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
2005 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
360,484 Residential Customers/$0.0633
69,642 Commercial Customers/$0.0486
121 Industrial Customers/$0.0353

Avista Utilities
2004 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
96,838 Residential Customers/$0.0647
15,426 Commercial Customers/$0.0653
502 Industrial Customers/$0.0414

2004 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
51,314 Residential Customers/$0.0408
7,228 Commercial Customer/$0.0601
5,436 Industrial Customer/$0.0345

--PAGE 13--

Rate adjustments

A good water year and softening wholesale gas prices led to both electric and gas rate decreases for Idaho
customers of major utilities during 2006

The commission approved a base rate increase for Idaho Power Co. customers of 3.2 percent. But
combined with a decrease in the annual Power Cost Adjustment of about 16 percent and the expiration of
a 2.2 percent tax adjustment, overall rates for Idaho Power decreased by 14 percent. A softening
wholesale gas market, nearly fully recovered from Gulf Coast hurricanes in 2005, resulted in a 3.8 percent
decrease in the Purchased Gas Cost Adjustment (PGA) for customers of Intermountain Gas (see page
40) and a 3.4 percent decrease for Avista Gas customers (see page 42).

Idaho Power rate case first in memory to be settled
Case No. IPC-E-05-28, Order No. 30035

On Oct. 28, 2005, Idaho Power asked the commission to approve a 7.8 percent increase in base rates.
Parties to the case, including commission staff, the Industrial Customers of Idaho Power, the Idaho
Irrigation Pumpers Association and several contract customers, entered into settlement negotiations. On
Feb. 27, 2006, the parties proposed a settlement for a 3.2 percent base rate increase and an $18.1 million
increase in annual revenue. The company originally sought a $44 million increase in annual revenue.
The commissioners commended the parties who “were able to compromise and settle the disputed issues
in this case.” Commissioners noted that this is the first instance in their recollection of an Idaho Power
rate case being settled.
These are the major components of the settlement:
The 3.2 base rate increase applies to all major customer classes, although the parties agreed that
the company’s model used to determine the cost of service to each customer class does not create
a precedent for any future rate case and the parties’ decision not to object to that model does not
preclude an objection to it in a future rate case.
The rate of return is 8.1 percent. The company originally requested 8.42 percent. The parties did
not set a return on common equity. The company proposed an ROE in the range of 11 to 12
percent.
The monthly service charge for residential and small commercial customers is increased from
$3.30 per month to $4. Idaho Power originally requested an increase to $6. Idaho Power agreed to
not file for an increase in the service charge for at least two years.
At the request of irrigation customers, Idaho Power agreed to convene a working group to review
the current operations and results of the Irrigation Peak Rewards program. (The case, IPC-E-06-
22), was filed in September and final order issued on Nov. 30, Order No. 30194. Changes to the
program included an increase in demand credits for irrigators and a reduction in the horsepower
limit to make irrigators using pumps rates at 75 hp (rather than the former 100 hp or higher)
eligible for the program.
--PAGE 14--

Finally -- a wet year! Customers benefit from record PCA reduction
Case No. IPC-E-06-07, Order No. 30047

Two weeks after the rate case order, Idaho Power filed its annual Power Cost Adjustment. Before the
2006 PCA, customers were paying about 0.6 cents per kWh surcharge for the PCA. After June 1, the PCA
was reduced to a credit that
subtracts 0.3689 cents per kWh
from the base rate. The overall
(base and PCA credit) non-
summer rate decreased from
6.02 cents per kWh to 5.05
cents, almost a full cent
reduction. The summer rate
decreased even further, from
6.69 cents to 5.73 cents per
kWh. The reduction for
commercial customers was
14.82 percent and 25.67 percent
for industrial customers.
Irrigation customers saw about an 18 percent reduction in their overall rate.
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 definition: The base rate includes the cost of everyday operations. The
power cost adjustment includes the variable costs of energy.

During 2006, with Snake River streamflows at 33 percent above the 30-year average, Idaho Power’s
annual power costs decreased by $123 million, which is $46.8 million below base rates. As the PCA
mechanism requires, 90 percent of that $123 million is credited back to customers and the other 10
percent to shareholders.

This year’s PCA represents the largest credit for customers since the mechanism was put in place in 1993.
It is also the first time, after six years of drought conditions, that customers received a credit rather than
being assessed a surcharge.

Avista base rates, PCA both stable
Case No. AVU-E-06-08, Order No. 30166; AVU-E-06-09, Order No. 30164; Case No. AVU-E-06-05, Order No. 30161

What is the Bonneville Power Administration?
The Bonneville Power Administration is a federally owned
wholesale power marketer, selling electricity at cost to
customers in four Northwestern states, including Idaho. The
electricity is generated from a number of hydroelectric
facilities along the Columbia River and its tributaries.
Residential customers of Avista Utilities received an approximate a 91-cent per month increase in electric
bills due to the expiration of a rate credit and about a 47-cent per month decrease due to an increase in
Bonneville Power Administration’s residential
exchange credit. Both adjustments became
effective Nov. 1.

The expiration of a credit given to customers
from the sale of the Centralia and
Skookumchuck power plants resulted in an
increase to average residential bills of about 1.45 percent. A second adjustment, an increase in the
Bonneville Power Administration (BPA) credit, reduced average residential bills by about 0.75 percent.

--PAGE 15 --

When Avista sold its share of the Centralia, Wash., power plant, customers were allowed to share in about
$7.5 million of the company’s net-of-tax gain. That credit was fully refunded to customers by Nov. 1,
requiring its removal. Added to the credit in 2004, was $154,000 from the sale of the Skookumchuck
hydroelectric generation facility, which supplied cooling water to the Centralia Power Plant.

While the Centralia credit expired, another credit, the BPA credit, increased.

The Northwest Power Act of 1980 requires that residential and small-farm electric customers share in the
benefits of the hydropower system, typically through a credit on their electric bills. The second half of a
10-year agreement (2001-2011) between Avista and BPA allows for increased benefits to Avista
customers. The credit increases from $4.12 per month to $4.59 per month for a customer who uses 1,000
kilowatt-hours per month.

Avista’s Power Cost Adjustment (PCA) was continued for another year at the same level, but must be
reviewed before it can be renewed again, the commission ruled.

The Idaho Public Utilities Commission approved Avista’ application for a 12-month extension of the 2.45
percent PCA surcharge, but expressed concern the surcharge is being continued to allow for projected
future power supply expenses rather than recovering only those costs directly attributable to the Western
energy crisis of 2000-01, the reason the surcharge was created.

Extension of the surcharge does not increase rates. It leaves the surcharge – about 0.163 cents per kWh for
residential customers – in place for another year. Revenues from the surcharge do not increase Avista’s
earnings. The surcharge is expected to raise about $4,268,000, which goes directly to pay debts Avista
owes its power suppliers.

The surcharge, originally at 19.4 percent, was implemented in October 2001 to allow the company to start
paying down a $78 million debt it incurred following the 2000-01 Western states’ energy crisis. In 2005,
with the debt down to $26.1 million, the surcharge was reduced to 4.38 percent. In April of this year, the
surcharge was reduced to its current level of 2.45 percent.

By June 30 of this year, the deferred balance was down to $1.5 million. But increased expenses that
Avista claims are due to a shortfall in hydro generation and to increasing gas fuel expenses for the utility’s
thermal generating plants, resulted in the deferral balance increasing to $3.2 million by July 31. The
company anticipated that by fall, the balance would have grown beyond the $4.3 million in annual
revenue the surcharge collects.

The commission said further study of the original intent of the surcharge and future methods for treating
extraordinary power supply expense are warranted before the surcharge can be renewed again. “We find
that the events that justified implementation of changes in PCA methodology, however, cannot be used to
support an unending continuation of the charges,” the commission said. “A thorough review and
examination is required.”

In the company’s current PCA filing, it uses a projected increase, rather than an actual increase, in power

--PAGE 16--

supply expense to justify its request to continue the existing surcharge level. “This recommended use of
projections is a significant departure from the approved PCA methodology,” the commission said.

The commission ordered the company and commission staff to conduct workshops to examine future
treatment of extraordinary power supply expense. Avista must file a report filed with the commission by
on or before August 15, 2007.

PacifiCorp, major parties reach rate settlement
Case Nos. PAC-E-06-04 (Order No. 30199) PAC-E-06-08 (Order No. 30196) PAC-E-06-09 (Order No. 30197)
The Idaho Public Utilities Commission in late December approved a settlement agreement between
PacifiCorp and major customer groups that will increase revenue to the company by $8.25 million
annually, or 5.1 percent. The agreement does not impact residential rates. The only customers to get an
increase will be irrigation customers (5 percent) and two industrial customers, Monsanto Company (16.5
percent) and Agrium, also known as Nu-West Industries, (4 percent).

PacifiCorp, which operates in eastern Idaho as Rocky Mountain Power (formerly Utah Power & Light),
serves about 64,000 Idaho customers.
The Idaho Irrigation Pumpers Association, Monsanto and Agrium, all agreed to the settlement. Rate
increases for irrigators and Monsanto are effective Jan. 1, 2007. Agrium rates, by an earlier commission
order, became effective Sept. 1, 2006.

The settlement prevented the need for PacifiCorp to file a full rate case before the commission. The
commission commended PacifiCorp and all the parties for reaching the agreement. “We acknowledge that
the stipulation … represents a compromise of party positions,” the commission said.

Irrigators will pay 5 percent more, increasing revenue for that class by $1.7 million. However, if irrigators
volunteer to participate in the company’s Irrigation Load Control Credit Rider Program, they will receive
a refund after the end of the 2007 irrigation season. Counting the refund, which totals $450,000, the net
average increase to irrigators is 3.7 percent. The increase to irrigators moves them $1.7 million closer to
the approximate $3.7 million in additional revenue the company claims is required for the irrigation class
to attain full cost of service.

Rates for Monsanto, PacifiCorp’s largest customer in its six-state area, increase by 16.5 percent, raising
$6.8 million. Monsanto, which operates an elemental phosphorous plant near Soda Springs, comprises
about 43 percent of PacifiCorp’s electrical requirement in Idaho. Electricity amounts to about one-third of
Monsanto’s total production cost.

A significant change in the Monsanto rate is the agreement by Monsanto to move from a contract
customer to a tariff customer. That means, as a tariff customer, Monsanto rate changes will take place
simultaneously with rate changes for other customer classes. Under the current contract, which expires
Dec. 31, rates for Monsanto would change only when a new contract was negotiated.

--PAGE 17--

Monsanto also agreed to an increase in the number of hours PacifiCorp can interrupt or curtail service to
Monsanto in order to meet demands on other sectors of PacifiCorp’s six-state service territory. The hours
service can be interrupted will be 1,000 annually compared to the previous 800 hours. Monsanto agreed to
increase the hours of interruption to offset what would have been a more substantial increase to its rates as
a result of a PacifiCorp cost-of-service study that concluded the revenue raised from Monsanto was about
$13 million under cost to serve it. The 16.5 percent increase in rates moves Monsanto $6.8 million closer,
or more than half way, to full cost of service.

The 4 percent increase for Agrium moves it $150,000 closer to the $428,000 PacifiCorp claims is needed
to serve that customer. Agrium produces phosphate fertilizer at facilities also near Soda Springs.

As part of the settlement, the Community Action Partnership of Idaho (CAPAI) agreed not to object to
PacifiCorp’s rate application if PacifiCorp also agreed to initiate a proceeding before the commission to
significantly increase the company’s contribution to low-income weatherization programs. CAPAI is a
non-profit corporation consisting of six community action agencies that fight poverty. The commission is
now considering, under a separate docket (PAC-E-06-10), whether the company’s policy of funding only
50 percent of weatherization costs for low-income customers is reasonable.

PacifiCorp also agreed to a one-time $10,000 contribution from shareholder money to two community
action agencies in eastern and southeastern Idaho to be used for the Lend-a-Hand program during the
2006-07 heating season. PacifiCorp further agreed to support legislation sponsored by CAPAI that would
give the Public Utilities Commission authority to approve utility-proposed low-income assistance
programs.

--PAGE 18--

Acquisition, reorganization

MidAmerican acquisition of PacifiCorp approved
Case No. PAC-E-05-08, Order No. 29973
MidAmerican Energy Holdings
Company's bid to acquire PacifiCorp,
which does business in southeastern Idaho
as Rocky Mountain Power, was approved
by the Idaho Public Utilities Commission
in February.
MidAmerican is a privately held Iowa corporation engaged primarily in the production and delivery of
energy from a variety of fuel sources including coal, natural gas, geothermal, hydroelectric, nuclear, wind
and biomass. MidAmerican's principal owner is Berkshire Hathaway, Inc, headed by billionaire investor
Warren Buffett.
Idaho was the third of six states to approve the acquisition before it became final. Before the acquisition,
PacifiCorp was a wholly owned subsidiary of ScottishPower. Under the acquisition, PacifiCorp becomes
an indirect, wholly owned subsidiary of MidAmerican, retaining its name and headquarters in Portland.
ScottishPower sold all of its PacifiCorp common stock, valued at $9.4 billion, to MidAmerican. That
includes $5.1 billion in cash and about $4.3 billion in net debt and preferred stock.
The acquisition is in the public interest, commissioners said, because of MidAmerican's desire to invest at
least $1 billion per year for the next five years in transmission and generation upgrades, its long-term
commitment to the utility business, its commitment to maintain or improve upon PacifiCorp's customer
service standards and its promise that rates will not increase as a result of the acquisition. Rates will not
increase for PacifiCorp's 60,000 customers in southeastern Idaho as a direct result of the acquisition.
The commission said there was no opposition from the public or intervening parties during the course of
the commission's seven-month analysis of the case. "This is our third merger-acquisition concerning Utah
Power & Light and the least contentious," the commission said. ScottishPower merged with PacifiCorp in
1999.
As part of the acquisition, MidAmerican agreed to abide by 52 commitments that apply to all six states in
PacifiCorp’s territory and another 36 commitments specific to Idaho. One of the Idaho commitments
grants Idaho customers $640,000 in rate credits in each of 2006 and 2007. Another requires PacifiCorp to
maintain its dedicated irrigation specialist in eastern Idaho. Another Idaho condition requires PacifiCorp
to establish a process to address the technical, economic and planning issues associated with the
development of integrated gasification combined cycle (IGCC) technology. IGCC plants convert coal into
a gas and then burn it, significantly reducing greenhouse gas emissions.

--PAGE 19--

Another commitment requires that none of the acquisition costs be included in PacifiCorp rates without
commission approval.
The agreement also includes, "ring-fencing provisions" which will isolate the credit risks of PacifiCorp
from the credit risks of MidAmerican or any of its subsidiaries. PacifiCorp will maintain its own
accounting system, maintain separate debt and its own credit rating. MidAmerican and PacifiCorp will
provide the commission access to all books of accounts as well as documents and records of
MidAmerican's affiliates. Neither PacifiCorp, nor its subsidiaries will, without commission approval,
make loans or transfer funds to MidAmerican or its affiliates or assume MidAmerican's obligations or
liabilities.
The commission also liked the fact that MidAmerican intends to own PacifiCorp for the long term,
leading to stability in ownership and investment in infrastructure. MidAmerican is uniquely suited to
make sizeable investment because it is privately held and, therefore, not subject to shareholder
expectations of regular, quarterly dividends and a fast return on investments. The PacifiCorp cost of debt
under MidAmerican, due to its association with Berkshire Hathaway, should be significantly reduced,
saving customers about $6.3 million over the next five years. Historically, MidAmerican’s utility
subsidiaries have been able to issue long-term debt at levels below their peers with similar credit ratings.
MidAmerican and PacifiCorp commit to contribute $40,000 annually for low-income bill payment
assistance to Idaho customers for a five-year period beginning July 1 this year. MidAmerican will also
provide shareholder funds of up to $66,000 to hire a consultant to study and then design a possible
“arrearage management project” with goals of reducing service terminations, reducing referral of
delinquent customers to third-party collection agencies, reducing collection litigation and increasing
voluntary customer payment plans.
The commission’s order approves a settlement agreement reached by parties in the case including
commission staff; PacifiCorp; MidAmerican; J.R. Simplot Co.; Monsanto Co.; the Idaho Irrigation
Pumpers Association and the Community Action Partnership of Idaho, which represents low-income
customers. The International Brotherhood of Electrical Workers and Idaho Power Co. did not sign the
settlement but do not oppose it.

Avista creates holding company
Case No. AVU-E-06-01 and AVU-G-06-01; Order No. 30091

The Idaho Public Utilities Commission approved Avista Corporation’s application to conduct a corporate
reorganization and form a holding company to be known as AVA Formation Corp.

Under the reorganization, AVA Formation Corp. becomes the parent company of Avista Utilities, which,
in northern Idaho, serves about 110,000 electric customers and 65,000 natural gas customers. The
majority of the Spokane-based utility’s customers are in Washington state.

--PAGE 20--

The commission agreed with findings of its staff that the reorganization should reduce financial risk for
the utility and improve its credit ratings.

The repeal of the Public Utilities Holding Company Act of 1935, often referred to as PUHCA, allows
utilities that operate in multi-state jurisdictions to form holding companies. The holding company
structure will provide additional protection for ratepayers by further separating the regulated utility’s
operations from the operations of other Avista subsidiaries that are not regulated. The protections, referred
to as “ring fencing,” are designed to ensure that ratepayers dollars are not used to subsidize unregulated
subsidiaries of Avista and that ratepayers are protected from the risks of Avista operating other non-
regulated businesses.

Avista stated in its application that the reorganization does not include the transfer of utility assets and
that Avista customers will not see any change in the utility or its operations. Avista Utilities will continue
to be subject to the Idaho Public Utilities Commission on matters impacting its Idaho customers such as
rates and customer service.

Commission staff said that a number of commitments in the stipulation between staff and Avista address
the need for ring-fencing around Avista Utilities, which will prevent the utility arm of the business from
being pulled into a parent corporation bankruptcy proceeding. Those provisions include the maintaining
of separate books and records for each Avista entity as well as granting commission staff full access to
books and documents pertaining to the regulated utility side as well as those of the unregulated Avista
affiliates and parent corporation. Both the parent corporation and Avista Utilities will be required to report
to staff and request commission approval when certain events occur, such as procurement of loans, the
spin-off of any entity, the dissolution of business activities, dividend payment arrangements and changes
in the credit ratings of each agency.

Another commitment prohibits Avista Utilities from making any dividend payments to the parent
corporation that would reduce Avista Utilities’ common equity capital below 25 percent of its total
adjusted capital without commission approval.

Utilities allowed to defer some expense from failed Grid West effort
Case Nos. AVU-E-06-03, Order No. 30151; IPC-E-06-06, Order No. 30157; PAC-E-06-03, Order No. 30156

Idaho’s three major regulated utilities will be allowed to defer costs they incurred in attempting to form a
regional transmission organization that ultimately was not created. The expenses were in the form of loans
made to the transmission organization called Grid West.

Establishment of the deferred accounts does not immediately impact customer rates. The commission will
determine the prudency of the expenses when each of the three regulated utilities files its next rate case.

The commission denied the utilities’ request that they also be allowed to recover interest that would
accrue on the deferred accounts. And the commission denied Idaho Power’s request to defer about $2.6
million in internal business expenses associated with the Grid West effort. (Idaho Power later petitioned
the Commission for reconsideration on the part of its order that denied the utility carrying costs of
about $191,000 on the deferral of Grid West expenses. The commission granted Idaho Power’s petition

--PAGE 21--

and, at the filing of this report, was waiting for more comments to be filed by Idaho Power.)

In response to orders issued by the Federal Energy
Regulatory Commission (FERC), utilities in the
Pacific Northwest were told to develop an
independent transmission operator, or Regional
Transmission Organization (RTO). RTOs are
designed to enable open and competitive
wholesale electric markets so that potential
competitors have the same access to regional
transmission grids as do established utilities.
What happens now that Grid West has failed?

Two new groups of transmission owners and interested
stakeholders have recently begun to address the efficiency,
reliability, planning, and expansion of the Pacific
Northwest’s electricity transmission grid.

ColumbiaGrid, a non-profit membership corporation with a
footprint covering Washington, Oregon, and northern Idaho,
formed in March 2006 with the following members: Avista,
Bonneville Power Administration, Chelan County Public
Utility District, Grant County Public Utility District, Puget
Sound Energy, Seattle City Light and Tacoma Power.
ColumbiaGrid will operate through Functional Agreements
entered into by its members and interested non-members.
The board approved the first agreement, Planning and
Expansion, in December 2006. Functional Agreements for
reliability and for a common queue for transmission service
requests are under development.

The Northern Tier Transmission Group consists of Idaho
Power, Rocky Mountain Power/PacifiCorp, NorthWestern
Energy, Deseret Power Electric Cooperative and Utah
Associated Municipal Power Systems, with a footprint
covering southern and central Idaho, Utah, Montana,
Wyoming, Oregon and northern California. Northern Tier
will address and coordinate regional transmission use and
planning under working groups guided by a steering
committee of transmission owner executives and state
regulators. The group has already entered into an agreement
to coordinate the sharing of regulation reserves and next will
address how to bring openness and transparency to the
regional transmission planning process.

In May 2006, the Federal Energy Regulatory Commission
(FERC) issued a proposed rule to reform the Open Access
Transmission Tariff required for all jurisdictional
transmission owners. The purpose of this reform is to further
competition and address the long-held goal of preventing
discrimination in the provision of transmission service to
both regulated utilities and to independent operators who
want access to the grid. The final rule FERC issues in 2007
will have an impact on the transmission work conducted by
both Columbia Grid and Northern Tier.

Grid West was proposed to serve as a non-profit,
independent transmission operator to manage and
control transmission in Washington, Oregon,
Idaho, Nevada, Utah and parts of Montana,
Wyoming and California. The Bonneville Power
Administration, which dominates ownership of
high-voltage transmission lines in the Northwest,
decided to withdraw from the Grid West effort.
PacifiCorp, after being acquired by MidAmerican
Energy Holdings Company, also withdrew due to
concern over costs, transmission operations and
other issues. Several utilities expressed concerns
that Grid West would mirror the experience of
RTOs in other regions of the country, which have
experienced higher than anticipated operational
costs.

Idaho Power sought a total deferral in its Idaho
jurisdiction of $3.35 million. Of that, the
commission agreed to allow the utility to defer
about $1,077,090. About 14 percent of that
deferral will be allocated the utility’s Oregon
customers. The $1.077 million excludes about
$197,000 in interest accrued through March 31 on
loans the company made to Grid West. The loans
ceased to accrue interest after that date. Idaho
Power will be allowed to amortize the deferral
over a five-year period beginning Jan. 1. 2007.

Avista, which has a much smaller customer base
in Idaho, loaned Grid West about $1.2 million, including $421,620 allocated to its Idaho jurisdiction. The
commission allowed deferral of $356,450 in Idaho after removing interest. Avista will also begin
amortization on Jan 1, 2007 over a five-year period.

--PAGE 22 --

PacifiCorp, which does business as Rocky Mountain Power in southeastern Idaho, loaned $2.7 million to
Grid West. The commission authorized a deferral of $174,000 for PacifiCorp’s Idaho jurisdiction.

Even though the effort to form a regional transmission organization has not been successful to date, the
commission said the utilities should be entitled to recovery of the amounts they loaned because they were
compelled by the

Federal Energy Regulatory Commission to participate in the development of an RTO. Had the RTO been
created, it would have acquired control of the region’s transmission facilities and implemented a
surcharge on transmission customers to repay the loans made by the utilities.

The commission agreed with the utilities’ contention that customers did benefit from the RTO formation
process.

Idaho Power said it gained experience in how an independent, regional transmission system operator
would be created and how it would manage a regional transmission system. Avista Utilities, as a result of
the RTO process, joined five other utilities to form a non-profit organization, ColumbiaGrid, to pursue
improvements to ways in which the region’s transmission providers operate and manage the system.

Customers to benefit from 90 percent of emission allowance sales
Case No. IPC-E-05-26, Order No. 30041

The commission approved a negotiated
settlement that grants Idaho Power customers 90
percent of the proceeds from Idaho Power’s sale
of emissions allowances. Customers would
benefit with nearly $70 million applied against
the annual Power Cost Adjustment (PCA),
beginning in the spring of 2007. The remaining
10 percent will be retained by the company as a
shareholder benefit.
Why emission allowance sales?
An amendment to the 1990 Clean Air Act establishes a
national program for the reduction of acid rain. Scientists
have determined that sulfur dioxide (SO2) and nitrogen
oxide (NOx) are the primary causes of acid rain. In the
United States, about two-thirds of all SO2 and one-fourth
of all NOx comes from thermal (coal and natural gas)
electric generating plants.

The PCA tracks the company’s above-normal or, as was the case during 2006, below-normal power
supply costs. The PCA appears as a surcharge or credit on customer bills to account for changing
streamflow and market conditions.

Idaho Power has sold 78,000 emissions allowances for about $81.6 million. The negotiated settlement
called for customers to receive about $42.1 million, after taxes, but commission staff and the U.S.
Department of Energy pointed that the after-tax credit to customers should be grossed-up to recognize the
tax savings that will accrue when the credit is actually provided to customers through the PCA. That
brought the customer allocation up to $69,126,518.

In August, the commission granted Idaho Power Co. blanket authority to sell its surplus sulfur dioxide
allowances. However, commission staff, Micron, and the Industrial Customers of Idaho Power were not

--PAGE 23--

able to agree on how much of those sale proceeds should be shared with Idaho Power customers. After
settlement negotiations, the parties were able to agree on a proposed settlement.

Under the federal program, thermal power plant owners are issued limited allowances for their plants’
sulfur dioxide emissions based on a specific plant’s past emissions and a nationwide cap placed on the
total amount of SO2 that can be emitted.

Each allowance authorizes the utility to emit one ton of SO2. At the end of each year, a utility generating
unit must hold allowances equal to its allotted annual SO2 emissions. A utility that holds over its annual
requirement is considered to have surplus allowances that can be sold on the open market or through
auctions sponsored by the Environmental Protection Agency.

Idaho Power has an ownership interest in three coal-fired plants: Jim Bridger in Wyoming, North Valmy
in Nevada and Boardman in Oregon.

--PAGE 24--

Wind issues dominate 2006
As was the case during 2005, the increasing development of wind as an energy source posed new
questions for the commission, regulated utilities and wind developers. 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.) At the filing of this report, the
commission was awaiting a study by Idaho
Power Co. on the costs of integrating wind into
its system.
The 100 kW limit does not apply to all PURPA
contracts, but only wind contracts that are not
“firm,” meaning they cannot be backed up by an
alternative energy source when wind fails to
generate the amount of energy the wind
developer commits to deliver to the power company. To ensure system reliability, Idaho Power stated that
intermittent wind resources must be “firmed” by backup power. An earlier company analysis concluded
that in order to safely integrate 1,000 MW of intermittent wind generation, it would be necessary to
concurrently add 640 MW of combustion turbines to provide capacity when wind resources were not
operating. Idaho Power said the added cost of backup power should be included in the calculation of rates
for wind. Wind developers argued that a performance band established by the commission in a 2004 case
that penalizes wind producers for not falling within 90 to 110 percent of their projected output sufficiently
deals with the firm vs. non-firm characteristics of wind.
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.

But the questions over a fair rate for wind did not seem to curb wind development in the state. By mid-
July 2006, the commission had approved 18 PURPA wind projects over 18 months. Combined, the
projects will have the capacity to generate up to 246.8 megawatts once installed. Over the same 18
months, the state of Idaho witnessed a 66 percent increase in PURPA project capacity due almost entirely
to the development of wind projects. Wind projects, when fully developed, will represent about 45 percent
of the state’s total 552.2 MW of PURPA capacity.
In addition to PURPA projects, Idaho utilities entered into negotiated wind agreements with independent
developers of projects too large to qualify for the PURPA rate. These projects are selected primarily
through a bid process. About 62.5 MW of wind have been added from the Wolverine Project, which sells
to PacifiCorp in eastern Idaho. In July, Idaho Power Co. named Texas-based Horizon Wind Energy as the
successful bidder for the development of a 66-MW wind project to be built in Union County, Ore., near
North Powder. The project is expected to be online by the end of 2007.
--PAGE 25--
Utilities, wind generators argue over transmission costs
Case No. IPC-E-06-21

A complaint filed by Cassia Gulch Wind Park and Cassia Wind Farm alleges that an Idaho Power plan to
require small-power producers to pay for nearly $60 million in transmission upgrades to accommodate
nearly 200 megawatts of new generation threatens the economic viability of a number of wind projects
and will stifle further development of renewable energy in Idaho.

The developer of the Cassia wind projects, Jared Grover, is asking the Idaho Public Utilities Commission
to determine that costs to upgrade the 138-kV transmission system in the Twin Falls area should be borne
by all Idaho Power ratepayers, not just small-power producers.

Cassia Wind Farm is a 10.5-MW facility with five, 2.1 MW turbines. Cassia Gulch Wind Park is an 18.9-
MW project that will include nine, 2.1-MW turbines. Both projects, in the Bell Rapids area near
Hagerman, were slated to be online by Dec. 31. Grover is not disputing developers paying for new feeder
lines and substations to interconnect with Idaho Power’s grid, but says the developers should not have to
finance upgrades to the “backbone” of Idaho Power’s transmission system.

Wind developers maintain that FERC does not require that QF projects pay all interconnection costs. It is
up to state commission to determine interconnection costs, the developers argue. The wind developers
argue that Idaho Power’s tariff for interconnection, Schedule 72, says QFs are responsible to pay for the
interconnection between the generation facility and the point of interconnection with the existing
transmission grid. The tariff does not address responsibility for upgrades beyond that point, the
developers say, adding that requiring new generators to bear the cost of grid upgrades discriminates in
favor of older, existing generators.

Idaho Power argues that requiring ratepayers to pay for interconnections costs would amount to a
ratepayer subsidy, violating the basic PURPA principle of “ratepayer neutrality” that says the cost to
ratepayers should be no greater for PURPA projects than if the power was generated by the utility itself or
purchased from another source. A decision favorable to the wind developers would result in more
favorable treatment than that given Idaho Power’s own generating units as well as independent, merchant
generation sources and could adversely affect the utility’s ability to require other developers to fund
system improvements, according to Idaho Power. The utility claims a decision for the wind developers
could result in economically inefficient siting decisions made by QFs because transmission costs are
ignored.

Idaho Power maintains the upgrade is needed to ensure system reliability when a loss of transmission in
some segments of the grid during a peak use period could create thermal overload on the lines remaining
in service. The wind generators argue that there are less costly means of preventing overloads than major
transmission upgrades such as curtailing predetermined amounts of generation during an outage.
At the filing of this report, the case remained to be resolved.

--PAGE 26--

East Idaho wind project gets commission approval
Case No. PAC-E-05-09, Order No. 3000
The commission approved a 20-year, $72.7 million sales agreement between PacifiCorp and developers
of the Schwendiman Wind LLC wind project 11 miles northeast of Idaho Falls.

The agreement was amended from an earlier agreement rejected by the commission because it did not
include performance provisions required in similar wind projects across the state to ensure that customers
receive the electrical generation for which they are paying.

Under the amended agreement, Utah Power will buy the net output of 7.15 average megawatts from the
project's eight 2.5 MW wind generators. The proposed agreement requires that output from the project fall
within 10 percent of its forecasted monthly capacity. If output falls outside that 10 percent, Schwendiman
will be paid only an energy rate with the capacity component reduced. The capacity component accounts
for about one-third the total energy rate.

Commissioner Marsha Smith issued a separate concurring opinion, agreeing with the commission
majority that the amended purchase power agreement is the result of negotiation and an amicable
settlement. However, Commission Smith has consistently opposed the use of a performance band that
applies a different payment method when generation fails to meet or exceeds output projections. “I
believe the banding requirements operate as a penalty, not an incentive,” Smith said. “I would have
approved the Schwendiman Agreement originally submitted in this case.”

The performance band provisions submitted by Schwendiman and PacifiCorp are different than
provisions in other wind contracts with regulated utilities. Idaho Power submitted comments expressing
concern that the Utah Power-Schwendiman provisions could impact existing or future agreements
between Idaho Power and wind developers. The commission said that is not the case. “Our decision in
this case sets no precedent for our future regulation of such agreements and is intended to provide no basis
for the amending of existing contracts,” the commission said.

The agreement requires Schwendiman to reimburse Utah Power’s costs for replacement power for up to
120 days if it fails to meet is operation date of July 31, 2007 and for up to 12 months if Utah Power is
forced to terminate the agreement in the event of a seller default.

Magic Wind attempts to get same agreement as Schwendiman
Case No. IPC-E-05-34, Order No. 30109
The commission denied a request from a Buhl wind developer to amend a sales agreement it had
submitted to Idaho Power Co. to match the one approved on the Schwendiman project in eastern Idaho
(see above item).
Magic Wind LLC, whose primary developer is Armand Eckert of Buhl, wanted to be paid for surplus
energy based on an alternative pricing method than has been used for other Idaho Power wind contracts.

--PAGE 27--

The commission ruled that because Idaho Power did not agree to the alternative pricing method, the utility
could not be forced to alter the sales agreement.

The commission ruling was unanimous, but Commissioner Marsha Smith issued a separate concurring
opinion.

Magic Wind plans to install eight 2.5-megawatt wind turbines eight miles northwest of Buhl. In August
2005, the commission reduced the size of projects that can qualify for the published rate from 10 average-
megawatts to 100 kilowatts. But because the Magic Wind project was already well on its way toward
development, the commission granted the developer’s request that the project be exempt from the size
limit.

Because wind output is not predictable, the commission in 2004 approved a “90/110 performance band.”
When output from wind projects falls under 90 percent of projected output or more than 110 percent, the
utility buying the wind is allowed to pay the developer less than the published avoided-cost rate. In that
2004 case, utilities argued for a lesser rate because when output is less than 90 percent, utilities must then
find power from other sources that can be more expensive. When output is more than 110 percent, utilities
said they might have to sell the energy in the surplus market or reduce output at a more economic
generation plant.

In this Magic Wind case, Commissioner Marsha Smith issued a separate concurring opinion stating her
continued opposition to the use of a performance band. “This case, however, is a question of which
contract terms may be required, not whether the performance band is appropriate,” she said. “I find it
persuasive that Magic Wind previously signed and submitted to Idaho Power a contract with the terms
that Idaho Power is now offering.”

All of the Idaho Power wind contracts to date have included provisions that when energy purchases fall
outside the performance band, the developer is paid 85 percent of the market price available at the time.
Magic Wind submitted to Idaho Power a wind agreement including that provision. Later it asked the
commission for a declaratory order requiring Idaho Power to pay Magic Wind for surplus energy under a
different formula than 85 percent of market price. Instead, Magic Wind sought to be paid for surplus
energy under a formula similar to one adopted in a sales agreement between PacifiCorp and the
Schwendiman wind project in eastern Idaho. The price for nonconforming energy in the Schwendiman
case is based on a fixed rate, not variable market rates. The fixed rate includes the use of the
commission’s already published avoided-cost rate along with an approximate 14.5 percent discount that
would be applied to nonconforming energy.

The commission approved the fixed-rate method in the Schwendiman case because it was reasonable and
both parties agreed to the alternative formula. The Magic Wind and Idaho Power case is different, the
commission said, because the parties are not in agreement. In its order approving the Schwendiman
method, the commissions said, “Our decision in this case sets no precedent for future regulation of such
agreements and is intended to provide no basis for the amending of existing contracts.”

Idaho Power said the Magic Wind proposal failed to acknowledge the role market prices play in
determining the cost Idaho Power is likely to incur should Magic Wind fail to meet projected output.

--PAGE 28--

Elimination of market prices from consideration shifts costs and risks that should be borne by Magic
Wind to customers of Idaho Power, the utility argued.

Magic Wind, other wind developers, the Renewable Northwest Project and the Northwest Energy
Coalition, argued that the contract terms demanded by Idaho Power are inconsistent with PURPA
regulations because they result in wind developers receiving less than the published rate. The
unpredictability of market prices makes it difficult for financial institutions to invest in wind, they argued.
Idaho Power said the performance band is not a computation of avoided cost, but a measurement of
damages. If a wind project performs as agreed, it receives the published rate. Idaho Power said its method
of pricing contracts has not discouraged investment in wind. The utility has signed 14 wind contracts
totaling 187 megawatts since the performance band was put in place.
(At this report’s publication deadline, the commission had yet to rule on Idaho Power’s application
for a sales agreement with Magic Wind under the original pricing method. The sales agreement has
since been filed as a new case, IPC-E-06-26.)
Commission approves sales agreements with four wind projects
IPC-E-05-30, 31, 32, 33

In early 2006, the commission approved Idaho Power Co. sales agreements with the developer of four
wind parks scheduled to be built in south-central and eastern Idaho. The developer of all four projects is
James Carkulis of the Montana-based Exergy Development Group. All four projects, if approved, were
slated to start producing energy in November 2006 and be in full operation by May 2007.

The four projects, all of which will be paid for delivery of 10 average-megawatts a month to Idaho Power,
include:

Milner Dam Wind Park (IPC-E-05-30) – Located about a mile west of Milner Dam (west of Burley) in
Cassia County, this project includes 12, 1.5-megawatt turbines.

Lava Beds Wind Park (IPC-E-05-31) – Located between Blackfoot and Arco, this project is also 12, 1.5-
MW turbines.

Notch Butte Wind Park (IPC-E-05-32) – Located between Twin Falls and Shoshone, this project is also
12, 1.5-MW turbines.

Salmon Falls Wind Park (IPC-E-05-33) – Located near Hagerman and south of Bell Rapids, this project
includes 14, 1.5-MW turbines.

The commission agreed with Idaho Power’s contention that the projects were sufficiently far enough
along in development that they should be grandfathered from a commission order in August 2005 that
temporarily reduced – from 10 average megawatts to 100 kilowatts – the size of projects that could
qualify for a rate published by the commission for renewable projects under PURPA provisions.
--PAGE 29--

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.
Case No. IPC-E-06-24

At the filing of this report, Idaho Power
Co. was seeking regulatory acceptance of
its IRP, which calls for 1,300 MW of
resource additions to meet the demands of
its growing customer base.
Idaho Power seeking approval of gas peaker

Case No. IPC-E-06-09
Idaho Power’s 2004 IRP included an additional gas peaker plant at
the existing 40-acre Evander Andrews Power Complex near
Mountain Home. The complex is already the home of two 45-MW
gas fired generators built by Idaho Power in 2001. The company
was waiting commission approval of the plant at the filing of this
report.

Idaho Power’s application includes a commitment cost of $60
million the company would like included in base rates if the
commission finds the costs were prudently incurred. Idaho Power
proposes that capital costs exceeding $60 million be absorbed by the
company and not passed on to customers. The commitment estimate
does not include an upper-limit estimate of $22.8 million to
construct transmission and substation facilities needed to
interconnect the project to Idaho Power’s transmission system.
Idaho Power’s 230 kV transmission system is about seven miles
from the Evander Andrews site.

After a bid process that included 31 proposals from nine companies,
Idaho Power selected Siemens Power Generation, Inc. to build the
plant, the same firm that constructed the company’s Bennett
Mountain Power Plant, also near Mountain Home. Once the plant is
built, ownership would be transferred to Idaho Power. If approved,
the plant is anticipated to be available to meet peak demand in the
summer 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 for expansion
at an existing coal plant is the addition of
a fifth unit at the Jim Bridger Plant. Idaho
Power owns a one-third share of the coal-
fired Bridger plant near Rock Springs,
Wyoming.

The IRP calls for 1,300 MW of resource
additions as well as conservation
programs designed to reduce peak demand
by 187 MW and average load by 88 MW.
Transmission upgrades, particularly to the
McNary-Boise transmission line, will
bring in more power from the Pacific
Northwest, adding another 285 MW of
capacity. McNary Dam, the source for the
McNary-Boise transmission line, is located near Umatilla, in north-central Oregon.

Idaho Power anticipates its customer base will increase from about 455,000 customers today to about
680,000 by the end of 2025, an increase of 11,000 to 12,000 customers each year.

The company’s immediate goals for the rest of 2006 were to conclude a 100-MW wind RFP, notify short-
listed bidders in a solicitation of 100 MW of geothermal electricity and initiate the McNary-Boise
transmission upgrade. In 2007, the company plans to bring 100 MW of wind on line. In 2008, the
company plans to acquire another 170 MW by expanding the Danskin natural gas plant near Mountain

--PAGE 30--

Home and evaluate and initiate more conservation programs. In about 2017, the company hopes to
acquire another 250 MW from a regional facility using 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. In 2023, Idaho Power may be able to acquire
250 MW from an anticipated nuclear facility at the Idaho National Laboratory in eastern Idaho.

Case No. AVU-E-05-08
Order No. 29943

In January, the commission accepted Avista Utilities’ 10-year plan to meet load growth. The plan relies
on 400 megawatts of wind, 250 MW of coal and 180 MW from other renewable resources by 2016 to
meet growing electrical demand.

The commission staff, which operates separately from the commission, commended Avista on its
commitment to renewable sources, but noted it may be too early to determine where Avista will be able to
get its power. “It is important to recognize that new resource additions are not needed for several years.
Consequently, the quantity and mix of Avista’s resource selections will likely change in future IRPs as
conditions change, fuel prices become more certain and technology advances,” said commission staff in
written comments.

Staff also encouraged the company to continue to include transmission planning into its long-range
planning process. Cooperation with regional power entities and transmission planning will allow the
utility access to more low-cost power across the Northwest, commission staff said.

The Renewable Northwest Project and the Northwest Energy Coalition also filed comments, commending
Avista’s plan to rely more on renewable, rather than thermal, resources. The organizations asked that
Avista delay any commitments to coal plants until further research into clean-coal technology and
emissions sequestration is completed.

Avista projects it will grow to 350,000 customers in its three-state territory by 2007 – up from the current
approximate 330,000 – and to 485,000 customers in 2026. There are about 110,000 customers in northern
Idaho.

Without adding to its generation, the company would begin to experience energy deficits in 2010.

To meet growth, the company’s preferred resource portfolio by 2016 is a mix of generation sources,
including 400 megawatts of wind, 250 MW from coal and another 80 MW from small renewable projects.
The company is not proposing any additional natural gas-fired generation due to the high level of natural
gas generation already in the company’s portfolio, the rising price of natural gas and the volatility that
creates.

--PAGE 31--

Resource requirements are 69 MW lower because of planned conservation programs and 52 MW lower
because of efficiency upgrades to existing generating plants.

By 2026, the company plans to have added a total of 1,332 MW of new capacity. Of that 650 MW would
come from wind, 450 MW from coal, 180 MW from other renewables and 52 MW from efficiency
upgrades. Needs would be 138 MW lower due to conservation programs.

The company currently has about 1,663 MW of installed capacity, 979 MW of that coming from
hydroelectric projects and 683 MW from thermal sources, primarily natural gas.

Avista is also in the process of implementing a transmission upgrade plan to add more than 100 circuit
miles of new 230 kV transmission line and will later increase its capacity another 50 miles. The company
is also building two new 230-kV substations and upgrading three existing transmission substations.
PacifiCorp’s IRP, accepted in 2005, plans to meet projected electrical demands by adding three natural
gas power plants and two coal plants in its six-state territory and increasing its capacity through
conservation programs. In addition to the new coal and natural gas plants, PacifiCorp is continuing to
pursue a commitment to procure 1,400 megawatts in renewable resources, such as wind.
PacifiCorp projects an annual growth in electrical demand of 3.8 percent in its three eastern states (Utah,
Wyoming and Idaho) and 1.5 percent in its western states (Oregon, Washington and California). Without
developing further resources, the utility would face a shortfall by 2009 and be 2800 MW short by 2015.
The company proposed to add 2,629 MW from two coal and two natural gas plants in its eastern territory
and one natural gas plant in its western territory. None are proposed in Idaho. PacifiCorp also proposes to
add 1,200 MW in purchased power from other suppliers and 100 MW in contracts from small-power
producers through federal PURPA requirements. It also proposes the addition of 177 MW from load-
control programs involving residential and commercial air conditioners, irrigation and commercial and
industrial lighting. PacifiCorp hopes to produce 250 average megawatts in energy and capacity savings
achieved through technological improvements in appliances, equipment and buildings.
Two major issues impacting PacifiCorp’s resource choices are the future cost of natural gas and the future
cost of or constraints on air emissions – carbon dioxide emissions in particular – that may be imposed on
the company by government regulation.

--PAGE 32--

Conservation, energy efficiency
De-coupling: Case seeks to remove financial disincentives to conservation
Case No. IPC-E-04-15

State regulators, Idaho Power Company and representatives of environmental and industrial groups
engaged in discussions during 2006 over the establishment of a rate mechanism that will remove financial
barriers to utilities that want to invest in and encourage energy efficiency and conservation programs.

Idaho Power, like other electric utilities, recovers most of its fixed costs of doing business through the
rates it charges customers. The Idaho Public Utilities Commission sets rates based on assumptions that
project a utility’s annual sales. If energy efficiency programs are successful, electrical demand is
decreased and sales decline. If sales lag below rate case assumptions, the utility may not recover its
commission-approved fixed-cost revenue requirement, which can be harmful to a utility’s financial
performance

Following Idaho Power’s 2003 rate case, the commission opened a new case to investigate financial
disincentives to utility investment in energy efficiency programs. Commission staff, representatives from
the company, the Northwest Energy Coalition and Industrial Customers of Idaho Power participated in
workshops to address the issue.

Idaho Power has filed an application and testimony favoring an annual “Fixed-Cost Adjustment,” that
“decouples” or separates utility sales from revenue so there is less of a disincentive for companies to
invest in energy efficiencies. The Fixed-Cost Adjustment, if implemented, would annually adjust rates up
or down to recover the difference between the fixed costs authorized by the commission in the most
recent rate case and the fixed costs the utility actually recovered from customers during the previous year.

With the use of this proposed rate mechanism, the utility is less impacted by decreases in energy sales,
thus removing any disincentives for utilities to aggressively pursue opportunities to reduce electric
consumption.

A study of Idaho Power’s fixed costs collected and fixed costs allowed by the commission over the last 10
years shows that residential and small-commercial customers would have received increases during some
of those 10 years and decreases in other years. The study showed that the average monthly impact to a
residential bill over the entire 10-year period was a 64-cent increase. To the average commercial
customer, the monthly impact was a 31-cent increase.

Idaho Power is proposing that the initial Fixed-Cost Adjustment apply only to residential and small-
commercial customers and that a cap allowing no more than a 3 percent increase be allowed even if there
were years when the difference between actual sales and fixed costs allowed was greater than 3 percent.

--PAGE 33--

Customers benefit from energy efficiency programs because they preclude or delay the need for building
new power plants, preclude or delay expansion of distribution and transmission facilities, reduce electrical
demand during peak periods when power is most expensive, reduce pollution and provide other
environmental benefits.

If approved, the FCA adjustment would likely be made at the same time as the yearly power cost
adjustment, or PCA. The PCA annually adjusts rates up or down to account for above-normal or below-
normal power supply costs.

Commission OKs efficiency rider for PacifiCorp customers
Case No. PAC-E-05-10, Order No. 29976

In March, the commission approved a 1.5 percent rider to the bills of PacifiCorp’s 62,000 customers in
southeastern Idaho to fund energy conservation programs. The commission believes the DSM (demand-
side management) rider is cost-effective for customers because the efficiency programs preclude or delay
the utility’s need to build additional power plants or buy power from other sources to meet growing
customer demand.

The rider will add about $1 to the monthly bill of an average residential customer who uses 790 kilowatt-
hours a month. The commission approved the rider, which became effective May 1, on a 2-1 vote with
Commissioner Dennis Hansen dissenting from Commissioners Paul Kjellander and Marsha Smith.
Hansen said he supports well-planned DSM programs, but believes one of PacifiCorp’s programs to pay
customers to dispose of inefficient refrigerators and freezers is not cost-effective.

The commission delayed approval of an earlier proposal by PacifiCorp because the array of programs
offered provided more benefit for other customer classes than they did for the residential class. The
company later submitted a revised proposal that provides a Home Energy Efficiency Incentive program
for residential customers.

Some of the programs offered will include:

An irrigation efficiency program to complement an existing irrigation load control program. The
program offers irrigators no-cost equipment exchange, equipment testing and financial incentives
for energy efficiency measures.
Energy efficiency measures for commercial and industrial customers that include efficient
lighting, premium motors and mechanical upgrades associated with heating and cooling.
Incentives to promote home energy efficiencies involving appliances, water heaters, lighting,
heating and cooling equipment, windows and insulation. More specific details of this program are
to be submitted to the commission by no later than April 30.
A refrigerator-recycling program for residential customers called “See Ya Later Refrigerator.” The
program offers incentives to homeowners and landlords to discontinue use of second refrigerators
and freezers or replace them with more energy efficient models.
An increase in Utah Power’s low-income weatherization program to $150,000 from $100,000 and
an increase in the maximum rebate allowed per weatherized home from $1,000 to $1,500.

--PAGE 34--

The commission said cost-effective DSM programs provide benefits even to non-participants because the
programs reduce the company’s overall cost of serving its customers. It also benefits all Idaho customers
by reducing Idaho’s allocation of PacifiCorp’s power supply costs in its six-state territory.

Rocky Mountain Power will be required to file a report with the commission demonstrating the programs’
cost-effectiveness. All expenses related to the programs will be kept in a deferred account and rebated to
customers or invested in new programs if the programs proposed by the company are not found to be
cost-effective.

Idaho Power allowed to continue with net metering programs
Case No. IPC-E-05-00, Order No. 30037

In May, the commission granted Idaho Power Company’s request to extend for another year two energy
conservation programs offered in the Emmett area.

The pilot programs, Time-of-Use and Energy Watch, are available to customers who volunteer to
participate and have advanced meter readers installed.

Advanced meter readers (AMR) can be read from a remote location without having to enter a customer’s
property and can provide the company and customer with hourly meter readings. Some AMR systems
have the ability to inform customers of current electric prices, potentially allowing them to manage their
electrical use and reduce their bills.

The commission agreed with the company that the extra year is needed to collect more data and provide
further evaluation before the programs can be expanded to serve a larger section of Idaho Power’s
territory. “We believe the time-of-use pricing pilots to be important programs with potential benefit to
both customers and the company,” the commission said.

Under the Energy Watch Pilot Program, Idaho Power allows volunteers to pay the less expensive non-
summer rate (5.08 cents per kWh) instead of the summer rate (5.72 cents per kWh) except during the
company’s selected Energy Watch periods, when the rate is 20 cents per kWh. The company notifies
volunteer customers either by telephone or by e-mail by 4 p.m. a day before the Energy Watch period.
Energy Watch periods can occur on any weekday from June 15 through August 15 for four hours between
5 and 9 p.m. Energy Watch periods will occur on no more than 10 days from June 15 to August 15 for a
total of 40 hours.

The Time-of-Day Pilot Program allows volunteers to shift their use to off-peak periods when the rate is
lower. In order to increase the financial incentive for customers to participate, Idaho Power is increasing
the difference between off-peak and on-peak rates.

In another minor change from last year’s programs, Idaho Power proposed to limit those who can
participate to customers who use 300 kilowatt-hours per month or more. The commission said limiting the

--PAGE 35--

programs’ availability to customers with the capability to shift loads significant enough to gain valuable
statistical information is reasonable.

Idaho Power reports that customers in the Time-of-Day program saved about 5 percent on their bills
during last summer and customers on Energy Watch saved about 10 percent. The Energy Watch
participants were able to cause a statistically significant reduction in Idaho Power’s overall load
requirements during peak hours when power is most expensive.

--PAGE 36--