20100409Reply Comments.pdf

BARTON L. KLINE
Lead Counsel
bklineláidahopower.com
1SIDA~POR~
An IDACORP Company
April 9, 2010
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilties Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-09-28
CONVERT SCHEDULE 54 - FIXED COST ADJUSTMENT - FROM A
PILOT SCHEDULE TO AN ONGOING, PERMANENT SCHEDULE
Dear Ms. Jewell:
Enclosed for filng please find an original and seven (7) copies of Idaho Power
Company's Reply Comments in the above matter.
Very truly yours,V~
Barton L. Kline
BLK:csb
Enclosures
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise, ID 83702
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l'" l ..",.-i'" ~',.,,/ -: =
BARTON L. KLINE (ISB No. 1526)
DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
bklineCâidahopower.com
dwalkerCâidahopower.com
20ia APR -9 Pl1 4: II
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Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-09-28
AUTHORITY TO CONVERT SCHEDULE )
54 - FIXED COST ADJUSTMENT - FROM ) REPLY COMMENTS OF IDAHO
A PILOT SCHEDULE TO AN ONGOING, ) POWER COMPANY
PERMANENT SCHEDULE. )
)
Idaho Power Company ("ldaho Powet' or "Company") hereby replies to the
comments filed by the Staff of the Idaho Public Utilties Commission ("Staff"), the Idaho
Conservation League ("ICL"), Snake River Allance ("SRA"), Community Action
Partnership Association of Idaho ("CAPAI"), and AARP.
i. BACKGROUND
In Order No. 30267, issued on March 12, 2007, in Case No. IPC-E-04-15, the
Commission approved a three-year pilot program under which the Company
implemented a fixed cost adjustment (" FCA") mechanism for residential service
(Schedules 1, 3, 4, and 5) and small general service (Schedule 7) customers. Idaho
REPLY COMMENTS OF IDAHO POWER COMPANY - 1
Power's rates for those two customer classes have historically been designed to
recover a significant portion of the Company's fixed costs in the energy price. When
energy sales increase or decrease, fixed cost recovery also increases or decreases.
The FCA provides a true-up mechanism that allows the Company to recover (or refund)
the difference between the amount of fixed costs authorized for recovery by the
Commission in the Company's most recent general rate ease and the fixed costs that
the Company actually recovered through energy related rate components during the
previous year. The FCA is often referred to as a "decoupling" mechanism because it
separates fixed cost recovery from energy sales volumes.
II. BENEFITS OF THE FCA
All of the parties that formally intervened in this case ("Intervenors") note in their
Comments that they support the FCA and recognize the positive benefits customers
obtain by implementation of the FCA.1 The FCA's ''true-up'' mechanism benefits
customers three ways. First, cost-effective energy efficiency and demand-side
management (collectively "DSM") programs can lower customer costs. Customers
benefit from the FCA true-up mechanism because the Company is not financially
harmed by decreases in energy sales within the residential and small general service
customer classes nor is it financially benefitted from increases in energy sales. Thus,
the FCA removes a disincentive that would otherwise discourage the Company from
pursuing additional DSM programs and expenditures. The implementation of the pilot
FCA has facilitated significant increases in the Company's promotion and expenditures
to pursue energy efficiency and demand-side management programs, which have
resulted in significant energy effciency savings.
1 AARP did not intervene but filed comments opposing any extension of the FCA.
REPLY COMMENTS OF IDAHO POWER COMPANY - 2
Demand-Side Management Activities
New Annual MW Percent Total #Percent
Investment Percent Savings Increase of DSM IncreaseIncreasePrograms
2006 $11,484,013 70,766 17
2007 $15,662,378 36%91,145 29%18 6%
2008 $21,193,520 35%140,156 54%22 22%
2009 $34,846,766 64%148,256 6%24 9%
Source:2006,2007,2008,2009 Demand-Side Management Annual Reports
As the above table shows, the Company has substantially increased the number of
DSM programs and its level of expenditures for energy efficiency and demand response
programs since the inception of the FCA pilot on January 1, 2007.
Second, the FCA true-up acts to stabilze customer bils when loads are
increasing because the fixed cost component being recovered through the energy rate
is less than the total energy rate. As a result, when average load per customer
increases during a year, the average customer bil is less with the FCA than it would
have been without the mechanism.
Third, customers benefit from the FCA when loads are decreasing because it
gives the Company a better opportunity to recover more of the fixed costs it incurs to
provide electric service to customers. Regulatory mechanisms that improve the
Company's abilty to recover its costs are perceived by the debt rating agencies and
financial community as positive attributes and therefore the Company's cost of capital.
may be reduced. The Commission is aware that the Company wil be making
substantial additional investments in transmission, distribution, and generation
infrastructure in the near term. Lower financing costs wil help lower customer costs for
funding these investments. The role of the FCA in improving credit ratings is not just
REPLY COMMENTS OF IDAHO POWER COMPANY - 3
speculation by the Company. Moody's Investor Service recently improved Idaho
Power's credit rating from Baa1 negative to Baa1 stable. In its credit opinion describing
the reasons for the upgrade, Moody's specifically identified the FCA as one of the
positive attributes it considered in making its decision to upgrade the Company's credit
rating. A copy of the pertinent portions of the Moody's credit opinion is enclosed as
Attachment NO.1.
1. The FCA Is Generally Recognized As a Beneficial Regulatory
Mechanism.
All the commentors, with the exception of AARP, indicate that they support the
FCA and recognize the positive benefits customers obtain by implementation of the
FCA. In addition to the Staff and Intervenors in this case, other entities in the state of
Idaho have also acknowledged the benefits flowing from the FCA.
For example, in his March 19, 2009, letter to the United States Secretary of
Energy, written in support of Idaho's effort to obtain stimulus funds, Governor Otter cited
the fact that he "has requested that the Commission continue their successful
decouplingefforts . . . ." as evidence that Idaho deserved a share of the $3.1 billon in
federal funding for the state energy program ("SEP"). A copy of Governor Otter's March
19, 2009, letter is enclosed as Attachment NO.2.
Another instance where. the FCA was cited positively was in the Commission and
the Idaho Offce of Energy Resource's ("OER's") December 11, 2009, Joint Report to
the Legislature regarding the successful implementation of the 2007 Idaho Energy Plan
("Joint Report"). In the Joint Report, the OER and the Commission specifically identified
the fact that the Commission had adopted one of the nation's first electric decoupling
mechanisms designed to remove financial disincentives for Idaho Power Company to
REPLY COMMENTS OF IDAHO POWER COMPANY - 4
implement energy cost effciency programs. In their Report, the OER and the
Commission describe the FCA as a positive step to encourage Idaho Power to
aggressively and cost-effectively pursue energy effciency and DSM programs. On
page 10 of the Joint Report, the OER and the Commission specifieally point to the fact
that shareholders are also an important stakeholder in the Company's efforts to
aggressively pursue DSM programs. For the convenience of the Commission's review,
a copy of the pertinent section of the Joint Report is enclosed as Attachment NO.3.
In Case No. GNR-E-08-04, the Commission fulfiled its obligation under the
Energy Independence and Security Act of 2007 by considering policies that "remove the
throughput incentive and regulatory and management disincentives to energy
efficiency." (16 USC § 2621(17)(B)(i).) In that case, the Commission found that "it has
or is presently considering energy efficiency programs such as fixed cost adjustments,
tiered rates, time of use rates, seasonal rates, and decoupling" such that it has "already
adopted comparable standards for rate design modifications to promote energy
efficiency investments by utilities." (Order No. 30966 at p. 6.)
A copy of the pertinent portion of the above-referenced federal law is enclosed as
Attachment NO.4.
Finally, as previously noted, the FCA is recognized by the financial community as
a positive indication of proactive regulation. Various utilty equity analysts have
identified the FCA as a positive attribute in assessing whether or not to recommend that
their customers buy Idaho Power's stock. Enclosed as Attachment No. 5 are copies of
the pertinent portions of equity research reports from RBC Capital Markets, Wells Fargo
Bank, and Key Banc. In these examples, the equity research firms identify the fact that
REPLY COMMENTS OF IDAHO POWER COMPANY - 5
Idaho Power has a de-coupling mechanism in place in the state of Idaho as an
indication of a positive regulatory environment in Idaho.
2. The FCA Is Penorming Exactly As Intended.
During the workshops that led up to the submittal of the Stipulation which created
the FCA, the workshop participants developed a list of criteria that any regulatory
mechanism for decoupling utilty energy sales from fixed cost recovery should meet.
The criteria developed by the participants are as follows:
a. Stakeholders are better off than they would be without the
mechanism. (Stakeholders include both customers and shareholders.)
b. Cross subsidies are minimized across customer classes.
c. Financial disincentives are removed.
d. The acquisition of all cost-effective DSM is optimized.
e. Rate stabilty is promoted.
f. The mechanism is simple.
g. Administrative costs and the impacts of the mechanism are known,
manageable, and not subject to unexpected fluctuation.
h. Short-term and long-term effects to customers and Company are
monitored.
i. Perverse incentives are avoided.
j. A close link between the mechanism and desired DSM outcomes is
established.
These criteria were presented to the Commission in the Final Report on
workshop proceedings filed with the Commission on February 14, 2004. The criteria
REPLY COMMENTS OF IDAHO POWER COMPANY - 6
were subsequently noted by the Commission in Order No. 30267 when the Commission
approved the FCA pilot program. (Order No. 30267 at p. 6.)
In comparing the above-described criteria to the actual operation of the FCA, it is
clear that the current FCA mechanism meets all of the criteria established by the parties
and presented to the Commission. As the Commission noted in Order No. 30267:
Promotion of cost-effective energy efficiency and demand-side
management (DSM), we find, it is an integral part of least-cost
electric service. This case was opened to identify financial
disincentives to Idaho Power's investment and energy efficiency.
The Company proposed FCA mechanism removes a Company-
identified financial disincentive to energy efficiency and DSM
investment and is designed to reduce on a per customer basis the
utilty's dependence on revenue from stable kilowatt-hour sales.
The FCA methodology is a departure from traditional ratemaking
and merits a cautious approach to implementation. The annual
FCA true-up mechanism assures a more stable utilty recovery of
fixed costs that are now recovered in the energy rate component of
residential and small general service customers. (Order No. 30267
at p. 13.)
The Commission went on to say in Order No. 30267, liMa king the Company
indifferent to reduced energy consumption and demand is but one-half of the quid pro
quo agreed to by the stipulating parties. In return for the FCA, the Company is
expected to demonstrate an enhanced commitment to energy efficiency and DSM."
(Order No. 30267 at pp. 13-14.)
The pre-filed testimony of Mr. Sparks provides verifiable evidence that the
existing FCA meets both prongs of the test for demonstrating the effectiveness of the
FCA the Commission described in Order No. 30267. First, the FCA provides a
symmetrical (surcharge/credit) when fixed cost recovery per customers varies above or
below a Commission-established base. As Mr. Sparks notes in his testimony on page
12, due to the operation of the FCA, customer rates were reduced in 2007 and
REPLY COMMENTS OF IDAHO POWER COMPANY - 7
increased in 2008. As a result, the Company has become indifferent to reduced energy
consumption and demand from the participating customer classes. Idaho Power's
recovery of fixed costs is more stable as are its customers' bils. This stabilzing effect
has been noted by the financial community as a positive regulatory approach. (See
Attachments Nos. 1 and 5.)
The second prong of the Commission's test of the effcacy of the FCA is whether
or not the Company has complied with its commitment to increase its energy efficiency
and DSM efforts. The evidence clearly demonstrates this is the case. Mr. Sparks' pre-
filed testimony in this case provides a detailed description of the numerous new and
expanded DSM and energy efficiency programs that the Company has initiated since
the FCA was implemented. As the bar chart provided below shows, there is no doubt
that removal of the acknowledged disincentive by the FCA has had the desired effect of
stimulating the Company's DSM efforts.
Number of DSM
Programs
MWh Savings New Investment
$34,846,766
140,156 148,256
$21,193,520
$15,662,378
$11,484,013
22 24
II 2006 II 2007 II 2008 lI 2009 II 2006 II 2007 II 2008 II 2009 II 2006 II 2007 II 2008 II 2009
3. Removal of the Disincentive to Promote Cost.Effective DSM Benefits
Customers.
In its Comments, Staff acknowledges that customers benefit when the Company
acquires DSM energy savings at costs that are lower than the alternative supply-side
REPLY COMMENTS OF IDAHO POWER COMPANY - 8
resources. (Staff Comments at p. 11.) As a practical matter, this disincentive extends to
other load reducing activities as well, including customer education and information,
support for revised building codes and standards, and pricing consistent with energy
effciency. Staff also acknowledges there is a financial disincentive for the Company to
pursue cost-effective DSM when doing so reduces recovery of prudently incurred
Commission-approved fixed costs. (Staff Comments at pp. 2 and 11.) While the
Comments of the Staff and Intervenors all support continuation of the FCA, they also
argue that the FCA should be continued as a pilot program rather than making it a
permanent program as Idaho Power has requested. In support of their recommendation
for continued pilot program status, ICL, Staff, and CAPAI all identify a number of
questions and uncertainties that they claim have not been resolved during the term of
the pilot program. For the most part, these are the same questions and uncertainties
that were initially raised in Case No. IPC-E-04-15. For example, throughout the entire
course of the workshops and negotiations that ultimately led to the Stipulation, one of
the questions that was addressed at length was how can we be sure that an increased
level of conservation activity by the Company is a direct result of the FCA?
In this proceeding, the Comments of Staff, ICL, and CAPAI all spend a
considerable amount of time discussing the different reasons why customer loads could
increase or decrease that do not relate to DSM activities. Some of these non-DSM
related variables include building code changes, federal weatherization programs, tax
incentives and appliance rebates, federal marketing programs, technological changes,
substitutions between gas and electric equipment, rate design changes, shifts in the
economy, and other behavioral changes. Idaho Power can assist in promoting many of
REPLY COMMENTS OF IDAHO POWER COMPANY - 9
the above-mentioned non-DSM program initiatives that benefit customers. The
Company should be encouraged to pursue all legitimate load reducing activities and the
FCA mechanism should appropriately capture all of the impacts to fixed cost recovery
that flow from these activities. Removing as many disincentives to load reduction
activities as possible is in the public interest.
4. Simplicity Benefits All Stakeholders.
During the workshops that led up to the Stipulation that was approved by the
Commission in Order No. 30267, all of the parties acknowledged that developing a
"decoupling" mechanism like the FCA would always be a tradeoff between complexity-
continuous analysis to provide some evidence that the FCA was the predominant driver
of load reductions directly related to utilty DSM programs-and simplicity-a decoupling
program somewhat less rigorous in its analytic approach but more manageable and less
prone to unintended and even perverse consequences. In the end, the parties agreed
that simple is better and filed the Stipulation implementing the FCA. Unfortunately, the
Comments of Staff, CAPAI, and ICL seem to be urging the Commission to return to the
path of complexity. Staff recommends that the pilot program be extended for two years
and during this time the Company began "isolating the impact of these changes on
residential and small general service consumption by conducting price elasticity,
economic, load research, and end-use market research studies." (Staff Comments at p.
12.) CAPAI and ICL recommend that the pilot program be extended for one year. Like
Staff, CAPAI and ICL recommend that numerous new studies, analyses, and workshops
be undertaken to address the issues raised in their respective Comments. Staff, ICL,
and CAPAI all recommend that the Commission reject Idaho Power's request to make
REPLY COMMENTS OF IDAHO POWER COMPANY - 10
the current FCA permanent. Idaho Power questions whether undertaking multiple new
analyses, studies, and workshops wil really produce results that are meaningful to the
purpose of the FCA. Idaho Power acknowledges that there wil always be a number of
variables, such as those cited above, that would change the Company's loads, either
positively or negatively, that are not directly related to DSM activities. Expending
substantial time and resources attempting to precisely parse the relative contributions to
load increases or decreases of all the potential variables does not seem particularly
usefuL. The evidence is clear that the FCA is doing what it was intended to do. The
FCA has disconnected the recovery of fixed costs from volumetric energy sales, thereby
eliminating the disincentive for the Company to pursue DSM and other load reducing
activities. It has induced the Company to faciltate its DSM programs in a very material
way. It provides rate stabilzation. The FCA is doing all of those things with a simple,
straightforward mechanism, consistent with the agreed-upon criteria that a decoupling
mechanism should be simple. While additional analyses related to specific
costs/benefits may be appropriate in a performance incentive mechanism, they are not
adding value to an FCA mechanism whose basic purpose is to true-up fixed cost
recovery.
II. MAKING THE FCA PERMANENT WILL BENEFIT CUSTOMERS
5. Making the FCA Permanent Does Not Preclude Future Adjustments.
While the evidence shows that the FCA is working as intended, Idaho Power
concurs that some fine tuning of the mechanism may be reasonable. However, there is
no reason that any additional analyses, studies, and workshops cannot be undertaken
after the Commission has made the FCA program permanent. Idaho Power has made
REPLY COMMENTS OF IDAHO POWER COMPANY - 11
a number of material adjustments to its power cost adjustment ("PCA") true-up
mechanism after the mechanism was approved on a permanent basis, A permanent
FCA can be adjusted in the same way.
A good case study of how an adjustment to a permanent FCA would work is the
FCA-LGAR issue raised by Staff. In its Comments in this case, Staff noted some
concern regarding the interaction between the load growth adjustment rate ("LGAR") in
the Company's PCA and the FCA. In Rocky Mountain Power's PCA case, PAC-E-10-
01, the Staff noted the same concern. In Order No. 31033, the Commission directed
the Staff to hold a workshop for Idaho Power, Avista, and Rocky Mountain to discuss the
LGAR and, in Idaho Power's case, the FCA mechanism. As this demonstrates, even if
the FCA is a permanent rate schedule, ample opportunity exists to address situations
like the FCAILGAR question as they arise.
6. There is Risk in Continuing the FCA as a Pilot Program Rather than
Granting It Permanent Status.
As the Commission noted in Order No. 30267, "The annual FCA true-up
mechanism assures a more stable utilty recovery of fixed costs that are now recovered
in the energy rate component of residential and small general service customers."
(Order No. 30267 at p. 13.) The stable utility recovery of fixed costs referenced in the
above quote rests on a foundation of predictabilty and certainty. Denying permanent
status for the FCA and instead continuing it as a temporary pilot program reintroduces
the element of uncertainty. Is the disincentive that everyone agrees exists really going
to be eliminated?
Fortunately, the Company, the Commission, and the Intervenors ean have it both
ways. The Commission can approve the FCA as a permanent program while at the
~
REPLY COMMENTS OF IDAHO POWER COMPANY - 12
same time allowing the stakeholders to explore potential adjustments to the mechanism,
based on new evidence and experience, which maintains the integrity of the FCA.
There is risk in continuing the FCA as a pilot program rather than granting it
permanent status. Credit rating agencies and stock research analysts view the FCA
favorably. (See Attachment Nos. 1 and 5.) Continuing the FCA in a pilot project mode
adds an element of uncertainty to the Commission's long-run commitment to the FCA.
Allowing the FCAto become a permanent mechanism with the understanding that there
are some aspects of the mechanism that should receive further consideration, and
perhaps adjustment, would be beneficiaL. Maintaining the program in limbo is not
beneficial.
7. Changing the Way the FCA Is Presented on Customer Bils Wil
Confuse Customers.
To reduce customer confusion, Staff recommends that the FCA be removed from
the Energy Efficiency Services line item and combined with the PCA to form an "Annual
Adjustment Charge." The Company believes this change would actually be more
confusing to customers as these adjustments can easily go in opposite directions.
Idaho Power's preference would be to leave the bil presentment of the FCA as it is for
now, ,particularly if there wil be follow-up regulatory activity related to the FCA
mechanism. If the Commission is persuaded to make a change to bil presentation at
this time, the Company's believes that a separate line item for the FCA is preferable to
combining its impact with the PCA.
IV. CONCLUSION
Idaho Power's FCA has operated as intended during its three-year pilot period.
The FCA's principal purpose of removing disincentives to energy effciency investments
REPLY COMMENTS OF IDAHO POWER COMPANY - 13
and other load reducing activities undertaken by the Company to benefit its customers
has been accomplished. The proof of this accomplishment is increased energy
efficiency activity, higher levels of customer education, and new pricing initiatives - all
targeted at using electricity wisely. The disincentive is removed by essentially creating a
new residential/small commercial rate design where fixed costs are recovered based
upon customers served versus kilowatt-hours consumed.
The mechanism meets the criteria established during the original workshops.
Customers are better off because lower cost options are pursued vigorously and bils
are stabilzed. The Company has an improved fixed cost recovery mechanism which-
absent the abilty to dramatically change its pricing structure-lowers risks. The
mechanism is simple, symmetrieal, easy to administer, and has not resulted in any
unintended consequences. Disincentives have been removed and energy effciency
activities enhanced. Its implementation has been widely acknowledged as a positive
regulatory policy.
Idaho Power maintains it is time to make the mechanism permanent. The
Company welcomes opportunities to enhance the FCA through future collaborative
efforts and accepts the challenge of doing a better job of explaining the mechanism to
customers and other interested parties.
DATED at Boise, Idaho, this 9th day of April 2010.
~~BARTOîì
Attorney for Idaho Power Company
REPLY COMMENTS OF IDAHO POWER COMPANY - 14
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 9th day of April 2010 I served a true and correct
copy of the foregoing REPLY COMMENTS OF IDAHO POWER COMPANY upon the
following named parties by the method indicated below, and addressed to the following:
Commission Staff
Weldon B. Stutzman
Deputy Attorney General
Idaho Public Utilties Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
-X Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-X Email Weldon.stutzmanaypuc.idaho.gov
Snake River Allance
Ken Miler
Snake River Allance
P.O. Box 1731
Boise, Idaho 83701
Hand Delivered
-X U.S. Mail
_ Overnight Mail
FAX
-X Email kmileraysnakeriveralliance.org
Community Action Partnership
Association Of Idaho
Brad M. Purdy
Attorney at Law
2019 North 1 ¡th Street
Boise, Idaho 83702
Hand Delivered
-X U.S. Mail
_ Overnight Mail
FAX
-X Email bmpurdyayhotmail.com
Idaho Conservation League
Ben Otto
Idaho Conservation League
710 North Sixth Street
P.O. Box 844
Boise, Idaho 83701
Hand Delivered
-X U.S. Mail
_ Overnight Mail
FAX
-X Email bottoayidahoconservation.org
ß~
Barton L. Kline
REPLY COMMENTS OF IDAHO POWER COMPANY - 15
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-09-28
IDAHO POWER COMPANY
ATTACHMENT NO.1
M()iisINVESTORS SERVICE
Credit Opinion: IDACORP, Inc.
Global Credit Research. 31 Mar 2010
Boise, Idaho, United States
Catgor
Outook
Issuer Rating
Sr Unsec Bank Credit Facilit
Senior Unsecured Shel
Commercial PaperIdaho PO'r COl
Outoo
Issuer Rating
First Mlrtgage Bonds
Senior Secured
Sr Unsec Bank Credit Facilit
Senior Unsecured Shelf
Commercial Paper
Moos Rang
Stable
Baa2Baa
(P)Baa2
P-2
Stable
Baa1
A2
A2
Baa1
(P)Baa1
P-2
Anly
Kevin G. Rose/New Yok
William L. Hes/New York
Phon
212.553.0389
212.553.3837
(1)IDACORP Inc.20 20 207 20
(CFO Pre-W/C + Interest) /Interest Expnse 4.5x 2.7x 2.2x 3.5x
(CFO PreW/C) / Debt 19%100Ái 6%14%
(CFO Pre-W/C - Divdends) / Debt 16%7%3%10%
Debt / Book Capitalization 46%47%45%43%
(1) All ratios calculated in accordnce with the Regulated Eletrc and Gas Utilities Rating Metholog using M:y's
standard adjustments
Note: For definitons of Moody's most common ratio terms please see the accompanying User's Guid.
Rang Driers
Dominant inflce of regulated utility subidiary wit relatiely low busines risk profile
f\re regulatory support through base rate increases and improvements to cost recovery mechanisms
Signifcant planned utlity capital expenditures suppored in part through Senate Bill 1123
Stronger credit metrics and Hquidit expected to remain sufcient
Coporae Prole .
IDACORP, Inc. (IDA) is a holding company whoe principa oprating subsidiar is Idaho Power Company (IPC), a
fully integrated regulated electrc utlit. On a standne bais, IPC repents the substantial majotity of IDA's
consolidated revenues, net incoe, and asset. IDA's ot subidiar include: IDACORP Financial Serces, an
investor in afordable housing projects an oter rea estate invetmen; and Ida-West Energy, an operator of nine
small hydrolectric geraton projects that satsfy th reuireent of th Public Utlit Regulatory Policies Act of
1978. IPC's servce territory encompasses soutern Idaho and eastern Oregon and its rates are regulated by the
Idaho PubHc Utilities Commission (IPUC) and the Oregon Public Utlit Commission (OPUC).
SUMMAR RAING RAIONALE
IDA's Baa2 senior unsecured debt rating primarily re~ects our assessment of key factors affecting the credit quaHty of
IPC (Baa1 senior unsecured debt rating), which is it single largest subsidiary. The rating also takes into account the
strctural subordination of IDA's obligations in right of payment to those of IPC and other subsidiaries. IPC's Baa1
senior unsecured rating reflects its reltively low busines risk profile, the company's cost advantage over most of it
national pers, and the improved cost recovery treaent it ha ben receiving from stae regulators in both
jurisdictions, partculary as it relates to several reula deisions in 20 and earl 2010. Key credit metrics
strengthened signifcant in 2009 and shold be sustainable fo 2010, despie the ongoing financial and operating
risks of executing a large capita program. Hyro conit reain a key rating concem given the extent of IPC's
dependence on hydroectric facilites, as doe th higher than histocal avere planned capit spending, even as
some projets have exprienc curtilment or delys. M:er, cotinue conservive financing strtegies will be
necessary to sustain the company's improed credit metcs, which rebonde in 2009 to leves more in line with
peers in the Baa1 rating category. To accomplish this, continued support from state reulators in anticipated future
general rate cases wil also remain an importnt rating driver.
DETAILED RAING CONSIDERAIONS
LOW BUSINESS RISK PROFILE OF DOMINAT UTILIT SUBSIDIAY
The low busines risk profile of IDA's largest subsidiary, IPC, is infuenced by its heavy reiance on low-cost hydro
electric power for its generating needs. IPC normaH generates nearl half of its electricity from 17 hydro-electrc
developments on the Snake River and it tributries. IPC also serves a portion of its electr load from three coal-fired
power plants in Wyoming, Neva, and Oreon, and from the natural-gas fired Bennett f\untain Power Plant and the
Evander Andrews Power Complex in M:ntain Home, Idaho. IPC is also the parent of Idaho Energy Resources Co., a
joint venture parter in Bridgr Coal Company, which suppie coal to the Jim Bridger generating plant owned in part
by ¡PC. Moeover, IPC is not burdene with supportng any materal debt load at the IDA level. IDA diveted most of its
prior investments in riskier nonregulated businesses during a three-year period covering 2005 - 2007, and has since
made IPC its principal focus. The remaining non-reulated invetments, which are relatiely immaterial to our
analysis, include independent power production at Ida-West Ener and affordable housing at IDACORP Financial
Servces.
SUPPORTIV REGULATORY ENVONWENT BODES WELL FOR CREDIT QUALIT
Favorabl regulatory practices in Idaho (IPC's principal jurisdicti), include: 1) a relatiy swif 7-month statutory
period goveming rate cases; 2) frequent deisios based on settent instead of Htited proceeings; 3)
reasonable allowed returns on equity 4) reliance on various cost trcking and adjustment mechanisms, periodic
utlization of single-issue rae cases and partally forecast test yers to avoid undue rate lag; and 5) pre-approval of
fure rate treatment for cern capital invetments aDowed under state law.
SUCCESSFUL INITIATIVS NOTED FOR 209...
IDA's consolidated credit qualit will continue to be infuenced in part by the fact tha the IPUC approved a total of
4.01 % (about $27 minion) in general rae increases for IPC during the first quarter of 2009, which reflected the
outcome of the utiltys 2008 general rate case filing. While this was about 40% of the $67 millon requested, the
decision was based on an aHowed return on equity of 10.5% (in Hne with many other jurisdictions) and did include
collection of about $10.6 millon for AFUDC associated with hydro relicensing construction activit. Also, in May 2009
there were several favorable rate orders from the Idaho and Oregon commissions combined to address various other
requests for revenue increases. These orders collectively approved rate increases of about $135 million effective
June 1, 2009 and contributed to a solid rebound in IPC's and IDA's financial results for the year. Mleover, Seate Bill
1123 (SB 1123) beame efective 7/1//2009. Under SB 1123, the IPUC may grant pre-approval of rae treatment for
certin utlit capital expnditures. We generally view pre-approval of rate treatent for a utiltys fuure capital
programs as a credit positie given the degree of assurance it would provide for cost recovery and the abilit to eam a
rate of return. (See below for furter details on how SB 1123 was favorably applied to IPC's capex program).
The most signifcant of the May 2009 rate orders was the power cost adjustment (PCA) rate decision. Specifcally, th
IPUC approved the full amount of IPC's PCA filing, which amounted to $84.3 milion above the current PCA rate.
Importntl, IPC was able to use its most reent operating plan to forecast power supply expses rather than the
previous method based on forecast Brownlee Reservoir infow and a regression formula. This change became
effective in Februar 2009 after the IPUC agreed with IPC that the utilits plan was a better indicator of anticipaed
expenses and should create a better matching between actual costs incurred and the amounts in customers' rates.
This practice will continue in future PCAfilings; accordingly, fuure PCAbalances should be considrably less and
thereby reduce cash lag. M:reover, the IPUC revised the sharing formula under the PCA mechanism to 95%/5%
(customers/shareholders) frm 900/0/10% previously, threby reducing risk to investors. Lastly, the lod growhadjustment rate (LGA) is now determined formulaically based on total production expenses included in current base
rates, which reduces regulatory risk previously associated with the LGA. The current LGAR of $26.63 per MIh is
reduced from the $28.14 per MIh level that would otherise apply based on the formula agreed to by partes in an
earlier approv stipulation. The signifcance of the LGA is that it adjusts IPC's net power supply costs tht are
included in the annual PCA filings for diferences betwee actual load and the load used in calculating existing bae
rates. The combination of anticipated better matching betwee actual net poer supply costs incurred and load
growh experienced with levels assumed in setting existing rates should allay concerns abo potential negative
effects on IPC's earnings and cash flow when larger mismatches occur.
The other revenue increases approved in May 2009 included: 1) an approved increase in IPC's Energy Effciency
Rider to 4.75% from 2.5%, establishing assurance for cost recovery of varius energy effciency programs; 2) -1
adjustments under IPC's decoupling program aimed at de-linking revenues from volume: 3) revenue requirements to
cover investments in advanced metering infrastructure; and 4) rate adjustments under the power cost adjustient
mechanism in Oregon.
...AND tvRE SUCCESS APPARENT TO DATE IN 2010
In lieu of filing another signifcant general rate case in Idaho in 2009, IPC successfully negotiated a settment that
was approve by th IPUC on 1/14/2010. We view this result as a creit poitive as we believe it fortifes the
collaborative workng relationship with the IPUC, which is a heavily weighted factor in our Regulated Electric and Gas
Utilities Rating Methodology pUblished in August 200 (the Rating Methodology). Alough the settlement includes a
two-yer base rate freee through 1/1/2012, it does not preclude the expted PCAand other rate mechanism filings
that wil occur regularly. Several other key features of the setuement included; 1) planned distributs of a portion of
the expted 2010 PCAdecrease to customers, with the balance returned to IPC to provide rate relief; 2) a means to
reset base net power supply costs for future PCA filings; 3) approval to use accelerated amortization of invetment
tax credits to achieve an ROE in the Idaho jurisdiction of 9.5%; and 4) a shanng mechanism for Idaho based earnings
in excess ofthe allowed 10.5% ROE.
In the smaller Oregon junsdiction, IPC was able to favoraby setue it rate case onginally filed in July 2009, when a
proposed setuement was approved by the OPUC on 21412010. The approval allowed IPC to increase it base
electnc ra in Oregon by $5 million effectie 311/2010, based on an allowed ROE of 10.175% and an assumèd
49.8% equit component in the capitl strcture. The alowed ROE compares favorably to IPC's former allowed ROE
in Oregon of 10%.
CAPEX PLA REMAN SIGNIFICAN EVEN p. TRAMSSION PROJECTS UNFOLD SLOWLY
IDAhas scaled back it planned utlityrelated capitl spending in line with economic conditions. Still, the level of
spending could excee $1.0 billion over the next three years as the company is moving ahead with construction of the
30033 megawatt natral gas plant at Langley Gulch. The estimated expnse for that project aJ is $427 million
including AFUDC, which could be in service by 7/1/2012. The IPUC approved a certcate of public convenience and
necessity (CPCN) for this plant in September 2009. In granting the CPCN, the IPUC relied upon SB 1123 to pre-
approve inclusion of up to $396.6 million of construction costs in IPC's rate base concurrnt with the commercial
operation date for the Langley Gulch plant. We view this pre-pproval as creit poite because it reduces the
reulatory and financial risk that would othrwse be associated wit this investment. Importntly, any investment in
excess of the prapproved amount would not necessanly be disallowed, but recovery of and return on the excess
would be subject to a separate rate proceeing. Other than the earl stage spending relating to two major
transmissionprojects (i.e. Boardman to Hemingway and Gateway West), IPC's capex budget for 2010 - 2012
includes ongoing investments in other basic utlity related distnbuton and geeral infrstructure, including advanced
metering infrastrcture.
We understand management reassessed the capi program during 2009, resultng in delays related to th 500 kV
Boardman to Hemingway Line, which stretches out th spendng to later yers and reduces near term financing
needs. IPC still expects to seek parters for up to 50 to 70 percent of this prject, which would further reduce capitl
needs.
As in the past, a mix of debt and equit infion from ÐA is exted to be used to meet external funding required
while targeting a capitl strture comprised of a peent of debt and equit close to current levels. Also, given the
level of planned capex, we expect that IPC will likel need to file for additonal general rate increases to take effect in
Idaho once the settlement peiod under its current rate agreemen expires.
KEY CREDrr tvTRICS HAVE STRENGTHENED; VOLATIUTY OF PAST YEARS SHOULD SUBSIDE
A variety of factors contributed to substantial strengtening of IDA's key credit metrics in 2009, including general rate
relief, cash recovery of regulatory assets, and favorable impact to cash flow from deferred income taxes and
investment ta credit. Specifcally, IDA's CFO Pre-W IC plus interest to interest and CFO Pre-W IC to debt for FY
2009 were 4.5x and 18.9%, respetively, bringing them to a level considered strng vis-' -vis it Baa2 rating according
to the Rating Methodoly. Alhough the level of IDA's metrcs continues to be constrained by a fairly significant
standard adjustment for undennded pension obligtions, th undennde pension poition is not cause for undue
concern at this stage because the IPUC provi for timel re of cash contrbutons through the rate process.
Menwhile, IPC is also in discussio with the IPUC abo establishing a trcking mechanism for pension expenses.
Also, as the effects of IPC's 2010 setment take effect ovr the balance of this year and as other regularly scheduled
rate adjustments occur, we antiipae that IDA's CFO Pre-WIC plus interet to interest an CFO Pre-WIC to debt
coverage metrics can be maintained close to FY 200 levels, respecely, for FY 201 O.
IDA's debt leverage ratio stood at 46.1% as of 12/31/2009. This level represents a slight improvement compared to
the 47% at 12/31/2008, as higher retained eamings and additional common equit sold in 2009 offset the slight
increase in debt. Impoantly, the metrc is comfortbly positioned relative to the range that we tyically observe for
Baa-rated holding companies with predominantly regulated electric utility subsidiaries under the Rating Methodology.
Even if debt levels creep slightly higher as capex is funded, management remains committed to keeping close to the
current mix of debt and equity in its capital structure.
Uquidity
On balance, IDAhas sufcient liquidity, including cash on hand, divdends peically provided by IPC and its other
operating subsidiaries, plus ample unused capacit under commited bank facilities at the parent level and at IPC. IDA
maintains access to short-term funding and alternati liquidity for commercial paper outstanding through a $100
million facilty, which terminates on April 25, 2012./J February 19, 2010, thre were no borowings under IDA's facilit
but $25 milion of commercial paper was outtanding. The IPC facility is currntly a $300 million credit agreeent that
terminates on April 25, 2012. /J February 19, 2010, no loans were outanding on IPC's facilit nor was there any
commercial pape outstanding. The only financial covenant in each facilit limit the debt to totl capitlization ratio as
defined to 65%. /J December 31, 2009, the leverage ratios for both IDA and IPC were 51 % and 53%, respectiely.
IDAhas attempted to minimize it reliance on short-term debt, especially in support of capital expenditures at IPC,
through the periodic issuance of common equit. We expect that this strategy will continue, including in part through
issuance of common stock under a continuous equity program and from divdend reinvetment proram (DRIP)
common stock offerings. Over the next four quarters, we expect IDA's commercial paper amounts outstanding will
continue to be influenced primarily by the timing of ta payments and divdends to shareholders. IDA has no
standalone long-term debt outstanding and no plans to issue holding company long-term debt in the foreseeble
Mure. IPC has a fairly manageable debt matunt schedule over the near term. The utilits next scheduled debt
maturities are in March 2011 when $120 millon of FlIs are due and Novembe 2012 when another $100 millon of
FlIs mature. We understand that management plans to explore market opportunities to pre-fund the scheduled 2011
maturity this year. Menwhile, IPC's issuance of $130 million of FIIs in 2009 effectively prefunde the long-term
financing needs for 2010. Looking forard, constrtion of the Langley Gulch plant primarily drives the capitl nees in
2011 and 2012 and we assume conservative financing strtegies will continue to guide Mure funding.
Raing Outlook
IDA's stable rating outook mirrors the stable outook for IPC, its principal subsidiary. IPC's stable rating outlook
reflects more supportive regulaton, especially in Idaho, which should help avoid past volatilit in key metrics, instead
keeping them closer in line wit similarly rated peers. The execution risks associated with ongoing capital spending
projects and external financing nees are tempered by assurances of Mure rate treatment for the Langley Gulch plant
and anticipated conservative funding strategies. The stable rating outook for IDA also takes into account the fact that
IPC provies th substantial majority of the parent's earnings and cash flow. ÄS a result, IPC substantiaUy drives th
credit rating and outook of its parent.
V\ Could Chage th Raing - Up
Because DA is largely dependent on IPC for cash flow in th form of dMdends, any improvement in the parent's
ratings will be considered largely in the context of our assessment of IPC's credit qualit. Alough a rating upgrade is
unlikely in the near term, DA's outook could tum to positive if the benefi from recent rate relief for IPC carr through
and thee are no material changes in the deree of regulatory supportiveness in IPC's future rate filing. In terms of
key metrics, the outk could tum to poite if CFO Pre-WC plus interest to interest and CFO Pre-W/C to debt, on a
three-year average basis, can be sustained above 3.5x and 15%, repectively.
Wh Could Change the Raing - Down
The rating could be revised down if the improved regulatory support for IPC wanes or if conservatve funding
strategies are not adhered to, thus contributing to undue pressure on IDA's key metrics. For example, if IDA's CFO
Pre-W/C plus interest to interest and CFO Pre-W/C to debt metrcs fall below 3.5x and 15%, respectivey, for an
extended period of time, then a downgrade could occur. A rating dongrade could also occur if the company
manages it significant utility capex program in a manner that is inconsistent with it current credit profile. Alo, any
unexpcted shif by IDAto material debt-financed invetments in other non-utilit businesses, or a material
acceleration of the utlitys capex program wherein IDA's consolidated debt level is increased signifcantl above its
current level and inflates its debt/capitalization ratio to well above 50% on a sustainable basis, could lead to a negativerating action. .
IDACORP Inc.
Facor 1: Regulatory Framewok (25%)
Facor 2: Abilit to Recover Cos and Ear Returns
(25010)
Factor 3: Diversifcaion (10%)
a) Market Positon (5%)
b) Generation and Fue Diversi (5%
Facor 4: Financal Stngh, Uquidit an Key Financal
Metrcs (40%)
a) Uquidit (10%)
b) CFO pre-WC + Interest /lneterest (7.5%) (3yr Avg)
c) CFO pre-WC / Debt (7.5%) (3yr Avg)
d) CFO pre-WC - Dividends / Debt (7.5%) (3yr Avg)
e) Debt / Capitlizatin or Debt / RAV (7.5%) (3y
"-Rang: .
a) Methodoly Implied Senior Unsecured Rating
b) Actual Unsecured Rating
x
X
X
x
X
X
x
X
X
BaBa
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BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-28
IDAHO POWER COMPANY
ATTACHMENT NO.2
l- ..
APPENDIX I
c. L. "BUTCH" OTTER
GOVERNOR
Mah 19, 20
The Hoporale Steven ebuSecr .
U.S. Deent ofBnei
1000 IndenCe Aven, S.W.
. Wasgt D.C. 205.85
\l.FACSIM & U.S.MA
Re: The Ståte ofIdalo's Energ Pr ÅSurce
Dea Sec Chu,
-k-¥ ''Prtheir obligaons 't'rifi Ju,.:im.~~~:.. ~. the pii ..a. .J.~~ ~:Wï.n the ap r. . .
----- sta ag åJ reeS tl lhéy eèøi. aiØn to .ve buiJdmg ~ .èO; CÓsiiì Wi i:ta Ja andState Cansona reuits and tò Còide the.sttUbf ~e i;~.in ARRA.
. We ar Pnorg.~úi,tnërgy inv~.to.ta ~ ofe~.~~ ln.~ pi ~~ .
( apro. Our St is coi~J6.~ rò~.biiy~"ei in ~.~c.êi~ ,li(l ~~e..éner, as Wen8S a ...
baanc~ 8ta en policy. I wa to as yo1Í tl Within.tlò 'lils .~f ö...;nor, we wi mo:y for in thesecriticà ar . '
We lok forw to imedte øi'butíon of th Fed.SB.W to~~.~y st to mak _ inenergy effciency and reewable ener. . ..
AS Alys - Idao, "B Pee.. .. :..... .
. ",'
CLOfsg..CL. "Butch" Ot
Govor ofIda
cc: Gi SpeligDi, 9fce ofWeaon and Inteoverenta Prgr
. U.S. Deen of Energ .
.Sta Ener Diror:David Ter, Exutve Dirr
Naton Asaton of Sta l?~ Offcias
STATE CAPITOL. BOISE, IDAHO 83720. (208) 334~210j)
/
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-28
IDAHO POWER COMPANY
ATTACHMENT NO.3
~'
December 11, 2009
Senators and Representatives,
The 2007 Idao Energy Plan, wrtten in compliance with House Concurent Resolution
62, directs that the "Energy Division (now the Offce of Energy Resources) and the
Public Utilities Commssion should report to the Legislatue every two years on the
progress ofIdao state agencies, energy providers and energy consumers implementig
the recommendations in this Energy Plan." (Action Item 1-3, page 65,2007 Idaho Energy
Plan)
The Office of Energy Resources and the Public Utilties Commission, acting jointly,
hereby submit the 2009 report. We consider this biennial fiing to be a critical component
to helping achieve the state's goal of ensurng a reliable, low-cost energy supply,
protecting the environment and promoting economic growth. Filng this report every two
years, as the Energy Plan requires, wil help us evaluate our progress and set futue goals.
You wil find that we firmly believe the State is mang progress in meeting many of the
plan's objectives. We also do not hesitate to point out those areas where some of the
plan's recommendations are best met with other approaches and methodologies.
As stated in Energy Plan's introductory letter from the Interim Committee on Energy,
Environment and Technology, "Idao's existing energy resource base has resulted in
some of the lowest electrcity and natul gas prices in the countr, providing enormous
benefit to customers." To maintain that benefit and yet meet the significant challenges of
the futue to provide energy supply at reasonable rates, the Office of Energy Resources
and the PUC concurs with the Committee's statement that we need a "pragmatic,
common-sense approach." We believe that the actions taken thus far, and those planed,
wil prepare us well for the futue.
Sincerely,
Paul Kjellander
Director, Idaho Office of Energy Resources
Jim Kempton
President, Idao Public Utilities Commission
2
conservation and renewable resource investments and in calculatig payments to
qualying facilties under the federal Public Utility Regulatory Policy Act (pUR A).
Because avoided cost is defmed as the cost of the next unit of power a utilty would
acquire if there were a need for additional generation, it is often argued that avoided cost
used to value a qualifying small-power PUR A project should also be used to evaluate
cost-effectiveness of proposed conservation projects or renewable resource options.
Under this proposition, it is logical to suggest that an "avoided cost benchmark" for each
utility could be established and updated periodically. In actul practice, the benchmark
concept is oversimplified.
To accommodate small (IOMW or less) PURA projects in Idao, the Commission has
established a published avoided-cost rate based on a surogate avoided resource (SAR)
that is curently defined as a combined-cycle combustion gas tubine. Ths over-
simplified methodology works relatively well for small base load-tye resources. It does
not work well for varable renewable energy resources because of the difference in SAR
operating characteristics. Instead, the utility uses its Integrated Resource Plan process
with actual planed resources and forecasted market prices to establish an avoided cost
for each proposed renewable project. The IR and its various parameters are published
and periodically updated. The avoided cost associated with this methodology more
accurately reflects the generation costs that a utility expects to avoid by acquirg any
other resource regardless of operating characteristics. It also forms the basis of the cost-
effcient resource acquisition calculations conducted to meet the stadads of E-I.
Published PUR A avoided- cost rates for small qualifying facilties were most recently
updated in March 2009 in response to a joint petition from the investor-owned utilties
and other paries to I) update the non-fuel cost components of the SAR and 2) reflect the
new natual gas price forecast from the Nortwest Power and Conservation Council?
Utility IRs used to determine actual planed generation costs avoided by proposed
renewable resources are updated every two years.
The PUC is continuously evaluatig both the processes used by utilities to deliver
demand-side programs and the assumptions and measurements used to determe cost-
effectiveness. The Commission is curently working with utilties to establish procedures
to anually report demand-side process improvement and to periodically update program
impact evaluation, measurement and verification (EMV) practices.
- The Idaho PUC should establish appropriate shareholder incentives for
investor-owned utities that achieve the conservation targets established by the
PUC. Shareholder incentives may include, but are not limited to:
i. Recovery of revenues lost due to reduced sales resulting from conservation
investments;
ii. Capitalization of conservation expenditures;
No. GNR-E-08-02, Order No. 30744. For press release, see Appendix C.
8
iii. A share of the net societal benefits attributable to the utility's energy effciency
programs;
iv. An increase in the utility's return on equity for each year in which savings targets
are met; or
v. "Decou piing" of utilit revenues from sales. -t
The PUC has not established "conservation tagets" as explained under E-2 except to
"achieve all available DSM, conservation and energy effciency."
However, in March 2007, the Commission adopted one of the fist electrc decoupling
mechanisms in the nation designed to remove financial disincentives for Idao Power
Company to implement energy efficiency programs. (Case No. IPC-E-04-15, Order No.
30267) The Fixed Cost Adjustment (PCA) is a mechanism that separates utility sales ''\
from revenues by allowing Idao Power to recover its fixed costs of providing power, as ~
established in the most recent rate case, regardless of reduced sales due to energy
efficiency and demand side management programs. In exchange for allowig Idaho
Power this recovery, the utility committed to aggressively and cost-effectively pursue
energy efficiency and demand side management programs. Idaho and the PUC are soon
to be in the final year of a thee-year pilot and Idaho Power has applied to have the FCA
made permanent. 3
each of the three major investor-owned utilities has energy efficiency riders in
place that allow them to recover costs of demad-side management, conservation and
energy efficiency programs. The Commission has been wiling to grant utility requests to
significantly increase these riders over recent years to encourage conservation, energy
effciency and DSM.
On June 1,2009, the Commission increased the Idao Power rider from 2.5 percent to
4.75 percent. According to Idao Power's application, energy effciency programs in
2008 resulted in 107,484 megawatt-hours of energy savings, a 72 percent increase over
the 2007 total of 62,544 MW. DSM programs that reduce demand on Idaho Power's
system provided 58 megawatt of demand reduction in 2008 compared to 48 MW in
2007.4
The commission recently completed a review of Avista's DSM and energy effciency
programs in conjunction with its earlier approval of an increase in the rider from 2.24
percent to 3.27 percent. Avista's DSM and effciency efforts are based on providing
fmancial incentives or rebates for customer parcipation in more than 30 programs.
A vista continues to exceed tagets in electrc and gas savings as the result of these
programs for its Washington and Idao customers. More than 110 average megawatts of
demand-side management programs are now in place on the company's total retail
average load (durg 2008) of 1,100 average megawatts.
5
3 Order approving FCA in Case No. IPC-E-04-15, Order No. 30267. For press releae, see Appendix D.
Press release re: Idaho Power application to make FCA pennanent, Case No. IPC-E-09-28, see Appendi E4 Most recent Idaho Power energy effciency rider increase, IPC-E-0-05, Order No. 30814. For press
release, see Appendix F.5 Case No. A VU-E-09-06. For Order 30918, see Appendix G.
9
In May 2008, the Commission authorized an increase in PacifiCorp's (Rocky Mountain
Power) rider from 1.5 percent to 3.72 percent. By implementing programs fuded by the
rider, the company estimates it wil save 13,140 megawatt-hours per year. At the former
1.5 percent, the rider fuded programs that saved about 8,000 MWh durg 2007.6
The independent American Coundi for an Energy-Efficient Economy (www.aceee.org)
rans Idaho 13th among the 50 states and the Distrct of Columbia in its 2008 State
Energy Effciency Scorecard. More noteworthy, is the report's declaration that Idao is
the "most improved" state, having moved up 12 spots from the 2007 scorecard. The link
to that report is as follows:
htt://aceee.org/pubs/e086 es.pdf
While the PUC does not establish explicit shareholder incentives, the aggressiveness of
the utility is a factor in settg Retu On Equity (ROE) in rate cases. In Order No.
22299, the Commission said, ''Accordingly, we take this opportunity to notif our
regulated electric utilities that in future rate cases we wil take into account the utilty's
commitment to energy conservation in determining the allowed rate of return. A utilty
that aggressively addresses the issues and concern found in this Order, all other things
being equal, may expect the allowance of higher return than might otherwise be
allowed. "
Also encouraging to shareholders is the fact that increased frequency of rate cases has
decreased the potential for lost recovery of fixed costs due to demand-side achievements
in between rate cases.
All three IOUs purchase power under contract from renewable resources. These costs are
allocated to anual Power Cost Adjustment (PCA) accounts until the costs are placed in
base rates following the next rate case. (A mechanism like a PCA, called the Energy Cost
Adjustment Mechanism, has just been approved for PacifiCorp, Order No. 30904) For
PUR A contracts, the utilities get 100 percent recovery of prudent expenses though the
PCA until costs are fully included in base rates.
Additionally, the Idao Offce of Energy Resources (OER) initiated a series of
workshops to develop an appropriate incentive mechanism to optimize cost-effective
demand-side management activities for Idao Power Company. The results of the
workshops may be presented to the PUC for its consideration in reguatory proceedings.
The goal of the workshops is to explore and potentially develop an incentive mechanism
for Idaho Power's investment in DSM activities that represents a reasonable and
attinable incentive, and that balances and aligns utility, customer and societal interests.
Paries indentified from previous PUC cases were invited to paricipate in the workshops.
6 Case No. PAC-E-08-01, Order No. 30543. For press release, see Appendix H.
10
"
. .
These workshops are also intended to advance commitments made by the State ofIdao
in relationship to acceptance of fuds provided by the American Reinvestment and
Recovery Act. In a letter addressed to the United States Secreta of Energy, ldaQ
Governor C.L. "Butch" Otter signed assurances that the state would seek to im i
eneral olic at utilty fiancial incentives are ali ed with hel in
customers use energy more effciently.
E-5 - The Idaho PUC, should support market transformation programs that provide
cost effective energy savings to Idaho citiens.
The PUC continues to allow Idao's regulated utilities to fud and actively partcipate in
the Northwest Energy Efficiency Allance (NEA), a regional market transformation
entity. PUC staff actively monitors NEEA's programs and decision-makng processes in
assessing the benefits to Idao customers. All thee IOUs have or are curently
negotiating new 5-year contracts with NEEA to contiue market transformation effort.
The PUC staff consistently supports NEEA's effort as cost-effective and prudent.
However, the commission continues to evaluate NEEA's cost-effectiveness calculation
methods and its past method of allocating savings to utility service areas. In this regard,
utilities are encouraged to compare the cost-effectiveness of NEE A programs to
programs that could otherwise be provided by the utilities within their own service areas.
To fuer support regional market transformation programs, Gov. Otter exercised his
authority to appoint a member to the NEEA board. Under provisions of the NEEA
bylaws, Idao and Montaa "rotate" a seat on the NEEA board. Governor Otter's
recommendation to the NEEA Board was approved in October 2009. 8
E-6 - The Idaho PUC and Idaho utiities should consider adopting rate designs that
encourage more efficient use of energy.
The PUC continues to consider the affects of rate design on electrcity consumption and
peak-energy demand. The PUC recognizes that, ultimately, cost-based and time-varg
rates wil provide importt price signals, but until customer meters are upgraded to
accommodate such dynamc pricing, other rate designs (e.g. tiered rates, seasonal rates)
have been implemented.
In conjunction with Idaho Power's 2008 rate case, the Commission re-instituted tiered
rates in early 2009 for Idao Power customers. Customers pay the lower rate for use
below 800 kWh. The next highest rate is for use between 801 and 2000 kWh. All use
above 2000 kWh is priced at the highest levei.9
7 Assurance letter dated March 19, 2009. See Appendix i.
8 Lettr from NEEA acknowledging appointment dated October 21,2009. See Appendix J.
9 IPC-E-08- i 0, Order No. 30722. For press release, see Appendix K.
11
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-28
IDAHO POWER .COMPANY
ATTACHMENT NO.4
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BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-28
IDAHO POWER COMPANY
ATTACHMENT NO.5
(),
IDA
MOU
NI
NW
PPL
POM
PNW
PGN
SO
TE
I ~ê II
KeyBanc Capital Markets Inc., Member NYSE/FINRASIPC
Equity Research
Table 11. Cost Recovery Mechanisms
AEE
AEP
AVA
CMS
CNL
p'X,,2 X X'X X'
X'X,,3 X'X'X X,,4
X X'
X X F'X P
X X m
w
i ~; I N:S I
m
XS S
G9
X'N
X'N G'o
II
ED
OPL
OTE
o
OUK
X X X X X'
F P X X X X )t
X'P X X F X P x:
p'X'p'X X X x4
X'X'X'X'X X X'x6
X'w
ETR
EXC
FPL
FE
GXP
X'X X'
X p'X'X'X X X'
X X X X
X'X,,3 X'X'X'X'x"s
p'X'X'
Legend
F - filed by company for cost recovery treatment, regulaory actance and approval to be determined
P - plan, program or law approves cost recovery, but requires a separate plan filing or prdency revie wit reulators (usually outside of a general rate case)
X - active cost revery mechanism, rate adjustment clause, rider, tracker, or specifc rate provision
G, I, N, S, W - (G)eneral planVpre-cnstrution, (I)GCC, (N)uclear, (8)0Iar, (Wind
Notes
1
2
3
4
5
6
7
8
9
10
11
12
13
X'X X F X'
X X'
X'X'X'X X'F,X'
X X'
P X p X X X
X'F X'X'X'X'X F F X'X'X
X X X X
X'3 X X'X p'X'
X'X X X
X X X X
X6."
X6,'2
X
X
X
X'X'X'
Not in all jllisdictions
80% of costs recoered as fixed nonlllumetnc monthly charge
Only reers vegetation management cost
Recors PJM-related co
Recoer purchased po""r payments to NYISO
Recer MISOlated costs
Flooda allow small project less than 0.5% ola utlitys plat in servce as component of rate base
FERC-g"ried trnsmission line project
Line extension fees
Alabama neN geneng facilties and Misslsslpi new baselcad cæad
Defe trnsmission cost excee::tng amount in rates and ea WAce. return on lIreoved transmission cost defes.
PSCO reU Transmisson Cost Adjus1ment (TCA) . allow fo rell on CWiP fo trsmission inves1ents
Smar Gnd recovery through the Energy Conseratin Cost Recvery nder in Floods, DSMÆE ride in carolinas
Sources: compiled fro Company report and SEC tegulatory filings, KeyBanc Capital Markets Inc. tesearch
November 2009 Page 46 of 47
September 10, 2009
Equity Research
IDACORP, Inc.
IDA: Takeaways Frm Company Visit
· On 9/2, we vited with key members of IDA's mgmt, regutory, and
inveor relations teams. We came away frm the meeg with increed
comfort with Idaho's relatory environment and IDA's long-term growt
profie. Other topics of discussion included the impact of the economy on near-
term sales, IDA's resource needs includig Lagley Gulch and major
transmission projec and the company's Oregon-jurdictonal earings profile.
· Reatory Progrss Contiues. Havig secued a number of positive
regulatory chanes in the past few yea, IDA plans to forge ahead with
additional enhcement proposal. Specific initiatives include the puruit of a
more forwd looking test year, energ effciency (EE) incentives and a pension
trackig mechanism. IDA management exressed confidence in the regulatory
acuen of the current Commission and pointed to the recent approva IDA's
ceficate of public convenience and necessity for the Laey Gulch Plat as a
positive data point.
· EPS Outlook. Our 2009-2011 EPS estiates are $2.35, $2-45 and $2.55,
respectvely versus our previous estmates of $2.45, $2.50 and $2.55. We exect
nea-term EPS growt to be drven by both rate base grwt and improved
eared ROEs in both Idaho and Oregon.
· Fianci Needs. We expect 2009 and 2010 fiancig needs will be satisfied
with debt, internaly generated funds and modes amounts of equity via IDA's
dividend reinvestent and employee related plans. We believe the company wi
need to issue equity in 2011 as spending on the Lagley Gulch plant continues to
rap. Overa, we view IDA's financig needs as manageable and ar
comfortable with the company's liquidity position and balance shee.
· Reiterate Market Perform Rati. While we ar attacted to IDA's servce
terrtory and rate base grwt opportties, vauation considerations keep us
on the sidelies. With that being said, we continue to be encouraged with
positive chanes to IDA's regulatory pnnciples, which has been an area of
signifcat concern in the pas As a result, we would consider a more positive
stce towads shar should vauation beme more attactve.
Valuation Rae: $29.00 to $30.00 frm $27.00 to $29.00
We vaue IDA under PIE multiple (apply an 12.0-12.sX multiple to our 10E EPS of
$2.45) and dividend discount analysis. Risks to our vauation include project delays
or cancellations and consisently below average hydroelecc condions.
Invesent Thess:
We are attacted to Idaho's servce terrtory and strong rate base growt potential,
and are encoured by recent regulatory improvements. Ou neutal ratig larely
reflec valuation considerations.
Please see page 12 for ratig defitions, importt
diclosures and require analyst certcations
Well Faro Secuties, LL doe and see to do busines with companes
core in its reea reort. As a reult, invesrs should be aware tht
the fi may have a confct of intere that could afec the objecty of the
rert and investors should consider ths rert as onl a single factor inmag their inveent decion.
.SECURITIES
Market Perform
Sector: Reguated Electc Utiities
Marke Weight
Company Note
200SA 200E 2010EBPS Cu. Prr Curr. Pror
Qi (Mar.) $0.48 $0.40 A NC NEQ2 (June) 0.39 0.58 A NC NEQ3 (Se.) 1.14 1.11 NC NEQ4 (Dec.) 0.16 0.26 0.35 NEFY $2.17 $2.35 2.45 $2.45 2.50CY $2.17 $2.35 $2.45FYP/E 13.1X 12.1X 1l.6x
Re.(1) $960 $984 $1,026
Sourc: Company Dat4 wël FargoSe, LL es~ an RereNA = Not Availabl, Ne - No Chnge, HE. No Esmate, NM. No Meain
TIcker
Prce (09/10/2009)
52-Week Rage:Shes Outsding: (M
Market Cap.: (MM)
S&P 500:
Avg. DaiyVo1.:
DividendlYield:
LT Debt: (MM
LT DebtlTot Cap.:
ROE:
3-5 Yr. Est. Growt Rate:
CY 2009 Es P /E-to-rowt:
La Reportng Date:
IDA
$28.37
$20-34
47.3
$1,341.9
1,043.35
196,368
$1.20/4.2%
$1,283.6
46.2%
9.0%
5.0%
2.4X
08/06/2009
Befre Opn
Sourc: Copany Da Wel Fargo Sæti LL esrn, and Rete
Nei Kan, CFA, Senior Analys
[phone] / neii.kalton~wachovia.comSarah Akers, Associte Anys
[phone] / sarah.akers~wachovia.comJonath Reeer, Assocte Anys
[phone] /
jonathan. reeder~wachovia .co m
Together we'll go far
Utities WELI FARGO SEC, LLC
EQUI REEACH DEPARTMEN
on the investment, it would provide the compay an opportty to glea fiancial benefts from its EE
investment.
· Pension Trackig Mecanm. IDA indicated tht it is exlorig a pension trackig mechanism as a
mean to improve the timeliness of pension cost recovery. Recall that per a June 1, 2007, Idao PUC
order, IDA's accountig for pension exense shifted from accal-based to cash-based. Under the cah-
based method, Idaho Power is alowed to defer, as a reguatory asset, non-ca exense for future recoery
frm cusomers when the company makes actal.cah contnbutions. As a result, the earings impact of
pension exene is not an issue for IDA as it is for a number of other elecc utities seeking pension
trackg mechanisms. IDA is mery exlori the idea as an enceent tht would alow the company
more timely revery. As a resut, if IDA decded to purue the peon tracer we would view its adoption
favorably, but note tht it wi not likely impac our near-ter EPS esates.
· Lagley Gulch Decion. On Septembe 1, the Idao Public Utities Commssion (iUC) approved
Idao Power's reques for a certcate of public convenience and necsity for the 300 MW combined-
cycle Lagley Gulch power plat. Consistent with Idao legislation pased in April 2009, the approvaincluded cost recovery assurance for at lea $396.6 milon, which repreents the known and measurble
portons of the tota $427Im cost esate. The $396.6 mion is not a cap, however, and we execIdao Power will be able to recvery and ea a rern on al just and reasonable cost. The ROE eared
on the investent wi be consistent with the commssion-approved ROE at the tie the plant goes into
servce.
The IPUC did not approve inclusion of constrcton work in progrs (CW) in rate base, but left the door
open for CWP recovery later in the projecs lie. We exec Idao Power to fie for CW as constcton
progrses.
We are encoured by the Commion's decion to appro ratema priciples on the proposed plant
and to consider the company's CW reues at a late date. It is our undersdig tht the company's
reques faced stff opposition by a number of industal irtion and envionmenta pares who were
requesng a ten month stay on the decon in lit of load gr uncety. The IPUC's decision
appea pragatic and generaly supportve of the compay's plan. We consder th to be an
incrementaly positive data point on the Idaho reguatory envinment.
· Transmision Projects. It appears that the approval of Lagley Gulch may aford IDA some additional
flexbilty in the pursuit of tWo major trsmssion projec: Gateway West and Boaran to Hemingway.
The 300 MW gas plat, which is scheduled for completion in 2012, wil serve exti and futu demand
thereby aleviati any urgency assigned to the tranmission project. We alo found it interestg that
the Gateway West Project is not necesary al or nothing. Some portons of the lie ar designed to fi
syem needs and would liely be buit under any cice, whie other portons ar drven byoutside request which could be scaed back in light of ecnomic conditions. With shares trdig near
book value and likely Lagley-related equity need and capita maet uncety, we view flexbilty on
the tiin and scae of the trmiion projec favorably.
Also, whie we tyicay favor transmission invesent, maagement confrmed that the projec would
likely be state- rather th FERC-jursdictona beuse they serve loca needs. We consider FERC
reguation to be more favorable than IPUC retion as the FEC provides for more incentives and/or
mechansms to compensate for the rik of undertg lare multi-state trsmission project. As such,
likely stte reguation is an incrementa negative relative to many peers that ar developing FEC-
reguated projec and reinforce our preous comments regardig our favorable view of the flexbilty
arund tiing and/or potenti to scae back plan.
.Sales Update and Pos Resion Growt Profie. Retai sales volumes deced 6% in the fist hal
of 2009 includin an 8% drp in the secnd quaer. Whe the fi ha sales number ar clouded by
unfavorable weather and poor sales to irgation cuomers due to a materal increae in prec'Pitationo" '.. .
recssionar presur ar al contrbutg to the saes decles. Of note reidential and smal genera
servce cutomer ar covered under the Fixed Cost Adjustent (F) mecanm, which mitites thefianci impact of sales declies - the FC mecan is ru on a pilot bas thugh 2009.
Industal sales were down 9% in the second quaer and 6% in the fi six month of 2009 drven, in
par by the sc down of operations, includig layof at Micrn Tecology.
" '
Management alo addrsed concern related to its ageement with new customer Hoku to provide electc
servce to the company's polysilcon producton facity in Poctelo, Idao, in light of an amended electc
serce agreeent (ESA) delayig the st date and reducing the levels of power in the ESA. Management
'- .
4
RBC Capital Markets Corp.
Lasan Johong (Analyst)
[phone]; lasan.johong~rbccm.com
Emily Christy (Associate)
[phone]; emily.christy~rbccm. com
Ella Vuernick (Associate)
[phone]; eUa.vuernick~rbccm.com
INDUSTRY I COMMENT
MARCH 16, 2009
Regulatory Structure is crucial for utilities
during tough economic times
Positive for companies with decoupling and
fuel/power pass-through
Durg tubulent economic penods, the importce of favorable regulatory
relationships and productive regulatory strctues canot be ignored.
Although as a group utilities are generaly considered to be lower nsk stocks,
upon closer examtion the sometimes vast differences in reguatory
frameworks set the companes apar within the sector. The two most relevant
regulatory mechansms are decouplig, which separate electrcity usage from
revenues, and fuel/power pass though clauses which limt or elimate
commodity nsk. The idea model dunng ths economic cycle is a decoupled
utility with a 100% fuel/power pass though clause. These mechansms
insulate utiities from reductions in demand and volatie, although presently
low, commodity pnces.
(
California is Kig: Goo for PCG, SRE, EIX
The Californa utiity framework support fmancially heathy utilities. The
state is decoupled and has an automatic fuel/power clause tht is adjuste
monthy, barng rar swings of 5% or greater. In Calornia, PCG is the only
pure-play utility, wherea roughly hal of SRE and EIX's eargs are denved
frm CA utility operations.
Wires and Pipes (CNP, UT): Inulated from commodities, exposed to
usge declines
CNP and UTL do not assume commodity nsk, but both companies are
curently at nsk of lower revenues from lower demand. Decupling is
approved for UTL in MA and pendig in NR and ME. For CNP, in TX a high
fixed-cost charge somewhat offsets the nee for d.ouplig.
Middle of the road: NVE, TE, DUK
These companes each have traditional fuel/power pass-though clauses in
their respetive opeatig states and each has strng histones of favorable
treatment in these proceedigs. There is, however, an element of nsk beyond
that of CA since adjustments are not automatic. DUK has decoupling in OR
for gas. NV and TE do not have decoupling.
UncertantylRoom for Improvement: AYE, BKB, IDA, PNM
Each of these companes recently underent reguatory changes in some
maner, creating uncertty in te of how the changes wil afect the
companes. Al now have fuel/power protection to some degr, but
mechanms difer and fal short of CA's automatic recovery system. IDA is
decoupled though a pilot progr in ID, but the other companes are not.
Priced as of prior trading day's market close, EST (unless otherwse noted).
All values in USD unless otherwse noted.
For Required Disclosures, please see Page 6.
March 16, 2009 Regulatory Structure is crucial for utilties during tough economic times
weaess or weather. Accordigly, we would view the Save-a- Watt program as fallig short of the ful downside protection accorded
by standard decoupling. To date, the program has ben approved in OH and is pendig in the other junsdctions.
Table 2. DUK Fuel/Power clause true-up schedule
NC sc OH - Gas OH-Electric IN KY
True-up frequency
Soiirce: RBC Capital Markets and Company Data
NVE: Average traditional structure
Nevada, Califoruia
In NY the company has a fuel and purchased power pass-though mechansm under which the company submits tre-up fiings every
quarr. Although there is always a risk that regulators wil not approve increased costs, the NYE Energy has a strong history of
receivig fair treatment in these proceedings. Regulators understad that commodity risk should be absorbed by the consumers. There
is curntly no decouplig in NY.
NYE Energy has a small group of customers in the Lake Tahoe area of CA. For details, see the CA description for PCG, EIX and SRE
above.
TE: Average traditional structure
Florida
TE has a traditional fuel and purchased power pass-thugh clause tht is regulated by anual tre-up fiings. As NV in NY, TE has a
strong history of favorable outcomes from these tre-up filings. Furermore, TE doe not have a large power gap which minzes
the affect of power prices on the business. There is no decouplig in FL.
IDA: Average traditional structure, but reguatory disconnect remains
Idaho, Oregon
In ID there is a traditional power cost adjustment, which includes fuel and purchased power, that is tred-up alUually. Diferences
between the actual and forecasted costs are split 9515 between customers and shareholders, recently increased from 90/10 sharing. The
sharng mechanism provides a shareholder benefit when hydrology is above normal, but we would prefer that 100% of the risk/reward
go to the consumers. Hydrology has been below normal more oftn than not in the last 10 years.
IDA is in the midst of a the-yea decouplig pilot program which has been favorably received. We believe that the fixed cost ~
adjustment mechanism wil become a permanent par of the regulatory framework and consider the company to be decoupled in ID. .- T,
IDA has a small customer base in OR which recently approved a fuel and purchased power clause. This clause is regulated by anual
tre-ups.
BKH: Unfavorable due to uncertainty of unchartered waters
South Dakota, Wyoming, Colorado, Montana, Nebraska, Iowa, Kansas
Prr to the 2008 acquisition of the Aquila utilities, BKH had operated in SD, WY, and MT. With the Aquila acquisition, the company
added operations in CO, NE, lA, and KS. Although ful-year results for the new assets have not been recorded, we estiate that a litte
over half of BKH's eargs are now subject to new regulatory envionments. Accordigly, th adds an element of regulatory
uncertinty which is unavorable in the curent risk-averse market.
South Dakota (Electric): Traditional, Less than 100% pass-through
Tranmission and steam plant fuel adjustments are passed though to customers based on actual costs incured, on an anual basis.
There is also a conditional energy cost adjustment, relatig to purchased power and natual gas for generation purses, in which BKH
Power absorbs the first $2MM of incresed costs, or $ IMM of the savings. Beyond these thesholds, the additional costs or refuds
are passed though by way of anual fiings.
Wyoming (Electric): Traditional, Less tha 100% pass-through
Cheyene Light has a pass-though mechansm for tranmission, fuel, and purchased power, subject to a $IMM theshold. For
amounts exceding ths theshold, BKH passes along or collects 95% .of the excess amount to consumers and shareholders absorb the
remainder.
Colorado (Electric and Gas): Traditional
The company has a cost adjustment mechanm for purchased power and fuel (though diect recovery or credts issued), and
transmission (though a rider to customer bils).
IRBe~Ci Capital
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