COC IDA 08 Update.pdf

Please see page 16 for rating definitions, important disclosures and required analyst certifications.
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IDA121608-093949

A publication of
WACHOVIA CAPITAL MARKETS, LLC

Equity Research
IDACORP, Inc.
Regulatory Improvements Pique Our Interest; Estimates Raised
But Holding Out For A More Attractive Entry Point

• Recent Improvements To Key Regulatory Principles Are Encouraging. Key
changes include the use of a 95/5 sharing formula (versus 90/10 previously) in the
power cost adjustment (PCA), which should lessen, but not eliminate, IDA’s
exposure to fluctuations in hydro conditions, improvements to the load growth
adjustment rate (LGAR), the initiation of an Oregon PCA mechanism, and the use
of forecasted data in ratemaking, among other improvements. These changes
should make it possible for IDA to earn closer to its allowed return on equity
(ROE).
• EPS Outlook. We expect IDA to increase EPS at an annual rate of 5% through
2012 (off of a 2008E EPS base of $2.25). We increased our 2008E EPS to $2.25
from $2.10 based on stronger-than-expected Q3 results and increased our 2009E
EPS to $2.40 from $2.30 on earlier-than-expected regulatory improvements,
partially offset by recessionary pressures, such as lower-than-expected sales
growth. Our 2010-12 EPS estimates are $2.45, $2.65, and $2.70. Assuming the
construction of a combined-cycle gas plant and two major transmission projects,
annual estimated EPS growth of 5% could extend through 2015, in our view.
• Rate Case Update. IDA expects an Idaho Public Utility Commission (IPUC)
decision in its pending general rate case (GRC) in February. Currently there is a
material $57 million difference between the company’s $67 million request and the
Staff’s recommendation. However, the staff and IDA are not worlds apart on the
return on equity (ROE) (the staff recommends 10.25%; IDA requested 11.25%).
• Capex Plans And Financial Position. While lower expected demand and tight
credit markets have prompted management to scale back near-term capex plans,
IDA still needs to make significant investment to maintain reliability and replace
and upgrade aging infrastructure. We expect IDA to fund its capex plan with a mix
of internally generated funds and external debt and equity issuances. Our model
assumes the issuance of an incremental $85 million of equity through 2009, in large
part through its continuous equity program, followed by another $50 million in
2010. Post 2010, we expect more sizeable debt and equity issuances to fund
additional capex, including two major transmission projects.

Valuation Range: $30 to $32
We value IDA under P/E multiple (apply a 12x multiple to our 2009E EPS of $2.40)
and dividend discount analysis, which indicate a 12-18 month valuation range of $30-
32 per share. Risk to our valuation analysis include project delays or cancellations and
consistently below average hydroelectric conditions.

Investment Thesis:
We rate shares Market Perform. We are attracted to Idaho's growing service territory
and strong rate base growth potential, and are encouraged by recent regulatory
improvements. Our neutral rating reflects (1) a below-average, though improving,
regulatory environment, (2) above average earnings volatility related to the impact of
supply costs, which are largely determined by unpredictable hydro conditions, and (3)
valuation considerations.

Market Perform
Sector: Regulated Electric Utilities, Market
Weight
December 18, 2008
Earnings Estimates Revised Up

2007A 2008E 2009E
EPS Curr. Prior Curr. Prior
Q1 (Mar.) $0.56 $0.48 A NC $0.65 NC
Q2 (June) 0.41 0.39 A NC 0.50 NC
Q3 (Sep.) 0.65 1.14 A NC 0.93 NC
Q4 (Dec.) 0.23 0.24 NC 0.32 NC
FY $1.86 $2.25 NC $2.40 NC
CY $1.86 $2.25 $2.40
FY P/E 15.6x 12.9x 12.1x
Rev. (MM)$879.4 $927.5 $987.6
Source: Company Data, Wachovia Capital Markets, LLC estimates, and Reuters NA = Not Available, NC = No Change, NE = No Estimate, NM = Not Meaningful

Ticker IDA
Price (12/18/2008) $29.04
52-Week Range: $21-37
Shares Outstanding: (MM) 45.6
Market Cap.: (MM) $1,324.2
S&P 500: 889.77
Dividend/Yield: $1.20/4.1%
LT Debt: (MM) $1,273.0
LT Debt/Total Cap.: 46.2%
ROE: 8.0%
3-5 Yr. Est. Growth Rate: 5.0%
CY 2008 Est. P/E-to-Growth: 2.6x
Last Reporting Date: 11/06/2008
Before Open
Source: Company Data, Wachovia Capital Markets, LLC estimates, and Reuters

Utilities
Neil Kalton, CFA, Senior Analyst
[phone] / [e-mail]
Sarah Akers, Associate Analyst
[phone] / [e-mail]
Jonathan Reeder, Associate Analyst
[phone] / [e-mail]

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IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

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Company Description

IDACORP (IDA) is the holding company for Idaho Power Company (IPC), a regulated electric utility serving
more than 485,000 customers in southern Idaho, including Boise and surrounding areas, and eastern Oregon.
In addition, IDACORP Financial Services (IFS), a non-utility business, invests in affordable housing tax
credits.

Investment Thesis

We rate the shares of IDACORP Market Perform. We believe the share price adequately reflects favorable
attributes such as an attractive service territory and improving regulatory environment. Over the past decade,
Idaho has been one of the nation’s fastest-growing states in terms of population, which is increasing at a
nearly 2.5% annual rate, versus the national average of 1.2%. The factors driving this growth are the state’s
natural beauty, temperate climate, and low cost of living, especially when compared with nearby California.
Our historically neutral stance toward the name has been primarily due to unfavorable regulatory principles
that have made it virtually impossible for IDA to earn its allowed ROE. We are pleased to report that there
have been recent positive changes to these regulatory principles, which we discuss in some detail herein,
which have improved both the near-term EPS outlook and longer-term predictability of earnings. While we
remain on the sidelines for the time being due to valuation considerations, we are encouraged by the
improving regulatory environment.

Valuation Analysis

Our 12-18 month valuation range of $30-32 is based on a combination of our relative valuation and dividend
discount analyses.

Relative valuation. We applied a 12x P/E multiple to our 2009 EPS estimate of $2.40, resulting in a $29
share price. The 12x multiple is a modest discount to the 2008 peer group multiple of 12.5x, reflecting
Idaho’s modestly below-average regulatory environment. The shares trade at an 8% and 19% premium to the
peer group on 2009 and 2010 EPS estimates, respectively. We do not believe a further expansion of the
premium valuation is warranted given our projected EPS growth rate of 5%, which is in line with the
company’s peer group, and above-average risk profile related to the impact of hydro variability on financial
results.

Dividend discount analysis. Our dividend discount analysis indicates a forward share price of $34.
Assumptions underlying our analysis include a 9% discount rate, using an approximately a 3% risk-free-rate
and 600-basis-point (bps) equity risk premium, a 10.25% ROE, and a 60% payout ratio.

Regulatory Update--2008 Workshops

Regulatory Workshops Result In Improved Principles

Idaho Power and members of the staff of the Idaho Public Utilities Commission (IPUC) conducted
workshops during spring and summer 2008 to address the underlying mechanics of a number of regulatory
principles. These included the appropriate test year for ratemaking purposes, the power cost adjustment
(PCA) sharing mechanism, and the load growth adjustment mechanism (LGAR). The workshops resulted in a
number of tweaks to these principles that, in our view, should result in material improvements to Idaho
Power’s earned ROEs. Idaho Power has consistently earned well below its allowed ROE, near 10.5%. While
we find it difficult to precisely pinpoint the factors causing the low ROEs, we crudely estimate that regulatory
lag and the LGAR mechanism had an adverse impact of 100-150 bps on the company’s earned ROE. In
addition, in each year since 2001, the 90/10 PCA sharing mechanism resulted in an incremental drag of up to
270 bps, with an average negative annual impact of 92 bps (per IDA’s 8-K, filed on July 30, 2008). In the text
that follows, we discuss in detail the outcomes of the workshops.

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• Test year. Following a March 12, 2008, workshop addressing the test year used to set Idaho Power’s
rates, the company, IPUC staff, and other interested parties came to an agreement. The staff expressed
support for the use of forecasted data for a 2008 test year in the company’s upcoming rate case. IDA filed
for new base rates in June 2008, which included six months of forecasted data. The new policy does not
constitute a “forward” test year in the traditional sense because by the time new rates become effective in
early 2009, the 12 months of data used in the 2008 test year will be historical; however, the use of
forecasted data represents a meaningful improvement versus the prior practice of using fully historical
(or actual) data. The use of a split test year should greatly lower, but not eliminate, the impact of
regulatory lag. In response to IDA’s GRC filing, the staff appears to have upheld its end of the bargain,
agreeing to use the test year ending December 31, 2008.

• PCA sharing mechanism. Following three workshops, on October 14, 2008, IDA, with its staff and
other interested parties, filed a settlement with the IPUC resolving a number of PCA-related issues,
including the sharing methodology. The agreement calls for a change in the allocation of excess costs or
benefits to customers and shareholders to 95/5 from 90/10. We view this change highly favorably. While
we would prefer that Idaho Power have no exposure to power supply costs, it is also been made
abundantly clear that the IPUC staff wants the company to at least have some skin in the game. The
IPUC believes such exposure creates added incentive for prudent power procurement and plant
management. Therefore, we are pleased with the outcome and estimate that it will reduce IDA’s EPS
exposure in “bad” hydro years to approximately $0.10 per share from $0.20 per share.

Idaho Power’s power supply costs are set via the GRC process, with the key input being normalized
hydro conditions. Roughly 55% of Idaho Power’s self-generated power supply comes from its hydro
facilities; thus, stream flows at the hydro sites have a significant impact on power supply costs. If stream
flows are below normal, which has, for the most part, been the case in recent history, Idaho Power is
negatively affected due to the sharing mechanism employed. Most regulated utilities’ power supply
recovery mechanisms allow the companies to fully pass through purchased power and fuel costs to
customers, as they are deemed out of the companies’ control. Idaho’s mechanism, however, requires the
company to share excess costs, or incremental gains in the event of a good hydro year, with customers
via a sharing mechanism despite the highly variable and obviously uncontrollable nature of water
conditions. This means that if actual supply costs are above what is embedded in rates, Idaho Power
defers 95% (previously 90%) of the incremental costs for future recovery and eats 5% (previously 10%).

The sharing mechanism creates disproportionate risk for shareholders. When hydro conditions are good,
Idaho Power generates excess power that it can sell into the market. If hydro conditions are poor,
however, the company is required to either run more expensive fossil fuel-fired generation facilities
and/or go to the market to fulfill the shortage. The cost/benefit is disproportionate because above-average
hydro conditions tend to lead to lower market prices (when the company has the opportunity to be a
seller) and below-average hydro conditions tend to put upward pressure on regional power prices (when
the company is a net buyer).

• PCA LGAR. The PCA also includes a mechanism intended to prevent the company from recovering
power supply costs associated with load growth related to customer growth, a change in customer usage,
and/or fluctuations in weather. This load growth adjustment mechanism compares actual system load
with the normalized load, which is determined in the most recent rate case. Because IDA has been
required to use a largely historical test year, if the company experiences customer growth in its service
territory, then actual load is likely to be higher than the “normalized” load, which has been the case with
IDA every year since 1997. A calculation using the load growth adjustment rate (LGAR) determines the
theoretical amount that IDA is collecting for power supply costs above that agreed upon in the last GRC.
IDA is then required to refund that amount to customers subject to the sharing mechanism.

The negative impact is compounded by the fact that the per megawatt-hour (MWh) LGAR used to
calculate the power supply cost of serving new customers is higher than the per MWh cost embedded in
rates. The result is that not only does IDA not recover the power supply costs to serve new customers,
but it is also penalized because a greater portion of the revenue collected from new customers is refunded
via the LGAR mechanism than is baked into rates for power supply costs, effectively eating into the
other costs embedded in rates.
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The October stipulation following IDA-led workshops also includes proposed changes for the load
growth adjustment calculation, including a LGAR of $28.14 per MWh, which compares with the $31.40
per MWh rate determined in the last rate case. The new LGAR methodology, which uses embedded
rather than marginal production costs, is to be first employed when new rates are effective in conjunction
with the pending GRC. According to the company, the use of marginal production costs would have
resulted in an LGAR north of $60 per MWh.

On the basis of information provided in IDA’s July 30, 2008, power cost adjustment analysis, we
estimate the average annual impact of the load growth adjustment mechanism on IDA’s earnings from
2001 to 2007 to be approximately negative $0.16 per share, in the range of negative $0.06-0.26 per share.
While we find it difficult to quantify the impact of the new methodology, the company has indicated that
the new LGAR formula will reduce the negative impact that the load growth adjustment has on IDA’s
financial results by improving recovery of actual power supply costs.

• Other items. While not necessarily as financially material as the sharing mechanism and LGAR, the
settlement agreement also included a number of other items that, on the margin, should improve the PCA
and lower the related risk to shareholders. The first is the forecast used to set the base PCA rates. Parties
agreed that the regression analysis typically used to forecast power supply costs has proven less accurate
than the company’s in-house forecasts. As a result, in the next PCA filing, IDA’s Operation Plan forecast
is to be used. A more accurate forecast should lead to a lower deviation between actual and planned
power supply costs, ultimately resulting in lower accrued or deferred balances and reducing the
variability of earnings.

The settlement also provides IDA with recovery of third-party transmission expenses as legitimate power
supply expenses. This, again, serves to better match actual costs with those recovered in rates.

Parties also agreed to abandon the even distribution of power supply costs, opting instead to allocate
costs on a normal seasonal shape that more closely tracks monthly loads in a given year. This change
does not affect the net amount collected from customers or the total deferral/accrual, but it does provide
more transparent price signals to ratepayers and clearer, more logical financial reporting on a quarterly
basis.

Overall, we view the settlement agreement positively as it improves IDA’s risk profile and indicates
willingness on the part of the IPUC staff and other parties to provide reasonable treatment to Idacorp. While
we still consider Idaho’s regulatory environment to be modestly below average, these steps should improve
the company’s ability to earn its allowed ROE.

Fixed Cost Adjustment Mechanism (Decoupling)

The momentum for energy efficiency and conservation programs has led a number of states, including Idaho,
to consider steps to better align the interests of utility companies with those of its consumers. The result has
been an emergence of decoupling in the electric regime, which aims to eliminate the disincentive for utilities,
which collect revenue based on sales volume, to promote energy efficiency. On March 12, 2007, the IPUC
approved a three-year pilot program that links fixed cost recovery to a certain amount per customer rather
than usage. The fixed cost per customer is determined in the GRC process and is subject to an annual true-up
for over or under-recoveries. The fixed cost adjustment mechanism (FCAM) pilot program, which runs
through 2009, should help mitigate the impact of declining electric sales in the current poor economic
environment.

Oregon PCAM

Roughly 5% of IDA’s operations are in Oregon, where, until recently, the company has been operating
without a power cost adjustment mechanism (PCAM). Despite the relatively small operating base and supply
cost deferral accounting, the lack of a PCAM has been negatively affecting EPS. As a result, IDA filed for
approval of a mechanism similar to the Idaho PCA in August 2007. Under a settlement agreement approved
by the Oregon Public Utilities Commission (OPUC) on April 28, 2008, Idaho Power’s base power supply
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costs are to be reestablished each October in Oregon for the April through March test year (rather than
through a GRC as in Idaho) and updated once in March for the upcoming test year with more recent data,
such as stream flows and power prices. Separately, Idaho Power is to submit a true-up filing in February of
each year to reconcile actual power supply expenses with those baked-in rates for the previous year. This
does not provide for a full true-up because IDA recovers or refunds only 10% of the costs and benefits that
fall outside of a certain dead band. In addition, collections or refunds kick in only if the deviation between
actual and planned costs has a greater-than-100-basis-point impact on Idaho Power’s ROE. While falling
short of a complete pass-through, the establishment of a PCAM in Oregon should further reduce IDA’s
exposure to power supply cost fluctuations.

Regulatory Update--2008 GRC

In June 2008, IDA filed for a $66.6 million, or 9.9%, general rate increase. Approximately $24 million of the
request relates to power supply expense and the remaining $44 million is for a base rate increase. The request
is based on an 11.25% ROE, 49.3% equity ratio, and rate base of $2,093 million using a test year ending
December 31, 2008. On October 24, the staff and other interested parties filed response testimony to IDA’s
request. The staff recommended a $9.7 million, or 1.44%, rate increase based on a 10.25% ROE (in the range
of 9.5-10.5%) and 49% equity ratio. While we consider the cost-of-capital parameters constructive, the
recommended rate increase makes up just 15% of the company’s total request. The staff attacked a number of
items in the company’s request, including the rate base calculation and a number of expense items, such as
depreciation, compensation expense, supply costs and attorney and director fees, along with cost escalators
on certain expense and capital accounts. The following table outlines the key differences driving the
$57 million lower recommended revenue requirement.

Figure 1. Key Drivers Of Staff Recommended Rate Increase Versus IDA’s Request

Driver $ millions
Lower ROE (10.25% vs. 11.25%) (16.9)
Lower O&M/Materials Escalation (15.0)
Lower Variable Power Supply Costs (11.2)
Other Items (lower legal fees, lower depreciation (7.3)
expense, lower Hells Canyon relicensing
AFUDC balance for recovery, etc)
Lower Compensation (4.6)
Total (55.0)
Actual Recommended Disallowance (57.0) Source: IPUC Staff Testimony

The Staff also criticized IDA’s cost-control efforts and recommended deferral of rider recovery of demand-
side management (DSM) investment until a full review of prudence is completed. On a positive note, the staff
accepted the company’s use of a split test year ending December 31, 2008.

IDA filed rebuttal testimony on December 3 and a final order is expected on February 2, 2009, after which
rates are to become effective immediately. While the large discrepancy between the company’s requested rate
increase and the staff’s recommended increase decreases the likelihood of a settlement, the parties have
recently proven their ability to work constructively together. As an example, the staff and company reached a
settlement in the 2007 GRC even though the staff’s initial recommended rate increase was only 27% of
IDA’s initial request.

2007 GRC And Other 2008 Regulatory Decisions

2007 GRC. IDA’s last general rate case (GRC) was decided in February 2008, when the IPUC approved a
settlement agreement providing Idaho Power with a $32.1 million, or 5.2%, rate increase. This compares with
the company’s request for a $63.9 million increase and the staff’s recommendation of $17.5 million. New
rates became effective in March 2008. The settlement was silent on cost-of-capital parameters, but we suspect
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they fell between IDA’s requested 11.5% return on equity (ROE) and 50.3% equity ratio and the Staff’s
proposed 10.25% ROE and 48.6% equity ratio. In its testimony, the staff expressed discontent with the
company’s use of a forecasted test year (IDA was using a test year ending December 31, 2007, which
compares with the initial filing date of June 8, 2007, implying six months of forecasted data) and instead used
a test year ending June 30, 2007. However, the staff and other interested parties agreed to conduct workshops
to discuss key regulatory policies, including the test year and power cost adjustment (PCA) mechanism.

Danskin rate increase. Effective June 1, 2008, the IPUC granted Idaho Power an additional $8.9 million, or
1.4%, rate increase to reflect the addition to rate base of the natural gas-fired Danskin plant, which became
operational in March 2008. The order was largely in line with the company’s request.

Depreciation settlement. Also in 2008, the IPUC approved a settlement reached between Idaho Power and
the commission staff regarding depreciation rates. The order results in an $8.5 million reduction in
depreciation expense effective, retroactively, August 1, 2008.

Idaho energy efficiency rider. On May 30, the IPUC approved Idaho Power’s request to increase its energy
efficiency rider to 2.5% of base revenue from 1.5%, bringing annual recovery to $17 million as of June 1,
2008. IDA is not currently allowed to earn a return on its investment in energy efficiency; it is just a pass-
through.

EPS Outlook

IDA’s EPS outlook is potentially strong driven in large part by rate base growth. We project a five-year
growth rate of 5% annually (off of an estimated 2008 EPS base of $2.25). However growth prospects are
tempered by (1) recessionary pressures that are affecting both the sales and expenses of electric utilities
across the board, (2) a below-average, though improving, regulatory environment, and (3) above-average
earnings volatility related to the impact of supply costs, which are largely determined by unpredictable hydro
conditions and (4) potentially significant external financing needs post 2010. Assuming the construction of a
combined cycle gas plant and two major transmission projects, growth of 5% could extend through 2015, in
our view.

Our 2008-2010 EPS estimates are $2.25, $2.40, and $2.45, respectively. (See Figure 2 for our EPS outlook
through 2013.)

Figure 2. EPS Outlook (2008E-2013E)

2008E 2009E 2010E 2011E 2012E 2013E
Wachovia Estimates $2.25 $2.40 $2.45 $2.65 $2.70 $2.90
Consensus Estimates $2.22 $2.25 N N N N Source: Wachovia Capital Markets, LLC estimates and Baseline

Near-term EPS outlook. We have increased our 2008 and 2009 EPS estimates to $2.25 and $2.40 from
$2.10 and $2.30, respectively. The majority of the increase in 2008 is based on stronger-than-expected Q3
results, which were driven by improved hydro conditions and rate increases. These factors are partially offset
by lower expected sales growth. The change from seasonal to even distribution regarding the power cost
adjustment (PCA) is expected to have a positive $200,000 pretax impact, or less than $0.01 per share after-
tax, in Q4.

Our 2009 EPS estimate of $2.40 is based on the following assumptions:

(1) Idaho jurisdictional earnings of approximately $100 million, or $2.11 per share. This is based on a
rate base of $2,093 million, a 48.0% equity ratio, an earned ROE of 10% (50-100 bps below our
expected allowed ROE in the pending GRC, reflecting the impact of regulatory lag and the LGAR
mechanism. Our estimate assumes normal hydro conditions, which should not become clear until late
January or February, when we should have a better idea of what the snow-pack looks like.
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(2) A $4.1 million earnings contribution from Oregon, or $0.09 per share. This is based on roughly a
$100 million rate base, a 48% equity ratio, and an 8.5% earned ROE. The relatively low assumed earned
ROE reflects significant regulatory lag because the company has not filed for new rates in Oregon in a
number of years. IDA is considering filing for a rate increase in Oregon sometime next year, which could
reduce the impact of regulatory lag in 2010 and result in a higher earned ROE.

(3) Federal Energy Regulatory Commission (FERC) jurisdictional transmission earnings of
approximately $3.8 million, or $0.08 per share. This is based on a rate base estimate of
$72 million, a 48% equity ratio, and an earned ROE of 11%. It is our understanding that the major
transmission projects IDA is planning (Gateway West and Hemingway-Boardman) will not necessarily
be additive to FERC-jurisdictional transmission rate base, but to remain under the Idaho umbrella.

(4) Roughly $4.1 million, or $0.09 per share, in allowance for funds used during construction
(AFUDC) earnings.

(5) Approximately $0.05 per share for unregulated and other operations.

The increase in our 2009 EPS estimate to $2.40 from $2.30 reflects regulatory improvements, including
changes to the LGAR, test year, sharing mechanism and other regulatory decisions, such as the depreciation
settlement discussed in the regulatory update herein and Oregon PCAM. These impacts are partially offset by
lower expected sales growth (we are assuming 1.5% growth for residential and commercial customers, versus
3% previously and 0.5% for industrial customers, versus 2.5% previously).

In addition to the aforementioned regulatory improvements and assumed return to more normal hydro
conditions, growth drivers in 2009 versus 2008 include an anticipated rate increase in conjunction with the
pending GRC in February 2009, a full-year impact of the 2007 GRC (new rates went into effect in March
2008), the Danskin-related rate increase (effective June 2008), and an incremental expected rate increase
related to IDA’s planned AMI investment.

Following, we outline two factors affecting the near-term outlook:

• Hydro outlook. IDA projects hydroelectric generation of 6.7-7.2 million MWh in 2008. This is an
improvement from 6.2 million MWh in 2007, but remains below average hydro generation levels of
8.5 million MWh. The company will likely provide 2009 guidance for hydro generation in conjunction
with its year-end earnings release in February 2009. Our 2009 estimate is based on normal hydro
conditions. By general rule of thumb, we assume that every 1 million MWh of hydro production below
normal has a negative $0.03 impact on EPS. Key assumptions include replacement power cost of $50 per
MWh, 95/5 sharing between customers and shareholders, a 40% tax rate, and 47 million shares
outstanding.

For the most part, hydro conditions have been below average in recent years. IDA argues that this
phenomenon could, in part, be man-made because the construction of storage reservoir and canal systems
and the conversion to sprinkler and groundwater-supplied irrigation systems, among other actions, have
led to there being less water in the Snake River.

• Impact of economic slowdown. IDA’s service territory, along with the territories of most companies in
our regulated coverage universe, is encountering difficult economic times, pressuring the company’s
near-term outlook. On its Q3 conference call, management indicated that its customer connections were
slowing and a large industrial customer recently announced layoffs. IDA’s top line will likely be affected
by lower sales growth during the rest of 2008, throughout 2009, and potentially into 2010. The negative
impact should be partially mitigated, however, by the company’s fixed cost adjustment mechanism
(FCAM), which is operating under a pilot program that runs through 2009. The FCAM links fixed cost
recovery to a certain amount per customer rather than electric usage per customer, serving as a partial
decoupling mechanism. (We provide greater detail in the Regulatory Outlook section of the report.) In
addition, the pending GRC filing incorporates CY2008 sales data.

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A lower expected electric demand growth outlook, coupled with uncooperative financial markets, has
prompted the company to reevaluate its capital program and other spending. For example, IDA is putting
restrictions on hiring to help reign in operations and maintenance (O&M) costs. These efforts should
soften the blow, on the margin, but we expect the overall economic downturn to negatively affect
earnings growth in the near term as other costs are likely to increase. We discuss the impact on the capex
in the Capital Investment Plans section of the report.

Longer-Term EPS Outlook

• 2010E. We have lowered our 2010 EPS estimate to $2.45 from $2.60. Our estimate had already assumed
some level of regulatory improvement by 2010 and is affected by modestly lower sales growth
assumptions and lower rate base levels on decreased or deferred spending. Our estimate is largely flat
with our 2009 EPS estimate of $2.40, reflecting some level of regulatory lag, as we assume IDA collects
rates set on a year-end 2008 test year through mid-2010, when we incorporate additional rate relief.
While Idaho Power filed for new rates, effective both March 2008 and February 2009, we believe the
consecutive rate filings were a product of the company’s regulatory agenda, including the test year and
PCA issues. Now that such issues are largely settled, we expect the company to file on an as-needed
basis. Given significant upcoming investment plans, we estimate that this will result in a 1-2 year rate
case cycle over the next few years. We expect the 2% year-over-year growth to be driven by a midyear
rate increase and modestly higher allowance for funds used during construction (AFUDC) earnings.

• 2011E. Our 2011 EPS estimate remains $2.65. We expect earnings growth to resume in 2011 driven, in
large part, by a full year of rate relief, a ramp-up of spending on the combined cycle plant, and the
commencement of modest spending on the Hemingway-Boardman transmission project. These factors
are partially offset by an assumed $125 million common stock issuance mid year. There is no guarantee
that the gas plant and transmission projects included in our model will be approved and constructed as
per the current time lines. The construction of a combined cycle plant, for example, is subject to the
outcome of the pending RFP. Regarding the high-voltage transmission projects, while we are relatively
confident that they will ultimately be constructed, we point out that large transmission projects are
vulnerable to siting delays. To account for such delays, along with the lower demand outlook, we assume
the transmission projects are put into service a year after originally assumed. If our assumptions prove
conservative, we do not see material upside potential (roughly $0.05 per share) to our 2011 EPS estimate
as higher AFUDC earnings would likely be mitigated, in part, by larger external financing, particularly
equity, needs.

Post 2011, transmission projects continue to be the main growth driver, although we would not be surprised
to see another self-build generation project, possibly wind, in the 2012-15 time frame. We expect EPS growth
to be partially mitigated by significant external financing needs and subject to modest regulatory lag.

Capital Investment Plans

Tightening The Belt

As is the case with other electric utilities, IDA is reevaluating its capital budget in light of the economic
slowdown. Specifically, management is taking a careful look at spending aimed at meeting customer growth
and non-core projects. IDA previously estimated that 2008-2010 capex would be approximately $900 million,
with upside potential related to a 250 megawatt (MW) combined-cycle plant and potentially large
transmission projects, such as the Gateway West project and the Hemingway-Boardman line. Included in the
$900 million estimate was capex of $280-300 million for 2008. IDA recently revised the 2008 estimate down
to $235-250 million, due to a decline in customer connections and deferral of spending on certain items.

Despite the near-term pressure created by lower expected demand growth and tight credit markets, IDA still
needs to make significant investment to maintain reliability, replace and upgrade aging infrastructure,
re-license hydro generating facilities, and meet environmental compliance standards. In addition,
management has indicated that the company will not lose sight of longer-term demands, noting that many
projects have long lead times (we suspect the high-voltage transmission projects fall in this bucket).
WACHOVIA CAPITAL MARKETS, LLC
Utilities EQUITY RESEARCH DEPARTMENT

10

On the basis of the planned cancellation and deferral of certain spending initiatives, along with other tweaks
in our outlook, we have lowered our 2008-2010 capex forecast at Idaho Power by 20%, to $828 million from
$1,029 million (our projections include the onset of spending on a combined cycle plant). Beyond 2010, our
capex projections are largely driven by the gas plant and Boardman-Hemingway and Gateway West
transmission projects. While these projects are currently “on the drawing board” and have not yet been
approved, we believe that additional spending, whether or not in the form of these specific projects, will be
required to meet demand growth and replace aging infrastructure. We pushed back the commencement of
pending on the transmission initiatives to account for (1) a lower demand outlook, (2) common siting delays
associated with major transmission projects, and (3) to error on the conservative side. We also removed an
anticipated 150 MW of self-build wind from our capex outlook, as it appears the company is pursuing
purchased power agreements (PPA) and other contracts to satisfy the 250 MW of wind generation targeted in
its preferred portfolio in the 2006 IRP. While we think the company may pursue self-build wind at some
point in the future, we are opting to exclude it at this time. Investors should get a better sense of the
company’s updated long-term plan, including the timing of new generation needs, when Idaho Power submits
its 2009 Integrated Resource Plan (IRP) in June 2009.

In the following chart, we provide a breakdown of our capex projections through 2015.

Figure 3. Capital Expenditure Breakdown, 2008E-2015E ($ In Millions)
0
100
200
300
400
500
600
2005 2006 2007 2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E
Thermal Additions/Upgrades Environmental (thermal)Hydro UpgradesCombined Cycle Gas Hydro Relicensing Transmission Hemingway-Boardman Line Gateway West Project AMIDistributionGeneral and Other Source: Wachovia Capital Markets, LLC estimates and company filings

Following is a discussion of several key capex initiatives.

• AMI. On August 5, 2008, Idaho Power filed for a Certificate of Public Convenience and Necessity with
the IPUC for automated metering infrastructure investment (AMI) throughout its service territory and
accelerated depreciation of existing meters. The total estimated cost is $71 million and deployment is
scheduled during the period 2009-2011. Activities such as securing contracts, ordering materials, pre-
implementation planning, and the installation of communication equipment are already under way.

Pending IPUC approval, IDA estimates the AMI-related revenue requirement to be $12.2 million in
2009, including $3.8 million for the AMI capital additions and $8.4 million for the accelerated
depreciation of the old meters less operations and maintenance (O&M) benefits. Due to the unavailability
of accurate costs estimates at the time, IDA was unable to include the AMI investment in its current
GRC, but in its filing for a Certificate of Public Convenience and Necessity, the company indicated that
it plans to seek recovery, as the new meters are placed in service in a separate filing.

• 300 MW Baseload RFP. In April 2008, Idaho Power issued a request for proposals (RFP) for
250-600 MW of baseload power, which has since been narrowed to 300 MW, for delivery beginning in
WACHOVIA CAPITAL MARKETS, LLC
IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

11

summer 2012. The company has indicated that it has bid in a combined cycle combustion turbine
(CCCT) project, which is to be compared against purchased power agreements (PPA) and tolling
agreements. On the basis of an $800-900 per kilowatt (KW) estimated cost for combined cycle gas
capacity, if IDA’s self-build proposal is selected as the winning bid, the company could begin investing
in a $240-270 million project beginning as early as late 2009. By our calculations, this would represent a
roughly $12-13 million earnings opportunity (assuming a 50% equity ratio and roughly 10% ROE) in the
year after the plant comes online. According to the RFP schedule, bidders on the short list are to be
notified in November 2008 and the winning proposal(s) will be selected in January 2009, subject to
commission approval. Our model assumes a self-build combined cycle plant at a total cost of
$255 million, constructed during the period 2010-12.

• Boardman-Hemingway Line. Idaho Power, with neighboring utilities, is proposing to construct a
roughly 300-mile, 500 kilovolt (kV) transmission line from southwestern Idaho heading northwest, to
Oregon. The line, which has a total cost estimate of $600 million, is designed to improve reliability and
provide for increased deliverable capacity of up to 1,500 MW. The company believes the line is needed
to bring power into and through its service territory, particularly in light of the current transmission
infrastructure operating at full capacity during periods of high demand in the area.

Technical studies sponsored by Idaho Power and other utilities are under way, and the plan has been
submitted to the Western Electricity Coordinating Council (WECC) for review. In addition, Idaho Power
filed a notice of intent (NOI) with the Oregon Department of Energy (DOE) requesting a site certificate
in August 2008; and in early October, the company filed the proposed project with the Northern Tier
Transmission Group (NTTG) Cost Allocation Committee for approval of the cost/benefit allocation. The
NTTG is not likely to issue a recommendation until 2H 2009. If approved, construction is expected to
commence in early 2011 and the Boardman-Hemingway line is expected to come online in June 2013.
Our model assumes modest preliminary spending ($25 million) in 2011 and a completion date of 2014.

It is difficult to determine IDA’s portion of the cost because the company has indicated that it will be
partnering with other utilities. On October 22, for example, IDA entered a memorandum of
understanding (MOU) with Portland General Electric (POR, $18.26, Outperform) agreeing to cooperate
on the Boardman-Hemingway line and another 500 kV project, the Southern Crossing line. However, it
appears that a significant portion of the project would go through IDA’s service territory. Our model
currently assumes a 50% interest, which translates to $300 million of investment.

• Gateway West Transmission Project. Together with PacifiCorp, IDA is exploring the Gateway West
Project, which consists of two 500 kV lines and additional 230-kv lines spanning from southwest Idaho
across Wyoming. As IDA’s transmission system is operating at full capacity in many areas, the project,
which entails more than 1,000 line miles, should relieve and reinforce the current system, as well as
accommodate growth and integrate renewable, particularly wind, energy into the grid, benefiting both
IDA’s and PacifiCorp’s systems.

IDA and PacifiCorp have entered a cost-sharing agreement for the initial phases of the project and have
submitted the plan to the Western Electricity Coordinating Council (WECC) for review. If approved, the
Gateway West project is expected to be in service between 2012 and 2014 at a cost of $800 million to
$1.2 billion (IDA’s portion), including allowance for funds used during construction (AFUDC). Our
model assumes preliminary spending in 2012 and project completion in 2015.

• Environmental. As an owner of a diverse generation fleet, which includes coal, gas, and hydro facilities,
IDA is subject to a variety of environmental compliance requirements, which are expected to result in
capital spending needs for the foreseeable future. For example, under federal regional haze rules, the
Oregon Department of Environmental Quality (ODEQ) is proposing best available retrofit technology
(BART) for the Boardman plant, in which IDA holds a 10% interest. If approved, the ODEQ’s proposal
is expected to cost Idaho Power $40 million by 2014, and another $19 million by 2017. The ODEQ plans
to issue a final determination in January 2009. The Wyoming Department of Environmental Quality
(WDEQ) is also assessing BART requirements for the company’s 33% interest in the Jim Bridger plant.
These coal plants, along with IDA’s natural gas-fired plants, Danskin and Bennett Mountain, are also
WACHOVIA CAPITAL MARKETS, LLC
Utilities EQUITY RESEARCH DEPARTMENT

12

subject to other requirements promulgated by the Clean Air Act, such as mercury emission restrictions,
New Source Review (NSR) permitting, etc. These, along with potential future regulations, such as
carbon legislation, could result in additional environmental-related capex.

In its 2007 10K, IDA projected environmental spending of $26 million in 2008, $15 million of which
would be dedicated to the company’s hydro plants and $11 million, to thermal plants. These expenditures
were expected to total $65 million in 2009-2010, with hydro facilities accounting for $29 million and
thermal, the remaining $36 million. We discuss hydro relicensing projects, which are included in these
cost estimates, in the text that follows.

• Hydro relicensing and upgrade. IDA’s hydro facilities operate under FERC licenses that generally last
30-50 years. As license expirations approach, IDA incurs re-licensing costs, which accumulate as
construction work in progress (CWIP) until the process is complete, at which time the capex is allocated
to rate base. IDA is currently in the process of re-licensing its Hells Canyon Complex (HCC) and Swan
Falls facilities. In July 2003, Idaho Power filed for a new license of its Hells Canyon Complex, which
represents roughly 40% of the company’s generating capacity. As the license expired in 2005, the
company is operating under annual licenses until the re-licensing process is complete. In anticipation of
the expiration of Swans Falls’ license in June 2010, Idaho Power submitted a draft application to the
FERC for a new license in September 2007, followed by a final application on June 26, 2008. Beyond
the HCC and Swan Falls projects, IDA’s next hydro license expiration does not occur until 2025. Our
model assumes re-licensing-related capex of roughly $15 million per year during the period 2008-2010.

Separately, Idaho Power filed to amend its license for its Shoshone Falls facility in August 2007. The
company is seeking to upgrade the facility to 62.5 MW from 12.5 MW and expects a decision in late
2008 or early 2009.

Liquidity Position

We consider IDA’s near-term liquidity position to be relatively healthy. During the period 2008-2010, we
expect capital spending to be more than 50% funded by internally generated funds. Our model assumes that
the remainder is largely financed by long-term debt issued at the utility subsidiary, along with frequent (but
relatively modest) equity issuances. Standard & Poor’s (S&P) and Moody’s rate IDA’s senior unsecured debt
“BBB-“ and “Baa2”, with Stable and Negative outlooks, respectively.

As of September 30, 2008, Idaho Power Company’s equity ratio was 45%, which compares with the
company’s targeted capital structure of roughly 50/50 debt/equity and the 49.3% equity ratio the company is
proposing in its pending GRC. We expect the company to work up its equity ratio over the next 12-18
months. At the consolidated level, additional shares can be issued via numerous ongoing programs, such as
the dividend reinvestment and stock purchase plan, employee savings plan, and long-term incentive and
compensation plan. But given the November 2008 expiration of the company’s continuous equity program
(CEP) through BNY Capital markets, Inc., which was used to issue a total of nearly 2 million shares since the
beginning of 2006, external equity needs appear necessary.

On December 5, IDA entered into another sales agreement with BNY Mellon Capital Markets, LLC to issue
up to 3 million shares of common stock over the next two years. At the current share price, this represents a
potential capital raise of roughly $85 million. Our model assumes the issuance of $85 million of equity
through 2009, followed by an incremental $50 million in 2010.

Longer term, assuming the company’s plans to build two 500 kV transmission projects come to fruition, IDA
will likely be more dependant on external financing needs, including both debt and equity. We assume a
$125 million equity issuance in 2011, followed by $50 million in 2012 and $175 million in 2013. We also
expect debt financing to pick up in these years to nearly $300 million per year. If regulated capital
expenditure comes in higher than our projections due, for example, to (1) increased environmental-related
capex; (2) new self-build generation; (3) an earlier-than-expected economic turnaround requiring more
customer hook-ups and other investment; and (4) earlier/higher spending on the two major transmission
projects than is assumed in our model and/or pension contributions have a material negative cash impact (see
following text for more detail), equity issuances could be earlier and larger than we are currently expecting.
WACHOVIA CAPITAL MARKETS, LLC
IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

13

Selling agency agreement at Idaho Power. Idaho Power entered into a selling agency agreement with 11
financial institutions on April 3, 2008. The agreement allows the company to issue up to $350 million first
mortgage bonds at an interest rate of 6.025%. The company used the selling agreement to issue $120 million
on July 10, 2008, leaving $230 million of the shelf registration available as of November 5. This is separate
from the $621 million shelf registration discussed in the preceding text.

Shelf registration for debt and equity. On November 20, IDA filed to replace two expiring shelf
registrations with one combined shelf for up to $598.8 million of debt and common stock issuances. It is our
understanding that the new arrangement also leaves open the possibility of issuing equity-like securities, such
as hybrids or preferred stock. In addition, on November 25, IDA filed a registration statement for up to
1.5 million shares of common stock through its dividend reinvestment and stock purchase plan.

Credit facilities. As of November 6, IDACORP and Idaho Power had credit facilities totaling $100 million
and $300 million, respectively, both of which expire in April 2012. The companies have the option of
drawing on the facilities and/or issuing commercial paper up to levels available under the facility. IDA had
drawn $35 million on the parent facility in addition to carrying an outstanding commercial paper balance of
$21 million, leaving $44 million in remaining borrowing capacity. Idaho Power had not drawn on its
$300 million credit facility, but did have $146 million commercial paper outstanding, resulting in net
available capacity of $154 million. These facilities provide the company with some valuable flexibility in the
current financial market environment.

Pension. Several regulated utility companies are currently experiencing and expect to continue to incur
higher pension expense as the fair value of their plan assets becomes depleted, partially offset by higher
discount rates. Due to a June 1, 2007, IPUC order, this should not be a near-term issue for IDA from an
earnings standpoint. That order allowed the company to shift from accrual-based to cash-based accounting for
its pension expense. Under the cash-based accounting method, Idaho Power is allowed to defer, as a
regulatory asset, non-cash pension expense for future recovery from customers when the company makes
actual cash contributions to the plan.

From a cash flow perspective, IDA may be required to make contributions to its pension plan under the
Pension Protection Act (PPA) of 2006. As of December 31, 2007, IDA’s plan was 97% funded. Given
significant deterioration in both debt and equity markets year to date, the company’s plan is likely to fall
below the 94% funding level on January 1, 2009, required under the PPA. As we outlined in our October 23,
2008, Pension Study, even severely under-funded plans are permitted to be funded over a seven-year period.
While the funded status, which is the fair value of plan assets less the projected benefit obligation, cannot be
accurately calculated until year-end 2008, IDA provided funding estimates for the years 2010-13 based on
September 30, 2008, data. Company estimates call for a $40 million contribution in 2010, followed by
$20 million in each year 2011-2013. IDA expects its cash contributions to be recoverable in rates. As the
method of recovery for these costs has not yet been established, however, we believe there is a risk of
regulatory lag associated with cash collection of the costs, potentially affecting external financing needs in
2010 and beyond.
WACHOVIA CAPITAL MARKETS, LLC
Utilities EQUITY RESEARCH DEPARTMENT

14

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M
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WACHOVIA CAPITAL MARKETS, LLC
IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

15

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WACHOVIA CAPITAL MARKETS, LLC
Utilities EQUITY RESEARCH DEPARTMENT

16

Required Disclosures

$20.00
$22.00
$24.00
$26.00
$28.00
$30.00
$32.00
$34.00
$36.00
$38.00
$40.00
$42.00
$44.00
$46.00
12
/
1
3
/
0
5
1/1
0
/
0
6
2/7
/
0
6
3/7
/
0
6
4/4
/
0
6
5/2
/
0
6
5/3
0
/
0
6
6/2
7
/
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/
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/
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9
/
0
6
10
/
1
7
/
0
6
11
/
1
4
/
0
6
12
/
1
2
/
0
6
1/9
/
0
7
2/6
/
0
7
3/6
/
0
7
4/3
/
0
7
5/1
/
0
7
5/2
9
/
0
7
6/2
6
/
0
7
7/2
4
/
0
7
8/2
1
/
0
7
9/1
8
/
0
7
10
/
1
6
/
0
7
11
/
1
3
/
0
7
12
/
1
1
/
0
7
1/8
/
0
8
2/5
/
0
8
3/4
/
0
8
4/1
/
0
8
4/2
9
/
0
8
5/2
7
/
0
8
6/2
4
/
0
8
7/2
2
/
0
8
8/1
9
/
0
8
9/1
6
/
0
8
10
/
1
4
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11
/
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8
12
/
9
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8
Se
c
u
r
i
t
y

P
r
i
c
e

IDACORP, Inc. (IDA) 3-yr. Price PerformanceIDACORP, Inc. (IDA) 3-yr. Price Performance
Date
Date Publication Price ($) Rating Code Val. Rng. Low Val. Rng. High Close Price ($)
12/13/2005 Hamlin 12/13/2005 NA 2 28.00 30.00 29.19
„ 2/14/2006 Brothwell
z 5/12/2006 NA 2 30.00 32.00 33.50
z 8/10/2006 NA 2 35.00 38.00 36.93
z 1/19/2007 NA 2 34.00 37.00 37.22
dz 2/16/2007 NA 3 31.00 33.00 35.60
z 5/10/2007 NA 3 30.00 33.00 32.84
z 6/11/2007 NA 3 30.00 32.00 31.78
z 8/9/2007 NA 3 32.00 34.00 34.77
c 8/30/2007 32.29 2 32.00 34.00 32.52
z 11/1/2007 34.89 2 33.00 35.00 33.70
„ 11/14/2007 Kalton
z 11/14/2007 33.79 2 34.00 35.00 33.85
z 2/15/2008 32.04 2 31.00 33.00 31.46

Source: Wachovia Capital Markets, LLC estimates and Reuters data

Symbol Key Rating Code Key
d Rating Downgrade ‹ Initiation, Resumption, Drop or Suspend 1 Outperform/Buy SR Suspended
c Rating Upgrade „ Analyst Change 2 Market Perform/Hold NR Not Rated
z Valuation Range Change ˆ Split Adjustment 3 Underperform/Sell NE No Estimate

WACHOVIA CAPITAL MARKETS, LLC
IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

17

$13.00
$14.00
$15.00
$16.00
$17.00
$18.00
$19.00
$20.00
$21.00
$22.00
$23.00
$24.00
$25.00
$26.00
$27.00
$28.00
$29.00
$30.00
$31.00
$32.00
$33.00
$34.00
12
/
1
3
/
0
5
1/
1
0
/
0
6
2/7
/
0
6
3/7
/
0
6
4/4
/
0
6
5/2
/
0
6
5/
3
0
/
0
6
6/
2
7
/
0
6
7/2
5
/
0
6
8/2
2
/
0
6
9/1
9
/
0
6
10
/
1
7
/
0
6
11
/
1
4
/
0
6
12
/
1
2
/
0
6
1/9
/
0
7
2/6
/
0
7
3/6
/
0
7
4/3
/
0
7
5/1
/
0
7
5/
2
9
/
0
7
6/
2
6
/
0
7
7/2
4
/
0
7
8/
2
1
/
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7
9/
1
8
/
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7
10
/
1
6
/
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7
11
/
1
3
/
0
7
12
/
1
1
/
0
7
1/8
/
0
8
2/5
/
0
8
3/4
/
0
8
4/1
/
0
8
4/
2
9
/
0
8
5/
2
7
/
0
8
6/2
4
/
0
8
7/2
2
/
0
8
8/
1
9
/
0
8
9/1
6
/
0
8
10
/
1
4
/
0
8
11
/
1
1
/
0
8
12
/
9
/
0
8
Se
c
u
r
i
t
y

P
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i
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e

Portland General Electric (POR) 3-yr. Price PerformancePortland General Electric (POR) 3-yr. Price Performance
Date
Date Publication Price ($) Rating Code Val. Rng. Low Val. Rng. High Close Price ($)
9/19/2006 Kalton
‹ 9/19/2006 NA 1 29.00 29.00 23.97
z 3/2/2007 NA 1 31.00 31.00 28.02
‹ 9/28/2007 NA NR NE NE 27.80
z‹ 11/14/2007 26.32 1 30.00 31.00 26.32
z 2/28/2008 23.93 1 29.00 30.00 23.66
z 10/30/2008 20.51 1 24.00 25.00 20.52
Source: Wachovia Capital Markets, LLC estimates and Reuters data

Symbol Key Rating Code Key d Rating Downgrade ‹ Initiation, Resumption, Drop or Suspend 1 Outperform/Buy SR Suspended
c Rating Upgrade „ Analyst Change 2 Market Perform/Hold NR Not Rated
z Valuation Range Change ˆ Split Adjustment 3 Underperform/Sell NE No Estimate
Additional Information Available Upon Request

I certify that:
1) All views expressed in this research report accurately reflect my personal views about any and all of the subject securities or issuers discussed;
and
2) No part of my compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed by me in this
research report.

ƒ Wachovia Capital Markets, LLC or its affiliates managed or comanaged a public offering of securities for IDACORP, Inc. within the past 12
months.
ƒ Wachovia Capital Markets, LLC or its affiliates intends to seek or expects to receive compensation for investment banking services in the next
three months from IDACORP, Inc., Portland General Electric.
ƒ Wachovia Capital Markets, LLC or its affiliates received compensation for investment banking services from IDACORP, Inc. in the past 12
months.
ƒ IDACORP, Inc. currently is, or during the 12-month period preceding the date of distribution of the research report was, a client of Wachovia
Capital Markets, LLC. Wachovia Capital Markets, LLC provided investment banking services to IDACORP, Inc.
ƒ IDACORP, Inc. currently is, or during the 12-month period preceding the date of distribution of the research report was, a client of Wachovia
Capital Markets, LLC. Wachovia Capital Markets, LLC provided noninvestment banking securities-related services to IDACORP, Inc.
ƒ Wachovia Capital Markets, LLC received compensation for products or services other than investment banking services from IDACORP, Inc.
in the past 12 months.

Risk to our valuation analysis include project delays or cancellations and consistently below average hydroelectric conditions.

WACHOVIA CAPITAL MARKETS, LLC
Utilities EQUITY RESEARCH DEPARTMENT

18

Wachovia Capital Markets, LLC does not compensate its research analysts based on specific investment banking transactions. WCM’s research
analysts receive compensation that is based upon and impacted by the overall profitability and revenue of the firm, which includes, but is not
limited to investment banking revenue.

STOCK RATING
1 = Outperform: The stock appears attractively valued, and we believe the stock's total return will exceed that of the market over the next 12
months. BUY
2 = Market Perform: The stock appears appropriately valued, and we believe the stock's total return will be in line with the market over the next
12 months. HOLD
3 = Underperform: The stock appears overvalued, and we believe the stock's total return will be below the market over the next 12 months.
SELL
SECTOR RATING
O = Overweight: Industry expected to outperform the relevant broad market benchmark over the next 12 months.
M = Market Weight: Industry expected to perform in-line with the relevant broad market benchmark over the next 12 months.
U = Underweight: Industry expected to underperform the relevant broad market benchmark over the next 12 months.
VOLATILITY RATING
V = A stock is defined as volatile if the stock price has fluctuated by +/-20% or greater in at least 8 of the past 24 months or if the analyst expects
significant volatility. All IPO stocks are automatically rated volatile within the first 24 months of trading.

As of: December 18, 2008
41% of companies covered by Wachovia Capital Markets, LLC
Equity Research are rated Outperform.
Wachovia Capital Markets, LLC has provided investment banking services
for 39% of its Equity Research Outperform-rated companies.
55% of companies covered by Wachovia Capital Markets, LLC
Equity Research are rated Market Perform.
Wachovia Capital Markets, LLC has provided investment banking services
for 26% of its Equity Research Market Perform-rated companies.
4% of companies covered by Wachovia Capital Markets, LLC
Equity Research are rated Underperform.
Wachovia Capital Markets, LLC has provided investment banking services
for 35% of its Equity Research Underperform-rated companies.

Important Disclosure for International Clients

The securities and related financial instruments described herein may not be eligible for sale in all jurisdictions or to certain
categories of investors. For certain non-U.S. institutional reader (including readers in the EEA), this report is distributed by
Wachovia Securities International Limited (“WSIL”). For the purposes of Section 21 of the UK Financial Services and Markets
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with retail clients as defined in the Markets in Financial Instruments Directive 2007, therefore clients will automatically be deemed
to be a professional or an eligible counterparty. This research is not intended for, and should not be relied upon, by retail clients.
Important Information for Australian Recipients
Wachovia Capital Markets, LLC (“WCM”) is exempt from the requirements to hold an Australian financial services license in
respect of the financial services it provides to wholesale clients in Australia. WCM is a registered broker-dealer registered with the
U.S. Securities and Exchange Commission, and a member of the New York Stock Exchange, the Financial Industry Regulatory
Authority, and the Securities Investor Protection Corp. WCM is regulated under U.S. laws which differ from Australian laws.
Any offer or documentation provided to you by WCM in the course of providing the financial services will be prepared in
accordance with the laws of the United States and not Australian laws.
WACHOVIA CAPITAL MARKETS, LLC
IDACORP, Inc. EQUITY RESEARCH DEPARTMENT

19

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For recipients resident in Hong Kong, this research is issued and distributed in Hong Kong by Wachovia Securities Asia Limited.
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described herein will be made in Hong Kong by Wachovia Securities Asia Limited. Please consult your Wachovia Securities Asia
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Important Information for Japanese Recipients
This material is distributed in Japan by Wachovia Securities (Japan) Co., Ltd., a foreign securities company registered with the
Financial Services Agency in Japan.
Additional Disclosures
WCM is a U.S. broker-dealer registered with the U.S. Securities and Exchange Commission and a member of the New York Stock
Exchange, the Financial Industry Regulatory Authority and the Securities Investor Protection Corp. Wachovia Securities
International Limited is a U.K. incorporated investment firm authorized and regulated by the Financial Services Authority.
This report is for your information only and is not an offer to sell, or a solicitation of an offer to buy, the securities or instruments
named or described in this report. Interested parties are advised to contact the entity with which they deal, or the entity that
provided this report to them, if they desire further information. The information in this report has been obtained or derived from
sources believed by Wachovia Capital Markets, LLC, to be reliable, but Wachovia Capital Markets, LLC, does not represent that
this information is accurate or complete. Any opinions or estimates contained in this report represent the judgment of Wachovia
Capital Markets, LLC, at this time, and are subject to change without notice. For the purposes of the U.K. Financial Services
Authority's rules, this report constitutes impartial investment research. Each of Wachovia Capital Markets, LLC, and Wachovia
Securities International Limited is a separate legal entity and distinct from affiliated banks. Copyright © 2008 Wachovia Capital
Markets, LLC.

SECURITIES: NOT FDIC-INSURED/NOT BANK-GUARANTEED/MAY LOSE VALUE

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WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT

Wachovia Capital Markets, LLC Institutional Sales Offices

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London, EC3M 3BD
44-207-962-2879

CONSUMER
Apparel Retailing John D. Morris [phone] Edward Plank [phone] Jennifer Redding [phone]
Broadline/Hardline Retailing
Peter S. Benedict [phone]
Robert W. Augenthaler [phone]
Justin Kleber [phone]
Homebuilding/Building Products
Carl Reichardt [phone]
Adam Rudiger, CFA [phone]
Leisure
Timothy Conder, CPA [phone]
Joe Lachky [phone]
Personal Care and Household Products
Jason M. Gere [phone]
Christopher Shively [phone]
Restaurants/Foodservice Jeffrey F. Omohundro, CFA [phone] Katie H. Willett [phone]
Jason Belcher [phone]
ENERGY
Exploration & Production
David R. Tameron [phone]
John Ragozzino, Jr., CFA [phone]
Gordan Douthat [phone]
Midstream Energy/Master Limited Partnerships
Michael Blum [phone]
Sharon Lui, CPA [phone]
Eric Shiu [phone]
Praneeth Satish [phone]
Ronald Londe [phone] Jeff Morgan, CFA [phone]
Utilities Samuel Brothwell [phone] Darin Conti, CFA [phone]
Michael Bolte [phone]
Jonathan Lefebvre [phone]
Neil Kalton, CFA [phone]
Sarah Akers [phone]
Jonathan Reeder [phone]
Oilfield Services and Drilling
Tom Curran, CFA [phone]
HEALTH CARE
Biotechnology
Aaron Reames [phone]
Matthew Andrews [phone]
Managed Care
Matt Perry [phone]
Julie Pavlovsky [phone]
Nicole Nesmith [phone]
Medical Technology Larry Biegelsen [phone] William Boland [phone] Denis Kelleher [phone]
Medical Technology/Devices
Michael Matson, CFA [phone]
Vincent Ricci [phone]
Pharma Services
Greg T. Bolan [phone]
Eric Hebert [phone]
Specialty Pharmaceuticals
Michael K. Tong, CFA, PhD [phone]
Hudson R Boyer [phone]
James Omstrom, CFA [phone]
FINANCIAL SERVICES
Commercial Mortgage/Specialty Finance REITS James P. Shanahan [phone]
Financial Services
Douglas Sipkin, CFA [phone]
Warren Gardiner [phone]
Herman Chan, CFA [phone]
Jonathan Casteleyn, CFA [phone]
Insurance
Susan Spivak Bernstein [phone]
Elyse Greenspan, CFA [phone]
Susan Ross [phone]
Life Insurance
John Hall [phone]
Sean R. Dargan [phone]
Vincent Caintic [phone]
Specialty Finance James P. Shanahan [phone]
C. Ryan Hitchins, CFA [phone]
Christopher Harris, CFA [phone]
INDUSTRIAL
Aerospace & Defense Gary S. Liebowitz, CFA [phone] Michael D. Conlon [phone]
Automotive
Rich Kwas, CFA [phone]
David H. Lim [phone]
Containers & Packaging
Ghansham Panjabi, PhD [phone]
Matthew Wooten, CFA [phone]
Diversified Industrials
Wendy B. Caplan [phone]
Allison Poliniak, CFA [phone]
Machinery
Andrew Casey [phone]
Justin Ward [phone]
Sara Magers, CFA [phone]
Transportation Justin B. Yagerman [phone]
Robert H. Salmon [phone] Michael Webber [phone]
MEDIA & TELECOMMUNICATIONS
Broadcasting
Marci Ryvicker, CFA, CPA [phone]
Timothy Schlock, CFA, CPA [phone]
Media & Entertainment
John Janedis, CFA [phone]
Jaime Neuman, CFA, CPA [phone]
Brendan Metrano, CFA [phone]
Telecommunication Services - Wireless/Wireline
Jennifer M. Fritzsche [phone]
Gray Powell, CFA [phone]
Andrew Spinola [phone]
REAL ESTATE, GAMING & LODGING
Lodging/Retail/Self Storage & Net Lease Jeffrey J. Donnelly, CFA [phone] Dori Kesten [phone]
Robert Laquaglia [phone]
Office and Industrial/Diversified and Specialty
Christopher P. Haley [phone]
Brendan Maiorana, CFA [phone]
Young Ku, CFA [phone]
Philip DeFelice, CFA [phone]
TECHNOLOGY & SERVICES
Electronic Processing
Daniel R. Perlin, CFA [phone]
Matthew Roswell, CFA [phone]
Enterprise Hardware/Networking Hardware
Aaron Rakers, CFA [phone]
Matthew Nahorski [phone]
Information Technology (IT) Services
Edward S. Caso, Jr., CFA [phone]
Christopher Wicklund [phone]
Suman Kaba [phone]
Eric Boyer [phone]
Semiconductors/Computer Hardware David Wong, CFA, PhD [phone] Amit Chanda [phone] Brian Cutlip [phone]
Software
Philip Rueppel [phone]
Priya Parasuraman [phone]
Sid Nargundkar [phone]
Sam J. Pearlstein Todd M. Wickwire
Co-Head of Equity Research [phone] Co-Head of Equity Research [phone]
sam.earlstein wachovia.co todd.wickwire wachovia.co
Diane Schumaker-Krieg
Global Head of Research
[phone] / [phone]
[e-mail]
Lisa Hausner [phone] Lisa Howard [phone] Paul Jeanne, CFA [phone]
Global Publishing Director Director of Administration & Operations Global Research COO
[e-mail] [e-mail] [e-mail]
Colleen Hansen [phone]
[e-mail]
December 9, 2008
EQUITY STRATEGY
Equity Strategy
Gina Martin Adams, CFA [phone]
Phillip Neuhart [phone]