine built on
the company’s west side in 2011.

Another 100 MW will come from programs that reduce demand on the system, such as irrigation and air
conditioner load control programs. The company currently gains 150 MW in demand reduction from
irrigation and air conditioning load control programs in Utah and Idaho.

Commission staff noted that PacifiCorp is slightly behind on its renewables acquisition target, with 335
MW of the target 400 MW expected to be online by the end of this year. While the wind projects conform
to PacifiCorp’s commitments, the cost has been higher than anticipated, staff noted. “This is evident with
the three large wind projects expected to be online this year, each of which have capital costs far in excess
of those used as assumptions in the IRP,” commission staff said. However, commission staff continues to
support cost-effective wind generation to serve Idaho customers, noting that these projects do not come
with the price volatility that impacts fuel costs or the cost of mitigation requirements that come with
carbon emissions.

Some states in PacifiCorp’s territory now require the utility to procure a certain amount of its energy from
renewable resources. These “renewable portfolio standards” could impact the company’s Idaho
customers, even though Idaho does not mandate a renewable portfolio standard on its utilities.
Commission staff said the renewable standard will further constrain PacifiCorp’s resource acquisition and
may expose its Idaho customers to the financial impacts of resource decisions “based less on economics
and more on politics.” Staff urged the Idaho commission to become more involved in PacifiCorp planning
processes to ensure that Idaho ratepayers are well represented.

Monsanto, an elemental phosphorus plant based in Soda Springs and PacifiCorp’s largest customer in its
six-state territory, expressed concern that other states in PacifiCorp’s territory, namely Oregon and Utah,
have disproportionate influence on PacifiCorp’s capital procurements. Monsanto further stated the utility
should be required to increase its demand-side reduction programs, should avoid the development of new
gas-fired generation and look instead to nuclear generation and coal-fired generation using “clean-coal”
technology.

Without added generation, PacifiCorp anticipates a resource deficit during times of peak use as soon as
next year allowing for a 15 percent planning reserve of generation available in case of emergencies. With

--PAGE 32--

no added generation, the company anticipates it will be 791 MW short, based on a 12 percent planning
reserve.

Based on the company’s load growth plan, total generation from pulverized coal will decrease from 64.8
percent of the company’s power supply to 43.4 percent, while purchases of power from the market will
increase from 4.5 percent today to 17.1 percent in 2016. Generation from the company’s own renewable
energy sources is slated to increase from 3.6 of total generation this year to 8.5 percent in 2016. Power
from combined cycle gas plants would increase from 8.5 percent of the company’s generation today to
17.4 percent in 2016. Generation from hydroelectric resources would decrease from 9.6 percent in 2007 to
6.9 percent in 2016.

The company says it will assume a leadership role in global climate change issues and continue to
investigate the development of carbon reduction technology, specifically clean-coal technology,
sequestration and nuclear power.

Avista Utilities
AVU-E-07-08, Order No. 30464
November 27, 2007

Avista Utilities, which serves about 115,000 customers in north Idaho, will be looking to natural gas and
renewable sources of energy for added generation over the next decade. Avista plans on contracting with
a natural gas plant near Rathdrum for 350 megawatts. It also plans on adding 300 megawatts from wind
sources, 35 MW from other renewable resources and 87 MW from energy savings due to conservation.

Without the additional generation, the company would face generation shortfalls of about 83 average-
megawatts in 2011 and 272 aMW by 2017.

Avista decided to drop plans for future coal-fired generation for several reasons including legislation
barring its use in the state of Washington where the utility has most of its customers. The company also
anticipates federal legislation in the near future that will place further limits on carbon emissions. In
response to the anticipated problems with coal-fired generation, the company substituted fixed-price
natural gas resources for coal-based resources. According to Avista, it has the eighth-smallest carbon
footprint among major U.S. utilities.

The company had hoped for additional wind and other renewable sources beyond the 335 MW already
planned. But wind development, the company said, has been hampered by a dramatic increase in the cost
of wind resources since 2005. Recent legislation in Oregon, Washington and other states that mandates a
certain percentage of generation from renewable sources has increased the demand for wind turbines,
reducing their availability and increasing their price.
The additional 87 MW from conservation measures represents an 85 percent increase in conservation
since Avista’s 2003 IRP and a 25 percent increase over the 2005 IRP.

--PAGE 33--

Conservation, energy efficiency
New rate mechanism to encourage energy efficiency is among first in nation
for electric utilities
Case Nos. IPC-E-04-15, Order No. 30267
March 14, 2007

The Idaho Public Utilities Commission has approved a yearly rate adjustment designed to remove
financial disincentives for Idaho Power Company to implement energy efficiency programs.

The rate adjustment, called a Fixed Cost Adjustment (FCA), is approved only on a pilot basis, subject to
modification or removal by the commission.

Currently, when Idaho Power initiates programs designed to encourage customers to reduce their energy
use, it negatively impacts energy sales. If customers significantly reduce their consumption through
conservation efforts, the company may not recover its fixed costs of serving customers.

The FCA will be a yearly adjustment to electric rates that would prevent the company from losing money
when it invests in energy efficiency programs. Often referred to in the industry as “decoupling,” the FCA
removes the link between energy efficiency and energy sales by allowing the company to recover its fixed
costs regardless of the volume of energy sales.

Initially, the three-year pilot program applies only to residential and small-business customers.

When the commission sets rates, it determines the annual revenue needed by the company to recover its
costs. During the rate-setting process, the commission determines the fixed cost that should be recovered
from residential and commercial customers. The FCA mechanism will allow for a “true-up” between
fixed costs actually recovered through rates and the fixed cost amount authorized by the commission for
recovery in the company’s most recent rate case. If the fixed cost recovered were less than the authorized
fixed-cost rate, customers would get a surcharge that can be no higher than 3 percent. If the company
collects more in fixed costs than authorized by the commission, customers would get a credit. The
surcharge or credit would last one year when the FCA would again be updated. According to Idaho
Power’s estimates, the impact on rates for average residential customers would typically be $1 or less a
month. The fixed-cost adjustment would be made at the same time the company adjusts bills for its annual
power cost adjustment (PCA), which allows the company an opportunity to recover above-normal costs of
supplying power.

In exchange for removal of the financial disincentive, the FCA requires Idaho Power to significantly
increase the size and availability of energy efficiency programs and to support more energy efficient
building and energy codes.

The pilot program is the result of a negotiated settlement between Idaho Power, commission staff and the
Northwest Energy Coalition. In its comments, the Northwest Energy Coalition said “decoupling results in

--PAGE 34--

a better alignment of shareholder, management and customer interests to provide for more economically
and environmentally efficient resource decisions.”

The Idaho Citizens Action Network opposed the FCA mechanism as one that would allow Idaho Power to
receive additional revenue without any proof of need. ICAN sought a more thorough review of the
program and public hearings.

In its findings, the commission said the program will require close monitoring, which is why the FCA is a
pilot program. Many of the issues raised by ICAN will be considered in the commission’s assessment of
the program during the pilot period, the commission said.

“Promotion of cost-effective energy efficiency … is an integral part of least-cost electric service,” the
commission said. In addition to their environmental benefits, energy efficiency programs benefit all
customers because they reduce or eliminate the need for the power company to meet load growth by
adding new generation plants or buying additional power from the wholesale market.

IPC-E-06-32, Order No. 30268

On the same day the commission approved the FCA mechanism, it also approved a pilot program that
should encourage the construction of energy-efficient homes.

Idaho Power currently provides an incentive payment of $750 to builders for each home built to meet
energy efficiency standards set forth by the ENERGY STAR® Homes Northwest program. The pilot
program provides incentive payments or penalties to Idaho Power for meeting or not meeting specified
participation goals in the program. The company will provide marketing to encourage more participation
in the program. On average, homes constructed to the ENERGY STAR® standard in Idaho will save an
estimated 2,078 kilowatt hours annually, or 30 percent greater energy efficiency than existing Idaho
residential building codes.

Under this program, Idaho Power would receive an incentive payment if the market share of homes
constructed under the ENERGY STAR® program exceeds 7 percent of the total number of residential
building permits issued in Idaho Power’s service territory in 2007, 9.8 percent of total service area homes
in 2008 and 11.7 percent of total service area homes in 2009. The amount of the incentive would equal the
percentage that exceeds the target. For example, if Idaho Power were able to achieve 105 percent of the 7
percent target for 2007, it would receive a payment equal to 5 percent of the total program net benefits.
The incentive would be capped at 10 percent of program net benefits. Penalties would be levied for any
year Idaho Power fails to reach the market share of 4.9 percent program participation it achieved in 2006.
Impact on customers’ rates would be negligible.

The Industrial Customers of Idaho Power opposed the program, saying customers should not be required
to pay Idaho Power to induce it to implement cost-effective conservation activities. The Northwest
Energy Coalition endorsed the program because it is structured in such a way that Idaho Power will need
to show excellent performance in order to received incentive payments.

--PAGE 35--

Net metering customers will continue to get retail rate
Case No. IPC-E-06-17, Order No. 30227
January 30, 2007

Net-metering customers of Idaho Power Company who generate their own electricity and sell their
surplus back to the company will continue to be paid the full retail rate rather than a wholesale rate.
However, an order issued by the commission allows the company to include power supply expenses
associated with the net metering customers in its annual power cost adjustment (PCA) process for
possible recovery from ratepayers.

Idaho Power has about 27 residential and small-business customers who offset their own power
consumption by generating their own power with small hydro, wind or solar projects. Another 13
customers have pending requests for net-metering generation interconnects.

In August 2006, Idaho Power filed an application with the commission to pay net-metering residential and
small business customers an amount equal to about 85 percent of the wholesale market rate for electricity
rather than the full retail rate. In December, the company modified its application to leave the rate paid for
excess generation the same. The final order issued by the commission leaves the rate the same, but grants
Idaho Power’s request to recover expenses associated with the net metering program through its annual
power cost adjustment process. The order also grants the company’s request to remove a financial
impediment for customers in classes other than residential and small-businesses to participate in net
metering by removing a requirement that those customers have a second meter.

In its original application, Idaho Power asserted that excess generation from residential and small-
business net metering customers is “non-firm,” or intermittent. Thus, those customers should be paid the
same rate – a lower wholesale rate – as all sellers of non-firm energy. Under the current system of paying
full retail rate for excess generation, Idaho Power said it does not recover its full costs of providing
service to net metering customers and that those costs are shifted to the remaining residential and small-
business customers who do not have net metering. Customers do get the full retail rate for all the energy
that offsets their own consumption, but, the company believes that generation in excess of the customer’s
consumption should be viewed differently.

The commission said the amount of excess generation sold back to the company by net metering
customers is not substantial enough to warrant a revision to the tariff. The cumulative capacity of existing
net metering projects is 336 kilowatt-hours and the total amount paid for the projects’ excess generation
over the past 12 months was $23,102. “If this increased substantially, it would be necessary to reconsider
the pricing of excess generation. There is no need for that reassessment at this time,” the commission said.

The commission cautioned potential net metering customers against relying on continuation of the current
tariff when calculating their investment in net metering projects. “We must note that the net metering
program price is a tariff rate. It is not a contract rate. As a tariff rate, it is subject to change,” the
commission said. “A persuasive argument could be made that net metering customers are being
subsidized by other customers.”

--PAGE 36--

Rocky Mountain Power, CAPAI reach weatherization agreement
Case No. PAC-E-06-10, Order No. 30239
February 13, 2007

The Idaho Public Utilities Commission has accepted a settlement between PacifiCorp and the Community
Action Partnership of Idaho (CAPAI) that expands the scope of weatherization activities and increases the
utility’s share of expenses to install weatherization measures in low-income households in southeast
Idaho.

The settlement comes from an earlier settlement between the commission and various parties to
PacifiCorp’s recent rate case. PacifiCorp, which does business in eastern Idaho as Rocky Mountain
Power, agreed to provide CAPAI an opportunity to contest the terms of Rocky Mountain’s participation
in low-income weatherization programs. In exchange, CAPAI agreed not to contest the rate settlement.
CAPAI is a non-profit corporation consisting of six community action agencies that serve every county in
Idaho to fight the causes and conditions of poverty.

Under the terms of this settlement, Rocky Mountain has agreed to expand the scope of allowed
weatherization measures, more closely aligning them to the weatherization measures provided in the rest
of the state. For example, Rocky Mountain did not reimburse for repairs related to weatherization, such as
a leaky roof or a damaged window frame. Under the settlement, those expenses will now be reimbursed to
the community action agencies based in Idaho Falls and Pocatello that do the weatherization.

The company also agreed to increase its maximum reimbursement from 50 percent of the total cost to 75
percent when matching federal grants are available. If federal grants are not available, Rocky Mountain
will provide 100 percent reimbursement.

Rocky Mountain has weatherized more than 600 homes since 1988. Rocky Mountain’s total funding for
its weatherization is capped at $150,000 per year. Under the terms of the settlement, that cap remains the
same.

CAPAI has also agreed not to intervene in any proceeding with the intent of modifying the program
further for the next two years. At the end of the two-year period, Rocky Mountain will submit to the
commission and to CAPAI an evaluation of the program’s results, particularly its cost-effectiveness.

The Low-Income Weatherization Program is intended to reduce electric consumption and monthly bills
by increasing the efficiencies of low-income homes. The weatherization is provided at no charge to
participating households.

--PAGE 37--

Commission continues funding of weatherization program
Case No. IPC-E-07-09, Order No. 30350
June 26, 2007

Stage regulators have approved a joint application by Idaho Power Co. and the Community Action
Partnership Association of Idaho (CAPAI) to extend a weatherization assistance program for low-income
customers and non-profit organizations.

After Idaho Power’s 2004 rate case, the Idaho Public Utilities Commission approved a request by CAPAI
to increase the annual investment for weatherization from $200,000 to $1.2 million for the years 2004 to
2007. The commission said it would consider renewal of the Weatherization Assistance for Qualified
Customers (WAQC) program in 2007 after reviewing reports of the program’s progress.

During the last three years, the program has saved more than 6 million kilowatt-hours, according to
commission staff. Staff also determined that the savings-to-investment ratio per home (including the cost
of health and safety measures) is about $2 for every $1 spent. “The program has demonstrated that it is a
cost-effective means of implementing conservation measures and promoting energy efficiency,” the
commission said.

According to annual reports filed by Idaho Power, the number of buildings weatherized under the
program was 264 in 2004, 570 in 2005 and 540 in 2006.

AARP-Idaho and the Idaho Community Action Network filed comments in the case, both endorsing
extension of the program.
Commission staff also recommended that Idaho Power use the weatherization program as a vehicle to
deliver other conservation programs to qualifying customers such as compact fluorescent light (CFL)
bulbs and efficient appliances. The commission adopted a staff recommendation that the company
develop a tariff that would more easily allow community action agencies and the public to obtain
information about how the program is operated. The tariff would include eligibility requirements,
allowable energy conservation measures and a description of the program’s structure.

Commission OKs new load control program
Case No. PAC-E-06-12, Order No. 30243
February 15, 2007

The Idaho Public Utilities Commission has approved a second Irrigation Load Control Program for
customers of Rocky Mountain Power that could save up to 45 megawatts of demand on Rocky
Mountain’s system.

Under the program, eastern Idaho irrigators who volunteer to participate would get financial credit for
allowing Rocky Mountain Power to interrupt service during times of peak demand. This program differs
from an existing irrigation load control program in that the company can interrupt service remotely from a

--PAGE 38--

central network server in Boise. Rather than service interruptions taking place on a scheduled basis – as is
the case with the existing irrigation load control program – interruptions would be at the company’s
discretion. The network server will communicate with customers, using either cell phone or e-mail
technology to alert them of impending interruptions to service, or “dispatch events.”

The pilot program also differs from the existing program in that credits are yearly rather than on a
monthly basis.

Rocky Mountain Power will allow eligible customers to enroll on a first-come, first-served basis.

Total curtailment per participating customer would be limited to no more than 65 hours during the 2007
irrigation season per customer. Dispatch events would occur anytime between 2 and 8 p.m., Mondays
through Fridays during the irrigation season. Rocky Mountain Power will credit the bills of participating
customers at the end of the irrigation season. Participants can opt out of a dispatch event up to five times
during the 2007 irrigation season. If participants opt out more than twice, the credit paid to the participant
will be reduced by the replacement cost of the energy during the dispatch event.

Commission says Avista pilot program should benefit all customers
Case No. AVU-E-07-04, Order No. 30365
July 11, 2007

State regulators have approved a pilot program by Avista Utilities that should reduce the need for the
utility to buy power from the expensive wholesale market during peak demand times when energy is most
expensive.

The Idaho Public Utilities Commission approved the two-year pilot that would enlist volunteer customers
to agree to have programmable controllable thermostats attached to a number of their appliances, with air
conditioning units given priority. The program is limited to the Sandpoint and Moscow areas, but could
be expanded if needed to gain more participants.

At least four times during the year when electrical demand is at peak, Avista will declare a peak event
during which the thermostats would be used to control the use of appliances in the homes of volunteer
customers. Each of the peak events is expected to last for four hours, but can be extended to six hours
depending on power price and conditions.

Avista estimates the pilot will cost $123,000, but believes it will save at least $150,000 in power costs
during the peak-periods when the program is in place.

Incentives for customers to participate include upgraded equipment and their associated features they will
receive from the utility. Customers opting in for a programmable thermostat will receive a thorough
inspection of their heating, ventilating and air conditioning (HVAC) system. Customers with demand
response switches will also receive an audit of all equipment controlled by the switch plus a $10 a month
credit during July, August, December, January and February.

--PAGE 39--

Avista will evaluate the effectiveness of the program by examining energy savings, effectiveness of the
technology, customer acceptance, and interaction of peak demand on the company’s overall distribution
system. The company will also present a final report to the commission. Commission staff acknowledged
the proposed pilot is limited in scope, yet designed to obtain considerable information for a relatively
modest investment.

The commission commended Avista for its continued efforts to develop cost-effective Demand Side
Management (DSM) programs. Such programs are designed to curb electrical demand on the company’s
overall system, reducing the need for Avista to buy additional power during peak demand periods when it
is most expensive. Such programs can even delay the need to build new power plants. “The proposed
pilot programs, we find, should benefit all customers, both participants and non-participants,” the
commission said, resulting in lower customer bills, deferring the need for new supply sources and
reducing the company’s high-cost peak power needs.

Idaho endorses efficiency plan; Commissioner Smith co-chairs national effort
September 7, 2007

The Idaho Public Utilities Commission, along with other Idaho agencies, is joining in a nationwide effort
to enhance energy security and protect the environment by encouraging public and private entities to
implement energy efficiency measures.

The commission, the office of Idaho Gov. C.L. “Butch” Otter, the Idaho Energy Division and the state
Department of Environmental Quality are endorsing the recommendations of the National Action Plan for
Energy Efficiency.

The aim of the national plan, co-chaired by Idaho Commissioner Marsha Smith and Jim Rogers, president
of North Carolina-based Duke Energy, is to secure commitments from public and private entities in every
state to reduce energy consumption.

The plan’s recommendations, if fully implemented, could save Americans billions of dollars in energy
bills over the next decade, contribute to energy security by reducing the nation’s reliance on foreign oil
and improve the environment through reduced greenhouse gas emissions.

“Conservation is the lowest-hanging fruit in the energy orchard, and it’s our first priority in making Idaho
and America more energy independent,” Gov. Otter said. “Idaho has a great team in place, including the
PUC, DEQ, the Energy Division, and other agencies, working together to address a range of energy-
related issues from greenhouse gas emissions to ensuring the infrastructure is in place to more efficiently
and cleanly meet tomorrow’s needs,” the governor said. “Taking part in this National Action Plan is
another step in the right direction.”

The plan, initiated under the leadership of the federal Department of Energy and the Environmental
Protection Agency, was developed by a leadership group of more than 50 electric and gas utilities, utility

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regulators, state agencies, large energy users, consumer advocates and environmental and energy
efficiency organizations.

Idaho’s Public Utilities Commission has already taken a number of steps to encourage energy efficiency
in the state. “Energy efficiency is the cleanest, least cost energy available and can be obtained more
quickly than other generation resources,” said Commissioner Smith.

The commission, in cooperation with electric utilities, has implemented “demand-side management”
programs that reduce demand on electric generators during peak operating times, often with the use of
advanced metering technology. The commission has approved time-of-use metering, which allows
residential and irrigation customers to shift their electrical use to non-peak times of the day in exchange
for paying a lower electric rate. Residents can also volunteer to participate in a program that allows their
electric utility to remotely control customers’ air conditioning units during peak periods to reduce
demand.

The commission, working with customer groups and utilities, recently doubled the funding for
weatherization projects for qualifying homes. In cooperation with Idaho Power Co., the commission has
authorized a pilot program that removes the financial disincentive to utilities caused when conservation
programs reduce energy sales.

Energy efficiency measures like these reduce consumption while delaying and perhaps even preventing
the need to build new power plants. “We need to make sure we’ve explored all the cost-effective energy
efficiencies we can before we build additional electric generation sources,” said Commissioner Paul
Kjellander, president of the Idaho Public Utilities Commission.

The commission isn’t the only state agency actively promoting energy efficiency. The Idaho Energy
Division has for years promoted energy efficiency programs that reduce consumption. The Energy Star
Homes Northwest program for site-built homes and the Northwest Energy Efficient Manufactured Homes
program are both examples of new housing that reduces energy consumption by 30 percent over standard
construction, according to Bob Hoppie, energy division administrator. “These are just two efforts the
Energy Division is vigorously working on to support the National Action Plan,” Hoppie said.

The state’s Department of Environmental Quality has also formally endorsed the plan.

“Energy efficiency not only makes good economic sense, but also goes hand-in-hand with other statewide
efforts to reduce air pollution, conserve water and reduce greenhouse gases,” said Toni Hardesty, state
DEQ director.

Rogers, the Duke Energy CEO who co-chairs with National Action Plan with Commissioner Smith, said
the cheapest way to generate emissions-free power is improving energy efficiency. “The most
environmentally sound, inexpensive and reliable power plant is the one we don’t have to build because
we’ve helped our customers save energy.”

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Other electric cases
Commission rejects Avimor agreement; Avimor appeals to Supreme Court
Case No. IPC-E-06-23, Order No. 30322
May 24, 2007

The Idaho Public Utilities Commission denied a Special Facilities Agreement between Idaho Power Co.
and Avimor, LLC, the developer for a major housing project north of Boise.

The agreement called for Avimor to advance Idaho Power $4.3 million to allow the utility to build 3.4
miles of a 138-kV transmission line and a substation. Avimor would receive a refund of its entire $4.3
million if, within 10 years, 685 permanent residential services had been connected or electrical demand at
the development exceeded 6,850 kilowatts.

The commission said the agreement creates an undue risk that existing customers will have to pay for the
transmission line and substation. “The risk needs to remain with the developer,” the commission said,
particularly since the expanded transmission and distribution is necessitated solely by the Avimor project.

Idaho Power historically has not required an advance from residential developers to extend transmission
and distribution facilities, but the company said the agreement was needed here because of the speculative
nature of the development.

The commission agreed that an advance is necessary, but the amount Idaho Power would eventually have
to refund Avimor, at about $6,277 per customer, was too high. The amount currently included in base
rates for transmission and investment is $350 per customer. For newer developments, the customer
investment is about $1,000. All the refunds paid by Idaho Power to Avimor would be considered
investment and ultimately included in the calculation of customer rates. That led to concern by the
commission that the difference between the investment included in current rates and the estimated
investment for the Avimor facilities would require a subsidy by existing customers, causing upward
pressure on rates.

Noting those concerns, Avimor revised its application to allow it to receive refunds of $3,900 per
customer, requiring 1,103 customers to connect to the facilities within 10 years before it received a full
refund from Idaho.

Even Avimor’s revised application was still far above the amount currently included as investment in
customer rates, the commission said. The commission said the per customer refund amount should be
$1,000 rather than $3,900. “At that rate, 4,300 customer connections places a greater risk on the
developer, where it properly belongs, for the success of its project,” the commission said.

If 4,300 customers are not connected within 10 years, Avimor will not receive a full refund of
transmission and substation costs. The commission further stated that Idaho Power collect contributions

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from other developers who may connect to the facilities. The commission also rejected a proposal by
Avimor that interest accrue on the unrefunded amounts paid by Avimor.

The commission commended Avimor for incorporating energy efficiency measures into the community
development. Avimor plans to construct 585 homes in the first phase of the project that meet standards 30
percent more energy efficient than traditional construction. Further, it plans to build a treatment plant
capable of recapturing 300,000 gallons of wastewater for irrigation purposes. “Avimor correctly notes that
the commission has, for a number of years, encouraged Idaho Power to implement energy conservation
programs, and the Avimor project as planned is consistent with the commission’s objectives,” the
commission said.

Note: Avimor later petitioned the commission for reconsideration. The commission denied
reconsideration. In September, Avimor filed an appeal with the State Supreme Court. That case was
still pending at the printing of this report.

Commission wants more refinement of Avista disconnect plan
Case No. AVU-E-07-09, Order No. 30471
December 5, 2007

The Idaho Public Utilities Commission is looking for “further development and refinement” of a proposed
pilot program that would allow Avista Utilities to disconnect and reconnect power to customers from a
remote location. The commission wants Avista and parties who have filed comments in the case to
conduct workshops and then present a refined program for commission consideration.

Customer groups filing comments in the case fear remote disconnection of customers who are behind in
payments could result in increased disconnections and threaten the health and safety of some customers.

Avista, which serves about 115,000 Idaho customers from Grangeville north to the Canadian border,
proposes to install about 250 remote disconnect collars in rural areas and about 350 wireless meter
devices in urban areas of its northern Idaho territory. Customers selected for the one-year pilot program
would be those who have had multiple disconnects, are located in rural areas or otherwise occupy
premises where Avista employees may be at risk for entering customer property and manually performing
disconnects or reconnects.

Avista claims the program will reduce operating and maintenance expenses related to multiple
disconnection and reconnections, increase the productivity of its employees by eliminating multiple trips
to customer homes for collections, enhance employee safety, establish a quicker response time to
reconnect service and recognize a reduction in bill defaults and write-offs by encouraging prompt
consumer payment over time.

However, AARP Idaho said remote disconnection might increase the number of disconnections,
impacting health and safety, particularly if customers are disconnected during extreme weather
conditions. Currently, a utility employee visits a home before a disconnection, giving customers a final
opportunity to pay. The home visit also provides an opportunity for the utility employee to observe

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possible health and safety dangers, such as a customer using a respirator or other medical devices
requiring electric service. AARP Idaho said Avista does not specify how customers would be selected
for the pilot program and further stated that low-income seniors, ill and disabled customers and families
with young children should not be included.

Another customer group, that Community Action Partnership of Idaho, said the program may benefit
shareholders, but diminishes the level of service provided customers. CAPAI also expressed concern
about a dramatic increase in disconnects and the loss of an opportunity to make a final payment before
disconnection. CAPAI said the pilot might set a precedent for other utilities that don’t have as good a
customer service record as Avista.

Comments filed by commission staff recommend approval of the program as part of its effort to
encourage all utilities to use “smart meter” technology. But commission staff did express concern about
how customers would be selected. An advantage of the program, commission staff said, is that power can
be restored to a disconnected customer within minutes any time during the day or night and even on
weekends. Under the current method, it can take several hours before a utility employee can schedule a
home visit to restore power.

Whether the pilot is approved or not, Avista and all regulated utilities must abide by nearly all the
commission’s customer service rules regarding disconnection. A first disconnection notice is sent at least
seven days before the proposed disconnection date. A second notice is sent at least three days before
disconnect. Then a call must be made to the customer at least 24 hours before disconnection. Under the
pilot, Avista plans to continue providing written and oral notices. The only rule waived under the pilot is
the one requiring a utility employee to knock on the customer door to provide a final opportunity to make
a payment.

This case was still open at the publication of this report.

PUC allows transfer of Rocky Mountain Power customers to Fall River
Case No. PAC-E-07-12, Order No. 30381
July 26, 2007

About 72 households in Teton County that have been electrical customers of Rocky Mountain Power
became customers of Fall River Rural Electric Cooperative, Inc. on Aug 1.

The commission approved a petition by Rocky Mountain Power and Fall River Rural Electric to approve
the transfer of about half of Rocky Mountain’s customers in Teton County to Fall River. Growth in the
Teton County basin is increasing the potential for duplication of facilities, which presents operational
issues for both companies.

The transfer includes not only customers on the west side of the valley, but also equipment such as poles
and transformers from Rocky Mountain to Fall River, which is headquartered in Ashton.

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The transfer does not immediately impact rates because Fall River has agreed to serve the transferred
customers under Rocky Mountain’s rate structure for five years. Further, about 22 customers who
participated in Rocky Mountain’s Time-of-Day rate structure will be billed under the same structure by
Fall River. The Time-of-Day program gives customers reduced rates for shifting electrical use away from
peak-use times of the day.

Idaho statutes require that the commission determine the following when considering the sale or transfer
of any public utility property: 1) the transaction is consistent with the public interest, 2) rates will not
increase because of the transaction and 3) the buyer has the intent and financial ability to operate the
property in the public service.

Commission staff said reliability would improve for all customers with the transfer and that Fall River,
with 13,000 customers in Idaho, Montana and Wyoming, has been providing reliable service to its
customers since 1938. Because Fall River is a non-profit electric cooperative, the commission does not
regulate it. However, Rocky Mountain Power is an investor-owned utility and is regulated by the
commission. It has about 67,000 customers in southeastern Idaho.

Commission staff reviewed the application to ensure it complies with the state’s Electric Suppliers
Stabilization Act which is to discourage duplication of facilities, prohibit one utility from “pirating”
customers from another, stabilize service territories and promote harmony between electric suppliers.

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