COC IDA020209.pdf

Please refer to pages 8-9 of this report for detailed disclosure and certification information.
Institutional Equity Research

IDACORP, INC.
February 2, 2009 IDA – NYSE

Rating:
NEUTRAL ↓

Price: (1/30/09) $29.11

Price Targets:
12-18 month: $29 ↓
5-year: $36 ↓

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) 2007A 2008E Y-O-Y
Growth 2009E Y-O-Y
Growth
Revenue ($M) $879.4 $968.7 10% $1,046.3 8%
Previous - NC $1,077.7
Price/Revenue ratio 1.5x 1.4x 1.3x
EPS Revised $1.86 $2.19 18% $2.24 2%
Previous - NC $2.32
Price/EPS ratio 15.7x 13.3x 13.0x
EBITDA ($M) $293.0 $342.4 17% $356.3 4%
EV/EBITDA ratio 9.4x 8.0x 7.7x

Quarterly Data: EPS EPS Revenue Revenue EBITDA
Previous ($M) Previous ($M)
3/31/08A $0.48 - $213.4 - $80.0
6/30/08A $0.39 - $230.2 - $79.1
9/30/08A $1.14 - $299.7 - $116.1
12/31/08E $0.18 NC $225.3 NC $67.2
Valuation Data Trading Data
Long-term growth rate (E) 5% Shares outstanding (M) 45.6
Total Debt/Cap (9/30/08) 53.9% Market Capitalization ($M) $1,327
Cash per share (9/30/08) $1.27 52-week range $21.88 - $36.72
Book value per share (9/30/08) $27.88 Average daily volume (3 mos.) (K) 477
Dividend (yield) $1.20 (4.1%) Float 97%
Return on Equity (T-T-M) 8% Index Membership S&P 400 MidCap

Recession a Major Factor in Rate Case Decision.
Despite Expected Belt Tightening, Downgrading to NEUTRAL.
• Rate relief comes up short. In a decision handed down January 30th by the
Idaho Public Utilities Commission (IPUC), Idaho Power (IPC) was granted
$20.9 million in rate relief – less than a third of the $66.7 million increase in rates
the utility had requested last June in its 2008 test year general rate case.
• Current recession was a major factor in the IPUC decision. Even though
Idaho Power’s management initially expressed disappointment in the amount of
rate relief and said it is weighing the company’s options, we sense that the utility
will ultimately accept the rate decision and attempt to adjust to the “new
realities.” This is the term the Commission used to describe how society is in the
current severe economic downturn together, and if IPC 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.
• Trimming estimate for rate decision. We are reducing our 2009 revenue
forecast by $31 million to $1.046 billion to reflect the Idaho rate decision.
However, we do not expect the company will achieve its allowed ROE in Idaho
in 2009 as the company’s belt tightening is unlikely to surmount the revenue
shortfall bought about by the rate case decision and a weak economy.
• We are lowering our 12-18 month target price from $32 to $29, or ~13x our
lowered 2009 earnings estimate, to reflect disappointment in the rate decision and
increased burden the utility has to support its ratepayers in a recession. At the
current share price, we are lowering our rating from Buy to NEUTRAL.
D.A. Davidson & Co.
2
Price Chart
Source: Thomson One
D.A. Davidson & Co.
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In a decision handed down January 30th by the Idaho Public Utilities Commission (IPUC),
Idaho Power (IPC) was granted $20.9 million in rate relief – less than a third of the
$66.7 million increase in rates the utility had requested last June in its 2008 test year general
rate case. Rates for Idaho Power Company customers increased by an average 3.1% effective
February 1, 2009, with rates for residential customers hiked an average 1.6%. It appears the
current recession was a major factor in the IPUC decision.

Even though Idaho Power’s management initially expressed disappointment in the amount of
rate relief and said it is weighing the company’s options, we sense that the utility will
ultimately accept the rate decision and attempt to adjust to the “new realities.” This is the
term the Commission used to describe how society is in the current severe economic
downturn together, and if IPC 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 utility has until February 20th to ask for reconsideration.

While the IPUC is statutorily required to allow IPC to recover all prudently incurred expenses
in order to serve customers, judgment on the appropriateness of the company’s expenditures
is in the eyes of the beholder. The Commission believes it is able to legally defend why it
disallowed certain costs as not being prudently incurred or in the best interest of customers.
In sum, and given the backdrop of the recession, the IPUC believes it has balanced the best
interests of ratepayers with the company’s financial needs. We expect the company will
decide against a challenge of the decision, given the overall progress it has made in the past
year on the regulatory front, the possible political backlash it may receive during tough
economic times for its customers, and the company’s ability to file a fresh Idaho rate case
application in 2009.

On the case’s positive side, many of the company’s recommendations were accepted by the
IPUC in part or all. These include: IPC’s rate base for its Idaho jurisdiction essentially
remained unchanged at the company’s 2.093 billion recommendation; 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 (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.

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 IPC has forecasted), then the company will collect 95% of that excess and only absorb
5%. Previously the mechanism called for a 90%/10% cost sharing.

We are reducing our 2009 revenue forecast by $31 million to $1.046 billion to reflect the
Idaho rate decision. However, we do not expect the company will achieve its allowed ROE in
Idaho in 2009 as the company’s belt tightening is unlikely to surmount the revenue shortfall
bought about by the rate case decision and a weak economy. Our bottoms up 2009 EPS
forecast is reduced to $2.24 from $2.32. Under normal weather and streamflow conditions we
believe the company could earn approximately $2.50 per share from its three regulatory
jurisdictions of Idaho, Oregon, and FERC and its non-regulated businesses. From the Idaho
Idaho regulators attempt to
mitigate impact of rate relief on
ratepayers
Positive aspects of rate case
Disallowed costs softened b recent
PCA changes
Trimming EPS estimate for rate
decision
D.A. Davidson & Co.
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jurisdiction alone, the just decided rate case should allow a theoretical top-down annualized
earnings power of $2.33 per share (($2.094 billion rate case x 49.27% equity ratio x 10.5%)/
46.594 million average 2009 shares)).

We are lowering our 12-18 month target price from $32 to $29, or ~13x our lowered 2009
earnings estimate, versus the median 14.8x price/earnings ratio of year-forward estimates over
the past decade. Our reduced target reflects our overall disappointment in the rate decision,
the apparent increased burden the utility has to support its ratepayers in a recession, and
deterioration in the company’s 2009 streamflow outlook in the past month. We reserve the
right to modify our earnings estimate and target price once the company weighs in on the rate
case outcome when it files a Form 8-K in the next few days. At the current share price, we
are lowering our stock rating from Buy to NEUTRAL.

James L. Bellessa, Jr., CFA
Vice President and Senior Research Analyst
406.791.7230

Recent Regulatory Decisions/Filings

2008 Idaho General Rate Case
See discussion above.

2008 Idaho PCA Proceedings
Idaho Power filed its 2008/2009 Power Cost Adjustment (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
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 Load Growth Adjustment Rate (LGAR) will
go into effect with the implementation of new rates from Idaho Power’s 2008 general
rate case. 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.
Lowering target price and rating
D.A. Davidson & Co.
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• 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.

Advanced Metering Infrastructure Case
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 began in January 2009 and will
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.

2007 Idaho General Rate Case
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.

Danskin 1 Power Plant Application
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.

Oregon Power Cost Adjustment Mechanism
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 APCU results in a $4.8 million, or 15.69 percent, increase in Oregon
revenues.

PPL Purchase Power Agreement
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.
D.A. Davidson & Co.
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IDACORP, Inc. Balance Sheet
$ thousands -- Fiscal year ends 12/31 2003 2004 2005 2006 2007 9/30/2008
ASSETS:
Electric Plant:
In service (at original cost) $3,220,228 $3,324,816 $3,477,067 $3,583,694 $3,796,339 $3,957,199
Accumulated provision for depreciation (1,239,604)(1,316,125)(1,364,640)(1,406,210)(1,468,832)(1,499,947) In service - net 1,980,624 2,008,691 2,112,427 2,177,484 2,327,507 2,457,252
Construction work in progress 96,091 152,427 149,814 210,094 257,590 225,965 Held for future use 2,438 2,636 2,906 2,810 3,366 6,318
Other property, net of accum. Depreciatio 9,166 45,708 29,294 28,692 28,089 27,615
Property, plant and equipment - net 2,088,319 2,209,462 2,294,441 2,419,080 2,616,552 2,717,150
Investments And Other Property 204,474 223,061 191,593 202,825 201,085 201,807
Current Assets: Cash and cash equivalents 75,159 23,403 52,356 9,892 7,966 57,726
Receivables:
Customer 93,599 92,258 94,469 62,131 69,160 78,192
Gas operations
Allowance for uncollectible accounts (43,210) (43,108) (33,078) (7,168) (7,505) (1,359) Notes
Employee notes receivable 3,347 3,523 2,951 2,569 2,128 203 Other 8,209 8,806 21,377 11,855 10,957 6,617
Total Receivables
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 39,065
Materials and supplies (at avg. cost) 21,351 28,008 30,451 39,079 43,270 51,324 Fuel stock (at average cost)6,228 6,539 11,739 15,174 17,268 24,402
Prepayments 27,779 30,035 17,876 9,308 9,371 10,299
Regulatory assets associated with taxes 4,382 23,407 23,922 28,035 25,672 14,375
Regulatory assets -- derivatives 6,269 5,510 3,064 0 0
Refundable income tax deposit 44,903 46,083 24,903 Other current assets 0 2,956 3,993 6,023 8,904
Assets held for sale 0 0 6,673 3,326 0 Total current assets 238,158 221,416 297,520 266,531 266,707 314,651
Other Assets:
American Falls and Milner water rights 31,585 31,585 31,585 30,543 29,501 26,592
Company-owned life insurance 35,624 35,765 35,401 34,055 30,842 29,535Energy marketing assets -- long-term 14,358 16,635 22,189
Regulatory assets associated with taxes 427,760 433,271 415,177 423,548 449,668 502,565Regulatory asset - PCA
Regulatory assets - long-term derivatives
Regulatory assets - other
Long-term receivables 3,106 2,895 4,015 3,802 3,583 4,262
Other 62,724 60,082 46,239 43,670 55,370 54,701 Assets held for sale 25,966 21,076 0
Total other assets 575,157 580,233 580,572 556,694 568,964 617,655
TOTAL ASSETS $3,106,108 $3,234,172 $3,364,126 $3,445,130 $3,653,308 $3,851,263
CAPITALIZATION AND LIABILITIES:
Capitalization: Common stock equity
Common stock $472,902 $589,440 $598,706 $638,799 $675,774 $691,162
Retained earnings 397,167 424,312 437,284 493,363 537,699 587,998
Other comprehensive income (2,630) (888) (3,425) (5,737) (6,156) (8,461)
Treasury stock (3,158) (4,578) (998) (2,242) (2) (39) Unearned compensation (6,316)
Total common stock equity 864,281 1,008,286 1,025,251 1,124,183 1,207,315 1,270,660 Preferred stock 52,366
Long-term debt 945,834 979,549 1,023,545 928,648 1,156,880 1,273,028
Total capitalization 1,862,481 1,987,835 2,048,796 2,052,831 2,364,195 2,543,688
Current Liabilities: Long-term debt due within one year 67,923 78,603 16,307 95,125 11,456 7,817
Notes payable 93,650 36,270 60,100 129,000 186,445 203,915 Accounts payable 60,916 79,156 80,324 86,440 85,116 66,195
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 14,736
Interest accrued 13,741 14,426 14,616 12,657 18,913 29,624 Deferred income taxes
Uncertain tax positions 26,764 27,297 Other 25,557 21,265 19,577 23,572 38,129 36,883
Liabilities held for sale 0 0 5,916 2,606 0
Total current liabilities 311,705 285,458 293,585 410,334 375,315 386,467

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 554,715 555,774 519,563 498,512 466,182 473,845
Regulatory liabilities associated with
income taxes Regulatory liabilities - PCA
Regulatory liabilities - other 258,524 275,854 345,109 294,844 274,204 276,469 Other 104,290 112,616 124,833 179,836 173,412 170,794
Liabilities held for sale 0 0 10,051 8,773 0
Total other liabilities 931,922 960,879 1,021,745 981,965 913,798 921,108
TOTAL CAPITALIZATION AND
LIABILITIES $3,106,108 $3,234,172 $3,364,126 $3,445,130 $3,653,308 $3,851,263
Shares Outstanding (000's)38,207 42,217 42,632 43,834 45,063 45,576Book Value per Share $22.62 $23.88 $24.05 $25.65 $26.79 $27.88
% of Total Capitalization
Long-Term Debt 50.8% 49.3% 50.0% 45.2% 48.9% 50.0%
Preferred 2.8% 0.0% 0.0% 0.0% 0.0% 0.0%
Common 46.4% 50.7% 50.0% 54.8% 51.1% 50.0%
D.A. Davidson & Co.
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IDACORP, Inc. Consolidated Statements of Income
$ thousands -- Fiscal year ends 12/31 4Q07 2007 1Q08 2Q08 3Q08 4Q08E 2008E 1Q09E 2Q09E 3Q'09E 4Q'09E 2009E
REVENUES:
Electric Utility:
General business $156,966 $668,303 $167,313 $188,748 $246,639 $186,500 $789,200 $182,551 $203,922 $263,849 $199,205 $849,527
Off system sales 25,089 154,948 33,363 25,641 34,637 32,050 125,691 37,823 37,903 34,138 34,138 144,003
Other revenues 14,374 52,150 12,120 14,556 16,831 5,794 49,301 12,200 12,200 12,200 12,200 48,800
Total Electric Utility Revenues 196,429 875,401 212,796 228,945 298,107 224,344 964,192 232,574 254,025 310,187 245,544 1,042,330
Diversified Operations:
Other 1,017 3,993 644 1,281 1,609 1,000 4,534 1,000 1,000 1,000 1,000 4,000
Total Revenues 197,446 879,393 213,440 230,226 299,716 225,344 968,726 233,574 255,025 311,187 246,544 1,046,330
EXPENSES:
Electric Utility:
Purchased power 48,091 289,484 45,299 50,089 79,513 59,738 234,638 48,795 61,139 76,368 60,063 246,365
Fuel expense 32,598 134,322 37,237 28,681 46,467 37,017 149,402 40,700 31,499 48,079 40,269 160,548
Power cost adjustment (13,674)(121,131)(17,744)(829)(20,105)(10,000)(48,678)(10,000)(1,500)(12,000)(6,000)(29,500)
Total Power Supply 67,015 302,675 64,792 77,941 105,875 86,754 335,362 79,495 91,138 112,447 94,332 377,413
Impairment of assets
Other Operations and Maintenance 70,639 286,510 68,927 75,617 74,778 71,566 290,888 72,331 84,082 74,755 76,610 307,778
Demand-side management 4,518 13,487 3,364 3,928 5,956 5,000 18,248 5,100 5,200 5,300 5,400 21,000
Gain on sale of emission allowances (2,754)(346) (158)(504) 0
Depreciation 26,203 103,072 25,750 26,617 25,717 26,500 104,584 26,750 27,000 27,250 27,500 108,500
Taxes other than income taxes 3,366 17,634 4,803 4,800 4,827 3,590 18,020 5,117 5,080 4,963 3,929 19,089
Total Electric Utility Expenses 171,741 720,624 167,636 188,557 216,995 193,410 766,597 188,793 212,501 224,716 207,771 833,780
Other:1,910 6,692 1,048 1,140 1,144 1,200 4,532 1,200 1,200 1,200 1,200 4,800
Total Operating Expenses 173,651 727,316 168,684 189,697 218,139 194,610 771,129 189,993 213,701 225,916 208,971 838,580
OPERATING INCOME
Electric Utility 24,688 154,777 45,160 40,388 81,112 30,935 197,595 43,782 41,524 85,472 37,773 208,551
Other Diversified Operations (893)(2,699)(404)141 465 (200)2 (200)(200)(200)(200)(800)
Equity in Earnings of Partnerships
Operating Income 23,795 152,078 44,756 40,529 81,577 30,735 197,597 43,582 41,324 85,272 37,573 207,751
TOTAL OTHER INCOME:6,657 20,524 4,417 6,082 4,629 5,000 20,128 5,000 5,000 5,000 5,000 20,000
Earnings of Uncons. Eq-method Inv.(1,567)(4,824)(4,036) (3,278) 2,642 (1,200)(5,872)(1,200) (1,200) (1,200) (1,200)(4,800)
TOTAL OTHER EXPENSES:1,597 8,434 365 1,820 2,764 2,000 6,949 2,000 2,000 2,000 2,000 8,000
INTEREST EXPENSE AND OTHER:
Interest on long-term debt 16,655 59,961 16,876 15,744 17,226 17,400 67,246 17,450 17,500 17,550 17,600 70,100
Other interest (502)3,380 596 1,313 1,310 2,044 5,263 1,350 1,350 1,350 1,350 5,400
Net interest charges 16,153 63,341 17,472 17,057 18,536 19,444 72,509 18,800 18,850 18,900 18,950 75,500
Dividends on preferred stock 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 19,444 72,509 18,800 18,850 18,900 18,950 75,500
INCOME BEFORE INCOME TAXES:11,135 96,003 27,300 24,456 67,548 13,091 132,395 26,582 24,274 68,172 20,423 139,451
INCOME TAXES:840 13,731 5,584 6,941 15,809 4,892 33,226 6,645 6,069 17,043 5,106 34,863
Income from Continuing Operations 10,295 82,272 21,716 17,515 51,739 8,199 99,169 19,936 18,206 51,129 15,317 104,588
Losses 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 8,199 99,169 19,936 18,206 51,129 15,317 104,588
Earnings per share from cont. ops.$0.23 $1.86 $0.48 $0.39 $1.14 $0.18 $2.19 $0.43 $0.39 $1.09 $0.32 $2.24
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
EPS $0.23 $1.86 $0.48 $0.39 $1.14 $0.18 $2.19 $0.43 $0.39 $1.09 $0.32 $2.24
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
Avg. common shares outstanding (000) 44,918 44,291 45,004 45,096 45,194 45,594 45,222 45,994 46,394 46,794 47,194 46,594
Segment breakdown of EPS
Idaho Power Company $0.29 $1.73 $0.47 $0.39 $1.05 $0.21 $2.12 $0.42 $0.38 $1.08 $0.31 $2.20
IDACORP Energy 0.00 ($0.00)(0.00) (0.00) (0.00)
Ida-West Energy 0.00 $0.05 0.00 0.02 0.03
IDACORP Financial 0.04 $0.16 0.02 0.02 0.02
Holding Company (0.10)($0.08)(0.01)(0.04)0.05
EPS from Continuing Operations $0.23 $1.86 $0.48 $0.39 $1.14 $0.18 $2.19 $0.43 $0.39 $1.09 $0.32 $2.24
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
Reported EPS $0.23 $1.86 $0.48 $0.39 $1.14 $0.18 $2.19 $0.43 $0.39 $1.09 $0.32 $2.24
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.
8
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.
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Copyright D.A. Davidson & Co., 2009. All rights reserved.
9
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.