COC IDA021909.pdf

Please refer to pages 9-10 of this report for detailed disclosure and certification information.
Institutional Equity Research

IDACORP, INC.
February 23, 2009 IDA – NYSE

Rating:
BUY ↑

Price: (2/20/09) $24.25

Price Targets:
12-18 month: $28 ↓
5-year: $35 ↓

Industry:
Utilities

James L. Bellessa, Jr., CFA
406.791.7230
[e-mail]

Company Description:
Boise, ID -- IDACORP, Inc. is the holding
company for the Idaho Power Company, an
electric public utility that serves an
approximate 24,000 square mile area in
Southern Idaho and Eastern Oregon. Non-
regulated subsidiaries include an affordable
housing project finance company and an
operator of small hydroelectric generation
projects.

FY (Dec) 2008A 2009E Y-O-Y
Growth 2010E Y-O-Y
Growth
Revenue ($M) $960.4 $1,036.1 8% $1,073.0 4%
Previous $968.7 $1,046.3 -
Price/Revenue ratio 1.1x 1.1x 1.1x
EPS Revised $2.17 $2.28 5% $2.37 4%
Previous $2.19 $2.24 -
Price/EPS ratio 11.2x 10.6x 10.2x
EBITDA ($M) $325.0 $354.0 9% $368.9 4%
EV/EBITDA ratio 7.7x 7.1x 6.8x

Quarterly Data: EPS EPS Revenue Revenue EBITDA
Previous ($M) Previous ($M)
3/31/09E $0.48 $0.43 $232.1 $233.6 $81.7
6/30/09E $0.45 $0.39 $253.6 $255.0 $80.3
9/30/09E $1.09 NC $313.0 $311.2 $122.3
12/31/09E $0.26 $0.32 $237.4 $246.5 $69.7
Valuation Data Trading Data
Long-term growth rate (E) 5% Shares outstanding (M) 45.6
Total Debt/Cap (12/31/08) 52.2% Market Capitalization ($M) $1,105
Cash per share (12/31/08) $0.19 52-week range $21.88 - $33.89
Book value per share (12/31/08) $28.58 Average daily volume (3 mos.) (K) 657
Dividend (yield) $1.20 (4.9%) Float 97%
Return on Equity (T-T-M) 8% Index Membership S&P 400 MidCap

Shares Appear Oversold, Upgrading to BUY

• IDACORP reported 4Q'08 EPS of $0.16, compared to $0.23 in 4Q'07. We
were forecasting $0.18 and the consensus estimate of four analysts was $0.24.
• Increased utility revenues offset by higher expenses. Idaho Power posted EPS
of $0.17 for the quarter, versus $0.29 last year. Although revenues increased due
to rate relief, the benefit was eclipsed by higher operating and maintenance
expenses and a FERC-mandated refund to its transmission service customers
(-$0.11). Unexpectedly, quarterly results were also held back by an impairment
of equity securities (-$0.09), partially offset by a settlement of prior years’ tax
returns (+$0.06).
• Raising 2009 EPS estimate. Our 2009 EPS forecast is being increased from
$2.24 to $2.28 to reflect lower O&M and depreciation expenses than we
previously projected, offset in part by a higher expected tax rate and share count.
• Initiating 2010 estimate. In this report we are introducing our 2010 EPS
estimate of $2.37. We expect results will be helped by additional rate relief in
both Idaho and Oregon.
• Lowering target price. Due to lower utility sector valuations, we are reducing
our 12-18 month target price of $29 to $28, or ~12x the average of our 2009 and
2010 EPS estimates. Over the past decade, IDACORP has traded at a median
multiple of 14.8x price-to-year-forward EPS estimates. Given the recently
reduced share price, we are upgrading our stock rating from Neutral to BUY for
total return investors, including a 4.9% current yield.
D.A. Davidson & Co.
2
Price Chart
Source: Thomson One
D.A. Davidson & Co.
3
IDACORP reported 4Q'08 EPS of $0.16, compared to $0.23 in 4Q'07. We were forecasting
$0.18 and the consensus estimate was $0.24.

The company’s principal subsidiary, the Idaho Power Company (IPC), reported 4Q’08 EPS of
$0.17, compared to $0.29 a year ago and our forecast of $0.21.

As expected, utility EPS took a $0.10 per share hit from a FERC order which increased the
utility’s Open Access Transmission Tariff (OATT) refund to transmission service customers
(see our details in the Regulatory Update section).

Unexpectedly, quarterly results at the utility were also held back by a $0.09 per share
impairment charge on equity investments set aside to help meet future obligations relating to a
non-qualified benefit plan. The investments (maintained by the plan’s trustees) are a broadly
diversified group of exchange-traded index funds which were negatively impacted by the poor
performance of the stock market in 4Q’08.

The company’s non-regulated businesses and holding company activity reported a 4Q’08 loss
of $0.01 per share, compared to a loss of $0.06 per share in 4Q’07. The loss narrowed due to
a $0.06 per share benefit in recent quarter from the settlement of prior years’ tax returns.
Included in the non-regulated businesses is IDACORP Financial Services (IFS), which
contributed EPS of $0.03, a decline from $0.04 a year ago because of lower tax benefits from
aging affordable housing project investments.

Electric revenues of $216 million increased 10% from $196 million, with the bulk of the
$20 million improvement coming from general business revenues, which benefited from rate
relief over the past year, customer growth, and power cost adjustment (PCA) recoveries.

Offsetting the increase in electric revenues was a $22 million, or 13%, climb in electric
operating expenses to $194 million. Primary drivers behind the higher expenses were higher
power supply, O&M, and demand-side management expenses.

These expense increases were partially offset by lower depreciation expense. On September
12, 2008, the IPUC approved a revision to IPC’s depreciation rates, retroactive to August 1,
2008. The new rates are based on a settlement reached by IPC and the IPUC Staff, and result
in an annual reduction of depreciation expense of $8.5 million based upon depreciable electric
plant in service as of December 31, 2006.

Our 2009 EPS forecast is being raised from $2.24 to $2.28, to reflect lower O&M and
depreciation expenses than we previously projected, offset in part by a higher-than-assumed
tax rate and share count. As part of the company’s belt tightening, management is guiding to
2009 O&M expenses of $280-$290 million, down from $294 million in 2008. With a
declining tax shelter from IFS, the company’s overall tax rate should rise to 24%-28% in 2009
from 16% in 2008. Also, the company should continue to use its continuous equity plan
(CEP) to issue common stock to maintain its equity ratios in the 45%-50% range. In 2008,
IDACORP raised $51 million through stock issuances, including $42 million from the
issuance of 1.5 million shares through the CEP. Management does not provide an EPS
guidance range.

We are initiating our 2010 EPS estimate of $2.37. We expect results will be helped by an
improving economy, as well as a boost from a new Oregon and possibly Idaho general rate
cases that should be filed later this year.

With utility valuations retreating to near their October 2008 lows, we are reducing our 12-18
month target price of $29 to $28, or ~12x the average of our 2009 and 2010 EPS estimates.
Over the past decade, IDACORP has traded at a median multiple of 14.8x price-to-year-
forward EPS estimates. Given the recently reduced share price, we are upgrading our stock
rating from Neutral to BUY for total return investors, including a nearly 5% current yield.

EPS Falls 29%
Rate Relief and PCA Recovery
Boost Revenues
Adjusting 2009 EPS Estimate;
Initiating 2010

Lowering Tar et Price, but Raisin
Rating
D.A. Davidson & Co.
4
REGULATORY UPDATE

On January 30, 2009, the IPUC issued its final order in Idaho Power’s 2008 general rate case.
The utility was granted a revenue increase of ~$20.9 million (+3.1%), less than a third of the
utility’s request for an increase of $66.6 million (+9.9%). In its order, the IPUC expressed its
view that the utility will need to adjust to “new realities” in the current economic
environment, and if Idaho Power is to attain the allowed ROE it will have to achieve it by
reducing operating costs and increasing efficiencies, and not through its sought-for rate
increase. The new rates went into effect on February 1st.

The bulk of the nearly $46 million of costs not allowed by the IPUC were comprised of three
items: $13.0 million of operating & maintenance expenses, $12.7 million due to the allowed
ROE of 10.5% compared to the requested 11.25%, and $10.6 million of net power supply
costs. Regarding this last rejected cost, it is important to note that under a new power cost
adjustment (PCA) mechanism accepted on January 9th, 95% of the company’s net power
supply costs over the amount in base rates are paid for by ratepayers. Therefore, lowering the
amount included in base rates by $10.6 million just means that if the costs are indeed higher
(as the utility forecasted in its rate case filing), then the company will collect 95% of that
excess and only absorb 5%. Previously the mechanism called for a 90%/10% cost sharing.

Positive points in the decision include: Idaho Power’s rate base for its Idaho jurisdiction
essentially remained unchanged at the company’s ~$2.1 billion recommendation (with an
8.2% allowed rate of return); the utility’s equity ratio of 49.27% was accepted as submitted; a
“higher” ROE was allowed (10.5% versus 10.25% in the last adjudicated decision); a year
forward test year was accepted for the first time as opposed to a historical test year; the load
growth adjustment rate has been lowered from $28.14/MWh to an estimated $26.52/MWh; a
new residential tiering rate schedule was enacted; and ongoing finance costs of $6.8 million
(allowance for funds used during construction) for the relicensing of the Hells Canyon Project
were allowed in rate base for the first time since the company’s relicensing efforts started ten
years ago, in order to support cash flows for the utility’s credit rating purposes (but not
profits), even though the company’s relicensing efforts are still ongoing.

Idaho Power’s management expressed their disappointment in the decision and filed a petition
for reconsideration and/or clarification on February 19th, stating that the IPUC decision on
certain issues was “unreasonable, erroneous, unduly discriminatory, not in conformity with
the facts of record and/or the applicable law, and result in a revenue requirement and rates
which are confiscatory.” In the filing, Idaho Power challenges several issues in the IPUC’s
order that aggregate approximately $8 million annually. The key issues include the method
used in calculating the utility’s labor expense, apparent accounting errors used in the
computation of the revenue requirement, and the deduction of credits from a 2006 FERC case
from the revenue requirement which the utility believes to be illegal “retroactive ratemaking.”
IPC also asked for clarification on how to implement certain aspects of the rate order. The
IPUC has a 28-day deadline to consider the petition, and if the petition is granted the
Commission’s decision would be handed down by the end of July 2009. Regardless of the
outcome of the petition for reconsideration, Idaho Power has the ability to file a fresh Idaho
rate case in 2009.

Idaho Power filed its 2008/2009 PCA in April 2008, requesting recovery of approximately
$87 million in power supply and fuel expenses incurred from April 15, 2007 through April 15,
2008. However, subsequent to its PCA filing, state regulators ordered that $16 million of
proceeds plus interest from the sale of SO2 credits in 2007 be used to reduce the impact of the
PCA filing from $87 million to $70.7 million.

On May 30, 2008, the IPUC ordered a change in Idaho Power’s methodology in calculating
the PCA. The new methodology results in an equal amount of power supply costs across all
months, compared with the older, more seasonal allocation that would have recognized
significantly more power supply costs in the third quarter and less in the first and second
quarters. The new PCA mechanism, which is not expected to have a material impact on
2008 Idaho General Rate Case
2008 Idaho PCA Proceedings
D.A. Davidson & Co.
5
annual financial results, went into effect on June 1st, as well as an approved increase to
existing revenues of $73.3 million (10.7%).

A stipulated agreement was accepted by the IPUC on January 9, 2009 which will allow for
annual adjustments to retail rates by tracking the difference between actual power supply
expenses and net power supply expenses currently being recovered in rates. The stipulation
addresses five aspects of the PCA, with a sixth aspect being deferred for future discussion:
• As of February 1, 2009, a new mechanism for sharing deviations in power supply
cost between the utility and its customers will be applied. The original methodology
distributed power cost deviations 90%/10% between customers and shareholders,
respectively. The stipulation changes the sharing percentage to 95%/5%.
• A new mechanism for calculating the LGAR will go into effect with the
implementation of new rates from Idaho Power’s 2008 general rate case (we estimate
that the new methodology will result in a LGAR of $26.52 per MWh). The LGAR is
intended to eliminate recovery of power supply expenses due to changing weather
conditions, a growing customer base, or different customer usage patterns.
• Beginning with the implementation of rates from the 2008 general rate case, third
party transmission expenses that are not already included in base rates will be
reflected in PCA computations.
• Idaho Power will be allowed to use its own forecast of net power supply expenses,
replacing the admittedly less accurate forecast of inflows into the Brownlee
Reservoir prepared by the federal government, as the starting point for the PCA.
This new methodology will become effective with the utility’s next PCA filing in
April 2009.
• Base net power supply expenses will be distributed throughout the year based on the
monthly shape of normalized revenues for purposes of the PCA deferral calculation.
This change will take effect with the implementation of rates from the 2008 general
rate case.
• The current policy of allocating PCA expenses to different customer classes on an
equal cents-per-kWh basis should be re-evaluated following Idaho Power’s current
general rate case.

On June 1, 2006, the FERC accepted a revision in the way open access transmission tariffs
(OATTs) were calculated for Idaho Power, the utility subsidiary of IDACORP, Inc. The new
method allowed the utility to move from a fixed rate to a formula rate which would be
updated annually. The approval translated into a revenue increase of $11 million for Idaho
Power and was subject to refund depending on the outcome of the hearing and settlement
process. Idaho Power also requested a return on equity of 11.25%.

A stipulated agreement was approved in August 2007 which settled all issues except the
treatment of certain legacy transmission service contracts. This settlement reduced the
estimated annual revenue increase to approximately $8.2 million, and required Idaho Power to
issue a refund of the rates collected in excess of the new agreed-upon rate. Also, the FERC
established an authorized return on equity of 10.7% as part of the settlement. Later that
month, the FERC’s presiding administrative law judge (ALJ) handed down an initial decision
in the case of the legacy contracts which would reduce the annual revenue increase to
approximately $6.8 million and require additional refunds of $5.4 million.

The ALJ’s decision was appealed, and on January 15, 2009 an order was handed down which
upheld the ALJ’s initial decision in most respects. One modification to the initial decision is
that Idaho Power was required to reduce its transmission rates to FERC jurisdictional
customers and refund $13.3 million to these customers for the period since the new rates went
into effect in June 2006. The refunds must be issued within 45 days of the FERC order. The
utility has filed a request for rehearing with the FERC.

FERC Transmission Rate Case
D.A. Davidson & Co.
6
Idaho Power mentioned in its recent earnings press release that it will seek approval from its
Board of Directors and the Idaho Public Utilities Commission (IPUC) to construct a new
baseload energy resource. As the company is still evaluating proposals and has not made a
decision on what form the resource would take, the cost associated with this power source
was not included in the utility’s 2009-2011 capital expenditures budget of $780-$800 million
(this capex budget does include expenditures for the siting and permitting of several major
transmission projects). The application is expected to be submitted during the first quarter of
2009, with a decision expected to come forth later this year.

On August 4, 2008, Idaho Power filed a request with the Idaho Public Utilities Commission
for permission to install Advanced Metering Infrastructure (AMI) technology throughout its
service territory at a cost of $71 million. The installations would begin in January 2009 and
conclude in 2011. Approximately two-thirds of the AMI costs are included in the company’s
2008-2010 capital expenditure guidance. Idaho Power noted that it will not seek a change in
customer rates at this time, even though the 2009 revenue requirement from deployment of
the AMI is estimated to be $12.2 million. However, rate impacts will be addressed in
subsequent proceedings after a deployment plan is approved by the Commission.

In February 2008, state regulators approved a settlement agreement associated with Idaho
Power’s June 2007 rate request. The order approves a general electric rate increase of
$32.1 million, or 5.2%, effective March 1, 2008. The agreement did not identify a rate base,
equity ratio, or an allowed ROE. Idaho Power had originally filed its rate case requesting an
increase of approximately $64 million, or 10.35%, and a return on equity of 11.5%. The then-
allowed authorized rate of return of 8.1% remained unchanged.

On May 30, 2008 Idaho Power received authorization from the IPUC to increase customer
rates by 1.39%, translating to $8.9 million as a result of $64.2 million being added to the
company’s rate base attributed to the new Danskin CT1 natural gas power plant and associated
transmission and interconnection upgrades located near Mountain Home, ID. The 170-MW
addition to the Danskin Generating Unit is primarily used as a peaking facility and began
commercial operation on March 11, 2008. New retail rates associated with the Danskin
facility became effective on June 1, 2008.

On August 4, 2008, the IPUC approved Idaho Power’s proposed 2-year power purchase
agreement with PPL EnergyPlus, LLC (a PPL Montana subsidiary) which was filed on June
16th. The agreement allows IPC to buy 83 MW per hour of electricity during heavy load
times during June through August, at a price of $110 per MWh. The agreement extends
through 2011 and replaces a previous agreement which would have expired in 2009. The
Commission also approved Idaho Power’s request that the expenses associated with the
energy purchase and transmission be included in its annual PCA filing, which is made each
April and made effective on June 1st each year.

In April 2008, state regulators in Oregon approved a stipulation agreement regarding Idaho
Power’s August 2007 filing for a purchased cost adjustment mechanism (PCAM) in the state
of Oregon. The mechanism differs from the Idaho PCA in that it reestablishes the base net
power supply costs annually. In Idaho, the base net power supply costs are set by a general
rate case. The OPUC approved the request and the new rates went into effect on June 1,
2008. The approved PCAM results in a $4.8 million, or 15.69 percent, increase in Oregon
revenues.

Plans for New Baseload Energy
Resource
Advanced Metering Infrastructure
Case
2007 Idaho General Rate Case
Danskin 1 Power Plant Application
PPL Purchase Power Agreement
Oregon Power Cost Adjustment
Mechanism
D.A. Davidson & Co.
7
IDACORP, Inc. Balance Sheet
$ thousands -- Fiscal year ends 12/31 2003 2004 2005 2006 2007 2008
ASSETS:
Electric Plant:
In service (at original cost) $3,220,228 $3,324,816 $3,477,067 $3,583,694 $3,796,339
Accumulated provision for depreciation (1,239,604)(1,316,125)(1,364,640)(1,406,210)(1,468,832) In service - net 1,980,624 2,008,691 2,112,427 2,177,484 2,327,507
Construction work in progress 96,091 152,427 149,814 210,094 257,590 Held for future use 2,438 2,636 2,906 2,810 3,366
Other property, net of accum. Depreciatio 9,166 45,708 29,294 28,692 28,089
Property, plant and equipment - net 2,088,319 2,209,462 2,294,441 2,419,080 2,616,552 2,758,165
Investments And Other Property 204,474 223,061 191,593 202,825 201,085 198,552
Current Assets: Cash and cash equivalents 75,159 23,403 52,356 9,892 7,966 8,828
Receivables:
Customer 93,599 92,258 94,469 62,131 69,160
Gas operations
Allowance for uncollectible accounts (43,210) (43,108) (33,078) (7,168) (7,505) Notes
Employee notes receivable 3,347 3,523 2,951 2,569 2,128 Other 8,209 8,806 21,377 11,855 10,957
Total Receivables 91,380
Energy marketing assets 4,176 9,203 23,859 12,069 0
Derivative assets
Taxes receivable Accrued unbilled revenues 30,869 33,832 38,905 31,365 36,314
Materials and supplies (at avg. cost) 21,351 28,008 30,451 39,079 43,270 Fuel stock (at average cost)6,228 6,539 11,739 15,174 17,268
Prepayments 27,779 30,035 17,876 9,308 9,371
Regulatory assets associated with taxes 4,382 23,407 23,922 28,035 25,672
Regulatory assets -- derivatives 6,269 5,510 3,064 0 0
Refundable income tax deposit 44,903 46,083 Other current assets 0 2,956 3,993 6,023 166,076
Assets held for sale 0 0 6,673 3,326 0 Total current assets 238,158 221,416 297,520 266,531 266,707 266,284
Other Assets:
American Falls and Milner water rights 31,585 31,585 31,585 30,543 29,501
Company-owned life insurance 35,624 35,765 35,401 34,055 30,842Energy marketing assets -- long-term 14,358 16,635 22,189
Regulatory assets associated with taxes 427,760 433,271 415,177 423,548 449,668 696,332Regulatory asset - PCA
Regulatory assets - long-term derivatives
Regulatory assets - other
Long-term receivables 3,106 2,895 4,015 3,802 3,583
Other 62,724 60,082 46,239 43,670 55,370 103,512 Assets held for sale 25,966 21,076 0
Total other assets 575,157 580,233 580,572 556,694 568,964 799,844
TOTAL ASSETS $3,106,108 $3,234,172 $3,364,126 $3,445,130 $3,653,308 $4,022,845
CAPITALIZATION AND LIABILITIES:
Capitalization: Common stock equity
Common stock $472,902 $589,440 $598,706 $638,799 $675,774
Retained earnings 397,167 424,312 437,284 493,363 537,699
Other comprehensive income (2,630) (888) (3,425) (5,737) (6,156)
Treasury stock (3,158) (4,578) (998) (2,242) (2) Unearned compensation (6,316)
Total common stock equity 864,281 1,008,286 1,025,251 1,124,183 1,207,315 1,302,437 Preferred stock 52,366
Long-term debt 945,834 979,549 1,023,545 928,648 1,156,880 1,183,451
Total capitalization 1,862,481 1,987,835 2,048,796 2,052,831 2,364,195 2,485,888
Current Liabilities: Long-term debt due within one year 67,923 78,603 16,307 95,125 11,456 86,528
Notes payable 93,650 36,270 60,100 129,000 186,445 151,250 Accounts payable 60,916 79,156 80,324 86,440 85,116 96,785
Energy marketing liabilities 4,317 9,420 24,093 13,532 0
Derivative liabilities 0 0 0 0 0
Taxes accured 45,601 46,318 72,652 47,402 8,492
Interest accrued 13,741 14,426 14,616 12,657 18,913 Deferred income taxes
Uncertain tax positions 26,764 Other 25,557 21,265 19,577 23,572 38,129 61,105
Liabilities held for sale 0 0 5,916 2,606 0
Total current liabilities 311,705 285,458 293,585 410,334 375,315 395,668

Other Liabilities:
Regulatory liabilities associated with
deferred investment tax credits
Energy marketing liabilities -- long-term 14,393 16,635 22,189 0 0
Derivative liabilities -- long-term 0 0 0 0 0 Deferred income taxes 554,715 555,774 519,563 498,512 466,182 515,719
Regulatory liabilities associated with
income taxes Regulatory liabilities - PCA
Regulatory liabilities - other 258,524 275,854 345,109 294,844 274,204 276,266 Other 104,290 112,616 124,833 179,836 173,412 349,304
Liabilities held for sale 0 0 10,051 8,773 0
Total other liabilities 931,922 960,879 1,021,745 981,965 913,798 1,141,289
TOTAL CAPITALIZATION AND
LIABILITIES $3,106,108 $3,234,172 $3,364,126 $3,445,130 $3,653,308 $4,022,845
Shares Outstanding (000's)38,207 42,217 42,632 43,834 45,063 46,900Book Value per Share $22.62 $23.88 $24.05 $25.65 $26.79 $27.77
% of Total Capitalization
Long-Term Debt 50.8% 49.3% 50.0% 45.2% 48.9% 47.6%
Preferred 2.8% 0.0% 0.0% 0.0% 0.0% 0.0%
Common 46.4% 50.7% 50.0% 54.8% 51.1% 52.4%
D.A. Davidson & Co.
8
IDACORP, Inc. Consolidated Statements of Income
$ thousands -- Fiscal year ends 12/31 4Q07 2007 1Q08 2Q08 3Q08 4Q08 2008 1Q09E 2Q09E 3Q'09E 4Q'09E 2009E 2010E
REVENUES:
Electric Utility:
General business $156,966 $668,303 $167,313 $188,748 $246,639 $181,611 $784,311 $181,312 $202,649 $262,325 $192,084 $838,370 $863,730
Off system sales 25,089 154,948 33,363 25,641 34,637 27,789 121,430 37,823 37,903 37,678 32,305 145,710 155,723
Other revenues 14,374 52,150 12,120 14,556 16,831 6,828 50,335 12,200 12,200 12,200 12,200 48,800 50,000
Total Electric Utility Revenues 196,429 875,401 212,796 228,945 298,107 216,228 956,076 231,335 252,752 312,204 236,589 1,032,880 1,069,454
Diversified Operations: Other 1,017 3,993 644 1,281 1,609 804 4,338 800 800 800 800 3,200 3,500 Total Revenues 197,446 879,393 213,440 230,226 299,716 217,032 960,414 232,135 253,552 313,004 237,389 1,036,080 1,072,954EXPENSES:
Electric Utility:
Purchased power 48,091 289,484 45,299 50,089 79,513 56,237 231,138 48,838 61,261 81,799 57,080 248,977 264,205
Fuel expense 32,598 134,322 37,237 28,681 46,467 37,018 149,403 38,170 34,122 43,709 40,220 156,220 160,418
Power cost adjustment (13,674)(121,131)(17,744)(829)(20,105)(8,735)(47,413)(8,000)0 (9,000)(2,000)(19,000)(20,000)
Total Power Supply 67,015 302,675 64,792 77,941 105,875 84,520 333,128 79,008 95,382 116,507 95,300 386,198 404,623
Impairment of assets
Other Operations and Maintenance 70,639 286,510 68,927 75,617 74,778 74,708 294,030 69,401 75,826 72,119 70,267 287,612 294,100
Demand-side management 4,518 13,487 3,364 3,928 5,956 5,631 18,879 5,700 5,800 5,900 6,000 23,400 24,000
Gain on sale of emission allowances (2,754)(346) (158)(504) 0 0
Depreciation 26,203 103,072 25,750 26,617 25,717 24,001 102,085 24,250 24,500 24,750 25,000 98,500 102,000
Taxes other than income taxes 3,366 17,634 4,803 4,800 4,827 4,653 19,083 5,089 5,055 4,995 4,968 20,108 20,320
Total Electric Utility Expenses 171,741 720,624 167,636 188,557 216,995 193,513 766,701 183,448 206,563 224,272 201,535 815,818 845,042
Other:1,910 6,692 1,048 1,140 1,144 (286)3,046 1,200 1,200 1,200 1,200 4,800 5,000
Total Operating Expenses 173,651 727,316 168,684 189,697 218,139 193,227 769,747 184,648 207,763 225,472 202,735 820,618 850,042
OPERATING INCOME
Electric Utilit 24,688 154,777 45,160 40,388 81,112 22,715 189,375 47,887 46,189 87,932 35,054 217,062 224,412 Other Diversified Operations (893)(2,699)(404)141 465 1,090 1,292 (400)(400)(400)(400)(1,600)(1,500) Equity in Earnings of Partnerships Operating Income 23,795 152,078 44,756 40,529 81,577 23,805 190,667 47,487 45,789 87,532 34,654 215,462 222,912
TOTAL OTHER INCOME:6,657 20,524 4,417 6,082 4,629 (3,267)11,861 5,000 5,000 5,000 5,000 20,000 21,000
Earnings of Uncons. Eq-method Inv.(1,567)(4,824)(4,036) (3,278) 2,642 675 (3,997)(1,000) (1,000) (1,000) (1,000)(4,000) (4,400)
TOTAL OTHER EXPENSES:1,597 8,434 365 1,820 2,764 2,912 7,861 2,000 2,000 2,000 2,000 8,000 8,200
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 16,655 59,961 16,876 15,744 17,226 17,404 67,250 17,450 17,500 17,550 17,600 70,100 72,500
Other interest (502)3,380 596 1,313 1,310 2,587 5,806 2,000 2,000 2,000 2,000 8,000 8,000
Net interest charges 16,153 63,341 17,472 17,057 18,536 19,991 73,056 19,450 19,500 19,550 19,600 78,100 80,500
Dividends on preferred stock 0 0 0 0 0 0 0 0 0 0 0 0 0
Total interest expense and other 16,153 63,341 17,472 17,057 18,536 19,991 73,056 19,450 19,500 19,550 19,600 78,100 80,500
INCOME BEFORE INCOME TAXES:11,135 96,003 27,300 24,456 67,548 (1,690)117,614 30,037 28,289 69,982 17,054 145,362 150,812
INCOME TAXES:840 13,731 5,584 6,941 15,809 (9,134)19,200 7,810 7,355 18,195 4,434 37,794 39,211
Income from Continuing Operations 10,295 82,272 21,716 17,515 51,739 7,444 98,414 22,227 20,934 51,787 12,620 107,568 111,601Losses from Disc. Ops. (net of tax)0 67 0 0 0 0 0 0 0 0 0 0
Net Income Available for Common 10,295 82,339 21,716 17,515 51,739 7,444 98,414 22,227 20,934 51,787 12,620 107,568 111,601
Earnings per share from cont. ops.$0.23 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.48 $0.45 $1.09 $0.26 $2.28 $2.37
Losses from Discontinued Operations $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
EPS $0.23 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.48 $0.45 $1.09 $0.26 $2.28 $2.37
Dividends paid per share of common stock $0.300 $1.20 $0.300 $0.300 $0.300 $0.300 $1.20 $0.300 $0.300 $0.300 $0.300 $1.20 $1.20
Avg. common shares outstanding (000) 44,918 44,291 45,004 45,096 45,194 46,027 45,330 46,627 47,027 47,427 47,827 47,227 47,027
Segment breakdown of EPS
Idaho Power Company $0.29 $1.73 $0.47 $0.39 $1.05 $0.17 $2.08 $0.47 $0.44 $1.08 $0.25 $2.24 $2.34
IDACORP Energy (0.00)($0.00)(0.00) (0.00) (0.00) (0.00)($0.00)
Ida-West Energy 0.00 $0.05 0.00 0.02 0.03 0.00 $0.05
IDACORP Financial 0.04 $0.16 0.02 0.02 0.02 0.03 $0.08
Holding Company (0.10)($0.08)(0.01)(0.04)0.05 (0.03)($0.03)
EPS from Continuing Operations $0.23 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.48 $0.45 $1.09 $0.26 $2.28 $2.37
IdaTech
IDACOMM
(Losses) from Discontinued Operations $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Reported EPS $0.23 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.48 $0.45 $1.09 $0.26 $2.28 $2.37
D.A. Davidson & Co.
Two Centerpointe Drive, Suite 400 • Lake Oswego, Oregon 97035 • [phone] • [phone] • www.dadavidson.com
Copyright D.A. Davidson & Co., 2009. All rights reserved.
9
Required Disclosures
D.A. Davidson & Co. expects to receive, or intends to seek, compensation for investment banking services from this company in the
next three months.
D.A. Davidson & Co. is a full service investment firm that provides both brokerage and investment banking services. James L.
Bellessa, Jr., CFA, the research analyst principally responsible for the preparation of this report, will receive compensation that is
based upon (among other factors) D.A. Davidson & Co.’s investment banking revenue. However, D.A. Davidson & Co.’s analysts are
not directly compensated for involvement in specific investment banking transactions.
I, James L. Bellessa, Jr., CFA, attest that (i) all the views expressed in this research report accurately reflect my personal views about
the common stock of the subject company, and (ii) no part of my compensation was, is, or will be, directly or indirectly, related to the
specific recommendations or views expressed in this report.

Ratings Information

D.A. Davidson & Co. Ratings Buy Neutral Underperform
Risk adjusted return potential Over 15% total return
expected on a risk adjusted
basis over next 12-18 months
>0-15% return potential
on a risk adjusted basis
over next 12-18 months
Likely to remain flat or lose
value on a risk adjusted basis
over next 12-18 months
Distribution of Ratings (as of 12/31/08) Buy Hold Sell
Corresponding Institutional Research Ratings Buy Neutral Underperform
and Distribution 48% 49% 3%
Corresponding Private Client Research Ratings Outperform Market Perform Underperform
and Distribution 95% 5% 0%
Distribution of Combined Ratings 52% 46% 2%
Distribution of companies from whom D.A. Davidson & Co. has received compensation for investment banking services in last 12 mos.
Institutional Coverage 2% 3% 0%
Private Client Coverage 0% 0% 0%
Distribution of Combined Investment Banking 2% 3% 0%

D.A. Davidson & Co.’s Institutional Research Rating Scale (maintained since 7/9/02): Buy, Neutral, Underperform
D.A. Davidson & Co.
Two Centerpointe Drive, Suite 400 • Lake Oswego, Oregon 97035 • [phone] • [phone] • www.dadavidson.com
Copyright D.A. Davidson & Co., 2009. All rights reserved.
10
Target prices are our Institutional Research Department’s evaluation of price potential over the next 12-18 months and 5 years, based
upon our assessment of future earnings and cash flow, comparable company valuations, growth prospects and other financial criteria.
Certain risks may impede achievement of these price targets including, but not limited to, broader market and macroeconomic
fluctuations and unforeseen changes in the subject company’s fundamentals or business trends.

Other Disclosures

Information contained herein has been obtained by sources we consider reliable, but is not guaranteed and we are not soliciting any
action based upon it. Any opinions expressed are based on our interpretation of data available to us at the time of the original
publication of the report. These opinions are subject to change at any time without notice. Investors must bear in mind that inherent
in investments are the risks of fluctuating prices and the uncertainties of dividends, rates of return and yield. Investors should also
remember that past performance is not necessarily an indicator of future performance and D.A. Davidson & Co. makes no guarantee,
express or implied, as to future performance. Investors should note this report was prepared by D.A. Davidson & Co.’s Institutional
Research Department for distribution to D.A. Davidson & Co.’s institutional investor clients and assumes a certain level of investment
sophistication on the part of the recipient. Readers, who are not institutional investors or other market professionals, should seek the
advice of their individual investment advisor for an explanation of this report’s contents, and should always seek such advisor’s advice
before making any investment decisions. Further information and elaboration will be furnished upon request.