20031021Gribble Workpapers (9.67MB).pdf

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-03-13
IDAHO POWER COMPANY
D. GRIBBLE
WORKPAPERS
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• II Ragen MacKenzie
I\ Division ofWe:ls Fargo lnvestrr.ents, LLC
M,:MBER NEW YORK STOCK EXCHANGE
-----· ---- ·-------
ALLYSON R. RODGERS, CFA
[phone] ALLYSON. [e-mail]
Pacific Northwest
Research
MAY 7, 2003
UTILITIES
IDACORP, lNC.
(NYSE-IDA)
Weak First Quarter Due to Weather, Hydro, and Settlement Charges
Analyst Opinion: HOLD
Value Recommended List: HOLD
• IDACORP reported IQOJ earnings results of a loss of ($3.J) million or ($0.08)
per share versus $0.66 per share last year.
Idulto I'ut><:t Compa"y carrecd $0.36 ,•c,sus S0.57 par sh aro Inst yonr
Weather was significantly warmer than last year and resulted in reduced loads
of about 6.5%.
.. IDACORP Energy earnings were reduced $0.34 by a non-cash litigation
settlement charge.
• We have lowered our FY03 EPS estimate to $/.00,from SI.60, reflecting warm
weather, poor hydro conditions, and the settlement charges. We are
maintaining our FY04 estimate of $1.90 per share, which depends, among
other things, on normal weather and normal hydro conditions.
rv c: ... d.
Pr-ice:
52- Week Range:
Market Cap (million):
Book Value:
Dividend:
Est. Sec. EPS G nh Rate:
Doc
$'.D.n
�39-$21
$906.2
$22.4-i
$1.86
6% --��--�-----�-----
PRIMARY STOCK STATISTICS
SUMMARY A."l"D STOCK OPINION
Consistent with its earnings pre-release, IDACORP reported weak first quarter
results, with the utility's earnings negatively impacted by warm weather and poor
hydro conditions and the energy trading unit's negatively impacted by a large
litigation settlement with one of its customers. We estimate weather and hydro­
related factors reduced earnings by about $0.25 per share and that the settlement
resulted in a $0.34 per share reduction in earnings. As such, we are lowering our
FY03 earnings estimate by $0.60 to $1.00 per share. We are maintaining our
FY04 earnings estimate of $1.90 per share, which assumes normal weather and
hydro conditions.
EARNINGS ESTIMATES
Prior Current P!C
CurrentQtr. $0.32
FY02A: $1.62 ,�.6,:
FY03E: $1.60 $1.00 23.h
FY04E: $1.90 $1.90 ll5x
Price Target $27
At this point, management seems lU be conuuiued tu the current dividend payment, ascuming good hydro conditions next year and
that it receives rate relief from its general rate case, which has yet to be filed. However, we are now estimating earnings at the utility
this year of $1.25 per share, which is significantly lower than the current annual dividend payment of $1.86 per share. We believe
FY03 is likely to be the third consecutive year that the utility has under-earned its dividend, excluding tax-related benefits. We still
believe the Company is likely to cut its dividend by about 30% within the next twelve months, and most likely, within the context uf
its general rate case, which will be filed this fall.
(Continued)
lnvastmant Products: � NOT FDIC Insured � NO Bank Guarantee � MAY Lose Value
ADDITIONAL INFORMATION ON SUBJECT COMPANIES MENTIONED HEREIN IS AVAILABLE UPON REQUEST R,gen '-4acKe!l1ie is a ct.mo a Weis Fargo lrweslnms, mentJef NYSEISIPC, a noo-1:&'lk aflire a Weis Fargo & Co. This is not a corrplete ooaysis of eve<y mmnal tact r,garoog � cmµiny, ro.isr,, o secuity. TJ-e ilbmaim has been <bai1e:l frun scuces we � lo be re!i,tk, but we carrot gu:raree Ille aa:uacy. o,::n:ns repesa:lt Ra;ieo Mad<fflZie's i,,dgrerJt as rJ Ille da'e a lhe repa1 a1Cl are SUJjed to diarge wllout nolioo Wets Fargo afliliates rray issue reports o ha.oe oi:nrs hat are ilcrnsislent Wiil a1Cl readl citlefent cmdusiJrs from tis repot. IMPORTANT DISCLOSURES ARE ON THE LAST PAGE OF THIS REPORT
RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
VALUATION
Our $27 price target is based on a l 3.5x multiple of our estimate of IDACORP's normalized earnings per share potential, which we
estimate to be in the $ l.90-$2. l O per share range. IDACORP's average price-to-earnings multiple over the last l O years is about
14.4x. Our belief has been that the stock would return to favor as investors perceive ancillary business and financial risk to
diminish and begin to more fully value IDACORP's primary hus inesx as a low-risk electric distribution company.
··--····----··--------�
We believe primary risks to IDACORP's ability to return to a more normal earnings range include continued slow economic
activity, weather, including hydro conditions, and unfavorable regulatory action at the state or federal level.
FUNDAMENTALS
IDACORP reported a net loss for 1003 of($3.1) million, or ($0.08) per share versus net income of $24.7 million, or $0.66 per share
in I Q02. About half of the earnings shortfall relates to litigation settlement charges that, when combined, amount to $10.9 million
before tax ($0.34 per share after-tax). The majority of the remaining shortfall amount has been caused by warmer-than-normal
weather, which reduced loads in 1Q03, and poor hydro conditions, which increase costs for the utility. Average temperatures
during the quarter in Idaho Power's service territory were l 9% warmer than in I Q02.
Idaho Power
Idaho Power, the Company's regulated electric utility, contributed earnings per share of $0.36 versus $0.57 last year. Our estimate
for the utility's earnings in I Q03 was $0.40 per share. Warm weather dunng the quarter reduced the Company's load by
approximately I l %, and is the major cause of this year's shortfall in earnings at the utility. General business revenues, which arc
comprised of revenues from Idaho Power's retail customer classes, decreased 6% to 5, 175.1 million, down from $186. l million in
IQ02. Total cnugy ao ld, on a megawo.tt hour b:,cio, dec line d 6_�% nvn the prior year. Residential customers' load was hit
especially hard, declining I 1.5% over the prior year. The load decline versus the prior year was partially offset by higher customer
rates. Customer growth was solid in l Q03, with Idaho Power adding approximately I 0,715 new residential and commercial
customers, reflecting growth rates of2.8% and 2.7% for residential and commercial customers, respectively.
The Company's off-system sales volume declined by about 50% over the prior year, but the negative impact was significantly offset
by an average sales price more than 80% higher than in 1Q02. For the quarter, off-system sales declined 7.7% to '.i,18.6 million
vercuc $20.2 million in IQO? n11P. tn ongoing drought conditions in Idaho. off-system sales volumes are expected to be below
normal.
Streamflow forecasts in Idaho Power's region are currently forecasted to be about 57% of normal, which compares to 56% below
normal in 2002 and about 4 I% below normal in 200 I. Management has indicated that it has secured resources to cover its native
load in 2003. Normal precipitation and streamtlow conditions in 2004 would likely not return Idaho Power's performance to
normal due to low reservoir levels. Reservoir levels above Brownlee Reservoir, the Company's reservoir to its largest hydro
facility. is about 86% of normal for this time of year.
Idaho Power will likely file a general rate case in FY03 due to growth in its service territory. Since IPC's last general rate case,
which took place in I 994, its customer base has grown by more than 25%, or 80,000 customers. We expect the amount requested
in the general rate case to amount to less than half of the amount requested under the deferral mechanism in prior years, or between
$50 and $75 million.
IDACORP Energy
IDACORP Energy reported a net loss of ($10.8) million, or ($0.28) per share versus a net profit or $4. J ruilliou, ur $0.11 per share
last year. We are currently estimating a net loss of about ($14. 7) million, or ($0.38) per year for the full year. The majority of
IDACORP Energy's contracts are expected to roll off by 2004, at which point the Company will have substantially exited the
business. We are anticipating a net loss in FYO� and, to a lesser extent. in FY04 as IDACORP Energy continues to work through its
exit and staffing levels continue to decline.
(Continued)
RISKS
---.._, _
Investment Products: ._ NOT FDIC Insured � NO Bank Guarantee 1> MAY Lose Value
ADDITIONAL INFORt.lATION ON SUBJECTCOll'ANIES MEI.JTIONED HEREIN IS AVAILABLE UPON REQUEST
Ra;)el1 MacKerule IS a d\1Si:Jn of Wells FaJJO lnvestrrel11s, rrerrber NYSEISIPC, a noo-lmk afiiate of Weis FaJJO & Co. Tbs is not a o:xrpete .mysis of every rralernl fact reym,g <11y <mµllly, ixiJsty, Cl' seruity.
The i1fooraicn has been cttailed from sou-res we crosid..- to be �. but..., C31R'.Jt gu,ra,tee lhe �- � rer,esait Ra;)el1 Mad<mzi,'s µjg1m as cf the dale of the repc,t im are Sltljcd to ctmge
Milo.rt ooka. WeJs Fargo a1liates ,ray issue ref.01S Cl' have qrirs flat are l'lcalslsterl Mf1 � ream differellt a:rdusini mn tis report. IMPORTANT DISCLOSURES ARE ON THE LAST PAGE OF THIS REPORT
•
•
RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
BALANCE SHEET AND CASH FLOW
The Company ended l Q03 with $41.5 million in cash and equivalents, reflecting, among other things, cash generated from
operations of $95.5 million. IDACORP's long-term debt as a percentage of total capitalization at the end of the quarter was 55.1 %,
with preferred stock comprising 2.6% and equity 42.3% of total capitalization. At quarter-end IDACORP had about $1.0 billion in
long-term debt (including l:UU\:11l uiatui itics), which is rated A- with a ponitive outlook by Standard & Poors at th,. cnrporate level
and Baa I with a negative outlook by Moody's. IDACORP's book value at quarter-end was $22.44, with an estimated $20.00 book
value at the utility. We are expecting the Company to generate positive free cash flow this year, which we define as cash from
operation less capital expenditures and dividend payments. We expect cash flow to be bolstered by about $90 million due to rate­
recovery of its excess power costs incurred in prior years.
IDACORP. Inc. is a holding company based in Boise, Idaho, that serves as the parent company to Idaho Power C ulated subsidiaries. Idaho Power
Company is a rezulatcd utility company providing electric services to people in southern Idaho, eastern Orcgo and northern Nevada. ID�ORP's other subsidiaries include:
merchant generators, fuel cells, energy trading, telecommunications, and one financial subsidiary that invests in -advantagca real es . Hcadquaners: Boise, ID.
S&P 500: 929.62
• Investment Products: I> NOT FDIC Insured ._ NO Bank Guarantee 1> MAY Lose Value
AOOfTlO!W. INFORMATION ON SUBJECT COMPANIES MElffIONEO HEREIN IS AVAILABLE UPON REQUEST � MacKenzie is a ti'm1 of Wets F.-go lnvestrrents, rrenner NYSE.51R::, a rion-mnk afliere of Wais F� & Co. This is not a cool)le'e ,r,aiysis of evecy miEria tact re;iaroog acry Oll1ll<f1Y. i1dlsty, a- searly . Ibe n:nrairn has been� Iran sot.rreS we amdef to be reialle, bl« v,e c,nd � Ille oco.r;,cy. � reiresrot Ra;iei, Mad<!mle's j..dtJnert! as ct Ille tlate of n., ,epoo ard are sulJjed to� wtl1out noice. Weis Fag:, aflliales may Issue rep:rts a- ha,;e qtt:m till are i1cOlsistet1t vill .m rooch clflerent amusi:r6 run tiis rep:xt
IMPORTANT DISCLOSURES ARE ON THE LAST PAGE OF THIS REPORT
RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
ANALYST CERTIFICATION
By issuing this research report, each Ragen MacKenzie analyst whose name appears on the front page of this research report hereby
certifies that: (i) the recommendations and opinions expressed in the research report accurately reflect the research analyst's personal
views about any and all of the subject securities or issuers discussed herein and (ii) no part of the research analyst's compensation was, is,
or will be, directly or indirectly, related to the spe�lfic recornrnendauous vi views ,;xprcs:scd by the rcscnrch nnnlyst in the reooarch report.
RATING SYSTEM
BUY - Immediate purchase is recommended; the stock is expected to outperform the general market over the next 12-18 months.
HOLD - Holding the stock is recommended. The stock has moved out of our preferred buying range, but there is further upside to the
share price; or stated objectives at the time of purchase have changed and share appreciation may take another 6-12 months.
SELL - The stock has reached the stated price objective and appreciation has been achieved; or certain company fundamentals have
changed which warrant investors selling the stock to avoid price decline.
NOTES
The price targets indicated in the chart below may be adjusted for stock splits. Where the price target was originally given as a range, the
midpoint of the range has been used.
Until February 15, 2001, Ragen Mackenzie used the following system for analyst ratings: Buy, Accumulate (ACC), Market Perform
(MP), Underperforrn, Sell.
From February 15, 200 I-July 8, 2002, Ra gen MacKenzie used the following system for analyst ratings: Strong Buy (SB), Buy, Market
Perform (MP), Underperrorm, Sell.
The current rating system, explained above, has been in effect since July 9, 2002.
°RATINGS ALLOCATIONS
----·---· Rating % of covered % for which tDACORP Inc. (IDA) 1 compames IB Services have May 1. 2000 -May 2. 2003 High: 51.813 with this rating been rovided U.S. Dollar Low: 20.600 Last: 23. 700 Anal st Coveraae p BUY, ·BUY-27
BUY 43% 7% Vlk lO- 50
HOLD 55% 6% 45 • SELL 2% 0% 40 Value Recommended List=Appreciation
BUY 35% 0% 35
HOLD 65% 6%
SELL 0% 0% r 30
Value Recommended List-Income 25 BUY ?0% 0%
HOLD 60% 33%
SELL 20% 0% 20 .--.-,--.--�-,�- .,.
Growth Recommended List 6/00 9/00 12100 3/01 6101 9/01 12/01 3/02 6/02 9102 12/02 3/03
BUY 80% 25%
HOLD 20% 0%
SELL 0% 0%
Updated nn 4/4/2003
Investment Products: � NOT FDIC Insured � NO Bank Guarantee � MAY Lose Value
ADDITIONAL INFORMATION ON SUBJECT COMPANIES MEN110HED HEREIN IS AVAILABLE UPON REQUEST R,;gerl MacKeruie is a tflisbl rJ Wets F;rgo lmes1Jrents, rrmter NYSE/SIPC, a roo-lmk afli.re o( Weis Fargi & Co. This is not a a:nµe'3 a,aysis o( INe('of nmm fad raga,oog arr; oorri:m,. i"d.Jsty, ex secuty.
lte l1bmatal has been cWli1ed Iran srures we CXXl'*1er to be reli>e, but we carrot guararnee ll1e acruacy. Clprb,; rep,esent R,;ger, MacKEruie's iJdgrenl as a the �are repat am are Slqed to d1oo;Je
wihx.tnolce. Wets FS'goalliatesimylssuemp:,nsah:M! � flataehxrlsislentv.ill alll rea'.11 cilllffl11 o:rdusms tcmtisrepat.
IMPORTANT DISCLOSURES ARE ON THE LAST PAGE OF THIS REPORT
Analyst Opinion
MAR.KET PERFORM
Price (2/25/02)
52-Week Price Range
Annu31 Dividend Rate
Indicated Yield
Shares Outstanding
Eslir11c1Le<.l Flvdl
Markel Cap.
A,g Daily Volume
COMPANY REPORT
Allyson R. Rudgers, CFA
February 25, 2002
IDACORP, INC.
(NYSE-IDA)
Fiscal Year: Dec EPS PIE
$38.17 2000A $3.72 2000A 10.3x
$41-$34 2001A $3.35 2001A 11 4x
$1.86 2002E $3.12 2002E 12.2x
4.9% T4Q $3.35 T4Q 11.4x
37.5 million Est. Secular EPS Growth 8% T4Q Relative P/E .47x
37.4 million ROAE (�Yr.Average) 13.1% M;c,r\<pt C":;ip/S:ilP.s NM
$1,431 million Book Value Per Share $23.09 (2002E P/E)/Growth 1.5x
137,024 shares LTD/Capitalization 46% Price/Book Value 1.7x
SU!vfAfARY AND STOCK OPINION
We recently visited IDACORP, lnc., in Boise, Idaho, and met with several i.ey
management personnel. We arc impressed with Idaho Power's reliable and consistent
earnings power, even as the Company takes on new growth initiatives. In our opinion,
the management team operates within a favorable regulatory environment and the
Cornpc ny h::,;: been m�kine reasonable business decisions that have added to
IDACORP's bottom line for many years. We arc re-initiating coverage of IDACORP
with a MARKET PERFORM rating based on our opinion that IDACORP's stock is
fairly valued given the current outlook for the utility and the energy trading and
marketing business.
Company Overview
IDACORP, Inc. is an essential services
company comprised of one regulated
electric utility and live non-regulated
subsidiaries, mcludrng energy trndmg
and marketing, teleconununications and
fu, I cell businesses. Idaho Power
Company, IDACORP's regulated
subsidiary, supplies electricity to
The average forward P/E multiple for IDACORP's peer group is l2.3x. forward
earnings. while IDACORP trades in line with its peer group average at l2.2x our
FY02 forward estimate. IDACORP pays a dividend of $1.86 that currently yields
about 4.9%, which compares favorably with other western region utility yields. The
average yield for a western region electric utility is 4.4%. Based on the Company's
payout ratio uf 60% (based on our fY02 earnings estimate), we consider the dividend
secure. We believe the Company recognizes the importance of maintaining cash flow during these
therefore do not expect the Company to raise its dividend over the course of the next couple of years.
volatile times, and
residential, commercial, industrial, and
irrigation customer, in southern Idaho
o.nd eastern Oregon, The Cornpany'c
system is interconnected with power
companies throughout the Northwest.
Headquarters: Boise, lD.
!DACORP is comprised of a regulated electric utility (Idaho Power Company) and five non-regulated businesses, incluuiug
IDACORP Energy, its energy trading and marketing subsidiary. Two of IDACORP's subsidiaries, Ida Tech and IDACOMM,
are early-stage businesses that have yet to reach profitability. We have used a sum-of-the-parts relative valuation
methodology as " basis for our rating on the stock. We have �<<ignP.cl PfE multiples of 13.Sx. 10.0x, and 10.0x to the
utility's, energy and trading's, and other segments' earnings per share estimates for FY02, respectively. We believe our
valuation of IDACORP's unregulated segments is conservative, given the early stages of the subsidiaries. However, we
believe conservatism is appropriate given today's market environment. As ldaTech and IDACOMM progress, we expect to
revisit our valuation.
Investments Products: • NOT FDIC Insured • NO Bank Guarantee • MAY Lose Value
UlllYTI\111 ;,ooz Ragen MacKenzie. A OMsrn of Welts Fargo lnvestm,nts. LLC I 9'.l9 3rd Avent.e. Suite <300 i Seattle, Wastvngtcn 981041206 343.5000 i llXJ.456.3306 /0 BOO 891177 (U.K WATS)
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"ra->sa'.:JOr6
RA GEN MACKENZIE, A Division of Wells Fargo Investments, LLC
Like other Northwest utilities, Idaho Power's electric and gas power costs spiked dramatically during the winter of 2000-
200 I. However, unlike its peers, Idaho Power put into place several years ago a purchase cost adjustment (PCA) mechanism
that allows the Company to adjust the price of power embedded in its rate structure on an annual basis. The PCA (which is
similar to the mechanism that gas distribution companies have in place) has served Idaho Power well as power prices
escalated over the last year. Idaho Power is expected ID recover up to 96% of its excess power costs through rate increases.
IDACORP, due to record earnings growth in its energy trading and marketing business, reported an outstanding FYOO and
FYO I and, as such, has made for a difficult benchmark for FY02. Earnings in FYOI were negatively impacted by high power
costs at the utility; however, offsetting this negative impact was a record year for the energy marketing and trading arm, which
benefited from volatile prices. We expect the utility to return to a more normalized earnings level in 2002 as the Company
benefits from lower power costs, and we expect a decline in earnings in the energy and trading business due to decreased
vnlari liry in power prices. For these reasons, our FY02 estimate is $3.12 per share, which is a 7% decline from FYO I's
earnings per share of $3.35. Our $3.12 earnings estimate also includes a $0.20 contribution from two of ID ACOR P's non­
regulated subsidiaries, which is offset by our estimated ($0.45) loss from IDACORP's lclecomm services and fuel cell
businesses.
\Ve believe IDACORP's non-regulated businesses, which include companies engaged in fuel cell development and telccorn
services, offer long-term growth potential. As with other Pacific Northwest utilities companies in our coverage universe, vec
believe we are being conservative in our estimates of these two businesses and have left room for upside potential. We have
trimmed our expectations in these areas due to recent market volatility in the two respective sectors. We note, however, that
IDACORP's tclccum unit is self-funding and is expected to reach net income profitability within the next year or two.
l-liGtoric�I �nd Es:tim:;1t,::,.n F�rninec; hy Seernent
---------·-------- 1000A_ 2QOOA 3QOOA ---� FYOOAi . ... 1Q01A __ 2Q0_1A ______ . 3C!01A 4Q01A FY01A -·· FY02!c Idaho Power Com pau',' S0.03 S0.40 S0.43 S0.42 St.97 S0.3 7 S0.16 S0.00 ·s001 S0.<-0 Sl.95
IDA,:OR.P energy 0.15 0.46 0.69 0.28 158 0.62 0.83 U.9J �.49 2.87 I :;1
IOACORP Financial 0.03 0.03 0 05 0.04 0.14 I 0.03 0.03 0 ()5 o 03 0.14 o. I 2
Ida-West Energy 0.25 U.UJ 0.02 0.02 0.32 0.01 0.0� 0.02 (J.07 O. IJ 0.08
Other Segments (0.04 I (0.06) (0.08) (0.13) (0 �9) (O. IOJ (0.101 (0.09) (0.11 I (0.39) (04.IJ
IDACORP Inc. EPS s 1.12 5 0.86 s 1.11 s 0.63 53.72 s 0.93 $ 0.96 S 0.91 S 0.55 $ 3.35 S 3.12
Source: Company reports an,i Rage11 MacKenzie estima<es
COMPA}!Y OVERVIEW
IDACORP, Inc., based in Boise, Idaho, is a diversified energy services company comprised of one regulated electric utility
and five non-regulated bus messes, including energy trading and marketing. Idaho 's service territory is mostly southern Idaho
and includes parts of eastern Oregon. Idaho Power is unique in the Pacific Northwest in that it serves both winter-peaking
loads as well a, summer-peaking loads. This diversification allows Idaho Power Company to buy energy in the summer
months when prices in the Pacific Northwest region are generally lower.
IDACORP recently changed its reporting for its IDACORP Energy subsidiary to reflect its transactions on a gross basis
(versus net basis), which significantly changed the amount of total consolidated revenues attributable to IDACORP Energy.
Prior to the rcstatcrneru, IDACORP Em:1gy icv cuucs accounted for about 16% of total sales. The restated revenue
attributable 10 IDACORP Energy is now 84% of consolidated revenues. While IDACORP Energy contributes the vast
majority of revenue to the Company, we note that margins in the energy trading and marketing business, even in a good year,
are extremely thin. Therefore, IDACORP Energy is a smaller proportion of total operating income than the regulated utility
business in a normal utility year.
IDACORP's total operating revenues for 2001 were $5.648 billion, of which IDACORP Energy (IDACORP's energy and
trading operauous) contributed about $4.721 billion, or 8�% of revenues, while about �914 million, or 16% of revenues.
came from Idaho Power Company, IDACORP's utility. The remainder, $13 million, was generated by IDACORP's other
non-regulated businesses such as Ida-West Energy, IDACOMM, ldaTech, and IDACORP Financial.
Pagel
7
RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
ECONOMIC OUTLOOK FOR IDAl{O
The economic outlook fur Idaho is expected to moderately outperform that of the United States. Idaho's economic growth
over the last decade has been positively impacted by expansion in its non-agricultural employment. In fact, this growth has
placed ld�ho among the top ten fastest-growing states in the nation. Idaho has benefited over the last decade from a
population growth rate higher than the national average. During this period, personal income growth doubled due to the
expansion in services employment in areas such as call centers and back office operations.
Rates of growth in Idaho's non-agricultural employment and growth in real personal income are expected to decline in 2002
versus 200 I. Growth in both of these areas came in below expectations for 2001. Hewlett-Packard and Micron Technology,
whose recent decreases in capacity utilization have negatively impacted non-agricultural employment growth, heavily
influence Idaho's economy. According to a January 2002 report published by Idaho's Department of Financial Management.
non-agricultural employment is expected to grow 0.5% this year, which is significantly less than last year's pace ot I.�%.
Idaho's personal income growth is estimated to be 2.2% versus last year's (2001 's) growth rate of 2.7%. Although slower
growth is expected for Idaho in 2002, both in employment as well as in real personal income, Idaho is expected to fare better
than the national average, outpacing national growth in these key indicators through 2005.
BUSINESS SEGMENTS
IDAHO POWER COMPANY (/PC)
Idaho Power Company, which is IDACORP's regulated utility, currently serves more than 400,000 residential and
commercial customers who reside mostly in tdano. IPC ·s service terrtrory encompasses upp1uAi111atclJ'" 20,000 �quarc mile
area, with the majority located in southern Idaho and eastern Oregon serving a population base of more than 800,000 people.
About 95% of !PC's general business revenues come from customer, within the state of Idaho. Residential and commercial
customers make up more than 60% of !PC's general business revenues.
IPC Revenue, Actual and Estimated
In 000'• �'YQRA FY99A FYOOA FYOIA FY02E
Electrlc Utility:
General Business $ 514.856 s 516,148 s 565,357 s 650,608 s 682,489
Off system sales s 214,418 $ 119,785 s 229,986 $ 219,966 $ 98,543
Other revenues s 27,[36 $ 22,403 s 41,663 s 43,626 s 41,500
Total Electric Utility Revenues 756,410 658,336 837 ,006 914,201 822,532
Annual Growth Race t'Y98 f'Y99 FYOO FYOI �·vou:
General Business 7.2% 0.3% 9.5% 15.1% 4.9%
Off system sales 113.2% -44.1% 92.0% -4.4% -55.2%
Other revenues 12.3% -17.4% 86.0% 4.7% -4.9%
Total Electric Utility Revenues 25.0% -13.0% 27.1% 9.2% -10.0%
Sourr.e: Company reports wul Rllge,i Mactcenzic est im ates
\PC owns and operates properties including l 7 hydro facilities located on the Snake River and shares ownership in three coal­
fired plants located throughout the region. Idaho Power Company also recently put into service a 90 MW combustion turbine
to serve peaking loads. These resources combined supply about 89% (56% hydro and 33% thermal generation) of IPC's
power needs under normal weather and hydro conditrons. In most years, !PC's peaking luau i cquircs about 2,900 MW.
Idaho Power typically relies on wholesale spot market purchases for serving a portion (about 11 %) of its load. Idaho Power
Company's energy portfolio is heavily dependent on hydro conditions in order to provide low-cost hydro generation. Idaho
Power Company's earnings arr- sensitive to variations in the weather because 41 % of general business revenues are dependent
on residents, who use heating in the winter and air conditioning in the summer.
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RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
Deferred Charges and Recovery of Excess Power Costs. In 200 I Idaho Power faced drought, volatile wholesale prices,
and heavier load requirements due to colder-than-normal weather. Fortunately, Idaho Power put into place a number of years
ago a purchase cost adjustment (PCA) mechanism that allows the Company to adjust the price of power embedded in its rate
structure on an annual basis. At the end of FYOI, Idaho Power had incurred $227 million in excess power costs. Of this
amount, IPC is allowed to recover $217 million. or Qfi%, of its cx ccss power costs through rate increases to customers. Idaho
Power Company docs not have a PCA in place for Oregon, which represents about 5% of utility revenues. Idaho Power
Company has not had a general rate case since 1995. Due to its growth in the customer base, we believe that the Company
may tile for a rate case within the next two years.
Improving Hydro Conditions Over Last Vear. Early indications of reservoir inflows to Idaho Power's Brownlee R cservoir
(IDACORP's main storage reservoir for its Hell's Canyon hydro complex) indicate that 2002 is likely to end at a lowcr-than­
averag,. leve l, yer significantly higher than last year's level. 200 I experienced one of the lowest reservoir levels on record,
and early estimates of 2002 levels have been negatively impacted by 200 l's drought.
Relicensing of Hell's Canyon. IPC plans to file its application for relicensing of the Hell's Canyon complex, !PC's largest
hydro facility. Relicensing is a 30-year cycle process that is continuously ongoing at Idaho Power Company. The process of
preparing and filing for federal relicenses, even in the smallest facilities, is an undertaking of a number of years. Hell's
Canyon is a three-dam facility with a potential generating capacity of 1167 MW, which is greater than the rest of the hydro
facilities combined.
IDACORP ENERGY
!OACORP Energy, which legally separated from the utility in June 2001, prirnanly focuses on natural gas and electricity
wholesale trading. Also, IDACORP Energy owns strategic transmission rights and has the opportunity to trade its access
rights to other utilities and marketers. Because power prices have begun to stabilize, IDACORP is focused on growing this
business unit's earnings through deal origination. We believe !DACORP Energy intends to change the focus of its business
over time to incorporate additional strategic assets. For example, IDACORP Energy does not own or manaec any generation
assets at this point in time, but we believe there may be some future opportunity in this area for the Company. IDACURP
Energy employs approximately 120 people, of which about 15% arc traders, with the core concentration located in Boise,
Idaho.
Due to the market intelligence acquired through its trading and marketing activities, Idaho Power Company relics on the
trading arm to transact its open market activities when it is iu a net purchasing position. About 5% of !DACORP Energy's
gross margin historically has been derived through power sales to Idaho Power Company. Likewise, when the utility is in a
surplus position, it has the option to sell excess generation to IDACORP Energy. These transactions are conducted, as one
would expect, at market prices through an arm's length transaction. As with other utilities, power sales made by the utility arc
then used to offset power costs.
IDA-WEST ENERGY
Ida-West owns and manages independent electric power projects. Ida-West is currently developing a 273 MW natural gas­
fired turbine located in Middleton, Idaho, for Idaho Power Company. IPC selected !DA-West for developing the site through
a proposal process. We believe there is a possibility that the timeline may be pushed back on this project due to the negative
impact the slowing economy has had on load growth. This proposed Gamet facility has the potential to double its capacity
over rime.
Historically, Ida-West has been a stable contributor to IDACORP's earnings, adding about $0.08-$0.10 to earnings per share
annually. Ida-West's $0.32 contribution to earnings per share in FYOO was positively impacted by a gain on the sale of its
Hermiston project to an indepcudeut pvwc, producer, which resulted in a net of tax gain of about $8.3 million, or $0.22 per
share. In FYO 1, Ida-West Energy contributed $0.13 to earnings. We are estimating a segment contribution of about S0.08 in
FY02, which is more in line with its historical range.
IDACORP FINANCIAL SER VICES (IFS)
IDACORP Financial Services (IFS), since its inception in 1989, has been a stable contributor to earnings through its tax­
advantaged investments. To date, IFS has more than $120 million invested in its properties, which are primarily affordable
housing projects. More recently, IFS has expanded its investment scope to include historical rehabilitation projects such as
the El Cortez hotel project in San Diego, California.
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RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
IDACORP Financial has over 300 properties in 42 states and one U.S. territory and invests about $30 million annually. This
division's investment focus has historically been affordable housing projects, but it is planning to expand its tax-advantaged
investments to include, among other things, energy credits. We believe this segment is a consistent bottom-line contributor in
the $0.12-$0.14 range. We have estimated in the low end of this range for FY02 at $0. I 2.
IDA COMM
IDACOMM, IDACORP's traditional and high-speed Internet access provider, offers its service in areas located outside major
metropolitan areas. Vclocitus, IDACOMM's high-speed Internet service, currently operates in areas such as Boise and
Pocatello, Idaho; Spokane, Washington; Portland, Oregon; Fresno, California; Reno and Las Vegas, Nevada; and most
recently, Santa Fe, New Mexico. IDACOMM originally targeted the entire western region for expansion of its customer base,
but due to challenging market conditions, has scaled back its more aggressive plans. While we believe IDACOMM may
eventually rerurn !O a more aggressive cxpausiuu plan v111x " stronger cash flow position has been catcbliahcd, for now
IDACOMM is targeting a slower rollout that includes expansion into eight cities with its fixed wireless service by year-end.
We believe it is important to differentiate between other telecom service providers and IDACOMM's Velocitus service.
Velocitus is not a long-haul fiber company. Instead, the Company is focused on providing local fiber to organizations located
outside major metropolitan areas. For example, it provide, service to hospitals and schools in areas that may be overlooked
by other service providers. We believe that the demand for this service is real and growing, and that IDACOMM's approach
(Iruihl it uftc) they come) to thi, buainc as is rccaonab lc. In light of IDACOMM 's recent slower expansion p l an s , we expect
IDACOMM to brcakcvcn on a net income basis within the next l 2-18 months.
!nATFrH
Ida'I'cch, IDACORP's non-regulated subsidiary located in Bend, Oregon, is focused on hydrogen-powered fuel cell
development. The target market for IdaTeeh's fuel cell is for small-scale portable units to be used for distributed generation
in residential and other markets. JdaTcch has an agreement with Bonneville Power Administration (BPA) for alpha and beta
testing of its fuel cells. ldaTech is also currently alpha testing a small number of fuel cells in Japan with Tokyo Becki.
ida Fech has announced its intention to launch a commercial product, most likely its fuel cell reformer, by year-end.
Idc'Tcch, ctill currently in research and de ve lopmr-nt stog,.,. h,s yf't to reach FRITDA profitability. IDACOMM and IJaTcch
combined have a dilutive effect on earnings of about ($0.40) per share annually. Due to the extended delays in production
and adoption timelines inherent in these emerging industries, we believe we are being conservative in our projections for the
financial performance of these two units. We believe that IDACORP's non-profitable subsidiaries offer long-term growth
potential.
FULL-YEAR FINANCIAL RESULTS
IDACORP Energy was the major contributor to earnings in FYO! (85.7%) and contributed about 40% to earnings in FYOO.
Although IDACORP Energy reported a record year in FYOI, its overall contribution to earnings was somewhat distorted by
the below-normal performance of the utility. While the utility's profitability deteriorated in FYO! due to a regional drought
and volatile power prices, IDACORP Energy's earnings per share grew 82% year-over-year, reflecting strong volume and
transaction growth as well as a reduction in general overhead costs.
In FYO I, [DACORP reported net income of$ 125 million, or $3 .35 per share, versus $140 million, or $3.72 per share, in
FYOO. A decline in net income at the utility was offset by the 82% increase in eam111gs at IIJACOKP Energy. I he regional
drought experienced in FYO I increased Idaho Power's cost of providing power, while at the same time reducing its ability to
use off-system sales to offset rising power costs .
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RAG EN MACKENZIE, A Division of Wells Fargo Investments, LLC • Actual Quarterly EPS, by Segment
1gooA 2QOOA 3QOOA 4QOOA FYOOA
Idaho Power Company $0.73 $0.40 $0.43 $0.42 $1.97
IDACORP Energy 0.15 0.46 0.69 0.28 1.58
IDACORP Financial 0.03 0.03 0.05 0.04 0.14
Ida-West Energy 0.25 0.03 0.02 0.02 0.32
Other Segments (0 04) (0.06) (0.08) (0.13) (0.29)
IDACORP, Inc. li:PS S 1.12 S 0.86 S I.I I S 0.63 S 3.72
IQOIA 2QOIA 3QOIA 4Q01A FYOIA
Idaho Power Company $0.37 $0.16 $0.00 $0.07 $0.60
IDACORP Energy 0.62 0.83 0.93 0.49 2.87
IDACORP Financial O.Q3 0.03 0.05 O.Q3 0.14
lda-W est Energy 0.01 0.04 O.Q2 0.07 0.13
Other Segments (0.10) (0.10) (0.09) (0.11) (0.39)
lfJACORI', Inc. El'S s 0.93 s 0.96 s 0.91 s 0.55 S 3.35
Source: Company reports
•
•
Operating income for the year was $7.43 million versus $248 million in the prior year, reflecting, among other things, higher
purchased power costs at the utility. Operating income for the utility, IDACORP Energy, and Other segments in FYO I was
S90 million, $177 million, and a loss of ($24) millior., respectively, versus $169 million, $95 million, and a loss of ($16)
million in FYOO. Pretax income for the full year was S 190 million versus $211 million, reflecting lower operating income, as
� interest expense due to lDACORP's incre!.sc i_n short-term financing to fi.mdPC�-�--,
JUALOKt' estimates mat Idaho Power Cu111J.ldllY'> t:dt uiu!;, wuuld have been $1.45 higher (£ 1.27 negative impact from
excess power costs not included in the PCA adjustment and a write-off of S0.18 for excess power costs) without the negative
impact of higher power costs. Idaho Power, on a normalized basis, should earn about $2.00 per share. We are expecting the
utility to benefit from improving hydro conditions and lower power prices in FY02. For IDACORP Energy, we arc expecting
FY02 to establish a more normal base year for the subsidiary given the dramatic fall in power prices and volatility this year
versus last. Thus, we arc estimating a decline in earnings to $1.42 per share, which is also a decline from the segment's FYOI
and FYOO earnings of $2.87 and $ l.58, respectively. This business is extremely difficult to forecast given that it depends on
the level uf vularility of power prices and industry-wide diminishing credit quality. We have not antieipared an increase in
the volarility in power prices in our estimates. W e are anticipating segment contribution from IDACORP Financial and Ida­
West Energy to be within the range of their historical contribution levels.
BALANCE SHEET
The Company ended 3QO I with $62 million in cash and equivalents, which is below normal for the Company, due to the
negative impact of excess powPr rMt� throughout the year. !DACORP's capital structure consists of 46% debt, 6% preferred
securities, and 48% equity. For FY02, budgeted capital expenditure requiremenrs for the utility for FY02 are $124 million.
The Company has announced its intention to issue between $150 million and $250 million in debt and/or equity by the first
half of 2002. Proceeds from the issuance are expected to add equity to the utility, provide liquidity to the energy trading and
marketing business, and, to a lesser degree, be used to fund capital ueeds of other non-regulated businesses. IDACORP has
about $900 million in long-term debt on its balance sheet, which is rated A+ with a negative watch by Standard & Poor's at
the corporate level and Baal with a stable outlook by Moody's .
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RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
Book values of Idaho Power Company and IDACORP, Inc., as of September 30, 2001, were $20.83 and $23.09, respectively.
Idaho Power Company has an authorized return on common equity of 11 %. For the last three years, IDACORP has earned a
return on equity significantly higher than its peer group over the same time period, due largely to the contribution to earnings
from its non-regulated subsidiaries. In 2000, 1999, and 1998, IDACORP's return on average equity was 17 .0%, 12.1 %, and
12.7%, re�peNively These returns compare to an industry average of7.2%. 12.2%. and 10.9%, respectively.
RISKS
A significant portion of IDACORP's revenue and earnings is generated from its energy trading and marketing business. This
business is difficult to forecast given that profitability in the sector is dependent on volatility in power prices. Accounting in
the industry is mark-to-market, meaning that some of the profits booked in a given quarter are due to unrealized gains on
changes in the fair market value of outstanding contracts and also a function of the amount of collateral posted by the
Company. These gains are generally realized over a number of years. IDACORP Energy management has recently increased
its disclosure in this area so that trendlines could be established. However, earnings in this segment of the business may be
volatile.
IDACORP Energy is engaged in a lawsuit with Overton Power District for failure to meet payment obligations under a power
contract where the Company believes Overton has breached its contract. Overton agreed to pay IDACORP Energy for power
at prices significantly higher than today's market prices for a period beginning July l, 2001 and continuing through June 30,
2011. Overton had agreed at the time to raise rates to customers 111 order to cover the power costs. The Company has a :673
miliion long-term asset on its balance sheet that has been discounted for uncertainties surrounding the situation. The
Company believes the case with Overton is unique and docs not believe it is indicative of the credit quality of its overall
portfolio.
The Company, because of the drought conditions in the region, engaged in demand-side management programs in FYO l .
These programs were intended to reduce the load of some of its larger customers by paying the customers to reduce power
consumption. One such arrangement with Astaris Corporation involved a 50 MW voluntary load reduction. The Company
and Astaris also entered into a take-or-pay arrangement where Astaris agreed to pay a comracted price for power whether or
not Astaris used the power. Subsequently, Astaris shut down operations and is disputing this take-or-pay arrangement. In
Nrwernher 700 l. the Company filed with the Commission for resolution.
CONCLUSION
We believe IDACORP's management team has made reasonable business decisions that have consistently added to
IDACORP's bottom line. Even though not all of the non-regulated businesses into which IDACORP has entered have met
expectations, the Company has been able to identify those situations as such and redirect its focus. Of the five non-regulated
businesses, two are not yet profitable; however, one of those is essentially self-funded and expected to reach net income
breakeven within the next year or two, and the other should have its first commercial product launch later this year. The other
non-regulated businesses have been solid contributors to earnings, with the energy trading and marketing business
contributing the majority of net income in FYOl. As for Idaho Power Company, we believe it operates in a favorable
regulatory environment in Idaho and, due to the PCA mechanism put into place, has avoided some of the financial crises that
have been a result of volatile power prices in the region. On a normalized basis, Idaho Power Company contributes about
$2.00 per share. IDACORP pays a dividend of $1.86, a 4.9% yield, which compares favorably to other electric utilities. Due
to the low payout ratio of 60% (based on our FY02 earnings estimate), we consider the dividend secure.
ALLYSON R. RODGERS, CFA
[phone]
Other public companies mentioned:
Hewlett-Packard Company (NYSE-HWP-S 19.98, not rated)
Micron Technology, Inc. (NYSE-MU-$34.05, not rated)
•
S&P 500: 1109.43
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• RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
(lat ........ )
lnroni,· St,1l1'nk'nf IIJNA 2000A 300GA 40NA 2000A IQOIA 2091A 3001A �OIA !OOIA 200ll
Electric Utility Rr:,et1l.)C,- 166,480 213,555 231,9351 225,035 !07,006 700,452 228.214 2K6.807 I 198.728 I 914,201 822,532
Energy M.rkcting i&0,70? 132,665 799.490 822.868 2.135,725 929,563 1,347,286 1,825.249 619,2r.1 1 4,721,365 2,315,000
Other 4,397 5,281 7,960. 5,025 22.663 2,(,36 l.068 J,019 3.724 12,448 12,SOO
Operatine: Ren-nuts 351.579 551,50 I 1.039,3861 1,052.928 2,995 . .19] 1,132,651 1,578,569 l,115.075 821.719 5.648,014 1.1 so.orz
UtililJ Optnting [1pcnw,
Purchased power 12,&&9 101,6.10 139.24] , 144.XR7 Jn.M9 125.2P 169,419 . 228,4(,0 <il,044 584,209 228,000
Fuel expense 24,659 20.056 ; 23.81 I 25.689 q4_215 25,247 22,350 I 25,Q.17 24,775 98,318 97,500
Power cost adjustmcn1 3.2581 (21.943) (45.612) (56.391) (120.6881 (5R,246) (6R.OU) (57.770) 8.177 (175.9251
Oth:r opcraticos ard maintenance 44,605 52,082 49.6]0 48.55] 194.870 49,401 49,978 50,906 60,476 210,762 230,000
Depreciation 19,887 19.949 19.93) W,519 80.287 20,952 21,448 21,894 22,748 87,041 8?,500
Taxes other than ircomc: taxc:-i 5,427 , 5.463 5,024 4,252 20,1661 S,235 5.409 4.947 4.102 19.693 20,000
Total utility opetaung expenses I I0,726 177,236 19,.028 187,509 667,498 167,876 200.518 274,31l-l 181,322 824,099 665,00-0 1 Marxc:tingCGS 169,449 300,759 741,903 778,324 1.990.434 857,588 ' 1.286.727 1,755,807 '78.48.l 4,478,605 2,164,525
Marketing SC.&/\ 2,711 3,913 15,492 28.69(, 50.811 I 33,428 I 9,295 11,770 11,553 66,047 46,800 Other non-utility opcratmg expense, I b,992 l\,C\)� 11.100 12,6,0 )').JOO 0,587 8,587 ".l,.t�-1 l'l.)"76 J6,o;, '\7 'qw)
Total Opfntiag [1prnsn 289,877 4?0,545 960,522 1,007 179 2,748.123 1,067.479 1.5-0.5,127 2.049,385 783 734 5.405 725 2,913,825
Income from operations i 61,702 60,956 78,864 45,749 247.271 65.172 73,442 65,690 37,985 242,2&<l 236,207
Other (ncQmC
I
20,674 3,978 1.043 4,853 30,5491 4,993 3,598 4,385 10.]17 23,294 30,000 [merest f").pi'.!OSC I 13,162) (13,253) (13,239) (13,703) (5).]5(,)1 (13,449) (14,768) (13,787) (13,779) (55,783); (57,00-0)
Other interest (2.211) (1,463) ( 1.758) (2,401) (7,833) (3,203)1 (3.041) (1,925) (4,371) (14,54-0)1 ( I0.000)
Preferred di,.,idends of Idaho 1·'01.,1,:er I 0.428) ll,4S-I) (1,511) (1,506) (5,929) 11,4<\IJ, (1,292)1 (1,375) (1,272) (5,4-00) (5.400)
Total other income (e:i..pensesJ • net ! 3,874 (12,2221 (15,464) (12,757) (36.569) (13,120)0 (15,503,I (14,701) (9,10.5) 1.52.429) (42..100)
Income bdo� tu.es ! 65.576 48,713 63,400 32.99] 210.701 52,052 57,939 50,988 26,881 189,860 193.11()7
Income taxes 23,496 IG.211 21,839 9;272 70,818 17,282 21,&GI 17,055 8,449 64,647 6.5,894
Nt:t hu.uun;: >IJ,080 J:l,S'lJ <1151.1 '>1,7"11 1'\QSUU 14 770 36.07X 33.933 20,432 125.213 127,913 Average common shares o1� 37,612 37,612 37,524 37.517 37.56(, 37.415 37,414 37 410 37,480 37.410 41.000
EPS, B�ic and Dilur('d s 1.12 s 0.86 s I.II s 0.61 · S l.72 s 0.93 s 0.96 , S 0 91 s 0.55 s 3.35 s 3.12
Dividends paid s 0.47 s 0 47 IS 0.47 s 0.471 s 1.86 s 0.47 s 0 .4·1 I� 0.47 s 0.47 s 1.116 s 1.86
Dividend payout rario I 41.6% 538%! 42.0�v 73.5%1 �.0'}11 500% 4.U�·.I 51 .3 .. /u' 85.3%1 55.6'?'u 59.6�1o ,,..... ....... .,.,.--=,�,...;..
Purchased power 7.7% 4i.6% 60.0% 64.4% -17.f.% 62.5�� 74.2% 79.7% 30.7% 63.9% 27.7%
Fuel cxpcn�e 14.8% 9.4% 10.3% 11.4°1. II 3% 12.6% 9.8% 9.0% 12.S'/o 10.8% 11.9%
Power cost ad jusunc nt 2.0% -10.]% -19.7% .25 1•t.. .J4A% -29.1% -29.8% -20.1% 4.1% -19.2°1, 0.0%
Other operations and maintenance :6.8% 24.4% 21.4% 21.6% �3.3% 24.6% 21.9% 17.7% 30.4% 2:l 1% 2R.0%
Depreciation 11.9% 9.3% 8.6% 9.l'lo 9.M'. 10.5% 9.4% 7.6'/, 11.4% 9.5°/. 10.9%
Tot.al Operating Expenses 82.5% 8tl.?% 92.4% QS.7% 91.7% 94.2% QSJ% 96.9';; 95.4'/, 95.7% 92.5% Ma,:in Ana./.l,�t
Marketing CGS 93.8°/, 90.4'Y. 92.8'1, 94,6% 93.2o/, 92.)% 95.5�1- 96.2% 9:l.4% 94.9% 9).5'1,
Operating margin 17.5% 11.1%, ).6'Yo 4.3% 8.3% l.8% 4.7% .'.l'lo 4.fi�lo 4.)% 7.5%
Pre-tax marein 18.7% !1:.8% 6.ll'o 3.1% 7.0% 4.6% 3.7% 2.4% 3.5% 3.4% b2% • Net margin 12.0% 5.9% 4.0% 2.3% 4.7% ).1% l..J}'o 1.0,-o l.)'"/o z.z v,
Tax Rate 35.8�0 33.J•/o 34.4% 2�.1% 33.6% 33.2% 37.7% 33.4% 29.3% 34.0% ]4.0��
Y�Yr O.,uq:c
Electric Utility Revenues 20.4% 6.9% 23.··o;. -11.7% 9.2% -10.0%
Enc:rgy Mar .. eting Revenues 414.4% 305.0Y, 128.3% -24.7% 121.1% -51.0%
Total Operating Revenue 222.2% 186.2% 103.5% -22.0o/. 88.6% -44.2•1.
Tot.al utility operating expenses 51.6% IJ.1•;. 42.9% .J.3% 2).5% ·19J'/,
Maixeting CGS 406.1•1. 327.8% 136.7°/, -25.7% 125.0% -51.7%
Marlceting S,G,&A 113).2% 1)7.6% -24.0% -59.7% 30.0% -29.IYci
Operating Income 5.6% 20.5% -16.7% -17.0% -2.0% .2 5%
Prc-j ax loco me 20.6!U. li.0% .IQ 1.iOJG .11,0.,:, .9 Q% 2.1%
Net Income ·17.4% 10.9°1, -18.4% -13.9% -10.5% 2.2%
E?S, Basic and Diluted -16.9% u.ss, -18.1% .J).8% -10.I'/, -6.8%
Source: Company reports ond Rngen MocKem:1e estimates
Aflvson R. Rodgers, CFA (l06) 464-595/
0!.25.2002
• Page8
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RAGEN MACKENZIE, A Division of Wells Fargo Investments, LLC
IDACORP, lnc.
tUstorical Balance Sheet (In OOO's� FY98A FY99A FYOOA 3Q01A
ASSETS
Caah and Equivalcntc 22,867 0,: 111 .11R " 106.795 s 62.415
Total Receivables 116,486 113,748 240,921 304,142
Energy Marketing Assets 37 ,398 1,060,128 294,825
Accrued Unbilled Revenues 34,610 31,994 44,825 32,427
Materials and Supplies 3 7,253 38,940 34,836 33,283
Regulatory Assets 2,965 893 8,672 68, 190
Prepayments 16,042 16,097 24,575 26,845
Other 20,75�
Current Assets 230,223 350,408 1,520,752 842,881
Investments and Other 124,021 139,091 157,068 187,750
Utility Plant, net 1,650,054 1,652,304 1,657,302 1,740,157
Construction Work in Progress 59,717 91,637 136,388 112,266
Other Property 7,154 8,670 11,346 21,125
Deferred Charges 385,650 398,261 556.850 1,045,022
TOTAL ASSETS s 2,456,819 s 2,640,371 � :1,039 ,706 s 3,949,201
LIABILITIES AND CAPITALIZATION
Notes Payable 38,524 19,757 120,600 325,500
Accounts Payable IO 1,975 145,737 272,3 76 353,466
Energy Marketing Liabilities 33,814 1,060, 180 356,690
Derivative Liabilities 56,270
Interest Accrued 18,365 19,126 16,985 20,576
Other 40,025 38,902 52,407 61,831
1-11rrPnt Portion of Long-Tenn Debt 6 029 __ 8?,101 39,774 --2.JlQ_
Current Liabilities 204,918 346,437 1,562,322 1,183,443
Regulatory Liabilities 106,831 107,991 110,901 110,013
Deferred Income Taxes 422,196 430,468 460,464 567, 733
Energy Marketing 46,769 170,711
Derivative Liabilities 15,229
Other 70,572 75,136 69,259 62,395
Long-Term Debt 815,937 821,558 864,114 870,140
Preferred Stock I 05,968 105,811 105,066 104,524
Common Stock 451,564 451,343 451,606 445,984
Retained Earnings 278,833 301,627 369,205 419,029
Common Shareholders' Equity 730,397 752,970 820,8 I I 865,013
TOTAL LIABILITIES I CAPITALIZATION s 2,456,819 $ 2,640,371 s 4,039,706 s 3,949,201
Sm,rrP · r.nmpany reports and Raeen MucK,mzie estimates
Allyson R. Rodgers, CFA [phone]
02.15.2002
Page 9
;j
RAG EN MACKENZIE, A Division of Wells Fargo Investments, LLC
IDACORP, Inc. • Historical Stataneut of Cash Flows �n OOO's�
1998 1999 2000 9-Mos
OPERATING ACTIVITIES:
Not income RQ, 176 QU49 139.883 104.782
NON-CASH ITEMS INCLUDED IN NET INCOME:
Allowance for uncollcctiblc accounts 19,347
Depreciation and amortization 87, 143 95,436 103,971 82,324
Provision for deferred income taxes (10,182) (1,820) 46,718 115,045
Power and natural gas cost deferrals and amortizations 21,658 (891) (122,353) (188,202)
Gain on sale of property and subsidiary investments-net (14,000) (1,605)
Energy commodity aeacts ond licbilitieo (3,584) 28,531 (116,299)
Other-net 2,314
Decrease (increase) in working capital components:
Receivables and prepaid expense 4,883 2,683 (157,182) (85,804)
Materials & supplies, fuel stock and natural gas stored (925) (1,687) 4,104 (510)
Payables and other accrued liabilities ( I 0,772) 42,906 107,191 41,715
Other (11,094) 6,196 (3,22R) (2,230)
Moncrtzauon of Contract
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 169,887 230,588 133,635 (29,123)
INVESTING ACTIVITIES:
Construction expenditures (excluding AFUDC-equity funds) (89, 184) (110,974) (140,302) ( 138,260)
Other capital requirements 3,206 (5,060) (642) (3,266)
Proceeds from property sales and sale of subsidiary investments 17,500 11,126
Assets acquired and investments in subsidiaries (19,139) (25,416) (29,166)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (105,117) (141,450) (152,610) (130,400)
l'IN 4 NrrNr. .trTrVITIF.S,
Increase (decrease) in short-term borrowings (18,992) (18,767) 100,843 204,900
Proceeds from issuance of long-term debt 80,556 98,730 94,381 120,000
Redemption and maturity of long-term debt (39, 154) (9,815) (102,427) (144,390)
Sale (repurchase) of common stock (8,014) (7,969)
Cash dividends paid (69,868) (69,863) (69,850) (52,343)
Other-net (l,350) (952) (501) (5,055)
NET CASH PROVIDED BY (USED IN) J,'JNANCING AC'TTVITIF.S (48.808) (667) 14,432 115,143
NET INCREASE (DECREASE) IN CASH & CASH EQUIVALENTS 15,962 88,471 (4,543) (44,380)
CASH & CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,905 22,867 111,338 106,795
CASH & CASH EQUIVALENTS AT END OF PERIOD 22,867 111,338 106,795 62,415
Source: Company reports and Rugen MacKenzie estimates
Allyson R. Rodgers, CFA (206) 464-595 I
02.25.2002
• Col]yrigit 2002 Ragen Macl(enzle. A Oivisi:>n of Wells Fargo lnVH1ment,;, uc I '3'll 3ro Aveiue, Slite 4300 I Seatle, Washngbn 96104 /206.343.5000 / 800A56.3� BOO Ill 1177 (U.KWATS)
NJOITO-W. NFORMATON Ctl COl,l'ANIES P.ENTONED HER� L5AVAI.All.E UPOI REOLEST
I
llis is not a (l]Olll . ete anaysis of ew:y matai . al fact regamrg rrrt CXllTllB'lY, irdusty, or sooiity. The q>rioos elljlfessed here f1afted OLr jud!,nerl at tis dai? a'ld are S<tjed lo ctmge. Tl'e iiformalon has
be«l ootained ln:rn so.m,s we consider lo be reliaUe, but we camot � 1l'e ttro.rOO/, OJ inn or its offiC811, rescoo:11 a,partne,t pers<mel, ohlf ""l)loyees, or wsbners may ha\'I! a po,;ifon, lorQ or
shat, in tie sea.mies mrioned, or in t1'.)liorls relalrg tl'sl!lo, may t,.,y and sell he Sl!O.lities on he Ol)ell rraket or D1hlr'Mse, may SEl'II! as ai �cef or clrector of fr'! <XJr4mY mentored, prior to or al fle lrne of pltJicaton of 1l'e report or mn ime lo wne tm,aler. OJ inn may be a ma1<et rrnl<er or act as pmq,ai in sea.rities tlnsrlcns.
/5
RELICENSING OF HYDRUt:Lt:� I Kil, t't(UJC\., I.:>.
IPC, like other utilities that operate nonfederal nydroelectric projects, obtains Iiccnscs fcir lts
projects from the FERC. These licenses generally last for 30 to 50 years depending on the size.an
of the project. Currently, the licenses for five hydro projects have expired. These projects continue to op
a-inder annual licenses until the FERC issues a new permanent license. Three more hydro project licenses wilt �xpire by 2010.
IPC IS actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15
years. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon
Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric projects. The licenses for the Hells
Canyon Complex (Brownlee, Oxbow and Hells Canyon) and the Swan Falls project expire in 2005 and 2010,
respectively. IPC is currently engaged in procedures necessary to file timely license applications for these
projects. Although various federal and state requirements and issues must be resolved through the license
renewal process, IPC anticipates that it will relicense each of the eight projects.
Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower
Salmon Falls and Shoshone Falls projects. New FERC licenses are anticipated in 2003. While the actual
environmental costs of protection, mitigation and enhancement (PM&E) measures and other costs associated
with the relicensing of the projects will not be known until the new licenses are issued by the FERC, costs
associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million
during the first five years of the licenses and $28 million over the following 25 years.
A final FTS has heen issued in October 2002 for the CJ Strike project and a new FERC license is expected in
2003. While the actual costs of PM&E measures and other costs associated with the relicensing of the project
will not be known until the new license is issued by the FERC, costs associated with the license (assuming a
30-year license) are expected to total approximately $9 million during the first five years of the license and $38
million over the following 25 years.
The four Mid-Snake River projects, Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls, and • the CJ Strike projects, may affect five species ot snails listed under the Endangered Species Act. Sec
discussion in the Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental
Issues - Threatened and Endangered Snails."
The Upper and Lower Malad project license expires in July 2004 and the new license application was filed in
July 2002. The application is proceeding through the normal FERC licensing process. The application
includes proposed PM&E measures estimated lu total (assuming a 30-year license) approximately $1 million
during the first five years of the license and $3 million over the following 25 years. However, the actual costs
of PM&E measures and other costs associated with the relicensing of the project will not be known until the
new license is issued by the FERC.
The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent ofIPC's hydro /
generation capacity aut.140 percent of its total generating capacity. TPr. developed its draft license application
with the assistance of a collaborative team made up of individuals representing state and federal agencies,
businesses, environmental, tribal, customer, local government and local landowner interests. The draft license
applicauon was issued in September 2002 and the final application will be filed in July 2003. The draft
application includes proposed PM&E measures estimated to total approximately (assuming a 30-year license)
$78 million during the first five years of the license and $100 million during the following 25 years. However,
the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be
known until the new license is issued by the FERC.
At December 31, 2002, $50 million of pre-relicensing costs were included in Construction Work in Progress
(CWIP) and $6 million of pre-relicensing costs were included in Electric Plant in Service. The pre-relicensing
costs are recorded and held in CWIP until a new permanent license or annual license is issued by the FERC, at
which time the charges are transferred to Electric Plant in Service. Pre-relicensing costs as well as costs
14
•
: , SUMMARY Ut- 2UU2 RES UL TS ANO 2003 OUTLOOK:
Overall Resu Its
IDACORP's overall results show earnings per share (EPS) of$1.63, a decrease of $1.72 from 2001. !PC's EPS
increased from $0.60 in 2001 to $2.24 in 2002 despite the operational impacts of continued below normal
streamflow conditions on !PC's hydro system and reduced general business sales. At IE, EPS decreased
significantly from $2.87 in 2001 to a current year loss of $0.39. !E's results have been significantly impacted
by deteriorating credit, substantially reduced pricing spreads, and low volatility in the W estem wholesale
energy markets as well as the decision to wind down energy marketing operations. IDACORP's results also
reflect an $8 million partial write-down of Ida-West's investment in equipment related to the proposed Garnet
energy project.
Since the announcement to wind down its energy marketing operations, IE has recorded $9 million in
severance expenses, non-cancelable lease liabilities and asset impairments, among other matters. IE has
reduced its workforce from a peak last year of 125 to fewer than 60 employees as of December 3 1, 2002.
Further reductions in the workforce to approximately 20 employees are expected by July 2003. J.,Co 2--
Utility operations benefited from a tax accounting method change that allowed IPC to record a $35 million tax /J/c. benefit. $31 million of this benefit is attributable to 2001 and prior years.
This benefit was partially offset by expensing $12 million in lost irrigation revenues disallowed by the IPUC.
IPC disagrees with the IPUC's decision to disallow recovery of the $12 million in Jost irrigation revenues and
has filed an appeal with the Idaho Supreme Court seeking to overturn the IPUC's decision. IPC filed its brief
on January 3 I, 2003 It is: anticipated that this: case will not be decided by the Idaho Supreme Court until late
2003 or early 2004. If successful, IPC would record any amount recovered as revenue.
Hydroelectric Generation and Below Normal Water Conditions
The following table presents IPC's system generation for the last three years:
MWh Percent of total generation e 2002 2001 2000 2002 2001 2000
Hydroelectric 6,069 5,638 8,500 45% 43% 52%
Thermal 7,286 7,622 7,701 55 57 48
Total system generation 13,355 13,260 16,201 100% 100% 100%
IPC relies on low-cost hydroelectric plants for a significant portion of its power supply. IPC's hydroelectric
generation has decreased since 2000 as IPC has experienced three years of below normal water conditions.
Under normal streamflow conditions, IPC's generation mix is 57 percent hydro and 43 percent thermal. The
amount of electricity IPC is able to generate from its hydro plants depends primarily on the snowpack in the
mountains above its hydro facilities, reservoir storage and streamflow conditions.
Current Snake River basin snowpack numbers suggest that streamflow conditions for 2003 will remain below
normal. IPC's March 2003 accumulations were 78 percent of normal, compared to 85 percent at the same time
a year earlier.
The U.S. Weather Service's River Forecast Center at this time is predicting April-through-July inflow into
Brownlee Reservoir will be 3.7 million acre-feet (maf). The normal 30-year average for inflow during that
time is 6.3 maf Based un the above snowpack and forecasted inflows, IPC is expecting its fourth year of
below normal water conditions. IPC currently plans to use wholesale purchases from the energy markets when
necessary to meet its energy needs during 2003.
23 17
Idaho Power Company Pagel of 3
Global Credit Research
Opinion Update
20 JUN 2003
Opinion Update: ldaho Power Company
Idaho Power Company
Boise, Idaho, United States
Ratings
Category
Issuer Ratino
Fir-;t Mortgage Bonds
Senior Secured
Senior Unsecured Shelf
F're�errcd Stock
Commercial Peper
Parent: IDACORP, Inc.
Issuer Rating
Senior Unsecured MTN
Ccmmerciai Paper
Moody's Rating
A3 A2
A2
(P)A3
Boo::?
P-1
Baa1
Baa1
P-2
Analyst
Kevin G. Rose/New York
A.J Sabatelle/New York
Da:1iel Gates/New York
Phone
1.212.553.1653
Opinion
Credit Strengths
Credit Strengths for Idaho Power Company (IPC) are:
- Good regulatory relations and support provided by the power cost adjustment mechanism (PCA)
- Very low production costs under normal nyoro conditions
- Continued growing economy and service territory
- Ongoing cost control efforts
;g
------- -----
- General rate increase needed to recover costs of customer growth, additional capacity needs, and expansion of
T&D system
- Effects of persisting drought and unfavorable weather
/�on. adequate llqu1d1ty and good banking relationships
/ Credit Challenqes
�
I Credit Challenges for IPC are - ------
ti I e://C: \Vocuments%20and%20Settings \lfs63 3 l \Local %20Settings\ T em p\Idaho%20Powe... 6/23/2003
Idaho Power Company
- Costs and potential operational changes tied to hydroelectric plant relicensing process
.. High dividend payout to IDACORP, the parent company
Rating Rationale
Page Lor J
I PC's A2. senior secured rating reflects its solid financial position, low rates, and relatively low business risk profile,
as well as its plans to control capital spending while striving to reduce other expenses. The A2. also reflects the
generally supportive regulatory environment in Idaho. Yet the A2. rating also considers the risk that IPC might face
less operating and financial flexibility as it seeks relicensing of hydroelectric plants and adds other supply
resources by 2005 to meet expected demand growth.
We note tnat under nounat l1yu1u conditions !PC's production costs are among the lowcct of any in the nation,
reflecting its sizable hydroelectric capacity base and shared ownership of economic coal-fired plants. Also,
evidence of generally supportive treatment from the Idaho Public Utilities Commission (IPUC) is apparent from
benefits of a power cost adjustment (PCA) clause in Idaho. The PCA fosters more stable earnings and cash flow
protection for investors.
I PC's rating outlook is negative as the utility continues to cope with difficult power supply markets in its region and
prepares to seek a base rate increase to bolster utility returns and cash flow. We note that affiliate transaction
issues with FERC and the IPUC have been largely resolved without undue cost, although certain internal
��eeo to be corupteteu. -------------------
What Could Change the Rating - UP
A.s ,eflected in the negative rating outlook, prospects for near-term improvement in the rating are limited. However,
success in securing adequate general rate relief in combination with help from improving hydro conditions and
other cas��co��d help stabilize !PC's credit rating.
What Could Change the Rating - DOWN ---·-�------ ----
Continued delay in return to more normal hydro and weather conditions in combination with unexpected harsh
treatment from Idaho regulators in the upcoming general rate proceedings. Significant increases in relicensing
costs and/or stringent operational constraints imposed as part cf the license renewal precess. Any unexpected
return to significant, debt-financed investment in more risky nonutility investments by IDACORP that places acomonat demands on !PC cash now.
•
IPC largely resolved certain affiliate transaction issues with FERC and the IPUC in May without undue cost and is
undergoing internal compliance assessments to assure compliance with due process in the future. Meanwhile,
I PC's contribution to IDACORP's earnings to date in fiscal 2003 is being hampered by the effects of the lingering
drougtlt and unfavorable weather condluous. 1111µ01 ld11lly, cash flow still benefits from the rcA mcchoniom, which
helps stabilize the earnings and cash flow effects of variability in hydro conditions and wholesale power prices.
Also, I PC's recent long-term financing activity in a very favorable interest rate environment has considerably
reduced its reliance on short-term debt, improved liquidity, and lowered its overall cost of capital. !PC's need to rely
on short-term debt during the remainder of 2003 Is expected tu , t::111di11 well below the unusually high levels
experienced during 2001 when wholesale markets were extremely volatile. I PC's lower net supply costs
contributed to significantly lower rates for customers, following the 5/16/03 PCA rate decision approving an
average 18% rate reduction. The PCA rate cut could exceed anticipated general rate increases in 2004 to recover
other costs of service not in current base rates. IPC Is expected to file the yt::11t::1dl rate case this fall. Lestly, we
note that IPC renewed its $200MM 364-day bank credit facility in March. The facility expires on 3/18/04 .
© Copyright 2003, Moody's Investors Service, Inc. and/or its licensors including Moody's Assurance Company, Inc.
(together, MOODY'S). All rights reserved.
fil e://C: \Documents%20and%20Settings\lf s63 3 l \Local%20Settings\ Temp\ldaho%20Powe... 6/23/2003
Idaho Power Company !'age J or J
•
•
ALL INFORMATION CONTAINED HEREIN IS PROTECTED BY COPYRIGHT LAW AND NONE OF SUCH INFORMA110f'J MAY BE
COPIED OR OTHERWISE REPRODUCED, REPACKAGED, FURTHER TRANSMIHED. TRANSFERRED, DISSEMIN.ATED.
REDISTil.IBUTED OR RESOLD, OR STORED FOR SUBSEQUENT US[ FOR AN'i SUCI-< PuRPOSE, IN WHOLE OR i[j PART, IN .�r;V
FORM Cl,1 MANNFR OR BY ANY MEANS WHATSOEVER, BY ANY PERSON WITHOUT l·IOODY'5 PRIOR WRITTEN CONSENT. All
mforrn at ion contained herein is obtained by MOODY'S from sources believed hv it re, o e accurate and reliable. Because of the
oos srbiutv of human or mechanical error as well as other Iact or-, �.nwever, suc.h information 1$ p:ovided "as rs" 'Nithout v1arra,,ty
of any kind and MOODY'S, in particular, makes no representation or war rantv, express or implied, as to the accuracy, tim�l<n-�cs,
(•)mple(eneSS, merChdllldl.Jilily VI rit11e�':i fv1 any p e rt ic ule r p u r p o c c of on v ou cli 1nform.:,tion ljnder n o crr'c u rn c t ar-v c c ":hAd
,',Q.)DY'S have any :,ability to any person or entity for(,·) ilny lo s s or d a ma q e ,c whole or is p art c a uc cc b v r�su/\,ng fr orn 01
r e latin q to, any error (negligent or otherwise) or other c.rcurnst ance 01 -:ontingenc�· v.rt hrn 'X out std« the con!rc-11 of t·lOODY'S :w,:
snv or its directors, officers, employees or agents. in connection with tht: proc urerne nt , c..:-,!recbon. c omcuauon. a:1�lvc:,1::,_
interpretation. communication, publicatron or delivery of any such information. or (b) a n v direct. indirect. special. conseouenuat.
cornpen s atorv or incident a l damages whatsoever {including without limit anon. lost profits ). even 1f MOODY'S !S �dvised 111
advance of the poc;:.i�i!ity of such darr.anes. resulting from the use of or in ab.htv to use. a nv such info rrne t ion ·,he ,:redit ratings, if any, constituting part of the information contained herein are. and must be construed colelv as, statements of 0�111:on and not
stname11ts of fact or r ecornm end ations to purd,ase, sell or hold any s ecurrtres . MO WARRANTY. EXPRESS OR :r-1,UED, P..S TO
THE ACC:.JR/\CV, THIEUNESS, COMPLETFNFc;c;, MFRtHANTARII lTY OR FlTNESS FOR ANY PARTICULAR PURPOSE OF ANY SUCH
RJI.TING OR OTHER OPINION OR INFORMATION IS GIVEN OR MADE BY M008\"S IN ,\NY FORM OR MANN[R VIH.tffSOE'./ER. Each
rating or other opinion must be weighed solely as one factor in any investment decision made by or on behalf of any user of the
information contained herein. and each such user must a ccordin qlv rna k e its own studv end eva luat.on of each sec ur itv and of
t.l3Ch issue, and guarantor of. and each provider of credit support for. each se,�1:rity that it ma/ consider pur c hasin q. h.olding er
seli1nv l'u�ci:ant to Section 17(b) of tile Ser urities Act of 1933, MOODY'S h e r erv crsc.oscs that most issuers o' d�bt secur,t,%
(inrludinq corpore t ; and munic:pal boud s. debentur es. notes. a·id c-:in:!·;-:prc,il• ;_-:upr:r) a u d preferred ':.tc(k ra�-2r. t"•\ i .. �OODY':"
'lave, prior to a5s1gnment of any ra tinn, agreerl t ... �.1_,ay to :,100DY'S Ior ,;pr;rars-l; and rat1!"1g :2rvit.:e5 r-=nd�red t. 1t fees 1ang:.�g
frorn $1,500 to $1.S00,000
f le://C: \lJocum ents%20and%20Settings\lfs63 3 1 \Local %20Seni ngs\ Temp\Jdaho%20Puwe... 6/23/2003
December 12, 2002
Securit, Maturij:y Amount �.!log Price Yield �read
FMB 11/15112 $100 mil. A2/A 9913 4.86% 85 Bid
rMO nh:5/:3� C,oo mil. J,2/A 99.6B 6.0:!.�l 11'.i Qid
(OIJ.QQ_'}
475%
G.vo?6
Philip(. Adams, (FA
[phone]
philip _ c _ [e-mail]
INVESTMENT GRADE CORPORATES
Idaho Power Company, Inc. (IDA)
Update and New Issue Review
BANC ONE CAPITAL MARKETS, INC. ' i
�---·-----------------------------·-···---
1 ' . ;
Recommendation: We think the new FMB issues by Idaho Power Company are currently fairly valued, and therefore
rate them a HOLD. The issues came at T +105 and T +125 on November 12, and have tightened nicely since then. The cur­
rent spreads are attractive for the ratings, but the small size of the issues and lack of frequency of the name in the
m::irkPt proh::ihly hamper liquidity. In addition. some intermediate-term strategic issues probably limit the near-te.rn
upside in the name.
! ! I e;I
I I
I
Investment Summary
As a vertically integrated regulated utility subsidiary, !PCs
single-A rated First Mortgage Bonds represent the most
favored security class in the utility sector at present. The
bonds were received well at issuance, and have tightened
by 10 to 20 bp since. Moreover, IDACORP and Idaho Power
look good to us in terms of: a) Demonstrating that Idaho's
Power Cost Adjustment mechanism works reasonably well; b} Prudently exiting the gas and energy trading
bucinecs, which was tying up capital without :i decent
risk-adjusted retun: and c) Prudently deciding against
investing in natural gas midstream activities (which in
our view would have done no better than trading). While
we view the FMBS as a pretty good safe haven, L11ei1 <,111dll
size and the utilities' future capacity needs suggest that
upside may be limited.
Business Overview
IPC is a wholly-owned subsidiary of IDACORP, Inc. based
In Boi<,e, icJdt1u (NYSE: IDA). IDA\ market capitalization is
about $913 million, down 41% YTD.
IPC is a regulated, integrated electric utility involved in
the generation, purchase, transmission. distribution, and
sale of electric energy. IPC also owns. through a
subsidiary. an interest in Bridger Coal Company, which
<upplie s coal to IPC's Bridger generating plant.
About 95% of IPC's revenues come from customers in the
State of Idaho. IPCs territory covers 20.000 square miles
in southern an d e:i�tern Idaho (72 cities) and e;atcirn
Oregon (10 cities), with an estimated population of
873.000.
© Copyright 2002. All rights reserved. No part of this publication may be reprocucez without consent. Permission ili granted for normal and limited quotation provided that
credit is given to Banc One Capital Marketi;, Inc.
BOCM may have underwritten an offering of securities within the last three years for any company or security mentioned in this report. BOCM may mate a market in the
fixed income securities mentioned iri this report and therefore may have a long and/or short position in the securities. Although the information in this report has been
obtained from sources that BOCM believes to be reliable. we do not gua·antee its accuracy. and such information may be incomplete or condensed. All opinions and estimates included in this report constitute our judgment as of this date and are subject to change without notice. This report is for information purposes only and is not intended as an offer or solicitation with respect to the purchase er sale of any securty Investors should obtain and read the prospectus related to the securities dlscussed.
Within the: last twelve months, BOCM has received compensation for managing or co-managing a public offering of securities for Idaho Power Company. t?C/
BANC ONE CAPITAL MARKETS, INC.
(
INVF§TMENT GRADE CORPORATE§
There can be no assurance that weather patterns will
revert to normal this winter or that sufficient
IPC is re-licensing ten of lts 17 hyrlroPIPctric projects from
FERC, a process that will take eight to 15 years. Re­
licensing is not automatic. \PC must demonstrate
(generally) that it is in the public interest for \PC to
continue to no!u Ure reuc1 di licerrse.
IPC has extensive capital expenditures planned for 2001
to 2005, aggregating $629 million. Over half of that is
for transmission and distribution lines and substations.
The company expects to be able to fund all but about
$100 million of this five-year capital expenditure
program from operating cash flow.
IPUC doesn't always grant IPC everything it asks for. In
the 2001 filing, \PC requested recovery of $227 million of
power supply costs. In May, the !PUC authorized recovery
of $168 million, but deferred recovery of $59 million
pending further review. The approved amount resulted
in an average rate increase of 31.6%. After hearings, the
IPUC authorized recovery of $48 million, plus $1 million of
accrued interest, beginning in October 2001. The
rcm.:iining $11 million not recovered in r:ate� from thP Pr A
filing was written off in September 2001.
In the 2002 filing, IPC requested recovery of $255 million
of txcess power supp.!,}I. costs. IPUC granted recovery of
about $256 million of power supply costs, mostly over a
one-year period. Approximately $12 million of lost
revenues from an irrigation toad reduction program were denied, as were $2 million of other costs. IPUl. atso aeniea
a request to issue $172 million of Energy Cost Recovery Bonds (essential'y an asset backed issue) that would have
spread the recovery period across three years. As a result of
these actions by \PUC, !PC's total deferred power supply
costs in Idaho declined from about $290 million at the
end of 2001 to $218 million as of June 30. In Oregon, !PC
had about $14.7 million of deferred costs, which it began
collecting (in meaningful fashion) effective November
2001.
Challenges:
IPC is on its third consecutive year of below-average water availability for hydroelectric power. Its reliance on
purchased power remains higher than normal, forcing
IPC to fund purchases in anticipation of rate relief. \PC
relies heavily on hydroelectric power for its generating
needs and can experience a negative impact from
adverse weather, such as a low snow pack in the
ountains above IPC reservoirs. or low precipitation
I vels. As demand outstrips hydroelectric capacity, more
xpcnsivc coal and diesel fccilitiec, along with purchased
power, are needed to make up the difference.
------
Strengths,
As of 12/31/01, IPC had over 401,000 general 1siness customers. Residential customers accounted fo about
40% of total utility revenue in 2001, wilh comm rcial at
2s%. industrial 24%, and irrigation customers at 1fo.
! IPC relies heavily on hydroelectric power. It myn� and
operates 17 hydroelectric power plants and on�. natural
gas-fired power plant, and shares ownership in three
coal-fired generating plants located in oming,
Oregon, and Nevada (fueled by low-sulfur co for tah
and Wyoming). In a "normal" year, \PC's power sources
would be J6% hydro. :i:s'% ll 1c1 mal, and 11% purchased.
Investment Considerations
IPC had 11688 employees of ID/\CORP'� 1,999 full-time
tota! as of 12/31/01.
When water is plentiful, IPC has abundant, cheap power.
\PC is one of the few investor-owned utilities with a
predominantly (very low-cost) hydroelectric generating
base. augmented by relatively low-cost coal-fired plants.
IDACORP is exiting non-regulated marketing and
trading. Because of the extraordinary, but temporary, success IDACORP had in trading, \PC accounted for only
16% of IDACORP's 2001 revenues and 37% of operating income. By contrast.for the nine months ended September
30. 200J. utility onemtions accounted for 93% of consolidated revenue and 129% of consolidated operating
income.
Access to purchased power. Through interconnections
with the Bonneville Power Administration and other
utilities, IPC has access to all the major electric systems in the West, facilitating the purchase of power when its
own resources fall short. ____________ ..
The Idaho power cost adjustment (PCA) mechanis
seems to work reasonably well. Administered by th
Idaho Public Utilities Commission (\PUC), the PCA
provides for an annual rate adjustment (effective
annually on May 16) to recapture the previous year's actual increases in fuel and purchased power costs, as
well as forecast costs for the coming year. The difference
between the actual costs incurred and the forecast costs
arc deferred, with interest, and "trued-up" in the nP)(t
annual rate adjustment. The relationship between \PC
and IPUC has been generally supportive (although \PC
doesn't get everything it asks for-see below.) Idaho has
not passed legislation wttn respet.t Lu d formal
restructuring of the electric industry, and !PC's Oregon
service territory is exempt from that state's legislation.
•
December 12, 2002 Page 2
BANC ONE CAPITAL MARKETS, INC.
hydroelectric power will be available next year.
Consequently, while IPC will have an opportunity to
apply for rate relief again next spring, the outcome of
future filings, and the excess fuel and power costs that
the cornr;:rny m;iy incur in 2002 and 2003. cannot be
confidently estimated.
IPC is considering, but has not yet committed to,
investing in additional fossil fuel plants to reduce its
deficit in generating capacity. A 500MW plant might
cost $400 to $500 million.
IUACORP disclosed on September 9, 2002 that several
issues require resolution with FERC and IPUC
surrounding the "winding down" of its power marketing
operations. With respect to IPUC, the primary purpose of
the proceeding is to determine the appropriate
compensation IDACORP Energy should provide to !PC as
a result of transactions between the affiliates since
Febru a ry 2001. Matters with the FEl<C incl 11rlP· 1)
Resolution of whether or not the trading operation
properly paid the utility for use of its transmission assets;
1) Certain transactions between IDACORP Energy and IPC
(spinrung reserves and lodll rul!uwi11g �t:,viLo) vvcr c
supposed to have prior FERC approval, but did not; and 3)
The assignment of Idaho Power's marketing contracts to
IDACORP Energy in June 2001 was supposed to be
approved in advance by FERC, but prior approval was not
sought The remedies for these issues are not clear and
will not likely be known for some time. We think the
mo st likely outcome would be :iddition:il cornpans atlon
for IPC-a good thing, though perhaps offset by a
tougher stance at IPUC, which might seek to have these
gains benefit IPC's customers in the form of lower rates
in the future. There might also be fines involved,
although we would expect them to be levied at the
IDACORP level.
Rating agencies' views differ. After downgrading IPC in
March 2002. on June 27 S&P affirmed its ratings on
IDACORP and Idaho Power {both have senior unsecured
ratings of BBB+ and CP ratings of A-2 and revised the
outlook to Positive from Negative. The action was the
result of IDACORP's decision to wind down the power
marketing business at its IDACORP Energy subsidiary. an
activity that ltdll �ul>�Ldrtlidlly increased the consolidated
entity's business risk and weakened its financial profile.
While servicing existing commitments will take up to 24
months to wrap up, IDACORP will not pursue prospective customers. is reducing its trading staff. and is limiting its
maximum value at risk limits to less than $3 million.
Moody's assigned a Negative outlook on the parent
company IDACORP upon rating its $500 million debt
shelf registration on March 8, 2002. but left their Idaho
Power outlook Stable at that time. On September 10,
2002, however, Moody'� changed its outlook on Idaho
Power Company from Stable to Negative. Moody's
outlook is based on "myriad factors" including the IPUC
December 12, 2002
INVESTMENT GRADE CORPORATES
and FERC issues disclosed on September 9 (detailed
above). Moody's now believes that the execution risks
associated with the exit of the power marketing
business now carry over to IPC, and is concerned that
FERC or IPUC might take an extremely harsh stance.
Recent Results and Outlook
IDACORP recently announced that it would not pursue
its previously announced strategy of investing in natural
gas midstream processing. We view this as a positive
development. The minimum purchase size would have
been about $3) milliur,. will, "uiliLal mass" requiring a
total investment of $150 to $200 million. {The business is
volatile, and the capital can better be deployed
elsewhere, in my opinion.)
In 2001, IPC reported net income of $73 million, down
45% ($59 million) from the previous year. Operating
inrnmP fPII ahout S8n million to Sgo million. despite PCA
deferral accounting. Purchased power and fuel costs
increased more rapidly than revenues and the PCA
mechanism, and operating expenses increased modestly
(i11Lluui11!', cust.ornc r accounting system and uncollcctiblc
write-offs of $4 million; $5 million for leased diesel
generators to ensure against shortages; a $7 million
increase due to unscheduled outages at thermal plants; and $7 million higher depreciation). At year-end. IPC had
total debt/capitalization of 56%, up about 5 points from
year-end 2000. IPC's coverage ratio was 3.2x, down from
f, 111 in ,nnn
In the third quarter and nine months year-to-date. IPC
has done much better than in 2001, and has emerged as
the strength of IDACORP. Operating income for the third
quarter was $22 million, up 69% from the year-earlier
quarter, and 129% of the consolidated total. For the first
nine months, !PC's operating income of $99 million is up 36%, and constitutes 138% of the consolldateo Luldl
operating income of $72 million.
Recall that in the second quarter, IDACORP Energy, the
marketing and trading subsidiary. reported a 32 cent per
share loss. In the third quarter, IDACORP Energy
contributed $0.02 per share, versus $0.92 in the third
quarter of :1001. With +hr- November s. 2002
announcement that IDACORP Energy will exit the natural
gas business. the company will record a restructuring
charge in the fourth quarter of between $8 mil lion and
$1::5 mllllou, u1 $0.13 and $0.20 per share, for severance
benefits. non-cancelable lease liabilities, and asset
impairment.
IPCs leverage as of September 30 was 52%, down 4
points from year-end. For the twelve months ended
September 30, interest coverage was 3-3x, versus 3.2x for
all of2001.
Page 3
BANC ONE CAPITAL MARKETS, INC INVESTMENT GRADE CORPORATES
e Idaho Power Company
Moo(ly_'.s s.11.e
Al A First Mortgage Bonds
Negative Positive
$ mittions, unfe�> otherwise noted
LIM LIH Fiscal Year End; 12/31 09/30 � 1.Q.00 1.929. Qll1Q 2001 2000 1999
lbolanrP sheet Leverage
cash & cash equivalents 15 43 83 95 Long-term debt/capital (%) 38.4 40.5 45.7 46.6
Total assets 2,754 2,860 3,696 2,563 Total debt/capital (%) 52.2 56.1 50.8 52.7
Net debt/capital (%) 51.3 53.9 16.1 47.3
Total short-term debt 240 309 90 109 Debt/market cap (%) nm nm nm nm
Total long-tenn debt 672 802 809 822
Preferred stock 54 104 105 106 FFO/debt (%) 28.3 1.5 19.4 20.0
Shareholders' equity 783 766 765 728 Debt/EtlllUA lXJ ·-� :;_3 z ... ).1
Total capitalization l,750 1,981 1,769 1,764 Debt/EBITDA-capex ( x) 3.7 20.8 3.B 4.9
Other debt-like instr (OOIJ 0 0 �
Mino,ity interests 0 0 0 EBIT interest covereqe (x) 1.6 1. ;· 46 3.3
Operatinq lease expense 0 0 0 0 EBITDA Interest coverage (x) 3.3 3.2 6.4 4.8
FFO interest coverage (x) 4.2 0.2 3.0 3.0 � EBITDA - ca pex/ir.terest 40 0.8 4.1 3.1
Total revenue 859 912 836 658 e FRITnA 203 210 371 299 eciifllil.b.lib'
EB!T 98 111 278 204 Gross Margin (%) 51.7 44.5 55.5 70.8
Gross interest expense 62 66 58 62 Operating Margin (o/o) 13.6 9.9 20.] 26.2
Pretax income 38 48 223 143 EB!TDA/sales (%) 23.7 23.0 44.4 45.4
Earnings bef. non-recurring 57 28 137 97
Non-recuning items 23 50 0 0 Return on ca�<tal (o/o) 5.7 5.9 15.8 11.9
Preferred Dividends 6 6 Return on equity ( % ) 9.7 9.5 17.2 12.6
Net income lb I j l32 92 CDCTDA(T1-1tol Copit:cli:z:.ct:ion 11.6 10.6 21 0 1,; q
Cit:ib flaw &:tataneat Consolidated Dividend Payout 92.0 95.S 53.1 76.1
Gross operating cash now 258 16 175 187 Nan..:ash working capital/Revenue -2.7 12.2 1.0 3.3
Working capital changes (23) (65) (6) 31
Net operating cash flow 233 (60) 161 214
C;apiblll QY.pqodih ,,.,, ••• : 45 (157) (132) (108)
Asset sales (acquisitions) 0 0 0
Dividends (75) (75) (76) (75)
Cash excess (shortfall) 203 (292) (46) 30
Debt issuance (repayment) (61) 212 40 74
Stock issuance (repurchases) (50) 0 0 0
Other (2) (4) (1) (1) .2m � � �
Net cash increase (decrease) 122 (40) (12) 75 scneoure or oeor maturmes 27 00 50 60
fiscal year end is December 31
*For rolling 12 month period e
December 12, 2002 Page a cx1
• investor
Relations
Release
For additional
information,
please contact:
Lawrence F Spencer
Director of
Investor Relations
[phone]
[phone] (fax) a:[e-mail]
Darrel T Anderson
Vice President,
Chief Financial Officer
and Treasurer
[phone]
Dennis C Gribble
Assistant Treasurer
and Bank Contact e [phone]
FOR IMMEDIATE RELEASE
September 18, 2003
IDACORP Reduces Dividend to Strengthen
Balance Sheet
Annual Common Stock Dividend Set at $1.20 per Share
Action Driven by Growing Capital Requirements
Board Approves 160-MW Generating Project Proposal
BOISE - TaKtng a strategic step to strengtnen IDACORP'::; financial poeition and ite
ability to fund Idaho Power's $675 million, three-year capital expenditure program, the
company's board of directors today reduced the annual dividend paid on IDACORP
(NYSE:IDA) common stock.
Today's action reduces the dividend from $1.86 to $1.20. The change will take effect
with the dividend for the quarter ending October 31, which the board declared at $0.30 per
share. The dividend will be paid December 1 to common shareholders ot recora on
November 5.
"We understand the importance of the dividend to our shareowners, which made this a
very difficult decision," said Chairman of the Board Jon H. Miller. "However, we also
understand the need to invest significantly in our business over the next few years - primarily
our utility operations at Idaho Power. Our approval today of a development contract for
construction of a new power plant is a case in point."
"This strategic dividend action will improve cash flow, and help maintain a strong
credit rating while balancing the level of borrowing necessary to meet these growing capital
requirements," Miller added. "This decision also better aligns IDACORP's dividend policy and
payout ratio with industry peers."
President and Chief Executive Officer Jan B. Packwood explained that with the
closure of IDACORP's wholesale energy marketing business, the long-term sustainability of
the dividend is dependent upon the earnings and operating cash flow generated by Idaho
Power Company.
"As we stated in our second quarter earnings release," said Packwood, "Idaho Power's
earnings and operating cash flow depend on many factors, but the most significant are
weather and hydroelectric generating conditions, the ability to obtain rate relief to cover
operating costs and capital spending requirements."
Based on last winter's snow pack and current and forecasted river flows, Idaho Power
is experiencing its fourth consecutive year of below normal water conditions, which has
negatively affected cash flows. "Although the board had hoped to defer making a decision on
the dividend until 2004, the combination of lower-than-expected cash flow for 2003 and the
decision to proceed with the Mountain Home project made it prudent for us to take this action
now," Packwood said.
e Investor
Relations
Release
For additional
information,
please contact:
Lawrence F Spencer
Director of
Investor Relations
[phone]
A [phone] (fax)
�[e-mail]
Darrel T Anderson
Vice President,
Chief Financial Officer
and Treasurer
[phone]
Dennis C Gribble
Assistant Treasurer
and Bank Contact e [phone]
Pacl<Wood explalned that Idaho Power will also increase its investment in its
transmission and distribution infrastructure and its power plants - including the costs related to
the relicensing of its hydroelectric facilities, the construction of new plants, and upgrade and
replacement needs at its existing hydro and thermal power plants. He cited as an example of
the growing capital requirements today's action by the board to approve the construction of a
160-megawatt generating plant near Mountain Home, Idaho, using simple-cycle combustion
turbine technology. The project cost - including plant construction and associated
transmission system upgrades - is $61 million. Idaho Power wilt take ownership of the plant
once it's fully tested and operational.
"These requirements are the primary reason for growth in the company's capital
budget from $427 million for the years 2001 through 2003 to an estimated $675 million over
the next three years," he said. "Our coal-fired plants are approaching their fourth decade of
service and we've had to rely on them to a much higher degree in recent years because of
below-normal hydro conditions. The time has come to ensure we can make the improvements
necessary to maintain reliable electrical service," Packwood said. "These investments also
provide an opportunity to grow value for our shareowners by re-investing in the core
business."
"Today's board action is a major step in strengthening our financial position and
flexibility." he said. "An eQually important factor will be our ability to recover past investments
through fair and reasonable rates. We will be requesting authority to raise rates in Idaho later
this year, to include a request for interim rate relief. Together these actions will ensure
adequate, reliable and affordable electricity for our customers and a fair and competitive
return tor our mvestors.:
Idaho Power Dividend Declarations:
• Directors declared a quarterly dividend on the four percent preferred stock of $1.00
per share, payable Feb. 2, 2004,to holders of record at the close of business on Jan.
15, 2004.
• Directors declared a quarterly dividend on the 7.68 percent serial preferred stock,
$100 par value, of $1.92 per share, payable Feb. 17, 2004, to holders of record at the
close of business on Jan. 26, 2004.
• Directors declared a quarterly dividend on the 7.07 percent serial preferred stock,
without par value. of $1 76750 per share. payable Feb. 20. 2004. to holders of record
at the close of business on Jan. 26, 2004.
Background Information
Boise, Idaho-based IDACORP, formed in 1998, is a holding company comprising
Idaho Power, a regulated electric utility; Ida-West Energy, a manager and developer of
independent power projects; IDACORP Financial, an investment vehicle that makes
investments primarily in low-income housing projects; Ida-Tech, a developer of fully integrated
fuel cell systems; IDACOMM, a telecommunications subsidiary providing high-speed access
technologies; Velocitus, a commercial and residential Internet service provider; and IDACORP
Energy, a marketer of energy and energy-related products and services that is winding down
its operations.
Certain statements contained in this news release, including statements with respect
to future earnings, ongoing operations, and financial conditions, are "forward-looking
statements" within the meaning of federal securities laws. Although IDACORP and Idaho
Power believe that the expectations and assumptions reflected in these forward-looking
statements are reasonable. these statements involve a number of risks and uncertainties. and
actual results may differ materially from the results discussed in the statements. Important
factors that could cause actual results to differ materially from the forward-looking statements
include: changes in governmental policies and regulatory actions, including those of the
Federal Energy Regulatory Commission (FERG), the Idaho Public Utilities Commission
(IPUC) and the Oregon Public Utilities Commission (OPUC), with respect to allowed rates of
return, industry and rate structure, acquisition and disposal of assets and facilities. operation
and construction of plant facilities, recovery of purchased power and other capital
Gribble, Dennis
Standard & Poor's is pleased to provide ongoing service to the investment community.
IDACORP and Unit Ratings Affirmed; Outlook Revised- to Stable
�ation date: 03-0ct��-003 _ - - =l
• i='lllly't( s ):-----=r:ami Venkataraman, San Francisco ( 1) 415-371-5071 j
Credit Rating: A-/Stable/A-2
Rationale
On Oct. 3, 2003, Standard & Poor's Ratings Services affirmed its 'A-/A-2' corporate credit ratings on
IDACORP Inc. and Idaho Power Co., and revised its outlook on the companies to stable from positive.
In June 2003, Standard & Poor's revised the outlook on the IDACORP and Idaho Power to positive from
negative following the company's announcement that it would exit completely from the energy trading business.
The resulting improved business profile raised expectations that the company would more readily achieve
financial ratio levels commensurate with an 'A' rating over a two- to three-year period.
Standard & Poor's now expects that ratios will only meet expectations for the 'A-' rating and may ev:e�be
slightly weaker in the interim, as Idaho Power continues to recover deferred power costs and face poor water
conditions in the Snake River and lower than expected sales.
•
However, the exit from the energy trading business, the change from an average to a 70th percentile resource
planning for load and water flows. and the 35% dividend reduction announced on Sept. 18, 2003 serve to
strengthen IDACORP's credit profile. IDACORP's business profile has improved to a '4' from a '5' on a 10-
point scale, where 'I' is the least risky. Idaho Power's business profile is also a '4.'
The ratings on IDACORP and Idaho Power reflect the consistent, credit-friendly regulatory environment in
Idaho and competitive rates and production costs. The annual power cost adjustment (PCA) mechanism, first �7
authorized by the Idaho Public Utilities Commission (!PUC) in 1993, allows annual rate adjustments based un the
difference between actual and forecast power supply costs. During the year, 90% of the difference between
actual and forecast costs of the Idaho jurisdiction is deferred with interest and recovered or refunded in the next
-12-month period.
In May and October 2001 and May 2002, the IPUC raised overall rates by more than 43% via the PCA
mechanism so as to allow Idaho Power to recover the majority ofits deferred power costs incurred during the
power crisis, a time period that was shorter than even the company's own request to issue securitization bonds
that would be repaid through rates over three years. The !PUC also acknowledged Idaho Power's biannual
Integrated Resource Plan (IRP) in 2002, using the 70th percentile water flows and load conditions for resource
planning as opposed to the historical average level approach. This was an important positive change in the
planning process and significantly reduced the chances of another significant accumulation of deferred power
costs.
Idaho Power serves more than 400,000 customers in southern Idaho and eastern Oregon, which exhibit average
economic characteristics overall. The service area, particularly around Boise, has exhibited strong population
growth in the last decade of 10.1 % compared with the national average of 3.8%. Growth in the customer base
has accordingly been strong at over 2.5% annually. Given the regional importance of agriculture, income levels
remain below the national average at about 88%, while rolling 12-month unemployment is 5.7% as of July 2UU3,
the same as the national average. Food processing, lumber and mining account for about 40% of the state's
employment and contribute to the economy's cvclicality, although the last decade has seen the growth of the
technology industry in the Boise area.
Idaho Power has a favorable customer mix, with residential, commercial, irrigation, and industrial customers
accounting for 34%, 27%, 14%, and 25%, respectively, of sales in 2002. There is no significant customer
concentration, with the top customer accounting for 3.4% of revenues and the top 20 only 13.2% .
• Idaho Power served a peak load of2,963 MW in 2UU:2 from U hydroelectric plants on the Snake River and its
tributaries with a total nameplate capacity of 1, 731 MW. The company also owns interests in three coal­
generating plants, 707 MW in Wyoming, 55 MW in Oregon, and 261 MW in Nevada. Idaho Power also owns a
90 MW gas-fired peaking plant in Idaho. In an average year, hydroelectric sources provide about 57% of total
generation needs, thus significantly exposing Idaho Power to waterflow variations. The 2002 IRP, which
provides for planning based on 70th percentile load and water levels, rather than average conditions, and the
PCA mechanism, are important risk mitigants for Idaho Power.
Idaho Power had among the lowest rates in the nation prior to the power crisis. Its residential and industrial rates
today are above the state average largely due to the cumulative 46% PCA rate increase to recover deferred
power costs. Rates will decrease as a matter of course. An 18% reduction was effected in May 2003 and another
reduction is expected to occur in May 2004, although it is also expected that the decrease will be offset by a
general rate case increase. Standard & Poor's does not consider competitiveness a major issue, given the lack of
any impetus towards deregulation in Idaho. In Oregon, Idaho Power is exempt from any restructuring legislation.
IDACORP exited the energy marketing business following the sale of its business to Sempra Energy. Idaho
Power now constitutes materially all ofIDACORP's business and is the cornerstone of the company's credit
quality.
Management policy is supportive of credit quality, as reflected by the decision to exit the energy trading business
completely, aggressively settle legal disputes surrounding contracts signed during the power crisis, and decrease
the dividend payout by 35% in view of the upcoming $675 million in capital expenditures over the next three
years. e IDACORP's financial profile has rebounded since the power crisis, aided by the IPUC's decision to allow Idaho
Power rapid recovery of all its deferred energy costs by 2003. The deferrals have yet to be completed owing to ;2-'6 2
an unexpectedly warm winter in 2003 and continued poor water conditions in the Snake River. Over the next few
years, Standard & Poor's expects that cash flow coverage of interest and debt will average about 4.0x and 20%,
respectively, while total debt to total capitalization will be about 54%. IDACORP's exit from the trading a business should save operating costs. Also, the upcoming general rate case for Idaho Power, the first in 10 years,
•should enable the company to improve its earnings and cash flows. Idaho Power is expected to request a 10% to
15% rate increase.
Currently, Standard & Poor's rates Idaho Power's first mortgage bonds a notch above the corporate credit rating
reflecting overcollateraliz.ation of these bonds with utility property. In its analysis, Standard & Poor's considers
the maximum amount of first mortgage bonds that could be outstanding under the terms of the indenture. In
Idaho Power's case, this amount, currently $1.1 billion, is subject to change without bondholder approval and
only requires a board resolution authorizing an increase. Should the same occur, and the increased maximum
amount be no longer overcollateralized with utility property to a sufficient extent, the rating on the first mortgage
bonds could be lowered to the level of the corporate credit rating.
Liquidity.
A $175 million one-year revolver (decreased from $350 million in March 2003, reflecting the exit from energy
trading) and a $140 million three-year revolver at IDACORP supported $119 million in commercial paper as of
June 30, 2003. Idaho Power has a separate $200 million one-year credit facility while cash on hand was about
$20 million as on June 30, 2003.
IDACORP's liquidity position is comfortable. Debt maturities are few, at $90 million and $58 million in 2003
and 2004, respectively, and the $675 million capital expenditures over the next three years are expected to be
funded almost entirely out of operating cash flows. The $175 million IDACORP line has a covenant that requires
an EBITDA to interest ratio of 2. 75x. The ratio, as defined by the bank line documents, stood at 2.94x for 2002.
IDACORP has no material ratings-linked triggers.
eoutlook
The stable outlook reflects the complete exit from energy trading and expectations for steady earnings and cash
flows from Idaho Power over the next few years.
Ratings List
Rating
IDACORP Inc.
Corporate credit rating A-/Stable/A-2
Senior unsecured debt BBB+
Cnrnmercial paper A-2
Idaho Power Inc.
Corporate credit rating A-/Stable/ A-2
Senior secured debt A
Senior unsecured debt BBB+ e Preferred stock BBB
Commercial paper A-2
3
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@idahopower.com
•
3o
RATINGS DIRECT
Research:
Summary: Idaho Power Co
Publication date: 08-Apr-2003 Credit Analyst: Swami Venkataraman. San Francisco (1) 415-371-5071
Credit Rating: A-/Positive/A-2
Return to Regular Format
•
§ Rationale
The ratings on Idaho Power Co. (A-/Pos/A-2) derive from the consolidated credit quality of IDACORP
(A-/Pos/A-2) and its subsidiaries and reflect the expected improvement in the financial profile at Idaho
Power as the utility recovers deferred power costs from the western U.S. power crisis, a business
profile that will benefit from the company's exit from all unregulated operations, the supportive
requlatory environment in Idaho, and competitive rates and production costs. Future credit prospects are strengthened by IDACORP's decision to tocus exclusively on Its re�uloh:::u utility operations.
IDACORP has decided to exit power and gas trading at IDACORP Energy, cancelled the proposed
75% merchant, 250 MW Garnett power project, and decided not to pursue an entry into the mid-stream
g:;:ic; h11i:.inPSS
Following the exit from power marketing, the regulated utility will once again constitute the bulk of
IDACORP's business and be the cornerstone of the company's credit quality. The regulatory
environment in Idaho is supportive, with a power cost adjustment (PCA) mechanism that allows
IDACORP to share 90% of excess power costs with customers. Idaho Power expects to recover
completely by June 2003, $256 million in deferred costs it incurred during the power crisis.
IDACORP's financial profile rebounded smartly in 2002, mainly on account of deferred cost recovery
and ratios are now line with expectations for the rating. Funds from operations coverage of interest and
debt to total capitalization stood at 5.5x and 52% respectively in 2002. Given that the large contribution
to cash flows from PCA collections ($164 million in 2002) will be reduced in future years, cash flow
interest coverage is expected to drop from the lofty levels of 2002, but will still remain in line with
expectations for the rating.
Liquidity.
IDACORP's liquidity position is comfortable. A $175 million one-year revolver (decreased from $350
million in March 2003, reflecting the exit from energy trading) and a $140 million three-year revolver
at IDACORP had $75 million and $140 million respectively available as of April 2003. Idaho Power
has a separate $200 million one-year credit facility with $189.5 million available as of Dec. 31, 2002
while cash on hand was about $43 million as of Dec. 31, 2002. The $175 million IDACORP line has a covenant that re quire e on EBITDA to interest ratio of 2. 75. Thp r::itin stood al 2.94x as of Dec. 31.
2002.
Debt maturities are small, at $90 million and $58 million respectively, in 2003 and 2004. Idaho
Power's recent $300 Million S-3 shelf filing would be utilized to rennance these bonds and to pay
down others as dictated by market conditions. IDACORP has no material ratings linked triggers.
Liquidity needs in the trading business are linked to credit ratings but are expected to wind down
�---..::i.:::;.u:..:::ickly over the next year. ·--------�--- .... -., .. � Outlook ··- ..
ThP rmsitive outlook reflects the expected improvement in IDACORP's consolidated financial profile on )
account of the collection of deferred power costs as well as the expected decrease in business nsk as
the firm completes its exit from all unregulated operations . -- -----------·--------------
--· -�--�- -------
•
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•
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FFO I Avg Total Debt
FFO Interest Coverage
Pre Tax Interest Coverage
l otal Uetlt I Total Capita!
Operating Cash
Non Recourse LTD Int Exp (aft le
Trust Preferred Div Exp (aft tax)
Adj Op Cash
Total Debt Prior Year (from Spillw
Adj Total Debt
Average Total Debt
FFO I Avg Total Debt
Adj Op Cash
Adj lntcrccl Expcnce
Op Cash Plus Interest Exp
Interest Expense (excl pref div)
Non Recou,�e LTD 1111 c,.f.i
Trust Pref Int Exp Adj
Adj Interest Expense
FFO Interest Coverage
COIT
AFDC - Equity
EBIT Less l,FDC- Eq
Adj Interest Expense
Pre Tax Interest Coverage
LT Debt
Less IC Financial NRD
Adj LT Debt
Current Maturities
ST Debt
Adj Total Dehl
Adj Total Debt
Common Equity
Preferred
Total Capital
Total Debt I Total Capital
S&P Ratios (Business Position 4):
FFO I Avg Total Debt
FFO Interest Coverage
Pre Tax Interest Coverage
Total Debt I Total Capital Weighted Average
BBB
A
BB
BBB
BBB
BBB
>A
BBB
BBB
DOD
BBB
>A
BBB
BBB
BBB 33
IDA-9
•
FINANCIAL TARGETS
FFO I TOTAL DEBT
Business Position AA A BBB BB B
I 20.0 16.5 16.5 12.5 12.5 7.0 < 7.0 . - -
2 25.0 21.0 21.0 16.0 16.0 10.S < JO 'i - -
3 31.5 26.0 26.0 20.0 20.0 14.0 14.0 9.5 9.5 4.0
4 36.5 30.5 30.5 24.5 24.5 17.5 17.5 12.0 12.0 6.0
5 40.0 33.0 33.0 27.0 27.0 20.5 20.5 15.0 15.0 7.5
6 47.0 39.0 39.0 31.0 31.0 22.0 22.0 16.0 16.0 8.5
7 56.0 47.0 47.0 36.5 36.5 24.5 24.5 17.0 17.0 9.5
8 66.0 55.0 55.0 42.5 42.5 27.5 27.5 18.5 18.5 11.0
9 - . 64.5 49.5 49.5 32.0 32.0 22.0 22.0 12.5
10 - . 78.0 60.5 60.5 39.0 39.0 28.0 28.0 17.5
FFO INTEREST COVERAGE
Business Position AA A BBB BB B
1 3.1 2.6 2.6 1.9 1.9 0.9 < 0.9 - -
2 3.9 3.3 3.3 2.5 2.5 1.5 < 1.:, - -
3 4.5 3.9 3.9 3.1 3.1 2.1 2.1 1.3 1.3 0.5
4 5.1 4.5 4.5 3.8 3.8 2.7 2.7 1.8 1.8 0.9 :, ::>.4 4.IS 4.11 4.0 4.0 3.0 3.0 2.1 2.1 1.1
6 6.6 5.7 5.7 4.5 4.5 3.1 3.1 2.2 2.2 1.2
7 8.4 7.0 7.0 5.1 5.1 3.3 3.3 2.3 2.3 1.3
8 10.2 8.J 8.3 5.9 5.9 3.5 3.5 2.4 2.4 1.5
9 - - 9.5 7.1 7.1 4.3 4.3 2.9 2.9 1.8
10 - - 11.3 8.6 8.6 5.3 5.3 3.6 3.6 2.3
PRETAX INTEREST COVERAGE
Business Position AA A BBB BB B
l 2.8 2.4 2.4 1.8 1.8 0.8 < 0.8 - -
2 3.4 2.9 2.9 2.3 2.3 1.3 < 1.3 - -
3 4.0 3.4 3.4 2.8 2.8 1.8 l.8 1.1 l.l 0.3
4 4.6 4.0 4.0 3.3 3.3 2.2 2.2 1.3 1.3 0.5
5 5.0 4.3 4.3 3.5 3.5 2.4 2.4 1.5 1.5 0.6
6 6.2 5.2 5.2 4.0 4.0 2.6 2.6 1.6 1.6 0.7
7 8.0 6.5 6.5 4.7 4.7 2.8 2.8 1.8 1.8 0.9
8 9.9 8.0 8.0 5.5 5.5 3.0 3.0 2.0 2.0 1.1
9 - - 9.1 6.6 6.6 J.7 3.7 2.5 2.5 1.4
10 - - 11.1 8.4 8.4 5.0 5.0 3.3 3.3 1.8
TOT AL DEBT I TOT AL CAPITAL
Business Position AA A BBB BB B
1 50.5 55.U 55.U 60.5 60.5 67.5 > 67.5 - -
2 46.5 51.0 51.0 56.5 56.5 63.5 > 63.5 - -
3 42.0 47.5 47.5 53;0 53.0 61.0 61.0 67.0 67.0 74.0
4 37.5 43.0 43.0 49.5 49.5 57.0 57.0 64.0 64.0 72.5
5 36.0 41.5 41.S 47.0 47.0 55.0 55.0 62.5 62.5 71.0
6 32.5 39.5 39.5 46.0 46.0 53.5 53.5 60.5 60.5 69.0
7 30.5 37.5 37.5 45.0 45.0 52.5 52.5 59.5 59.5 68.0
8 28.0 35.0 35.0 43.0 43.0 51.5 51.5 58.0 58.0 66.0
9 - - 30.0 39.0 39.0 47.5 47.5 54.0 54.0 61.5
10 - - 24.0 33.0 33.0 40.5 40.5 46.0 46.0 53.0 ...
Standard and Poor's Corporate Credit Risk Analysis
Overall Rating Structure and Process
S&P Rates Issuer's overall credit worthiness and also specific debt instruments - over 30,000
current ratings.
:.,. Corporate credit rating (CCR)
>"" Sovereign rating
:.,. Specific Debt Instrument
o Likelihood of default
o Nature and provisions of obligation
Outlook is given for all long-term ratings to assess potential direction over 1 - 3 years
Credit Watch focuses on a possible short-term (90 days) change
Rating Scales
TnvP<:tmPnt (.;r;:irlp:
Non-Investment Grade:
Debt in Selective Default:
AAA
AA
A BBB BB
B
CCC cc c
SD/D
- 'Highest Rating'
- 'capacity to meet financial obligation is strong'
- 'Adequate protection'
'Faces uncertainties'
- 'Likely to be impaired'
- 'Vulnerable to non-payment'
Outlook: Positive
Negative
Stable
Developing
Credit Watch: Positive
Negative
Developing (such as a merger)
Market Statistics
Global Corporate Rating:
Ratings Process
64% Investment Grade
36% Speculative Grade
1. Ratings request and document preparation
2. S&P Analytical team prepares research and analysis
3. S&P Analytical team meets with management
4. S&P Committee decides and issues ratings (Committee is odd-numbered)
5. A possible appeal is submitted by the issuer
6. S&P continually watches issuer news
•
•
Ratings Methodology
Business and financial risk are both analyzed in an equally weighted, comparative process to
determine a final rating. The business risk determines the appropriate level of financial risk as
benchmarks vary greatly by industry.
Industry Characteristics
o Strength of prospects
o Industry structure
Competitive Position
o Basis of Competition
o Market Size and/or growth potential
o Market share and position
Management
o Track Record
o Business Strategy
o Controls/Information system
Financial Risk Analysis
o Five vears of audited historical data alone with 2 -3 year of forecast
o Ratios should reflect ongoing operational profitability
o Analytical focus on: policy, earnings protection measures, Cf
adequacy, flexibility, and capital structure
o CF is King!!!!!!!
o Key Ratios:
o Total Debt/capitalization
u funds from Operetions (FFO)
o EBITDA Interest Coverage
o FFO/Total Debt
o Free Operating Cash Flow/ Total Debt
o Total Debt/EBITDA
•
xanngs Denrunons
CREOITWATCH
CreditWatch highlights the potential direction of a short- or long-term rating. It focuses on
identifiable events and short-term trends that cause ratings to be placed under special
surveillance by Standard & Poor's analytical staff. These may include mergers,
recapitalizations, voter referendums, regulatory action, or anticipated operating
developments. Ratings appear on CreditWatch when such an event or a deviation from an
expected trend occurs and additional information is necessary to evaluate the current
rating. A listing, however, does not mean a rating change is inevitable, and whenever
possible, a range of alternative ratings will be shown. CreditWatch is not intended to
include all ratings under review, and rating changes may occur without the ratings having
first appeared on CreditWatch. The "positive" designation means that a rating may be raised; "negative" means a rating may be lowered; and "developing" means that a rating
may be raised, lowered, or affirmed.
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DUAL RA TINGS DEFINITIONS
Stanctara & Poor's assigns ·auar ratings to all debt Issues that have a put uplluu u,
demand feature as part of their structure. The first rating addresses the fikelihood of
repayment of principal and interest as due, and the second rating addresses only the
rlP.mann fP.atmP. ThP. Iona-term debt rating symbols are used for bonds to denote the tone­
term maturity and the commercial paper rating symbols for the put option (for example,
'AAA/A-1+'). With short-term demand debt, Standard & Poor's note rating symbols are
used with the commercial paper rating symbols (for example, 'SP-1+/A-1+').
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INSURER FINANCIAL ENHANCEMENT RA TING OEFINITIONS
A Standard & Poor's Insurer Financial Enhancement Rating is a current opinion of the
creditworthiness of an insurer with respect to insurance policies or other financial
obligations that are predominantly used as credit enhancement and/or financial
guarantees. When assigning an Insurer Financial Enhancement Rating, Standard & Poor's
analysis focuses on capital, liquidity, and company commitment necessary to support a
credit enhancement or financial guaranty business. The Insurer Financial Enhancement
Rating is not a recommendation to purchase, sell, or hold a financial obfigation, in that it
does not comment as to market plice or suitability for a particular investor.
Insurer Financial Enhancement Ratings are based on information furnished by the insurers
or obtained by Standard & Poor's from other sources it considers reliable. Standard &
Poor's does not perform an audit in connection with any credit rating and may, on
occasion, rely on unaudited nnanclal Information. Insurer Financial E11hanctm1tml Rc:!lirrys
may be changed, suspended, or withdrawn as a result of changes in, or unavailability of,
such information or based on other circumstances. Insurer Financial Enhancement Ratings
are based, in varying degrees. on all of the following considerations:
1. Likelihood of payment-capacity and willingness of the insurer to meet its financial
commitment on an obligation in accordance with the terms of the obligation;
2. Nature of and provisions of the obligations; and
3. Protection afforded by, and relative position of, the obligation in the event of
bankruptcy, reorganization, or other arrangement under the laws of bankruptcy and
other laws affecting creditors' rights.
Insurer Financial Enhancement Ratings
AAA
An insurer rated 'AAA' has EXTREMELY STRONG capacity to meet its financial
ragt: .J u1 o
37
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Kaungs uetmmons
commitments. 'AAA' is the highest Insurer Financial Enhancement Rating assigned by
Standard & Poor's.
AA
An insurer rated 'AA' has VERY STRONG capacity to meet its financial commitments. It
differs from the highest-rated insurers only in small degree.
A
An insurer rated 'A' has STRONG capacity to meet its financial commitments but is
somewhat more susceptible to the adverse effects of changes in circumstances and
economic conditions than higher-rated insurers.
BBB
An insurer rated 'BBB' has ADEQUATE capacity to meet its financial commitments.
However, adverse economic conditions or changing circumstances are more likely to lead
to a weakened capacity of the insurer to meet its financial commitments.
Insurers rated 'BB', '6', 'CCC', and 'CC' are regarded as having significant speculative
characteristics. 'BB' indicates the least degree of speculation and 'CC' the highest. While
such insurers will likely have some quality and protective characteristics, these may be
outweiohed by large uncertainties or major exposures to adverse conditions.
BB
An insurer rated 'BB' is LESS VULNERABLE in the near term than other lower-rated
insurers. However, it faces major ongoing uncertainties and exposure to adverse business,
financial, or economic conditions that could lead to the insurer's inadequate capacity to
meet its financial commitments.
B
An insurer rated 'B' is MORE VULNERABLE than the insurers rated 'BB', but the insurer
currently has the capacity to meet its financial commitments. Adverse business, financial,
or economic conditions will likely impair the insurer's capacity or willingness to meet its
financial commitments.
CCC
An insurer rated 'CCC' is CURRENTLY VULNERABLE, and is dependent upon favorable
business, financial, and economic conditions to meet its financial commitments.
cc
An insurer rated 'CC' is CURRENTLY HIGHLY VULNERABLE.
Plus(+) or minus(-):
Ratings from 'AA' to 'CCC' may be modified by the addition of a plus or minus sign to show
relative standing within the major rating categories.
R
An insurer rated 'R' is under regulatory supervision owing to its financial condition. During
the pendency of the regulatory supervision the regulatorG may have the power to favor one
class of obligations over others or pay some obligations and not others. Please see
Standard & Poor's issue credit ratings for a more detailed description of the effects of
regulatory supervision on specific issues or classes of obligations.
N.R. • An issuer designated N.R. is not rated.
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Ratings Definitions
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• RA TING OUTLOOK DEFINITIONS
A Standard & Poor's Rating Outlook assesses the potential direction of a long-term credit
rating over th9 intermediate to longer term. In detP.rminino a Rating Outlook. consideration
is given to any changes in the economic and/or fundamental business conditions. An
Outlook is not necessarily a precursor of a rating change or future CreditWatch action.
• Positive means that a rating may be raised.
• Negative means that a rating may be lowered.
• Stable means that a rating is not likely to change.
• Developing means a rating may be raised or lowered.
• N.M. means not meaningful.
Regulatoty Dtsciollures Privacy Notice Torm, of UH Dllclalmer She Map sne Feedback
Cop)<igt,t e standard & Poor's, 1 dvision '11 The MeGntw-Hitl Companie•. Inc. All ngt,ts reserved .
•
•
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IMPORTANT: PLEASE SEE CONFLICT DISCLOSURES AND ANALYST CERTIFICATION IMMEDIATELY ATTHE END OFTHETEXT OF THIS REPORT.
DEUTSCHE BANK DOES AND SEEKS TO DO BUSINESS WITH ISSUERS COVERED IN ITS REPORTS. /lS A RESULT INVESTORS SHOULD BE
AWARE THAT DEUTSCHE BANK MAY HAVE A CONFLICT OF INTEREST THAT COULD ADVERSELY AFFECT.THE OBJECTIVllY OF ITS REPORTS.
__ · ._ . Deutsche Bank .. ·I• ·•.. Moody1s· · -• ·:"-""W>_ • . - S&P .•••.• - •
. . Senior �enior Corporate _ .
· Secured Unsecured \ Secured Unsecured · _ ! Secured Credit Unsecured
Issuer . . Rating .Rating Outlook Rating · Rating. Outlook . Rating Rating Rating Outlook "' ) -"" -
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888 S A S
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Robert Rubin 212 250-5403
[e-mail]
Steph811 Levine 212 250-2891
[e-mail]
Deutsche Bank
A3 S A2 s
Baa3 s
A3 s Baa2 s A2 s A- A2 s A-
Baa3 s Baa2 s BBB Rrt.=i1 s A- A3 WN BBB+
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Baa2 s Baa3 WN BBB Baa2 s A3 s BBB Baa1 s A- Baa1 WN A- A3 N A-
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Baa1 s A3 WN A Baa1 s A-
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Baa2 s Baa3 s
Baa1 s A-
Baa2 s Baa3 s BBB+
Bal s BBB- Baa3 s BBB+ Baa3 s BBB+ Baa3 N BBB
Baa2 s
Baa1 s
Baa2 WN A1 s A A2 N BBB+ A2 N A
A2 s A A2 s A+ Baa1 s Baa2 s BBB Baa1 s A A3 WN BBB+ Baa2 s BBB
A3 s
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A3 N
tnsuesseu Watch Positive Watch Negative
Dis WP WN
A1 A1
A3
A3 A3
A2
A2 A3
A1 A1
A2 A2 Aa3
Aa3 A1
A2 A1
Baa1 A3 A2 Baa1
Baa2
Baa3 Baa2 Baa2 Baa2
Baa2
Baa1 A1 A2
Baa3 A1
A3
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RATINGS CARD
s s s s s s N N s s <; N
N s N s ::, s s s s s s N p s s s s N s s s N
N s s
3 s s s s s s s s s s s s s s s s s s s s s s s
Lower BBB Middle BBB Middlo BBB Upper BBB
Lower BBB Lower A Middle A lower A Lower A
Middle BBB
Lower BBB Middle BBB Middle BBB Middl<> BBB
Lower A Middle BBB Upper BBB
Lower A
Middle A Lower A
Upper BBB
Middle BBB Upper BBB
Upper BBB
Middle BBB Lower BBB
Upper BBB
Upper BBB Middle BBB
Miuuit, BBB Middle BBB Middle BBB Middle BBB Middle BBB
Upper BBB
Middle BBB
Lower BBB Middle A lower A lower A
Lower A Middle A Middle A Middle A Middle BBB Mirl<11A BBB Middle BBB Middle BBB
Upper BBB
Middle BBB Upper BBB Milhlit,A
Upper BBB
Middle BBB Middle A
Lower BBB Middle BB
Upper BBB Middle BBB Lower A LowerA
Lower A
Upper A Middle A
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Middle A Middle A
Upper BBB Lower A Upper A
Upper A Upper A Upper A
Upper BBB lll'f'Ar RRR Upper BBB
Upper BBB
Upper BBB
Upper BBB Upper BBB Upper BBB Upper BBB
Upper BBB Lower A
Upper BBB Upper A
Upper BBB Uppor 999 Lower A
Middle BBB Middle A
Middle A MlddleA Upper BBB
Upper BBB
Upper BBB
Middle A
Dominion Resources
DTE Energy Duke Capital
Duke Energy
Energy East Entergy Arkansas
Entergy Corp. Enteigy Gulf States Entergy Louisiana Entergy Mississippi Entergy New Orleans
Exelon
Exelon Generation
FirstEnergy Florida P&L Florida Power FPL Group Capital
FPL Group, Inc. Georgia ftlwer Gulf Power Indiana Gas Indiana Michigan Power
lntor�t::ito P&L Jersey Central P&L Kentucky Power
KeySpan Energy
Metropoitan Edison Michigan Con Gas MISSISSlppi POwer
National Fuel Gas I I
Symbols/Legend: I
DBS! upgrade :s stame OUTIOOK l DBSI downgrade N Negative Outlook P Positive Outlook D Developing/Uncertain Ou ok
Bolded ratlngs/let1ars signify agency change from previous month.
AEPTexas North Co. Alabama Power
Alliant Energy Corp. Alliant Energy Resources
Ameren Ameren Generating AmerenCIPS
AmerenUE
American Electric Power Appalachian Power Arizona PS Atlantic City Electric
Avista Baltimore G&E Boston Edison Carolina P&L Central Maine Power Cincinnati G&E
Cinergy
Cleveland Electric Illuminating Columbia Energy Columbus Southern Power
Commonwealth Edison Conectiv Connecticut L&P
Consolidated Edison
Consolidated Edison of NY Consolidated Natural Gas
Constellation Energy Group Delmarva P&L Detroit Edison
August 29, 2003
•
• Hober L Rubin
Stephen Levine
212 250-5403
212 250-2891
[lectric Utilitiee Rotingo Cord Doutcche Bank I/I
- - _ - · Deutsche Bank ! Moody's -J . · S&P - _- ---------------------- - -r-----·-------- : - I Senior · - l Senior_ Corporate _ -
- _ Secured Unse.:ured ·.: - Sei:ured JJn:.ecured, ; J,iecured Credit Unsecured
: Issuer _ _ - • _Rating" Ratltig Out:look Bating ':Rating . 'outlook trc Rating 00 Rating Cc Rating : Outlook
August29,2003
NiSource Finance Corp. i.Dwer BBB s Baa3 s BBB BBB s
NiSource Inc. Lower BBB s BBB s
Northeast Utilities Middle BBB p Baa1 N BBB+ BBB s Northern Indiana PS Upper BBB Middle BBB s Baal Baa2 s BBB+ BBB BBB s Northern States P=er- MN Middle BBB Lower BBB p A3 Baal s BBB+ BBB BBB- WP
Northern States Power· WI Middle BBB Lower BBB p A3 Baa1 s BBB+ BBB+ BBB WP
NSTAR Lower A N A2 s A A- s NY State E&G Middle A lower A s Baa1 Baa2 s A-- BBB+ BBB N Ohio Edison Upper BBB Middle BBB s Baa1 Baa2 WN BBB WN Ohio Povver Upper BBB Middle BBB s A3 A3 s BBB BBB BBB s orange & aooaeoo Mi<.l.Jl.,A :3 A1 N A A s PECO Energy Middle A Lower A s A2 A3 s A A-- BBB+ s Pennsylvania Electric Upper BBB Middle BBB s A2 A3 WN BBB+ BBB 888 WN
PEPCO Holdings Inc. Middle BBB N Baa1 WN BBB+ BBB WN
Pinnacle West Capital Lower BBB s Baa2 s BBB BBB- s Potomac Electric Power Upper BBB Middle BBB N A1 A2 WN A-- BBB+ BBB WN PPL Capital Funding Lower BBB s Baa3 s BBB- N
PPL Corp. Lower BBB s Ba1 s BBB- N PPL Electric Utilities Upper BBB Middle BBB s Baa1 Baa2 s A-- A- N PPL Energy Supply Lower BBB s Baa2 s BBB BBB N
Progriu;c; l=nP.rQY Middle BBB s Baa2 s BBB+ BBB N PS E&G Lower A Upper BBB s A3 Baal s A-- 1:11:!B :,
PS Enterprise Group Middle BBB s Baa2 WN BBB BBB- s PS of Colorado Middle BBB Lower 81:!B p Baa1 Baa2 s BBB+ BBB BBB· WP PS of New Hampshire lower A Uppsr BBB p A3 Baal s BBB+ BBB+ s PS of Oklahoma Upper BBB Middle BBB s A3 Baa1 s BBB BBB BBB s r-:,t:u Energy HOKJlngs Luv� eee N OaaO W>I DD- DD- s PSEG Povver Middle BBB s Baa1 WN BBB BBB s PSI Energy Upper BBB Middle BBB s A3 Baa1 s A- BBB+ BBB s Puget Sound Energy Middle BBB lower BBB s Baa2 Baa3 N BBB BBB- BBB- s Rochester G&E Middle A Lower A s Baa1 Baa2 s BBB+ BBB+ N San Diego G&E Middle A Lower A N Al A2 s A+ A+ s
SCANA Upper BBB s A3 s A· BBB+ s
Sempra Energy Upper BBB N Baa1 s A- A· s South Carolina E&G Middle A Lower A s A1 A2 s A- A- BBB+ s Southern California Gas Middle A lower A N Al A2 s A+ A+ A s
Southern Companl Lower A s A3 s A A- s Southern Indiana G E Upper A MKIOleA :, A,j eaa I s A- A- 600,- N Southern Power Company Upper BBB s Baal s BBB+ BBB+ s Southvvestem Electric Power Upper BBB Middle BBB s A3 Baal s BBB BBB BBB s Southwestern PS Middle 888 Lower Bl:!B p Baal s BBB BBB WP System Energy Resources Upper BBB Middle BBB s Baa3 Bal s BBB· BBB- BBB- s Tampa Electnc Lower A Upper BBB s A3 Baal s BBB- BBB- BBB- WN Toledo Edison Upper BBB Middle BBB s Baa2 Baa3 WN BBB BBB BBB· WN Vectren Corp. Upper BBB s A- N Vectren Utility Holdings Upper BBB s Baa1 s A· A- N Virginia Electric & Power Middle A lower A s A2 A3 s A- A- BBB+ s Western Massachusetts Electric Lower A Upper BBB p A3 s BBB+ BBB+ s WISCUH�ill Eh:-Jl.;U le Plwvt:t Lower AA Upper A N Ao2 Ao3 WN A- A- A. s
Wisconsin Energy Mid<fe A N A2 WN BBB+ BBB+ s Wisconsin P&L Lower A Upper BBB s A1 A2 s A+ A A- s
High Yield
Allegheny Energy Middle BB N 82 WN B CCC+ N Allegheny Energy Supply Lower BB N 83 WN B CCC+ N
AQuila Lower BB N Caa1 N B B B N CenterPoint Energy Middle BB N Ba1 N BBB BBB· s CenterPoint Energy Houston L=er BBB Upper BB s Baa2 Baa3 s BBB BBB s cemerPoJm Energy Resources luwt::1 aaa :3 Oo1 N 99B 999 s
CMS Energy LO"/\ler BB N 82 83 s BB B+ N Consumers Energy Upper BBB Middle BBB s Baa.., Ba1 s BBB- BB B+ N
Edison International Lower BB p 83 s 8- B· D Monongahela Ftiwer Middle BBB lower BBB N Bat 8112 WN BB- B 8- N Nevada. f1ower LOY.'Or BB Dictr�cod N Ba?. R1 s RR R+ 8- N Oncor 8ectric Delivery Middle BBB Lower BBB N Baa1 Baa2 s BBB BBB BBB· N Potomac Edison Middle BBB Lower BBB N Bat Ba2 WN BB· B 8- N Sierra Pacific Power Lower BB Distressed N Ba2 Ba2 s BB B+ B- N
Sierra Pacific Resources Distressed DIS 82 s B+ B- N Southern California Edison Middle BB lower BB D Ba2 Ba3 WP BB BB B+ D TECO Energy Middle BB s Bal s t:l!:lt:1- tit!+ WN:;o
1XU Middle BB s Bal N BBB BBB- N,- West Penn Power Middle BBB Lower BBB N Bat WN B B N Xcel Energy Middle BB p Baa3 s BBB BBB- WP
Symbols/Legend: • DBSI upgrade s Stable Outlook Dis Distressed Holding companies are highlighted DBSI downgrade N Negative Outlook WP Watch Positive p Positive Outlook D Developing/Uncertain Outlook WN Watch Negative
Balded ratings/letters signify agency change from previous month.
2 Global Markets Research �1/
Except[JorfJJheCECONOMICICOMMENT,flhisfinateriafrbas[lleenlpreparedfbyfJherFixedrJncomeriradinglJleskiandl1sO
not\lhe!/lroduct\lJI\Jhel/FbcedtklCGlnelResearchLOepartment.u
MediumrTermr:Notec&CCapitalrMarketsrJJpdate
forfJherweekr1!mdingrJFriday, CSeptemberr12th, [20030
0
D
U.S. i.J"reasurytMarketu
Last Fri. Mon. Tue. Wed. Thu. Fri. Wk. Chg.
3M[]J80RD 1.1422 1.14 1.14 1.14 1.14 1.14 -0.0022
2yru 1.722 1.761 1.689 1.632 1.696 1.621 -0.101
3yru 2.272 2.344 2.244 2.161 2.244 2.139 -0.133
5yro 3.269 3.345 3.251 3.144 3 ?53 3 14 -0 129
10yrO 4.349 4.428 4.357 4.273 4.316 4.254 -0.095
30yr[{5.375%!of[2/31)[ 5.189 5.264 5.227 5.154 5.205 5.16 -0.029
DJIAC 9503.3 9586.3 9507.2 9420.5 9459.8 9471.6 -31.7
LJ
Economicl£ommentarvuu
i,I·itlillt•tM -0.24
0.019
0.179
0.404
0.438
0.382
1130.0
PlentytofLIDemand, Lbuti.lf eWLJobsu
I hececonom1clhewsLUnaerscoreal.ltleLmessageLOfl.ltlet.pr1orLWeek: Orhec:economy oscgrowlng rrast, Cbutrnotcrastc::enough non generatet.empl oym entigai ns. L©n LtheLdem an dtside, Lth el.Situation I.isl.rosy. lb.lthough tmtal l.11etai It.sales unseimuch I.Less ttnatexpected LJ
inCAugust, ElhelJ:lownsideCsurpriserJyasetnostfy[)n ElheCilom inal!JlalueCbfCSurging!JlehicleCSales. [Excluding!Jlehicl es, Ctetai I csal O
increased[0.7%[)nCAugust[]rtopcan[]Jpward-revised[0.9%[ljainOnQJuly.rupward[Jevisions[loCbothQlunecandQJuly[JlushedllheD annua11zedl.ltlira-quarter1.1renaL1orl.ltleL£omponentLUseouot..eSt1matectotalcpersona1cconsumpt10nQwhlchcsLrlp5ruutct,uildinyo
materialsCBsrJyellD:ls[lfehicles)above010%.CFiscalCstimulusQmdetapid(ljebt[ljrowthOlppear[lo[be0uelingE1he[Jise0nCSales­
suggestinglihat[JurtherClarge(£1ainsOhmetaillsalesCtnay[F>roveOlo�emnoreCillifficult. ITher:Fed's[lllowl])f[JIJnds(lteportlshowed[Jhato
householdCillebtlc:li mbedratraCI 0. 9% [year-over-year[pacel1h flhelsecondlJlluarter. lllJpllblhow, r1hisCillebt�rowth masmotllllriven[lllpO householdD:lebtCServiceeburdensClJecauseOnteresto-atesdlave[been aalling. [With O-atescstabilizi ng, Ohowever, ClheD:;urrento
borrowing[jbace[lnpliesi:aCilapidCilisel1hrnouseholdli1ebtlservicelburdens.rMost!Dkely,[Jhis[Sl{ill!IioUoccur[f)ecauseiliouseholds!WillD
prudentfylSlowi.Jhe1.pacel.11lfltheirLl!>orrowing. tJ'helirnprovementl.ini..Cllemandlisi..alsot.evidentl.inltheWulyllradel.lleport.t.61.1thoughllheu
trade(ljeficitiJVidenedCslightfy[lo[$40.3CbillioniJrom[$40.0[1>illionunQJune,l1heeteal[lrade[balance[}vascstillCilarrowerl1han[lheO secondt.qUi:ff Lt::1 u:tvt::1 c:tyt::, ll>uyyt::Slir 1yi.ll 1c1li.lJ crut::llJ;uul uUJ;u1 ,Lt il.JulelJllo::.ilivcly 1.b;,tgrowthlthi::,tqu,utcr.11Jloth umportetandtexpcrteuoeeti sharply. [!Exports[iiavecmow[Osen Cilapidlyl1brflhreelmonthsl1hi:a!i'.ow-alsi gn [Jhatlilemand lDutsi de[JhelllJSOiasialsolstrengthened. D
On Llhell.abonsi de, Lthel.!llatautontinueltlol.disappoint. Llhiti al utlai msl.llosel.ll>yll, 000 l1lo 1.422, 000 Lin Lthell.atestl.lNeek, tpulli ng Lthelfiour­
weeketnovi ngcaverage(]Jp [lo�07, 250, CtnoreE1han[J O, 000 [BboveE1h e[lrough Cteached On etnid-August. CContinuing [];lai msfalsofl
driftedOhigher, [l>ut[Breestill CbelowElhelJevelsCteached[)n l:May[BndQlune. IThese(ljataCSuggestE1hatat0s[looCSoonl1ocanticipateO
meaningfulOmprovement[JnctheOnonthly[):>ayrollCemployment(ljata.arhe[):>roducer[):>riceaeportOorCAugustrJyas[predictably[Il]
boring, Ohotwithstanding[lhe[]ecent[];harp[l)unupOh Utommodity[prices. r:AtiJher:finished�oodsc:tevel, atlcreasesOh i:energy(Jbriceso and, []o ra Oesserlllxtentllood [jl)ri ces, raccounted[llor [yirtual lyl:al I Lil>f flhe ClD. 4 % [ihcrease[ih r:Au gust; [lhel]:or eOhdexmose[]mlyClD. 1 % . o
Li kcwi$C, Elhe[]:;orodhdox[])f[partly[proc�od[(intermediato) (Sood51J!oseCll>nlyaD.1 %. roverl:Jlhe(Jbast[3ix0lnonths, [lhisr:lhdcxOhasD changedCiielatively!Dttle. o Thei1fOMC[lo[Malntaln[D')e[Statusat>uoo
WeCexpectOittfeO::hangeortoiextrJyeek'sCFOMCetneeting.CPolicyewillctemain[JockedlJ>nOholdcandctheCbalancelJ>fcthe[JisksO statement[willu!emaincasymmetricl])verall,[Withr:FedLI!>fficials[Worriedl:lllbout[]he[iliskOlhat[Jhe[]lisinflation(l,rocessi:eouldrj,ersist.o TheLStatementUsLJikelyLtoLbeL!weaked, LbutLI>nlyLmodestfy. LF edLI>fficialsl.Will LJi kelyL.acknowledgeL.theLStrengtheningLI>fLfin alu
demand. [However, �ey[Blso(]vill [J>ointl10Elhei:lackl])f!Jmprovement0h Olhei:labor[]narketC1:ls[B[)Jstification llorElhecasymmetricO
bal anceLJDfllleutisksLStatement. tJ'heutoncludingllinelkom i.JtreWuneLStatementliSLllkelylto LbeLnetained: LlniNlesel.Jtircumstances, u
thclJCommittecrJx,/iovoer/hatr:po/icyr;&ccommodationlDan(bo[maintainodf!Drfa[1;onsidorablo[poriod. llh !fact, [IF edCil>ffi cials [lnay[Wish D
tolDesh[Jhis[i)ut[Sl{ith1WhatllheyJmean[lpy[Ihe1WordClconsiderable"[aivenllhelmarket'sllliewr1hatlllghteningusillkelyllbi:aommenceO
byOlhe!Secondi]juarter[lbfC2004.IThernecentiaommentsLI!>f[lfedi:mfficials[suchi:asCBovemorllBemankelsuggestlihatlihemnonetaryo
aJthoritiesCl!lomotr:anticipateil!lavingl1bl:startflhe!Dghteningl1tycie[Soon. D
Anothor£$8711Bllllon!J:foro .•• o
... AndlsoonatlWilli:add[Upl1bCilealJmoney, l1b[j,araphrasemrte[$enator[!Everett[1J)irksen.IThe!size[i)f[l?residentllBush's[ilequestCToro
cW1cadditional[$670l>illionlll>f[JIJndsCTorlltaq, !Whichl1hcludesr1hei:aostsrassociated[Sl{ithlkeeping[a0arge[c:Qntingenti:Ml1toopslihereo ElldCforetebuilclingElheOraqi [)nfrastructure, cstunnedetnanyl:bbservers. [Undoubtedly, ElheCPresidentCWill [1;1etE1herfundsllhatllleO
i.-ki.. 113ut[lheC£oni.equence13vill [be Clan Ceven dbiggerdbudgetl]:jeficit. f)/Ver:h::iveCi::ii,;:ed[ji)urr:fi,;:c::ii Cl!004(]1eficitLforec�t[)o[$525 D billion crrom [$475llbillionCear1ier. DNel:alsoCillowlllstimatelihatOlhern kelyOlen-yearlaumulativeEilleficit[Will llberabout[$5 .5!n"illion, [WpO from 1.$4. SI.trillion [?reviously. tJ'hel.defi citl.issu el.istnow LOn lthe llladart.screen LOf lbond !investors. tJheyl.'ilill tbe 11.ooki ngtm lSeel'llmeth eru
the[l)olicyLI!>fClguns[]md[lputter"[Will[l)ersist[i)r[Whether[JhellBushi:administrationusllllowlJ)reparedllb[make�ome!lbughl:ahoicesl1hD
termst.l)fl.taxesuindl.Altheruire:;isl.tlfl..ltliscretionary�ending. L.Si gnificantL1tpwarnl.j!lres.c:ure1.�ntlDond1 yiP.lcis, 1 JnowevP.r, I isl unlikely1 J soon. Cf.sllbng [asilhe[]f OMC [llem ainslltiendly, flherelsh oul d[belsuffici entrn qui ditytavail ab! el1b [accom m odatelbothllhe[J)ublici:and o
privatet.sectors. LJ
Forfl. ddltlOlll!llrlnfonnation :1Cal/'1on Ill argollsiatf.TEL.-12)1J02-2651 O Pagei1U
Except!fot11helECONOIIIICCCOIIIMENT,IJhislrnaterlatrbas!J,een�repwed',J)yfJherl'lxedrlncomeriradlngWesklandflsD notl!he111roducttDflJhet5ixedJncomelResearchtDepartment.u
Bond []RallyCSensi ble; ISeeklngllBetterllEntryO Note:CfherJollowin�mentsr:tenectfJradingfYiewsrandflnayf]llffet1Jrom�rf1Dnger-termrJnterest!!ater1orecast.o In rnecentlllays, [)helllJSlfixed IThcome[marketOiasrshed lsome[Ofulslfears[Of[a[ll.maway!aeonomy. C$urprisingly!Weakllabor[marketo
data[1orr:1\ugusttwere !lhe [];atalysmor[l)hisEshiftOh Esenti m ent. ITheEiln arket's!Jh itial uallyllollowi ng [l)hel]\ugust{]Jetail [Sal esueporto
suggests[llhatEiln any[l)articipantststi II lb arbor lllears L.CDfLWndu e !Strength. �lthough lltie[JI) avetn ol[Itctpi lalizeu rn,, 1 rn 1ilSmnov e[i:11 Clbrm al o
recommendations, at[]lts[with [Our[iiiew[)hat[)he[CUrrentistrength [ls[linli kelyl:tbtpersist[much rfieyond�ear-end. !That[Said, [welareo
disi nclinedtl!o uthasel.lhelinarket, t.especiallytgiven Llhe [potential !fur tconsu menpriceidata tl!o tsurpriseten Llh ew psi de. lW eLWill ll.boku
for(si gnificant[fllullbackstto[l>rovide!betterrentry[flloints. 0 u
0 Economlc[]ReleasesiandlDtherl:Events: o
0
Dare Time ll1tli1.;dlu1 G3 Conae n eu e Las t Report
Mon1Sep[]50
0
0
0
Tue[SepcJ6o
0
Wed1Sepl'l7U
0
Thui.Sepl'l8U
0
0
8:300
8:300
9:150
9:150
8:300
0
8:30LJ
14:000
10:00U
12:000
Buslnessunventorles�ul)D Currentll\ccount[]Balance[{Q2)0
lndustrtalll?roduction[('Aug)o
Capacitylllltilizatlon[('Aug)D
Consumerll?rice[lndex[('Aug)O
OI1Exl1Food l&r:Energyo
HouslnglStarts�ug)u r ederal 1::113udgctl::ll3ctlctncc ({IAug) o
Leading!lndicators�ug)u
Ph Hadel phla[fed rsu rvey[{Sep_o
-0.3%0 -0.1%0
-$143.0bnD -$138.0bno
+0.5%[ +o.2"/oD 7 4.8%0 7 4.6%0
+0.3%[ +o.3%0
+0.2%[ +o.2"/aD
+3.0%L -2.5%U -$86.0bno -$78.0bno
+0.4%L +o.4%LJ
+20.0%0 +18.5%0
+0.1%0
-$136.1bnD
+0.5%0 74.5%0
+o.2%0
+o.2"/oO
+1.5%U
-$64.7bno
+0.4%LJ
+22.1%0
•il;111pln::ui,talecMcmufac.turlngr3urvcy�Mon,r3cpCIS-0;30)D
•[]!tomebullders'lSurve�ues,CSepcJ6-13:00) o
•lf'OMCl1Jleetingt:Results[(Tue,[SepcJ6-14:15)0
•ITreasuryl2-YearrNoter.Announcement[(Wed,ISep[]7-11:00)C
·�ugust[]2[FOMCr:Mlnutest:qThu,tSept:18-14:00)UlJ
0
FixedrRaterJJpdateu
Over[$5. 3bn[l!)fCihewClixed-rate[jl)aper[jl)ric9d!Jhi,;;fil/,;,ek!31,;;Cih,;,w�,;;ui;,[lloctivityul'.ontim.r"""[lllt[almntiPrmP!fb::i�Pr1hr 1l0.rli::irrthil0.rh'lnnth n
(1 )ClCoca-ColaCHBC []finance EB. V. [(A3/A)Ossued [$500m m Cl OyrCSeni ormJotesratrt92bps�.125%taoupon) iand[$400mm Cl 2yro
Senior[JllotesEat13-120bps[ij5.50%utoupon).Dlllt2)i::GECC�Aaa/AAA)[plriced[$750mmClynFixed-Ratei:GlobaletJotescatrn-57bpsO
(2. 75%utoupon ). Ol6ECCIJ!lso[];oncurrently[fllriced[$1 . 75mm OyrDFRNs[ijseerll>elowl1orealetails). �3)00:arolinall?oweriandl:Lighto
(A3/BBB)[Was[]n[1he1JnarketewithcalJlual-trancheCbfferina:onsisting[l)f[$400mm[]0yrCfirst[Mortgagel:Bonds,Ewhichl];amer.ato
+85bps�.125%iaoupon)iand1$200mml:30yrllFirstl:MortgageaBonds, !'llhichrpricedratrt102bps[(6.125%[lt()upon). !l{l4)illtBOS[l?fcO
(Aa2/AA) [Wrote[$750m m IJJfCSyrC$eni or[}JotesCilrtG-60. ITC5) r.Amerlcan !:General [flnance[lA 1 /A+ )[issued[$500m m cryrsartB-890 v .s. [])8/1 Olll.lST. Olhl:emerginglJnarketlspace, (16) [lfederatlve[]Repu bllcu)f[Brazll [(B2/B+) 11apped[)heEmarketl1b[l)rint[a[$750mm o
reoprming1 of1its110%1 �lobal11Bonds1cllue12011. 1ThetiSsueL11>ricedt.att.al.llliscounttl!o1YieldtJ 0.66%. utl3oldmanl.$achsLServedt.ast.at.aU joint-bookrunner[On[)heflransaction. �)ll\mbev[fBaa3/BBB-)[wrote[$500mmrofCI OyrC$eniormJotesratra. 75%. [JlI[J u
s.C3JJnonthr1/BOR D
I .
M ld-Market!SwaplSpreads:o +29.500 +43.500 +40.500 +43.500
Last!Week:o +31.500 +45.500 +45.500 +46.500
L L
I' . .
fnduatrtalO 3[JectrC S�ro 7(Jearo 10(Jearo 30(?carO
AAAO 30-350 45-500 55-6000 65-700 90-950 AAD (lJ!J[]!][(]lff0-450 55-600 80-850 95-1000 105-1100
AD 60-700 80-900 100-1100 120-1300 140-1500
BBBD 100-1100 125-1350 150..1600 165-1750 180-1000
UtilityD 3[JearC 5[JearD 7ryearo 10[Yearo 30[JearO
AAAU 40-45U 50-55U 55-60u 60-65U 70-80U
AAD 60-6500 65-700 75-800 - 050 -1200 Au 75-85U 85-95u 05-105u 120-1
BBBO 110-1200 130-1400 145-1550 175-1850 • F�ddltlonalrlnfonnation:fJCalfr.Jon !JI argollslatlTEL.1.#11212) rJ02· 2651 o
Pagei2u
• IPCo CP Debt - Average Spread Over/(Under) LIBOR BBA US$ Fi>
01/01/2003 - 06/30/2003 ,
(+)=higher than benchmark
(-) = lower than benchmark
- does not include bid-ask spread of trader
Data
Average of Dane America Sec
Average of Merrill Lynch
Average of CS First Boston
Average of Wells Fargo-Overnig
Avera e of US Bank-Overni ht 0.80%
• 47
•
4944212 01702090
364-DAY
CREDIT AGREEMENT
UATJi;U AS OF MARCH 19, 2003
AMONG
IDAHO POWER COMPANY,
THE LENDERS,
KEYBANK NATIONAL ASSOCIATION,
AS SYNDICATION AGENT,
WELLS FARGO BANK, N.A.,
U.S. BANK NATIONAL ASSOCIATION
AND
WACHOVIA BANK, NATIONAL ASSOCIATION,
AS CO-DOCUMENTATION AGENTS,
BANK OF AMERICA, N.A.,
AS SENIOR MANAGING AGENT,
AND
BANKONE,NA
AS SWING LINE LENDER AND ADMINISTRATIVE AGENT
BANC ONE CAPITAL MARKRTS, INC.
AND
KEYBANK NATIONAL ASSOCIATION
AS CO-LEAD ARRANCERS AND JOINT BOOK RUNNERS,
\
•
le/Jo� ��
PRICING
SCHEDULE��
1! {;,JM
A/A2 A-/A3 BBB+/Baal BBB/Baa2 BBB-/Baa3 <BBB-/Baa3
APPLICABLE LEVELi LEVEL II LEVEL III LEVEL IV LEVEL V LEVEL VI
MARGIN STATUS s� :STATU�.............__ STATUS STATUS STATUS
Eurodollar Rate 0.540% 0.750% 0.850% ,, 1.075% 1.30% 1.875%
Floating Rate 0% v v V/'O 0% 0% 0.500%
APPLICABLE Level I Level Il Level III Level IV f Rvel V Level TV
FEE RATE Status Status Status Status Status Status
Facility Fee 0.110% 0.125% 0.150% 0.175% 0.200% 0.375%
For the purposes of this Schedule, the following terms have the following meanings,
subject to the final paragraph of this Schedule:
"Level I Status" exists at any date if, 011 such date, the Borrower's Moody's Rating is A2
or better or the Borrower's S&P Rating is A or better.
"Level II Status" exists at any date if, 011 such date, (i) the Borrower has not qualified for
Level I Status and (ii) the Borrower's Moody's Rating is A3 or better or the Borrower's S&P
Rating is A- or better.
"Level III Status" exists at any date if, on such date, (i) the Borrower has not qualified for
Level I Status ur Level II Status and (ii) the Borrowcrs Moody's Rating is Daul or better or the
Borrower's S&P Rating is BBB+ or better.
"Level IV Status" exists at any date if, on such date, (i) the Borrower has not qualified for
Level I Status, Level II Status or Level III Status and (ii) the Borrower's Moody's Rating is Baa2
or better or the Borrower's S&P Rating is BBB or better.
"Level V Status" exists at any date if, on such date, (ii) the Borrower has not qualified for
Level I Status, Level II Status, Level III Status or Level IV Status and (ii) the Borrower's
Moody's Rating is Baa3 or better or the Borrower's S&P Rating is BBB- or better.
"Level VI Status" exists at any date if, on such date, the Borrower has not qualified for
Level I Status, Level II Status, Level III Status, Level IV Status or Level V Status.
"Moody's Rating" means, at any time, the rating issued by Moody's Investors Service,
Inc. and then in effect with respect to the Borrower's senior unsecured long-term debt securities
without third-party credit enhancement.
··s&P Rating" means, at any time, the rating issued by Standard and Poor's Rating
Services, a division of The McGraw Hill Companies, Inc., and then in effect with respect to the
Borrower's senior unsecured long-term debt securities without third-party credit enhancement.
4944212 01702090
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7 give a corporation.
4 Wildlife Service presented Idaho Power Company with the
In 1993 the u. s. Fish and
In its June 1991 issue, Money Magazine
The award is the highest honor the agency can Award".
and green investments" .
listed Idaho Power Company as one of its 50 best ''clean
6
5 agency's "Director's Corporate Wildlife Stewardship
3
8 Q. What is the status of Idaho Power Company's
9 bond rating?
12 Control Revenue Bond (PCRB) ratings tor lctano Power
11 Mortgage Bond (FMB), Preferred Stock, and Pollution
10 A. 'l'hP following are the current First
13 company:
14
15
16
17
18
Standard Duff &
Moody's & Poors PhelQS Fitch
PMD A-2 A A+ A+
Preferred a3 A- A A
PCRB a3 A-
19 Q. Have the Company's ratings been under
20 pressure in recent years?
21 A. Yes. Idaho Power Company currently
22 maintains a middle A rating on its First Mortgage Bonds,
23 and a low A rating on its pollution control revenue bonds
24 and preferred stock from both Moody' s and Standard &
25 Poor's. Standard & Poor's, as recently as October 1992,
26 lowered the first mortgage bond, pollution control
27 revenue bond, and preterred stock ratings uf the Company.
• BOWERS, Di 8 Idaho Power company
• Idaho Power
Indicative Rates as of August 7, 2003
!!!!!!!:
Humboldt Co-Nevada 11/1/2014
Par Value
(mff.)
$49.8
Current
AMT �
Non-AMT 8.3006
Indicative Cash Market Ftxed Rates as of August 7, 2003
;·)itk
2014
202)
2033
4.09
.... 88
5.02
4.50
5.30
5.40
0.41
0-42
0.38
5.00
5_80
5.90
0.91
0_92
0.88
•
1 High Grade, general market names (non-AMT)
2 2023 and 2033 Maturities assume NC10 .
Indicative Cash Market
Floattnt Rates as of August 7, 2003
7-day
35-da
0.73 - 0.78
0.83 - 0.88
Note: BMA Reset on August 6 at 0.73%
current Martcet Conc:11t1ons - Thunday Au111.1st 7. 2003
The tax-exempt yield curve remains steep on the short end and quite flat on the long end of the
curve. As of 8/7/03 L-year MMD was 1.00% and JO.y.-.:1r MMTl was at 5.02%, a spread of 402 bp.
At 7/31/03 I-year MMD was .92% and �0-year MMD was at 4.95%, a spread of 403 bp. After a
few weeks of significant volatility, the fixed income market has stabilized, although at higher yields.
Moreover, the tax-exempt market has continued to perform well relative to its taxable counterpart.
• Tax- Exempt Origination 1 � SANK10NE .
53
• Idaho Power
Indicative Rates as of July 31, 2003
Issuer
Humboldt Co-Nevada
Maturity
Date
121112014
Par Value Current
(mil.) A.Mr Coupon
$49.8 Non-AMT 8.30%
lncffcatlve Cash Marloet Ftxed Rates as of July 31, 2003
2014
2023
2033
4.04
4.81
4.95
4.49
5.25
5.40
0.45
0.44
0.45
5.05
5.80
6.00
1.01
0.99
1.05
•
1 High Grade, general market names (non-AMT)
2 2023 and 2033 Maturities assume NC10 .
Indicative Cash Market
Float"9 Rates as of July 31, 2003
7-day
35-dtiy
0.75 - 0.80
0.85 - 0.95
Note: BMA Reset on July 30, 2003 at 0.85%
The tax-exempt yield curve continues to be relatively steep on the short end and rather flat on the
long end of the curve. As of7/3l/03 l-year MMD was .92% and 30->'ear MMD was at 4.95%, a
spread of 403 bp. As of 7 /24/03 I-year MMD was at .90%, and 30-year MMD was at 4. 74%, a
spread of 3ll4 hp. The tax-exempt market continues to be volatile and as a result of the weakening,
credit spreads have widened. Although the fixed-income market has sold off within the last couple
of days, the tax-exempt market has outperfoaned the taxable market. New issuance for the next 30
days in the tax-exempt market is expected to be moderate with about$ 8.6 billion coming to market
(negotiated and competitive transactions), which is about the 30 and 60 day average .
• Tax-Exempt Origination 2 l:c BANK10NE.
c?-}
• Humboldt Bonds - Estimated Interest Rate
•
Principle
Expense of lssue
Net Proceeds
Average 10 Year BMA Interest Rate
Plus: Average spread of Auction Rate
over BMA lndP.ic
Plus: Broker Dealer Fees
Plus: Annual Insurance Premium
Adjusted Interest Rate
Effective Interest Rate (on Proceeds)
Expense of Issue:
Call Premium
Insurance up-front premium
Underwriter's Fee
Legal and Other Fees
Total
Assumed index rate for 2024 bonds
Principle Repayment
Interest Repayments
Total Debt Service
Upfront Premium Rate
Insurance up-front premium calculation
49,800,000.00
2,389,181.50 From Below
47,410,818.50
3.04%
0.25%] 0.25% r G.-> f
0.105% ) ___;;:>
3.65% e;
3.83%
1,494,000.00
1546, 181.50 From Delow
249,000.00
100,000.00
2,389,181.50
5.25%
49,800,000.00
52,290,000.00
102,090,000.00
546,181.50
• IDAHO POWER COMPANY
TAX-EXEMPT BONDS
RATE COMPARISON TO BMA INDEX
BMA AM Falls Port of Morrow Sweetwater-GS Sweetwater-MS
Date Index Rate Spread Rate Spread Rate SQ read Rate Spread
Average Spread over BMA
IPC Bond Lifes - 1.08 0.94 -0.07 -0.12
Average BMA = 3 years 2.28
Average BMA = 5 years 2.75
Average BMA = 10 years 3.04 (} 1f"' Average BMA = Life of Index 3.31 (J2v·y J.<1 (Since 1990) ./· 0-):fov
AM Falls Port of Morrow Sweetwater-GS Sweetwater-MS
Rate Rate Rate Rate
I lietoricel Rato Sp mad RatG Sp mad R;:itp Spread Rate Spread
2003 2.64 1.52 2.24 1.12 1.24 0.11 1.16 0.04
2002 2.77 1.40 2.50 1.12 1.61 0.24 1.56 0.18
2001 3.75 1.14 3.74 1.13 2.45 -0.16 2.45 -0.16
Since lssue(Jai.ZGe') 3.47 1.08 3.27 0.94 2.90 -0.07 2.86 -0.12
BMA Rate + Historical Spread
Usino 3 Year BMA 3.36 1.08 3.22 0.94 2.21 -0.07 2.17 -0.12 • Using 5 Year BMA 3.83 1.08 3.69 0.94 2.67 -0.07 2.63 -U.lL �
Using 10 Year BMA 4.12 1.08 3.99 0.94 2.97 -0.07 2.93 -0.12 ·
Using life of BMA - 1990 4.39 1.08 4.25 0.94 3.24 -0.07 3.20 -0.12
•
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NEW PRODUCT UPDATE
Moody's Announces Intent to Abolish _ ei..=- . Preferred Stock Rating Scale
. ., - ' .. £ _
Moody,s Announces Plan to Abolish Preferred Stock Rating Scale1
Yesterday, Moody's announced its intention to abolish its separate rating scale fur preferred stock and to rate preferred stock and
hybrid securities, including trust preferred securities such as Salomon Smith Barney's ("SSB's") TRUPS�. on a single consolidated
debt rating scale. Moody'• proposecl mo- to a single sc:ale ls not a crecllt event and does not reflect any
change in Moody's view of the risk characteristics of preferred stock and other hybrid instruments, but is instead intended to increase the comparability of senior debt, aubor<linatect debt, hybrid and preferred securities.
Moody's Existing Preferred �!o_ck __ an_d_De_b_t_Ra_ti_ng�S_cal_es _
Unlike Moody's debt rating scale, which emphasizes investors' recovery rates in bankruptcy, Moody's existing preferred stock
rating scale focuses on the likelihood that investors will receive timely payments of dividends and inherently anticipates a lower
recovery rate in bankruptcy. However, as discussed in our New Product Update dated December 8, 1999, Moody's has become
inereasinalv concerned that investors do not appreciate the primacy difference between the agency's preferred stock rating scale
and its debt rating scale. Therefore, while a security with a current preferred rating of "al" anticipates greater losses in
bankruptcy than a debt instrument rated "Al w, Moody's rears that investors may use these ratings interchangeably.
Prospective Notching Practices for Issuers
To detennine ratings for different classes of an issuer's liabilities, Moody's Will nrst assign a pnmary ranng to the issuers rnosr
important class of liabilities, then rate other liabilities in relation to that rating.
For example, for investment-grade non-financial corporate issuers, Moody's will generally assign a senior unsecured debt rating,
then rate other liabilities in relation to the senior unsecured rating:
LiabWty
1J11, Senior secured debt
.... S-ior un�«-UrM d,bt
Rating Relative to Senior Unsecured
plus 1 notch
O notches
1J11, Subordinated debt, includingjwtior subordinated debt minus 1 notch
.,. Hybrid securities, including US-style nmPS (aanulatiw., dated securities) minus 1 notch
.,. Preferred stock/preference shares, including European- and Asian-style SP\/ minus 2 notches
preferred securities (non-cumulative, perpetual securities)
The above notching guidelines should apply to all bond market sectors rated by Moody's, although the primary rating type will
vary by industry sector.i For example, Moody's will generally first assign "deposit" ratings to banks and "insurance financial
strength" r<11.iJ1KS to Insurance companies, and then determine rnting:J for subordinated debt, hybrid and profarred llOCUrirux,
using the same notching differentials as above.
Moody's expects that hybrid securities, including US-style TRUPS, will likely be treated as subordinated debt in the event of the
issuer's bankruptcy, and will therefore generally assign the same rating to hybrid securities as that assigned to subordinated
debt. However, for issuers with significant amounts of senior debt, Moody's may rate hybrid securities two notches below senior
debt.
Implication for Existing Issues
.James Revell
Fl New._...._ C.O.p - London
44-207·986-8978
Jennifer Piekut
C.pl!E ....... bl ft New P.......t- Ocooap - New Yock
Howard Hlller212·72.'l.fi09fl 212-72.'Ui029 John Oickey
Yukari Saegusa 212-723-6101 Peter Jurdjevic Stanley Louie
C.J. Arrigo 212-72.1-6005 Adam Dohrenwend David Rosenwaks
Moody's decision is not final, and the agency is currently soliciting feedback from the financial community on the Impending
change. However, in all likelihood, Moody's will formally abolish its preferred stock rating scale sometime in early 2001. At
that time, the agency will announce adjustments to all outstanding ratings to reflect the debt rating scale in a single press
release. Although the adjustments mav ostensiblv result in "downgrades" of two notches for certain issuers, they do not reflect
any fundamental change in the creditworthiness of the issuers.
SSB wUl continue to monitor the latest rating a.g-ency developments rqarding TRVPS and will keq
issuers rued of d.evelo menu.
1 Similarly, in February of 1999, S&P introduced a single ratings scale ilr both preferred and debt instruments that replaced the previously separate preferred stock and debt ratings scales. See SSB's "New Product Update: S&P Distributes Pres:; Releases Relating to its Treatment of Preferred. and Capital Sl!Cllrities", dated February 17, 1999. 2 An exception to this general rule is the �raged finance corporate issuer sector. Because issuers in this sector have complex and highly differentiated capital structures, Moody's believes that unitbrm notching guidelines could be misleading.
�:i § Moody's Investors Service
--- - Global Credit Research
November 2000 Rating Methodology
•
NewYorlr •-••'"""""'"'••M•••.,,• Richard Cantor Jerome Fons
Brian Oak Patrick Finnegan
Michael Rowan
Michael Foley
Chris Mahoney Ken Pinkes
London
Chester Murray Michel Madclain
Tokyo
Tom Keller
UonoKono
Julia Turner
1.212.553.1653
44.20. 7772.5454
81.3.3593.0922
852.2916.1120
Priority of Claim Standing Committee
Rating Symbols and Definitions Standing Committee li'Jn��tli��mf::��¥?.i)f$ii'ifflf��-, �1�Jj�f7,'� ,lmi.%��fJU$:(Q'(��t*-'feW:,N":�filfu�lSlJft�,
Notching for Differences in Priority of
Claims and Integration of the Preferred
Stock Rating Scale
Invitation to Comment
Contents
• Summary
• What Is Notching?
• Moody's Historical Notching Practices
• Historical Differences in Loss Severity By Class of Debt
• An Expected-Loss Framework for Notching
• Notching for Hyhnd Sernnries and Holding Company Debt
• Notching Practices in the Leveraged Finance Sector
• Making the Adjustment
This Rating Methodo/,o!!JI outlines ongoing refinements to Moody's notching practices for debt
aml preferred stock uf a single business enterprise or issuer. We believe our analytical approach
achieves comparability in the meaning of ratings across the widest possible range of corporate
securities and also provides appropriate guidance for the Structured Finance and Public Finance
markets. Our notching practices are intended to result in expected loss rates of similarly rated
securities that are roughly the same, regardless of whether the bonds are secured, unsecured or
subordinated claims on individual issuers. Moreover, to expand the range of comparability, we
expect to rate preferred stock on an expected-loss basis as well, using our traditional debt rating
symbols. We therefore plan to abolish the separate rating scale for preferred stock we have used
in the past.
:II DJ ... = ca
I i 0 a. 0 - 0 =
• A final determination on the issues outlined in this Rating Methodology will occur in early 2001. It is
expected rhat rating adjusnneurs fur all outstanding pi efer r ed iaLiug:, will be: made: at that Lime and
announced in a single press release. We expect that other changes to existing ratings will be issuer and issue
specific, and will be addressed over the remainder of 2001 through ongoing credit monitoring. Moody's
encourages interested parties to submit comments to the Priority of Claim Standing Committee to the
attention of Patrick Finnegan, 99 Church Street, NY, NY, 10007, or at [e-mail].
Since the various liabilities of a single corporate enterprise generally share the same (or nearly the
same) probability of default, differences in their expected loss rates are determined by their relative priori­ ty of claim - and, hence, relative expected loss severities - in bankruptcy. Our notching practices translate
these differences in expected losses to differences in ratings - in a manner that is consistent with the differ­
ences in historical loss rates associated with different rating categories. This general methodology is
applied universally throughout the corporate sector, but practical aspects of its implementation differ
between the investment-grade and leveraged-finance sectors.
For speculative-grade companies, where default is a clear and present danger, Moody's intensively ana­
lyzcs each issuer's capital strucrurc and bond covenants. Given the wide variability in capital structures
that we see in the leveraged-finance sector, our expected-loss approach often leads to large differences in
notching for relative seniority from one issuer to another.
In the irivcoemcne grade acctor, however, there ic Iecc of o bocic for making such diseinceionc o.crocc
issuers because one cannot reasonably predict an issuer's future capital structure - and hence the relative
recovery prospects of its liabilities - at the time of default. Analysts of investment-grade issuers, therefore,
generally rely on the average experience reflected in our defaulted bond recovery database to predict the
relative recovery (and loss severity) of different classes of debt. As a result, notching practices in the
investmenr-grade sector tend to be more uniform, based on average debt recovery statistics, without spe­
cific reference to individual issuers.
TypJc@Uilotchi�g Pr@J�tices,fpr lnv�stment:-Gr,ide. IJ�11.er,s
• If, as is generally the case, an investment-grade issuer's largest class of debt is unsecured, a Moody's
rating committee first assigns a senior unsecured debt rating and then contemplates the ratings of its
other liabilities in relation to the senior unsecured rating.
• Absent any issuer-, region- or industry-specific information that might alter the relative recovery
assumptions, an irrvestrnerrt-grade issuer's
- Secured debts are generally rated one notch above its senior unsecured debt rating.
- Subordinated debts (including junior and senior subordinated debts) are generally rated one notch
below its senior unsecured debt rating.
- Hybrid (debt/equity) security ratings are based upon the issue's expected seniority in bankruptcy,
which is often the same as subordinated debt.
- Preferred stock, which in the pa:,L l1a� been 1aLt:J on au euurely different scale, will soon be rated on
the same debt rating scale. Cumulative preferred issues will generally be rated one notch below subor­
dinated debt. Further, given the small differential in expected loss, Moody's will consider eliminating
the existing notching differential between cumulative and noncumulative preferred.
- Holding company debt is generally rated at or below the lowest rated debt security that would be
assigned at the principal operating company.
• The largest class of rated liabilities for speculative-grade issuers may be either secured bank debt,
secured bond debt, unsecured senior debt, subordinated debt, or preferred stock.
• A Moody's rating committee first assigns a "senior-implied" rating to a speculative grade issuer, which is
the rating that would apply if the enterprise had a single class of liabilities and a consolidated legal entity
structure. The enterprise's specific various liabilities are then rated above or below its senior implied rat­
ing based on their relative default probabilities and their relative expected loss severities in default.
1 See Moody's Special Comment, "Moody's Analytical Framework for Speculative Grade Ratings,• May 1999.
Moody's Rating Methodology 3 �)
• • Since these entities often have complex and highly differentiated capital structures, uniform notching
guidelines could be misleading in mis sector.
• The expected-loss methodology does, however, impose substantial discipline on notching across each
company's liability structure.
- The rating assigned to each of a company's liabilities is a function of the company's senior implied rat­
ing, the expected credit loss of that issue relative to the company's other liabilities, and the uncertainty introduced by the overall complexity of the capital structure. As a result, the par-weighted average of the
rerings �"�ignPrl to all of the company's liahilities will be equal to, or lower than, its implied senior rating.
- Expected differences in loss severity generally give rise to wider notching differentials for companies with Ba3, single-Band Caa senior-implied ratings than for Bal or Ba2 issuers.2 (Notching widens for
companies rated Ba3 or below because the historical default rates in the B and Caa rating ranges vary
less - on a percentage change basis - from one rating notch to another than they do in the Ba portion
of the rating scale.)
What. Is f(Q�hing?
•
Notching refers to the general practice of making rating distinctions among the different liabilities of a
single entity or of closely related entities. When an entity has a number of different classes of debt out­ standing, Moody's analysts generally employ a rwu-srep rating pruc<::ss. First, they assigu a 1atiug 1u au
issuer's most important class of liabilities or to a weighted average of its liabilities. Then, they decide how
to rate the issuer's various debt instruments in relation to this initial rating. This two-step rating process
helps ensure analytical consistency across an issuer's liability structure.
• In the investment-grade, nonfinancial corporate sector, analysts generally first assign a senior unse­
cured debt rating to an issuer, and then determine the company's senior secured debt, subordinated
debt, and preferred stock ratings in relation to its unsecured debt rating. In the speculative-grade sec­ tor, the process is similar although the benchmark is the "senior-implied" rating, the rating that would
be assigned if the company had a single class of debt and a consolidated legal entity structure.
• In the banking sector, analysts generally first assign a deposit rating (which itself may depend upon the
sovereign's rating), and then assign ratings for debt and preferred securities issued at the level of the
operating company or holding company. Si.nee deposit obligations frequently benefit from third-party official support in times of stress, rating differentials for unsupported obligations can be significantly
gre�ter rhcn the guideline<l prnvirlerl.
• In the insurance sector, analysts generally assign an insurance financial strength rating that speaks to
the probability the insurer will fulfil its insurance policy obligations, and then ratings are assigned to
the debt and preferred securities issued at the level of the operating company or holding company.
• In the structured finance sector, analysts generally first assign a rating to an entire securitization struc­
ture as if it were to be issued as a single-tranche security, and then decide how the ratings on individual
tranches of the securitization should relate to the hypothetical single-tranche rating.
• In the public finance sector, analysts generally first assign a general obligation rating to a municipality,
and then decide the ratings of its specific bond issues, which may carry less or more security than a
general obligation pledge. Many sectors within Public Finance, although tax-exempt, resemble tradi­ tional corporate issuers and or structured transactions am! therefore mauy uf ihe :;a111e uou.hiug p1ac­ tices are employed. Examples of these are not-for-profit hospitals and universities as well as single
family and multi-family tax-exempt housing transactions.
While this lv1tittg JH�thudol-Ogy Iocuscs on the nonfinancial corporate sector, the general principles that
are discussed here are relevant to virtually all bond market sectors rated by Moody's.
Moody's ratings have always placed considerable weight on relative priority of claim. Until relatively
recently, however, notching practices were necessarily subjective, since there was no quantitative basis for
deciding whether a particular difference in seniority was significant enough to merit a rating distinction,
or whether it should give rise to a one-notch, or even a two-notch, rating distinction.
2 While this guideline is directly relevant for subordinated and preferred stock securities, notching for secured claims should generally widen later in the rating scale, when the issuer's rating moves from Ba3 to B 1.
4 Moody's Rating Methodology
•
•
The notching practices developed during the early 1980s generally reflected a desire to recognize each
subsequent layer uf suburdinariou with a cun.espoudiugly luwer raLi11g. For invesuncnt-grade companies,
an issuer's senior unsecured debt was generally rated one notch lower than its secured debt, its subordinat­
ed debt was one notch below its senior debt, and its junior subordinated debt was one notch below its
senior subordinated debt. However, for below-investment-grade issuers, notching for differences in pri­
ority of claim was often wider (by an extra rating notch) because we felt that as the likelihood of default
increased, more emphasis should be place on priority of claim. At that time, we never considered the pos­
sibility that the changes in the width of the rating bands as one moves along the rating scale could influ­
ence the degree of notching.
Three key developments in the late 1980s subsequently led to changes in Moody's notching practices.
1. Moody'.s began compiling and analyzing its authoritative data set on corporate bond defaults and
recovenes.
2. The meaning of Moody's corporate bond ratings steadily migrated away from a system that empha­ sized relative default rates, intrinsic financial strength, and the quality of the promise to one that
emphasizes relative expected loss rates.
3. With the development of the junk bond market, most speculative-grade companies no longer had the
simple balance sheets of fallen angels (with a preponderance of senior unsecured debt); rather, they
employed highly complex and varied capital srrucrurce.
By the 1990s, historical data could be used to estimate the differences in expected-loss rates across
instruments with different priorities of claim. Moreover, the significance of those differences in terms of
expected loss could be compared to the differences in historical loss rates generally associated with differ­
ent Moody's bond ratings. The pieces were now in place to develop simple notching guidelines that
enhance consistency in the meaning of ratings across different classes of liabilities.
However, an the ccpirol structures of speculative-grade companies become increasingly complex and v,ir­
ied, it became clear that investors in the leveraged finance market would be better served by an in-depth,
expected-loss analysis of each component of a company's capital structure, Moody's Leveraged-Finance
Group subsequently developed an analytical approach to notching that utilizes company-specific informa­
tion, while achieving consistency in the meaning of ratings in terms of expected loss across companies. 3
,is.t�ri�ctl.Differem:�s in1o�s:$everity J1y ClaJs 0,f, Deb.t�.�;;'"'"'" .,,.""
Moody's June 1999 Special Comment, "Debt
Recoveries for Corporate Bankruptcies," reports
recovery rates on a wide variety of debt securities
for 15 5 issuers with more than one class of debt
outstanding at the time of default. This data can
be used to calculate the average percentage differ­
ence in recovery rates between two classes of debt
securities for individual issuers. In Figure 1, we
apply these average percentage differences to the
mean defaulted senior unsecured bond recovery
price of 19 cents per face dollar, as reported in
Moody's January 2000 Special Comment,
"Historical Default Rates of Corporate Bond
Issuers, 192 0-1999. ,,4
3 See Moody's Special Comment, "Moody's Analytical Framework for Speculative-Grade Ratings,• May 1999 . 4 We recognize that our data is heavily weighted toward the U.S. corporate experience. To the extent that the loss severity experience is different in other sectors or regions, the application of these notching prindpals will be adjusted where appropriate. This year, Moody's has published extensive country-specific studies - for the UK, Germany, and France - which analyze the relative standing of different claimants in corporate bankruptcy and the potential implications for differences in expected loss severity. See "Bankruptcy & Ratings: A Leveraged Finance Approach for Europe - UK versus France and Germany," Moodys Special Comment, March 2000.
Moody's Rating Methodology 5 63
• How do these averages compare to each other? Table 2 presents average loss
severity recovery rates for different classes
of debt relative to the average recovery
rate on senior unsecured debt. For exam­
ple, in default, senior secured debt loses
30% (which equals (51 %-36%)/51 %) less
on average than senior unsecured debt;
whereas, preferred stock loses 85% mun:
on average than senior unsecured debt.
This relative loss severity data underpin the notching guidelines Moody's employs in the investment­
gra<le corporate sector. For investment-grade credits, since the risk of default will likely remain low for
many years into the future, it is very difficult to anticipate what a company's capital structure will look like
when it eventually defaults. Therefore, despite the high variance in relative recovery rates that exists in
the historical data, Moody's analysts generally rely heavily on historical average recovery rate data when
notching the securities of investment-grade issuers for differences in priority of claim.
In contrast, for speculative-grade issuers, default is much more likely in the near future, capital structures
and covenants tend to lock in a claimant's position, and analysts have a much better fix on the company's probable capital structure at the time of default. As a result, the average relative recovery statistics reported
in Figure 1 are less relevant to notching practices in the speculative-grade sector. For these credits, Moody's
analysts base their notching practices on company-specific analyses of relative loss severity.
Regardless of the source of data for the expected loss severity expectations, the following questions still
need to be addressed:
• Are these differences in expected-loss severity large enough to warrant rating distinctions?
• If rating distinctions are appropriate, should secured and subordinated obligations carry ratings that
differ from the issuer's unsecured rating by one or more rating notches?
Should notching conventions be constant or should they vary with the issuers' placement on the rating scale?
An. EJ<pected��o�s FrantQwork fot Notchipg
•
Relative loss severity data is not enough, by itself, to determine the appropriate amount of notching.
Within an expected-loss framework for the meaning of ratings, notching guidelines are a function of both
expected loss severity and expected default probability. Table 3 outlines the mechanics of how - in three
steps - the expected-loss framework can be used co derive notching guidelines.
Step 1. Identify the historical default rates of debt issuers with different senior unsecured debt ratings.
Compare the expected loss rares of various debt instruments for issuers that carry these senior
unsecured debt ratings.
Step 3. Assign the same rating to all securities that have similar expected loss rates.
Our estimates of expected default rates arc derived from Moody's latest corporate bond default study,
which reports the historical default frequencies associated with different senior unsecured ratings over a
wide variety of investment horizons. Although all potential investment horizons are factored into the
analysis, for simplicity, the analysis presented in this Rnting Methodology is based exclusively on the ten­
year cuiuulati Vt: defauli I alt: statistics,
For each initial senior unsecured narrow rating category (with the 1,2,3 rating modifiers), we estimate
the expected cumulative default frequency by interpolating the historical default experience for the broad
iaL.i.11g categories shown in column (a).' Expccrcd-loss rates for an issuer's senior unsecured debt are then
derived by multiplying the modified default rates by 51 % , which is the average loss severity on defaulted
senior unsecured bonds. Similarly, expected-loss rates for an issuer's senior secured debt and subordinat-
5 In 1982, Moody's introduced rating modifiers (i.e., Aa 1, Aa2, etc.) and currently reports cumulative default stalislics by modified rating category for horizons up to eight years. Statistically useful, cumulative default rates for these broad categories are thus not available for the ten-year horizon. Based on patterns observed in the cumulative default rales for shorter horizons, we interpolated the broad category default rates to derive ten-year default rates for modified ratings.
Step 2.
6 Moody's Rating Methodology
•
•
ed debt are tabulated (according ta an issuer's unsecured debt ratings) by multiplying the unsecured
default rates by the average loss severity of 36% and 78% on secured and subordinated debt, respectively.
Regardless of an issuer's senior unsecured rating, the percentage difference in expected loss rates
between secured and unsecured debt is 30%, which equals ((51 %-36%)/51 %]. Similarly, regardless of an
issuer's senior unsecured rating, the percentage difference in expect loss rates between senior unsecured
and senior subordinated debt is 40%, which equals ((71 %-51 %)/51 %]. However, as shown in Table 3
and Charts 1 and 2, these percentage differences translate into absolute expected-loss-rate differences that
vary from one rating category to another.
The expected-loss rates presented in Table 3 imply different notching criteria at different rating levels.
For example, consider an issuer with a Baa2 senior unsecured debt rating. Ten-year expected-loss rates
for its senior secured debt and subordinated debt are 1.52% and 3.28%, respectively. These loss rates are
extremely close to the expected-loss rates for the senior unsecured obligations of issuers rated Baal
(1.51 %) and Baa3 (3.10%), respectively. This analysis for Baa2-raced issuers suggests that secured debt
should be rated one notch above senior unsecured debt, and subordinated debt should be rated one notch
below �eu.iUl unsecured deln, The light grouping of 1033 rares at the senior euborciinatcd, subordinated
and junior subordinated levels further suggests that no rating distinctions be made across obligations with
these standings. Moreover, these results indicate that preferred stock should be rated one notch below an
issuer's subordinated debt.6
6 In previous research, we have shown that. when applying an expected-loss perspective, there is generally little basis for making rating distinctions between cumulative and noncumulative preferred issuers. See 'Pretenea Stock Dividend and Credit Risk;" Moody's Spec/a/ Report, December 1994.
Moody's Rating Methodology 7
• Chart 1: 10-Vear Expected Loss Rates -
Investment Grade Issuers
Chart 2: 10-Vear Expected Loss Rates -
Speculative Grade Issuers
70%�--------------�
Sr. Secured m Sr. Secured
6% • Sr. Unsecured 60% II Sr. Unsecured
0%......,.._,&.a..:.2.&l.:.<L&'-'lu.;..J.J......., ...... ...a ......... "'--U .......
Aaa Aa1 Aa2 Aa3 Al A2. A3 Baa1 Baa2 Baa3
3% I
20o/.
Sr. Subordinated
Ba1 Ba2 Ba3 Bl 82 83 Caal Caa2
10%
50%
• Subordinated
4o% II Jr. Subordinated
30% Preferred Stock
Sr. Subordinated
• Subordinated
!Ill Jr. Subordinated
?%
4%
1%
5%
While the general rules presented here - one notch up for secured and one notch down for subordinated -
are generally consistent with the Table and the Charts, there arc two notable exceptions.
First, in the highest (Aaa and Aa) rating categories, a pure expected-loss approach might imply a two­
(or more) notch distinction. rather than the proposed one-notch rating differentials. However, as dis­
cussed in other reports, Moody's ratings are not based purely on expected-loss rates. In particular,
Moody's assigns extra weight in the meaning of ratings to default risk (relative to severity of loss) for
investment-grade credits, because the risk of default is very low.7 Hence, at these high rating levels, rat­
ings are adjusted upward or downward from senior unsecured levels by only one notch to reflect differ­
ences in priority of claim. 8
Second, in the lower portion of the speculative range (issuers with senior unsecured debt rated Ba3 or
lower), a pwc expected-loss approach again suggcst:5 a two- (or more) notch differential is sometimes nec­
essary to account for differences in priority of claim.9 If ratings are intended to indicate relative expected­ loss rates, then notching for subordination and preferred stock should generally be wider for issuers rated
Ba3 or below, and notching for security should be wider for issuers rated Bl or below. Note that this rec­
ommendation is somewhat at variance with our historical practice, in which we generally widened notch­
ing differentials as soon as an issuer's rating fell below investment grade.
The general approach laid out in this Special Comment can also be applied to the ratings assigned to
hybrid securities and holding company debt. In each case, the analyst estimates the expected loss severity of the instrument to be rated and compares that loss severity to a reference security that is rared - either
the senior unsecured debt or senior implied rating of the principal operating company or business enter­
prise. Differences in expected loss severity are translated into rating notches by referencing an expected­ loss matrix such as Table 3.
• 7 See "The Evolving Meaning of Moody's Bond, Ratings,• Moody's Special Comment, August 1999. 8 Furthormoro, tho hictorica/ dolauJt ratDc for Aa;ii- and Aa-ratod it:&UQ� arQ not VQ,Y pr1.>cisQ/J' o�timatlJ.d bocaUf;(;'.I Sl".'l f,;;,w h�va defaulted over a ten-year horizon. There is, therefore, less justification for a purely quantitative approach to relative ratings determination in this part of the rating scale. 9 For example, consider an issuer with senior unsecured debt rated 82. The expected losses on its secured and subordinated obfigations are 15.54% and 33.49%, respectively. These values are very close to the losses one might expect to incur on the senior unsecured obligations of issuers rated 8a3 (15.92%) and Caa2 (31. 72%), respectively at the senior unsecured level. The analysis suggests that the secured debt of an issuer rated 82 at the senior unsecured (eve/ shoufd be rated two notches above its unsecured
debt, and its subordinated debt should be rated three notches lower than its senior unsecured debt. In contrast to the one-notch adjustments recommended for most of the rating scare, two-notch adjustments will be more common tor issuers holding senior unsecured debt rated 81 or lower.
8 Moody's Rating Methodology
•
•
Hybrid securities are structured securities that generally have both debt and equity characteristics from a balance sheet perspective. However, from au iuvesuir's perspecuve, a security's credit quality is deter­
mined by its default probability and its expected loss severity in default. Since the expected default fre­
quency on most hybrid securities is the same as that of the issuing company's other debt securities, then
hybrid's should be notched based on their expected priority in claim in bankruptcy. In most cases, we
expect that hybrids will be treated like subordinated bonds in bankruptcy and so they will usually carry the
same credit rating. However, some hybrid issuer's have a preponderance of more senior securities that
could negatively affect the recovery of their hybrid securities in default. In such cases, the recovery of those securities is unlikely to differ meaningfully from the preferred stock of the same issuer, hence the
rating could be the same as that of preferred stock.
Holding company debt is generally structurally subordinate to all debt and preferred stock of the prin­
cipal operating company. Holding company debt will generally be rated at or below the lowest rated
instrument of the principal operating company. The guiding principle is that the degree of subordination
is determined by the extent to which structural elements distance an obligation from the entity's operating assets and economic value. An evaluation of an issuer's corporate structure, its other obligations, the
obligations of its subsidiaries, the role of third party support available to subsidiary creditors (e.g. banks or
operating utilities) and the covenant protections contained in the holding company obligations are all fac­
tored into the notching decision.
No�hipg, PraJ:ticesjq tile Leveraged Finance,Se,�or
The notching guidelines discussed above are appropriate if one assumes that the expected-loss severity on
a company's debt security equals the historical loss severity for that type of instrument. We generally
make this assumption when analyzing investment-grade credits, because these companies are highly
unlikely to default for many years, and it is generally very difficult to foresee their likely capital structure
at the time of default.
In the leveraged-finance sector, however, analysts have a much better fix on a company's likely capital
structure at the time of default. Moreover, capital structures in this sector are highly varied, so that loss
severity on similar debt instruments are likely to vary significantly from one company to another. As a
result, Moody's leveraged finance analysts undertake a detailed analyses of the capital structure of each
speculative-grade company and the relative expected loss severity of each component of its liabilities.
The notching process for speculative-grade credits starts with the establishment of a senior-implied
racing, which assumes that an enterprise's obligations are collapsed into a single generic class of senior
debr.J? As such, the senior-implied rating reflects the expected credit loss (i.e. default and loss severity) of
that single class of debt. As stated earlier, Moody's generally expects that a company will default on all of
its obligations at approximately the same time, so the key factor that distinguishes the rating of a compa­
ny's "senior" and "junior" debt are differences in expected loss severity in the event of a default.11 The
notching process for speculative-grade credits distributes the expected loss severity that is incorporated in
the senior implied rating across the enterprise's capital structure. In developing its opinion about this dis­
tribution, Moody's considers the relative size of the different classes of debt, the contractual terms of each
specific instrument, and the company's likely capital structure and enterprise value in a distressed scenario,
and the average historical recovery rates incorporated in this report.
Consider the following stylized example. Suppose a company has $500 million in total debt, com­
prised of $250 million in senior-secured bank loans and $250 million in subordinated bonds. The
Moody's analyst estimate of the distressed value of the firm and or its assets in a default scenario is $250
million. The average loss severity on all the debt is therefore 50%. Suppose further rhan the expected loss severities on the bank debt and bonds are 2 5 % and 7 5 % respectively.12
10 See Moody's Special Comment, "Moody's Analytical Framework for Speculative-Grade Ratings," May 1999. 11 For enterprises with complex corporate structures, expected default rates may vary across debt instruments as well. 12 On average, the price of secured bank debt trades at about 70% of par shortly after default, although the long-term recovery value may be closer to 90% or 95% of principal. In assigning ratings, Moody's analysts generally focus more on the long-tenn expected recoveries than post-default expected trading prices. For notching practices to be consistent, it is important that relative recovery rates for different instruments be estimated on a like basis, eitner long-tenn expected recoveries or post-default trading prices.
Moody's Rating Methodology 9
•
•
If this company had a 10-year cumulative default probability of 19%, its 10-year expected-loss rate would be 9.5% (=l 9%x50%), which would Lt: cuusisteru, (Ii uru Table J) with a Da2 senior-implied rating.
The expected-loss rate on its bank debt and bonds would be 4.8% and 14.3 %, respectively, which (from
Table 3) correspond to Bal and Ba3 ratings, respectively. In this case, the senior-secured bank debt
would be rated one notch higher than the senior-implied rating, and the subordinated bonds are rated one
notch lower than the senior implied rating.
On the other hand, if the company's default probability were 42%, its 10-year expected-loss rate
would be 21 % (=42%x50%), which would be consistent (from Table 3) with a B2 senior-implied rating. The expected-loss rate on its bank debt and bonds would be 10.5% and 31.5%, respectively, which (from
Table 3) correspond to Ba2 and Caa2 ratings, respectively. In this case, a pure expected-loss analysis
would suggest that the senior-secured bank debt should be rated three notches higher than the senior­
implied rating, and the subordinated bonds should be rated three notches lower than the senior implied
rating. However, because Moody's somewhat overweights default probability relative to loss severity in
the meaning of its ratings, we would probably assign ratings to this issuer that would result in a four- or
five-notch rating spread, rather than the six-notch spread that exists between Ba2 and Caa2.
These two examples highlight two key implications of the use of an expected loss approach to notch­
ing in the speculative-grade sector. One, the assignment of senior-implied ratings and the expected-loss
analysis help achieve consistency in our notching practices. Since the expected-loss rate on a firm's total liabilities is the par-weighted average of the expected loss rates on each or its Iiabihnes, the semor-imphed
rating is a weighted average of the ratings of its various debt instruments.l ' Two, wider notching is appro­
priate for companies with Ba3 or lower senior-implied ratings than for firms rated higher.14 Given our
historical practice of applying wider notching differentials to all below-investment-grade issuers, narrower
notching differentials for Bal and Ba2 issuers are likely in the future for priority of claim purposes.
In those cases where rating changes are called for, based on the guidelines presented here, Moody's will
make those adjustments and their rationales transparent to the capital markets. Changes to our preferred
stock ratings will be made on a single date and reported in a single press release. As the preferred stock is
brought into the long-term debt rating system, downgrades of two notches may occur. These adjustments are not meant to reflect any fundamental change in the credit worthiness of these obligations. We expect
that other changes to existing ratings will be issuer and issue specific, and will be addressed over the
remainder of 2001 through ongoing credit monitoring .
13 To the extent that the complexity of a company's capital structure increases uncertainty about the perfonnance of its individual liabilities and reduces the company's financial flexibility, its senior implied rating may be in fact higher than the par-weighted average of the ratings on its individual liabilities. 14 As indicated in Table 3, this rule of thumb can be applied directly when notching relative to an issuers rating for its subordinated obligations. Notching for secured claims, however, should generally widen somewhat later in the rating scale, when the issuer's rating moves from Ba3 to 81.
10 Moody's Rating Methodology