COC IDA050809.pdf

Please refer to pages 10-11 of this report for detailed disclosure and certification information.
Institutional Equity Research

IDACORP, INC.
May 11, 2009 IDA – NYSE

Rating:
NEUTRAL

Price: (5/8/09) $23.98

Price Targets:
12-18 month: $24
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 $1,033.9 8% $1,074.5 4%
Previous - $1,040.6 NC
Price/Revenue ratio 1.1x 1.1x 1.1x
EPS Revised $2.17 $2.20 2% $2.39 8%
Previous - $2.32 NC
Price/EPS ratio 11.1x 10.9x 10.0x
EBITDA ($M) $316.9 $340.7 8% $367.3 8%
EV/EBITDA ratio 8.1x 7.5x 7.0x

Quarterly Data: EPS EPS Revenue Revenue EBITDA
Previous ($M) Previous ($M)
3/31/09A $0.40 $0.48 $228.6 $232.1 $73.7
6/30/09E $0.45 $0.46 $254.1 $254.8 $78.7
9/30/09E $1.09 $1.11 $313.5 $314.7 $120.6
12/31/09E $0.26 $0.28 $237.7 $238.9 $67.8
Valuation Data Trading Data
Long-term growth rate (E) 5% Shares outstanding (M) 47.1
Total Debt/Cap (3/31/09) 53.6% Market Capitalization ($M) $1,131
Cash per share (3/31/09) $1.89 52-week range $20.91 - $33.89
Book value per share (3/31/09) $27.76 Average daily volume (3 mos.) (K) 506
Dividend (yield) $1.20 (5.0%) Float 97%
Return on Equity (T-T-M) 8% Index Membership S&P 400 MidCap

Reducing 2009 Estimate as Recent Rate Relief Provides Little 1Q Benefit.
Maintaining Target Price and NEUTRAL Rating.

• IDACORP reported 1Q'09 EPS of $0.40, down 17% from $0.48 in 1Q'08.
We were forecasting $0.48 and the consensus estimate of five analysts was $0.55.
• Two drags on EPS were: 1) an $0.08 hit from a May 2008 change in the power
cost adjustment (PCA) mechanism, and the timing of that mechanism’s impact
on quarterly results; and 2) a $0.05 combined hit from a FERC fee refund ordered
by state regulators and a reduction in open access transmission tariffs ordered by
federal regulators.
• Three unexpected boosts to EPS were: 1) a $0.03 contribution from life
insurance benefits; 2) a $0.02 increase in interest income primarily related to a
federal income tax refund; and 3) earnings improvements at Bridger Coal
Company provided a $0.02 higher contribution than we expected.
• Our 2009 EPS forecast is being lowered from $2.32 to $2.20 to reflect the
weak 1Q’09, and to factor in lower customer growth and reduced sales due to the
recession. We are maintaining our 2010 EPS estimate of $2.39. We expect
results will be helped by an improving economy as well as a general rate case in
Oregon (and possibly Idaho) that should be filed later this year.
• Maintaining target price. Despite a lowered 2009 EPS estimate, we are
maintaining our 12-18 month target price of $24, or ~10x our 2010 EPS estimate,
given the recent utility valuation rally. At the current share price, we are
maintaining a NEUTRAL rating for total return investors, including a 5% yield.
D.A. Davidson & Co.
2
Price Chart
Source: Thomson One
D.A. Davidson & Co.
3
IDACORP reported 1Q'09 EPS of $0.40, down 17% from $0.48 in 1Q'08. We were
forecasting $0.48 and the consensus estimate of five analysts was $0.55.

The company’s principal subsidiary, the Idaho Power Company (IPC), reported 1Q’09 EPS of
$0.41, compared to our forecast and the year ago amount of $0.47. Non regulated activities
produced a 1Q’09 loss of $0.01 per share, versus an earnings contribution of $0.01 a year ago
and our forecast of a similar amount.

Two drags on EPS we expected were: 1) an $0.08 hit from a May 2008 change in the power
cost adjustment (PCA) mechanism and the timing of that mechanism’s impact on quarterly
results (see our Research Bulletin dated July 9, 2008); and 2) a $0.05 combined hit from a
FERC fee refund ordered by state regulators and a reduction in open access transmission
tariffs ordered by federal regulators (see our Research Bulletin of January 26, 2009).

The change in the PCA mechanism that was implemented on June 1, 2008 required an equal-
weighted monthly expensing of annual base power supply costs. Since the effective date of
the change was March 1, 2008, Idaho Power had to recognize an additional $6.4 million of
PCA expense in 2Q’08, which related to the month of March 2008. Therefore, the PCA
expense in 1Q’09 was $6.4 million greater than what would have been recorded had the PCA
mechanism change been in effect in 1Q’08.

Unexpected boosts to EPS were: 1) a $0.03 contribution from life insurance benefits; 2) a
$0.02 increase in interest income primarily related to a federal income tax refund; and 3)
earnings improvements at Bridger Coal Company provided a $0.02 higher contribution than
we expected. A year ago this coal mining operation was experiencing losses due to longwall
operation difficulties; this year’s upward EPS swing of approximately $0.06 was perhaps
$0.02 higher than the level we had implicitly expected.

If the aforementioned EPS drags were known, and the company benefited from at least three
unexpected EPS boosts, we ask ourselves why our EPS forecast over-estimated actual results.
We believe the answer lies in the 1Q’09 rate increase ordered in Idaho, weaker than expected
sales due to the recession, and reduced hydroelectric generation.

Idaho Power received a 3.1%, or $21 million, annual rate increase that went into effect on
February 1, 2009 and was subsequently modified on March 19, 2009 to $27 million (+4.0%),
following the utility’s request for reconsideration. The $27 million rate increase consists of
an $11 million annual recognition for the first time of ongoing finance costs relicensing the
Hells Canyon Project, a process that started ten years ago and may be concluded later this
year. Therefore, the utility began collecting in rates AFUDC (allowance for funds used
during construction) on February 1, 2009. AFUDC collection helps the company’s cash
flows, but does not help earnings, as the utility must defer revenue recognition of the amounts
collected until the license is issued and the asset is placed in service through the rate case
process. The 1Q’09 deferral amount was $1.7 million, which held back reported EPS by
approximately $0.02 per share. The $27 million rate increase also includes a $15 million
recovery of net power supply costs, from which the company does not profit.

We conclude the rate increase stemming from the Idaho 2008 General Rate Case order, which
was in place for two months of the quarter, did not help 1Q’09 EPS very much. The primary
benefit of the rate case was to reallocate costs by customer class, improve the timing of cost
recovery, and allow mechanisms to keep the utility financially solid for credit rating purposes.

Regarding reduced sales, the utility reported a 5% decline in kWh sales. Management
identified that approximately 2 percentage points of the decline were due to weather-related
factors and 3 percentage points were related to recession-reduced commercial and industrial
sales. Our model implicitly expected both lower temperatures (6% below last year as
measured by heating-degree days) and reduced sales from the recession, but not to the extent
actually reported. Overall, management calculated that nearly $10 million of revenues were
“lost” due to changes to usage, which we calculate held back EPS by approximately $0.09.
EPS Slips 17%
From whence comes the 1Q’09
shortfall?
D.A. Davidson & Co.
4
Partial offsets to reduced sales are two recently allowed changes. These constructive changes
are the load growth adjustment rate (LGAR), which was lowered to $26.63 per MWh, and the
fixed cost adjustment (FCA) mechanism, both of which help to mitigate the impacts of
changes in sales volumes and customer usage.

Hydroelectric generation for 1Q’09 was 5% below the 1Q’08 level, and 29% below the 30-
year average. This shortfall was due to a combination of below normal rainfall (2.33 inches
versus 2.70 inches a year ago and the historical 3.94 inch norm) and near record low flows in
the Snake River from several years of drought. Because hydrogeneration is cheaper to
produce than thermal generation, the reduced hydroelectric generation had an undisclosed
impact on EPS in our opinion. Under the new PCA rules effective for February and March,
ratepayers and shareholders share in changes in power costs on a 95%/5% basis, compared to
the former sharing arrangement of 90%/10% which was in place in January.

Electric revenues of $188 million in the recent quarter increased 12% from $167 million a
year ago. This $21 million improvement in general business revenues benefited from rate
relief put into place over the past year (+$13 million), power cost adjustment recoveries
(+$17 million), and customer growth (+$2 million), which were partially offset by the
aforementioned $10 million reduction in usage. Retail base rates are up in the past year due
to a 5.2% general rate increase effective March 1, 2008, a 1.4% increase for the Danskin plant
effective June 1, 2008, and a 3.1% general rate increase effective February 1, 2009 (raised to
4.0% effective March 21, 2009 to correct errors in the original order).

Offsetting the $21 million increase in electric revenues was a $25 million (+15%) climb in
electric operating expenses to $192 million. Primary drivers behind the higher expenses were
a $33 million swing in the PCA (of which $6 million related to the aforementioned PCA
change) and a $2 million increase in fuel expense, offset by a $13 million drop in purchased
power expenses. The decline in purchase power expense was due to a 4% drop in volumes
purchased and a drop in the price per MWh.

The company’s non-regulated businesses and holding company activity reported a 1Q’09 loss
of $0.01 per share, compared to a profit of $0.01 per share in 1Q’08. Included in the non-
regulated businesses is IDACORP Financial Services (IFS), which contributed near breakeven
results, a decline from $0.02 a year ago because of lower tax benefits from aging affordable
housing project investments.

Idaho Power has filed an application with the Idaho Public Utilities Commission (IPUC) for a
Certificate of Public Convenience and Necessity to construct the proposed 330 MW natural
gas-fired Langley Gulch combined cycle combustion turbine (CCCT) in Payette County,
Idaho. The estimated cost of the proposed facility is $427.4 million, which is not included in
the utility’s current 2009-2011 capital expenditures budget of $780-$800 million. Also
included in Idaho Power’s application is a request to include construction work in progress
(CWIP) in rate base for all or a portion of the construction expenditures. If the application is
approved by the IPUC, Idaho Power expects to spend $45-$50 million on the project during
2009 and begin construction in mid-2010. Idaho Power entered into equipment supply
contracts for the project with Siemens Energy in December 2008 and February 2009 for a gas
turbine and a steam turbine, including an $8.7 million deposit. The contract does not call for
any additional payments before September 2009. The IPUC decision is expected in the third
quarter of 2009.

We note that the CPCN filed by Idaho Power in the case of the Langley Gulch facility is a
tool created by the recently-passed Idaho Senate Bill 1123, which is designed to provide a
clearer view of cost recovery and return on investment for large-scale projects by allowing a
utility to file an application with the IPUC for an order that specifies in advance the
ratemaking treatment a proposed project would receive.

Rate Relief and PCA Recovery
Boost Revenues
Regulatory Approval Sought For
Major New Plant
D.A. Davidson & Co.
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Our 2009 EPS forecast is being lowered from $2.32 to $2.20 to reflect the weak 1Q’09 and to
factor in lower customer growth and reduced sales due to the recession. These pressures are
partially offset by the company’s continuing 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, during the recent cut backs in capital expenditure plans, the company is saying it
may not have to use its continuous equity plan (CEP) to issue common stock to maintain its
equity ratios in the 45%-50% range, rather the dividend reinvestment plan (DRIP) should be
sufficient for near-term capital raises. (Note this could change if the Langley Gulch project
gets the go ahead). 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 maintaining our 2010 EPS estimate of $2.39. We expect results will be helped by an
improving economy, as well as a boost from new Oregon and (possibly) Idaho general rate
cases that should be filed later this year.

Despite a lowered 2009 EPS estimate, with the recent utility valuation rally, we are
maintaining our 12-18 month target price of $24, or ~10x our 2010 EPS estimate. While the
target multiple is below IDACORP’s median multiple of 14.8x price-to-year-forward EPS
estimates over the past decade, it is in line with the current average 2010 valuation in our
coverage list, excluding one outlier. Given the current share price, we are maintaining a
NEUTRAL rating for total return investors, including a nearly 5% current yield.

Lowering 2009 EPS Estimate;
Maintaining 2010

Maintaining Target Price and
Rating
D.A. Davidson & Co.
6
IDACORP 2009-2011 CAPITAL SPENDING BUDGET

($ in millions) 2009E 2010-2011E
Capital Requirements for Regulated Operations
Ongoing capital expenditures $150-155 $400-410
Advanced Metering Infrastructure 20-22 40-50
Major Projects 1 50-53 95-105
Minimum Transmission for Baseload Resource - 20-25
Total capital expenditures $220-230 $555-590
* Boardman-Hemingway Line: New 500 kV transmission line between Boardman, Oregon and Hemingway,
Idaho. The project is expected to relieve existing congestion by increasing transmission capacity and improving
reliability, with the initial project phase estimate of $50 million will be funded by Idaho Power. Cost estimates
for the project (including initial phase project estimate and construction costs of the line) are approximately $600
million. Idaho Power is seeking partners for up to 50% of the project when construction commences. The
estimated in-service date has been delayed from 2013 to 2015 subject to siting, permitting and regulatory
approvals, so construction costs are not included in the 2009-2011 CapEx budget.
* Gateway West Project: Joint venture with PacifiCorp to build transmission lines between Douglas, Wyoming
and Hemingway, Idaho. Initial phases of the project could be completed by 2014 depending on the timing of
rights-of-way acquisition, siting and permitting, and construction sequencing. Idaho Power's estimated total
construction cost of $500-600 million are not currently included in the 2009-2011 forecast.
IDACORP, Inc. - Capital Expenditures
* Langley Gulch Power Plant (2012 Baseload Resource): 300 MW natural gas-fired facility expected to be
operational by December 2012 (subject to approval from the Idaho Public Utilities Commission (IPUC) before
September 1, 2009) at an estimated cost of $427 million. The project is currently in the permitting process, and
Idaho Power expects to spend $45-50 million during 2009 on the project.
* Hemingway Station: New 500 kV station needed to meet growth, capacity and operating constraints at an
estimated total cost of $52 million. The station was originally part of the Gateway West Project but was
accelerated to 2010 to meet forecast deficits and improve reliability.
* Hemingway-Hubbard Transmission Line: Part of the Hemingway Station Project, expected to provide
power to the Treasure Valley in southwest Idaho by 2010 at an estimated total cost of $25 million.
Notes to Capital Expenditures Plan
1 Construction costs for the Langley Gulch Power Plant are not included in the 2009-2011 CapEx budget. Major
projects include:
Source: Company reports

D.A. Davidson & Co.
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REGULATORY RATE CASE SUMMARY

Revenue
Increase
Average Rate
Base
Return on
Equity
Return on
Rate Base Equity Ratio
2009-2010 Idaho Power Cost Adjustment (PCA)1
Application, April 2009 $93.8 (+11.4%)
Application, June 2008 $66.6 (+9.9%) $2,093 11.25% 8.55% 49.27%
Approved, January 2009 $20.9 (+3.1%) $2,094 10.5% 8.18% 49.27%
Revised, March 2009 $27.0 (+4.0%) $2,094 10.5% 8.18% 49.27%
FERC Open Access Transmission Tariff (OATT) Case3
Application, March 2006 $11.0 11.25%
Calculation Change Approved, June 2006 $11.0 11.25%
Stipulation, August 2007 $8.2 10.7%
ALJ Initial Decision, August 2007 $6.8 10.7%
Revised/Appealed, January 2009 $6.8 10.7%
Application, June 2007 $64 (+10.35%) 11.5% 8.10%
Approved, February 2008 $32.1 (+5.2%)
4 The 2007 Idaho general rate case was decided under a "black box" settlement agreement. Therefore, no data is given for line items including allowed ROE, rate
base, etc.
Notes to Rate Case Summary
2 As part of the 2008 general rate case, ongoing finance costs of ~$10 million (allowance for funds used during construction (AFDUC)) 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. Also included in the rate case were a
lowering of the load growth adjustment rate (LGAR) from $28.14/MWh to $26.63/MWh, and a new residential tiering rate schedule was enacted.
($ in millions)
2008 Idaho General Rate Case 2
2007 Idaho General Rate Case 4
3 The new OATT calculation allowed the utility to move from a fixed rate to a formula rate which would be updated annually. The Administrative Law Judge's
(ALJ) initial decision required refunds of $5.4 million. On appeal, the ALJ’s initial decision was upheld in most respects and Idaho Power was required to
reduce its 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 utility has filed a request for rehearing with the FERC.
1 The PCA mechanism is a pass-through mechanism and does not contain a profit component. It provides annual adjustments to rates by tracking differences
between actual net power supply costs and power supply costs recovered in retail rates. The adjustment contains 1) a forecast of power supply costs in the
coming year and 2) a true-up component, based on the difference between the previous year’s actual power supply costs and the previous year’s forecast. The
true-up component is calculated monthly, and interest is applied to the balance. Effective February 1, 2009, the PCA mechanism provides that 95% of deviations
in power supply costs are reflected in Idaho Power’s rates for both the forecast and the true-up components. The significant size of this PCA filing includes a
true-up for higher than projected power costs last year as well as higher expected costs in the coming year. Also contributing to the size of the PCA is Idaho
Power's expectation of reduced volumes and prices for off-system power sales in the coming year (wholesale revenues are deducted from power costs and reduce
customer rates).
Source: Company reports and regulatory filings

D.A. Davidson & Co.
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IDACORP, Inc. Balance Sheet
$ thousands -- Fiscal year ends 12/31
2004 2005 2006 2007 2008 3/31/2009
ASSETS:
Electric Plant:
In Service (At Original Cost) $3,324,816 $3,477,067 $3,583,694 $3,796,339 $4,030,134 $4,077,121
Accumulated Provision For Depreciation (1,316,125) (1,364,640) (1,406,210) (1,468,832) (1,505,120) (1,520,896)
In Service - Net 2,008,691 2,112,427 2,177,484 2,327,507 2,525,014 2,556,225
Construction Work In Progress 152,427 149,814 210,094 257,590 207,662 186,662
Held For Future Use 2,636 2,906 2,810 3,366 6,318 6,653
Other Property, Net Of Accum. Depreciati 45,708 29,294 28,692 28,089 19,171 19,270
Property, Plant And Equipment - Net 2,209,462 2,294,441 2,419,080 2,616,552 2,758,165 2,768,810
Investments And Other Property 223,061 191,593 202,825 201,085 198,552 185,532
Current Assets:
Cash And Cash Equivalents 23,403 52,356 9,892 7,966 8,828 89,113
Receivables:
Customer 92,258 94,469 62,131 69,160 64,733 70,919
Allowance For Uncollectible Accounts (43,108) (33,078) (7,168) (7,505) (1,724) (1,482)
Employee Notes Receivable 3,523 2,951 2,569 2,128 179
Other 8,806 21,377 11,855 10,957 10,260 15,099
Total Receivables
Energy Marketing Assets 9,203 23,859 12,069
Taxes Receivable 18,111 9,710
Accrued Unbilled Revenues 33,832 38,905 31,365 36,314 43,934 35,751
Materials And Supplies (At Avg. Cost) 28,008 30,451 39,079 43,270 50,121 52,778
Fuel Stock (At Average Cost) 6,539 11,739 15,174 17,268 16,852 13,941
Prepayments 30,035 17,876 9,308 9,371 10,059 9,878
Deferred Income Taxes 23,407 23,922 28,035 25,672 37,550 14,792
Regulatory Assets -- Derivatives 5,510 3,064
Refundable Income Tax Deposit 44,903 46,083
Other Current Assets 2,956 3,993 6,023 7,381 8,956
Assets Held For Sale 6,673 3,326
Total Current Assets 221,416 297,520 266,531 266,707 266,284 319,455
Other Assets:
American Falls And Milner Water Rights 31,585 31,585 30,543 29,501 26,332 25,008
Company-Owned Life Insurance 35,765 35,401 34,055 30,842 29,482 30,036
Energy Marketing Assets -- Long-Term 16,635 22,189
Regulatory Assets Associated With Taxes 433,271 415,177 423,548 449,668 696,332 692,270
Long-Term Receivables 2,895 4,015 3,802 3,583 4,012 3,844
Other 60,082 46,239 43,670 55,370 43,686 44,723
Assets Held For Sale 25,966 21,076
Total Other Assets 580,233 580,572 556,694 568,964 799,844 795,881
Total Assets $3,234,172 $3,364,126 $3,445,130 $3,653,308 $4,022,845 $4,069,678
Capitalization And Liabilities:
Capitalization:
Common Stock Equity
Common Stock $589,440 $598,706 $638,799 $675,774 $729,576 $731,756
Retained Earnings 424,312 437,284 493,363 537,699 581,605 586,408
Other Comprehensive Income (888) (3,425) (5,737) (6,156) (8,707) (9,458)
Treasury Stock (4,578) (998) (2,242) (2) (37) (20)
Unearned Compensation (6,316)
Total Common Stock Equity 1,008,286 1,025,251 1,124,183 1,207,315 1,302,437 1,308,686
Noncontrolling Interest 4,434 3,987
Preferred Stock
Long-Term Debt 979,549 1,023,545 928,648 1,156,880 1,183,451 1,279,504
Total Capitalization 1,987,835 2,048,796 2,052,831 2,364,195 2,490,322 2,592,177
Current Liabilities:
Long-Term Debt Due Within One Year 78,603 16,307 95,125 11,456 86,528 81,502
Notes Payable 36,270 60,100 129,000 186,445 151,250 150,700
Accounts Payable 79,156 80,324 86,440 85,116 96,785 53,010
Energy Marketing Liabilities 9,420 24,093 13,532
Taxes Accured 46,318 72,652 47,402 8,492
Interest Accrued 14,426 14,616 12,657 18,913 16,727 24,054
Uncertain Tax Positions 26,764 4,119 4,509
Other 21,265 19,577 23,572 38,129 40,259 47,017
Liabilities Held For Sale 5,916 2,606
Total Current Liabilities 285,458 293,585 410,334 375,315 395,668 360,792

Other Liabilities:
Term 16,635 22,189
Deferred Income Taxes 555,774 519,563 498,512 466,182 515,719 511,281
Regulatory Liabilities - Other 275,854 345,109 294,844 274,204 276,266 282,440
Other 112,616 124,833 179,836 173,412 344,870 322,988
Liabilities Held For Sale 10,051 8,773
Total Other Liabilities 960,879 1,021,745 981,965 913,798 1,136,855 1,116,709
Total Capitalization And Liabilities 3,234,172 3,364,126 3,445,130 3,653,308 4,022,845 4,069,678
Shares Outstanding (000's)42,217 42,632 43,834 45,063 46,920 47,145
Book Value per Share $23.88 $24.05 $25.65 $26.79 $27.76 $27.76
% of Total Capitalization
Long-Term Debt 49.3% 50.0% 45.2% 48.9% 47.5% 49.4%
Preferred 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Common 50.7% 50.0% 54.8% 51.1% 52.3% 50.5%
D.A. Davidson & Co.
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IDACORP, Inc. Consolidated Statements of Income
$ thousands -- Fiscal year ends 12/31 2005 2007 1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09E 3Q'09E 4Q'09E 2009E 2010E
REVENUES:
Electric Utility:
General business $667,270 $668,303 $167,313 $188,748 $246,639 $181,611 $784,311 $187,927 $203,176 $262,852 $192,377 $846,332 $865,273 Off system sales 142,794 154,948 33,363 25,641 34,637 27,789 121,430 28,530 37,903 37,678 32,305 136,416 155,723
Other revenues 27,619 52,150 12,120 14,556 16,831 6,828 50,335 11,572 12,200 12,200 12,200 48,172 50,000
Total Electric Utility Revenues 837,683 875,401 212,796 228,945 298,107 216,228 956,076 228,029 253,279 312,731 236,882 1,030,920 1,070,997
Diversified Operations: Other 5,181 3,993 644 1,281 1,609 804 4,338 545 800 800 800 2,945 3,500
Total Revenues 842,864 879,393 213,440 230,226 299,716 217,032 960,414 228,574 254,079 313,531 237,682 1,033,865 1,074,497
EXPENSES:
Electric Utility:
Purchased power 222,310 289,484 45,299 50,089 79,513 56,237 231,138 32,795 61,261 81,799 57,080 232,934 259,098
Fuel expense 103,164 134,322 37,237 28,681 46,467 37,018 149,403 39,133 34,193 43,782 40,270 157,378 160,649
497 906
Power cost adjustment (2,995)(121,131)(17,744)(829)(20,105)(8,735)(47,413)15,859 0 (9,000)(2,000)4,859 (21,000)
Total Power Supply 322,479 302,675 65,289 77,941 105,875 84,520 333,128 88,693 95,454 116,581 95,350 395,171 398,747
Impairment of assets Other Operations and Maintenance 241,209 286,510 68,430 75,617 74,778 74,708 293,533 68,769 75,984 72,241 70,354 287,347 294,524
Energy efficiency programs 13,487 3,364 3,928 5,956 5,631 18,879 4,057 5,800 5,900 6,000 21,757 24,000
Gain on sale of emission allowances 0 (2,754)(346) (158)(504)(228) (172)(400) 0
Depreciation 101,485 103,072 25,750 26,617 25,717 24,001 102,085 25,963 24,500 24,750 25,000 100,213 102,000 Taxes other than income taxes 20,856 17,634 4,803 4,800 4,827 4,653 19,083 5,062 5,066 5,004 4,975 20,106 20,349
Total Electric Utility Expenses 686,029 720,624 167,636 188,557 216,995 193,513 766,204 192,316 206,631 224,475 201,678 824,194 839,620
Other: 2,182 6,692 1,048 1,140 1,144 (286)3,046 624 1,200 1,200 1,200 4,224 5,000 Total Operating Expenses 688,211 727,316 168,684 189,697 218,139 193,227 769,747 192,940 207,831 225,675 202,878 829,324 844,620
OPERATING INCOME
Electric Utility 151,654 154,777 45,160 40,388 81,112 22,715 189,375 35,713 46,648 88,255 35,204 205,820 231,376
Other Diversified Operations 2,999 (2,699)(404)141 465 1,090 1,292 (79)(400)(400)(400)(1,279)(1,500)
Equity in Earnings of Partnerships
Operating Income 154,653 152,078 44,756 40,529 81,577 23,805 190,667 35,634 46,248 87,855 34,804 204,541 229,876
TOTAL OTHER INCOME: 17,121 20,524 3,741 4,302 2,038 (6,250)3,831 6,921 2,950 2,950 2,950 15,771 12,400
Earnings of Uncons. Eq-method Inv. (713) (4,824)(4,036) (3,278) 2,642 675 (3,997)402 (1,000) (1,000) (1,000)(2,598) (4,000)
TOTAL OTHER EXPENSES: 8,006 8,434INTEREST EXPENSE AND OTHER:
Interest on long-term debt 56,930 59,961 16,876 15,744 17,226 17,404 67,250 16,639 18,200 18,250 18,300 71,389 75,000
Other interest 2,799 3,380 596 1,313 1,310 2,587 5,806 836 1,300 1,300 1,300 4,736 5,500
Total interest expense and other 59,729 63,341 17,472 17,057 18,536 19,991 73,056 17,475 19,500 19,550 19,600 76,125 80,500
INCOME BEFORE INCOME TAXES: 103,326 96,003 26,989 24,496 67,721 (1,761)117,445 25,482 28,698 70,255 17,154 141,589 157,776
INCOME TAXES: 17,610 13,731 5,584 6,941 15,809 (9,134)19,200 6,796 7,462 18,266 4,460 36,984 41,022
Income from Continuing Operations 85,716 82,272 21,405 17,555 51,912 7,373 98,245 18,686 21,237 51,989 12,694 104,605 116,754
Losses from Disc. Ops. (net of tax) (22,055) 67 0 0 0 0 0 0 0 0 0 0 Net Income 63,661 82,339 21,405 17,555 51,912 7,373 98,245 18,686 21,237 51,989 12,694 104,605 116,754
Adjustment for noncontrolling interest 311 (40) (173) 71 169 198 50 50 50 348 400
Net Income Available for Common 63,661 82,339 21,716 17,515 51,739 7,444 98,414 18,884 21,287 52,039 12,744 104,953 117,154
Earnings per share from cont. ops.$2.02 $1.86 $0.48 $0.39 $1.15 $0.16 $2.17 $0.40 $0.45 $1.09 $0.26 $2.20 $2.39
Losses from Discontinued Operations ($0.52) $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 $1.50 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.40 $0.45 $1.09 $0.27 $2.21 $2.40
Dividends paid per share of common stock $1.20 $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)42,362 44,291 45,004 45,096 45,194 46,027 45,330 46,876 47,276 47,676 48,076 47,476 48,876
Segment breakdown of EPS
Idaho Power Company $1.70 $1.73 $0.47 $0.39 $1.05 $0.17 $2.08 $0.41 $0.44 $1.08 $0.26 $2.20 $2.35
IDACORP Energy $0.12 ($0.00)(0.00) (0.00) (0.00) (0.00)($0.00)(0.00)
Ida-West Energy $0.06 $0.05 0.00 0.02 0.03 0.00 $0.05 0.00
IDACORP Financial $0.26 $0.16 0.02 0.02 0.02 0.03 $0.08 0.00 Holding Company ($0.12)($0.08)(0.01)(0.04)0.05 (0.03)($0.03)(0.02)
EPS from Continuing Operations $2.02 $1.86 $0.48 $0.39 $1.14 $0.16 $2.17 $0.40 $0.45 $1.09 $0.26 $2.20 $2.39
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.
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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 3/31/09) Buy Hold Sell
Corresponding Institutional Research Ratings Buy Neutral Underperform
and Distribution 47% 47% 6%
Corresponding Private Client Research Ratings Outperform Market Perform Underperform
and Distribution 86% 9% 5%
Distribution of Combined Ratings 51% 44% 6%
Distribution of companies from whom D.A. Davidson & Co. has received compensation for investment banking services in last 12 mos.
Institutional Coverage 2% 3% 9%
Private Client Coverage 0% 0% 0%
Distribution of Combined Investment Banking 2% 3% 8%

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.
11
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
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