HomeMy WebLinkAbout200806202008 IRP Update.pdf?;IDA~PORtI
An IDACORP Company
LISA D. NORDSTROM
Attorney II
t~ ~
June 20, 2008
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
Re:. Case No. IPC-E-06-24
200BIRP Update
Dear Ms. Jewell:
Please find enclosed for filing an original and seven (7) copies of Idaho Power
Company's 2008 Integrated Resource Plan ("IRP") Update filed pursuant to Order No.
30317. In that Order, the Commission approved Idaho Power's proposal to file its next
full IRP in June 2009. To bridge the gap created by the shift in filing dates, this
compliance filing updates the 2006 IRP that was accepted for filing in Case No. IPC-E-
06-24.
I would appreciate it if you would return a stamped copy of this transmittal letter
in the enclosed self-addressed, stamped envelope.
If you have any questions regarding this filing, please contact me at 388-5825.
Sincerely,~£1.'1~
Lisa D. Nordstro~
Attorney II
LDN:csb
Enclosures
cc: Ric Gale - w/encl.
Bart Kline - w/encl.
P&RS Files - w/encl.
Legal Files - w/encl.
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise. ID 83702
4: 48 *SIDA~POR~
An IDACORP Company
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UPDATE
IPC-E-06-24
2008 Integrated Resource Plan
UPDATE
eslDA~POR$
An IDACORP Company
Acknowledgement
Resource plang is a contiuous process that
Idaho Power Company constantly works to improve.
Idaho Power values the knowledgeable input, comments,
and discussion provided by the Integrated Resource Plan
Advisory Council and the comments provided by other
concerned citizens and customers. Idaho Power looks
forward to contiuing the resource planing process with
its customers and other interested pares.
You can learn more about Idaho Power's resource planng
process at ww.idahopower.com.
Safe Harbor Statement
This document may contain forward-looking statements, and it is important to note that the future results
could difer materially from those discussed. A full discussion of the factors that could cause future results to
differ materially can be found in our filings with the Securities and Exchange Commission.
()
Printed on recycled paper
Idaho Power Company June 2008
TABLE OF CONTENTS
List of Tables .......... .... ......... ........................................ .... ..... ............ ......... ................... ............................. iii
List of Figures.. .... .......... ......... .... .... ....... .... ......... .............. ............. ......... ................... ............. .... ............... iii
List of Appendices.................................................................................................................... ................. iv
Glossary of Terms................................................ ........................................................................................v
i. Introduction............................................................................................................................................1
2. Idaho Power Company Today ................................................................................................................3
Regulatory Issues........................................................................................................................... ........3
Idaho Proceedings...................................................................................................................... ......3
Oregon Proceedings.. .... .... .... ....... .... ........ ....... .... .... ......... ....................... ........... .... ...... ....................3
Idaho Energy Plan.. .... ............... ................... ............... ............ ............... ........... ...............................3
Oregon Renewable Portfolio Stadard .... ...... .... ..... .... .... ............................ ..................... ................4
Fixed Cost Adjustment.. ........ .... ....... .... ............... ........ ............... ......... .... ............. .................................4
Dispatchab1e Customer Generation.. .................................. ............ ............... ........... .......... ...................5
Wind Integration Study..........................................................................................................................5
FERC Re1icensing Process .. .............. ..... .... .... ....... .... .... ........... ........ ..................... ..... .... .......................6
Renewable Energy Credits (Green Tags) ..............................................................................................7
PURP A Contrcts .. .... ...... .... ......... ...... ..... ......................... ......... .............. ..... ............................. ............7
Wholesale Contracts.. ...... .... .... .......................... .......... ..... ................... .... ............. ........ .........................8
3. Plang Period Forecasts......................................................................................................................9
Sales and Load Forecast......................................................................................................................... 9
Customer and Load Growth...... ...... .... ..... ..................................................... ................................ ...9
Load Forecast.................................................................................................................................11
Average Load (Energy)........ ........... .............. ........... ........... ........................................ ...................11
Peak-Hour Load.............................................................................................................................12
Hydroelectrc Generation Forecast ......................................................................................................14
Water Issues in Idaho.................................................................................................................... .14
Flow Augmentation...................................................................................................................... .14
Coal Price Forecast............................................................................................................................. .14
Natual Gas Price Forecast...................................................................................................................15
4. Demand-Side Management................................................................................................................. .17
Demand Side Resources.................................................................................................................... ..17
Progrm Performance.................................................................................................................. ..17
2008 Integrated Resource Plan Update Pagei
Idaho Power Company June 2008
Residential Programs..................................................................................................................... .17
Residential Results.... .... ............. .... ............... .......... ....... ................... ...... ........... .... ......... ...............18
Commercial and Industral Programs........................................................................................... .18
Commercial and Industral Results................................................................ ............................... .18
Irrgation Programs...................................................................................................................... ..18
Irrgation Results............................................................................................................................19
DSM Future Performance............................................................................................................ ..19
5. Supply-Side Resources ........................................................................................................................23
Evander Andrews Peakig Resource.................................................................................................. .23
Shoshone Falls Upgrade .. ........ .... ....... .... ............. ........ .... ......... .......................................... .................23
Horizon Wind Energy Power Puchase Agreement.................................................................... ........23
U.S. Geothermal Power Purchase Agreement .....................................................................................23
Wyoming Pulveried Coal Resource.................................................................................................. .24
2012 Baseload Resource RFP ..............................................................................................................25
2008 Combined Heat and Power RFP ............................................................................................... ..25
6. Transmission Resources................ ...................... ...... .... ..... ........ ..................... ......... .... ....................... .27
Northern Tier Transmission Group......................................................................................................27
Transmission Project Status.................................................................................................................27
Borah-West Upgrade..................................................................................................... ................ .28
Hemingway-Boardman Project.......... ................. ............. ........ ..... .... ...... .... ..... .... ..........................28
Gateway West Project...... ................... ............. ................. ........ .... ........... ........ ..... .......... ...............28
7. Resource Portfolio and Action Plan Update.... .................................................................................. ..29
Average Energy Load and Resource Balance......................................................................................29
Peak-Hour Load and Resource Balance ..............................................................................................29
Plannng Reserve Margin.....................................................................................................................32
Action Plan Update and Portfolio Comparison ....................... ............................................................32
8. Sumary ..............................................................................................................................................35
2009 Integrated Resource Plan ............................................................................................................35
Coordination with Other Idaho Electrc Utilities.................................................................................35
Pageii 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
Table 1.
Table 2.
Table 3.
Table 4.
Table 5.
Table 6.
Table 7.
Table 8.
Table 9
Table 10.
Table 11.
Figure 1.
Figue 2.
Figue 3.
Figure 4.
Figue 5.
Figue 6.
Figue 7.
Figure 8.
Figure 9.
Figue 10
LIST OF TABLES
Historical Data (1990-2007) ....................................................................................................10
Range of System Load Growth Forecasts (aMW 2008 IRP Update......................................11
Change in System Load Growth (aMW) 2008 IRP Update vs. 2006 IRP...............................12
Range of System Peak Growth Forecasts (MW) 2008 IRP Update ........................................13
Change in System Peak Growth (MW 2008 IRP Update......................... ..............................13
Coal and Natual Gas Forecasts...............................................................................................16
DSM Growth Forecast - 2008 IRP Update vs. 2006 IRP (aMW) ...........................................20
DSM Peak-Hour Savings - 2008 IRP Update vs. 2006 IRP (MW) .........................................21
Capacity Planng Margin Sumary.......................................................................................33
Updated Near-Term Action Plan though 2010................................................ .......................34
2006 IRP Preferred Portfolio and Updated Portfolio...............................................................34
LIST OF FIGURES
Retail Customers..................................................................,.................................................. .1 0
Forecasted Fir Load - 70th Percentile ..................................................................................12
Forecasted Fir Summer Peak - 95th Percentile ....................................................................13
2006 IRP Fuel Forecast............................................................................................................15
DSM Forecast Anual Savings................................................................................................19
Levelized Price for Generating Resources vs. Carbon Adder............................................... ..24
Monthly Average Energy Surlus/Deficits with Existing Resources (70th Percentile
Water and 70th Percentile Average Load)................................................................................30
Monthy Average Ener~ Surlus/Deficits with Existing and IRP Resources (70th
Percentile Water and 70t Percentile Average Load)...............................................................30
Monthy Peak-Hour Deficits with Existing Resources (90th Percentile Water and 95th
Percentile Peak-Hour Load).....................................................................................................31
Mon~l Peak-~our Deficits with Existing and IRP Resources (90th Percentile Water
and 95 Percentile Peak-Hour Load).......................................................................................31
2008 Integrated Resource Plan Update Page iii
Idaho Power Company June 2008
LIST OF ApPENDICES
Appendix A. Sales and Load Forecast Data ............................................................................................37
Expected Case Sales and Load Forecast.............................................................................................39
Expected Case Average Forecast Anual Growt Rates (%)........................................................39
Monthy Sumary........................................................................................................................ .40
Anual Summary ...........................................................................................................................60
70th Percentile Sales and Load Forecast ..............................................................................................63
70th Percentile Average Forecast Anual Growth Rates (%) ........................................................63
Monthy Sumary.. .... .... .... ..... .......... ..................... ..... ........ .... ...................... ......................... .... ...64
Anual Summar ...........................................................................................................................84
Appendix B. Aurora CCCT Analysis Assumptions ................................................................................87
Appendix C. Load and Resource Balance...............................................................................................91
Average Energy Load and Resource Balance......................................................................................93
Peak-Hour Load and Resource Balance ............................................................................................103
Page iv 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
GLOSSARY OF TERMS
A/C - Air Conditioning
aMW - Average Megawatt
CCCT - Combined-Cycle Combustion Turbine
CFL - Compact Fluorescent Light
CHP - Combined Heat and Power
CO2 - Carbon Dioxide
CSPP - Cogeneration and Small Power Producers
DSM - Demand-Side Management
EA - Environmental Assessment
EEAG - Energy Effciency Advisory Group
EIA - Energy Information Admnistration
FCA - Fixed Cost Adjustment
FERC - Federal Energy Regulatory Commssion
FPA - Federal Power Act
HCC - Hells Canyon Complex
IDWR - Idaho Departent of Water Resources
IGCC - Integrated Gasification Combined Cycle
IN - Idaho Nationa Laboratory
Idaho PUC - Idaho Public Utilities Commssion
IRP - Integrated Resource Plan
IRP AC - Integrated Resource Plan Advisory Council
kV - Kilovolt
kW - Kilowatt
kWh - Kilowatt Hour
MAF ~ Milion Acre Feet
MMBtu - Millon British Thermal Units
MSTI - Mountain States Transmission Intertie
MW - Megawatt
MW - Megawatt Hour
NEPA - National Environmental Policy Act
NTTG - Nortern Tier Transmission Group
NWPCC - Nortwest Power and Conservation Council
2008 Integrated Resource Plan Update Page v
Idaho Power Company June 2008
Oregon PUC - Public Utility Commssion of Oregon
PCA - Power Cost Adjustment
PM&E - Protection, Mitigation, and Enhancement
PUR A - Public Utility Regulatory Policies Act of 1978
REC - Renewable Energy Credit
RFP - Request for Proposals
RPS - Renewable Portfolio Standard
SOi - Sulfur Dioxide
WECC - Western Electricity Coordinating Council
WRGIS - Western Renewable Energy Generation Information System
Page vi 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
1. INTRODUCTION
Idaho Power Company filed the 2006 Integrated
Resource Plan (IRP) in the fall of 2006. The
Idaho Public Utilities Commission (Idaho PUC)
accepted the plan for fiing in Order 30281
issued on March 26,2007. In April 2007,
Idaho Power requested a one-year delay in the
filing of its next IRP until June 2009 to
coordinate the fiing with the A vista and
PacifiCorp Integrated Resource Plans. The
Idao PUC accepted the one-year IRP filing
delay in Order 30317 issued on May 23, 2007.
The Idaho PUC fuer noted in Order 30317
"Idaho Power also proposes to file an 'IRP
update' in June 2008 to highlight the
progression in its short-term action plan,
changes in its load forecast, existing loads,
customer base and purchased power contrcts;
and any significant deviations from its
2006IRP." The Idaho PUC required
Idaho Power to file the IRP update in June 2008
as part of Order 30317.
The Idaho PUC is not alone in requesting an
IRP update. The Public Utility Commssion of
Oregon (Oregon PUC) specified that utilities
file an IRP update with one year of the most
recent IRP acknowledgement date as part of
Order 07-002 issued in Januar 2007.
The resource plan update is expected to be an
inormational fiing and the update requirements
specified by the Oregon PUC are similar to the
Idaho requirements. In Order 07-002, the
Oregon PUC requires that utilities "describe
what actions the utility has taken to implement
the plan; provide an assessment of what has
changed since the acknowledgment order that
affects the action plan, including changes in
such factors as load, expiration of resource
contracts, supply-side and demand-side resource
2008 Integrated Resource Plan Update Page 1
Idaho Power Company June 2008
acquisitions, resource costs, and transmission
availability; and justify any deviations from the
acknowledged action plan."
Integrated resource planng is a dynamic
process and durng the time between resource
plan filings, the public and regulatory oversight
of the activities identified in the IRP allows for
discussion and adjustment of the IRP as
waranted. Idaho Power continues to analyze
and evaluate the resource plan and make
periodic adjustments and corrections to reflect
changes in technology, economic conditions,
anticipated resource development, and
regulatory requirements.
This update outlines the changes to the
2006 IRP that have occured since the plan was
filed in the fall of2006. Idaho Power intends to
file a complete IR in June 2009. The 2008 IRP
Update is a sumary of the resource plan
changes that have occured since the 2006 IRP
and is limted in scope and analysis.
Page 2 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
2. IDAHO POWER COMPANY
TODAY
Regulatory Issues
Idaho Power operates in both Idaho and Oregon
and the company's operations are regulated by
the Idaho PUC and the Oregon PUC. Since
fiing the 2006 IRP, Idaho Power has been
involved in a number of significant regulatory
proceedings in each state jursdiction.
Idaho Proceedings
. IPC-E-07-03
Increase Wind Power Rate Eligibility
Cap & Elimnate 90/110 Performance
Band (wind integration issue, also
includes IPC-E-05-22 Temporary
Suspend PUR A Obligation Re Wind
Power), Order No. 30488
. IPC-E-07-15
Modify Methodology of Determing
Fuel Costs to Establish Published Rates
. IPC-E-07-18
Idaho Power - S02 Allowances Revenue
Allocation, Order No. 30529
Oregon Proceedings
. UM 1056
Investigation into whether the
requirements for least-cost planng,
first established in Order 89-507, should
be revised, Order No. 07-002
. SB838C
Oregon Renewable Energy Act
. UM 1302
Investigation into the Treatment of C02
Risk in the IRP Process
. UM 1066
Investigation into regulatory policies
affecting new resource development
Idaho Energy Plan
In 2006, the Idaho Legislatue directed an
Interi Committee on Energy, Environment and
Technology (the Committee) to develop a state
energy plan that provides for the state's power
generation needs and protects the health and
safety of the citizens ofIdaho. In Januar 2007,
the Commttee completed the Idaho Energy Plan
and concluded that all ofIdaho's energy
systems have performed very well with electrc
and natual gas prices that remain some of the
lowest in the countr.
The Committee also recognized that Idaho's
reliance on low cost coal plants may become a
source of risk in the futue due to the economic
impact of potential federal regulation of carbon
and mercury emissions. To address these
concerns, the Committee recommended
increasing investments in energy conservation
and in-state renewable resources. In a resource
priority policy statement, the Commttee stated,
"When acquirg resources, Idaho and Idaho
utilities should give priority to: 1) Conservation,
energy efficiency and demand response; and 2)
Renewable resources; recognizing that these
alone may not fulfill Idaho's growing energy
requirements." The Commttee fuer stated,
".. . energy suppliers must continue to have
access to conventional energy resources to keep
Idaho's energy costs as low as possible."
The Commttee also expressed support for the
"25x'25" vision which states: "By 2025,
America's fars, forests and ranches wil
2008 Integrated Resource Plan Update Page 3
Idaho Power Company June 2008
provide 25% of the total energy consumed in the
United States, while continuing to produce safe,
abundant, and affordable food, feed and fiber."
Additional information regarding the "25x'25"
vision can be found at ww.25x25.org.
Oregon Renewable Portfolio
Standard
The State of Oregon's Renewable Portfolio
Standard (RPS) requires utilities and electrcity
service suppliers serving Oregon load to include
in their portfolio of power sold to retail
customers a percentage of electrcity generated
from qualifying renewable energy sources.
Oregon's RPS, like most states, is phased in
over a number of years with fial targets set for
the year 2025. The Oregon RPS also includes a
tiered system based on the amount of load a
utility serves in Oregon. Larger utilities have
higher RPS requirements and interim targets
while smaller utilities have less rigorous
requirements and no interi targets.
Under the Oregon RPS, Idaho Power is
categoried as a "smaller utility" because the
percentage of the company's retail electrc sales
in Oregon are between 1.5 and 3% of the total
retail sales in the state (less than 5% of
Idao Power's total load is in Oregon). As a
"smaller utility" Idaho Power is not subject to
interi tagets, however, by 2025 at least 10%
of Idaho Power's retail sales in Oregon must
come from qualifying renewable energy
sources.
Fixed Cost Adjustment
On January 27,2006, Idaho Power filed an
application with the Idaho PUC requesting the
authority to implement a Fixed Cost Adjustment
(FCA) mechanism similar to the Power Cost
Adjustment (PCA). The FCA is designed to
adjust rates downward or upward to recover
fixed costs independent of the volume of the
company's energy sales. The filing was a
contiuation of a 2004 case that was opened to
investigate the financial disincentives to
investment in energy efficiency by Idaho Power.
Idaho Power and the Idaho PUC staff agreed in
concept to a thee-year pilot program beginng
Januar 1,2007, and a stipulation was filed on
December 18, 2006. The stipulation called for
the implementation of the FCA mechanism pilot
program as proposed by the company in its
original application with additional conditions
and provisions related to customer count and
weather normalization methodology, recording
of the FCA deferral amount in reports to the
Idaho PUC and detailed reportg of DSM
activities. The Idaho PUC approved the
stipulation on March 12,2007. The pilot
program retroactively began on Januar 1,2007,
and wil ru though 2009. The first rate
adjustment occured on June 1, 2008, and
subsequent rate adjustments wil occur on
June 1 of each year thereafter durg the term of
the pilot program.
Whle Idaho Power believes the FCA removes
an inerent disincentive to pursue DSM
programs, additional experience and results are
necessary to determe the full impact of the
pilot program. In order to implement the
package of DSM programs contained in the
2006 IRP, Idaho Power has substatially
increased staffng levels in its Customer
Relations and Energy Efficiency Deparent.
This group is responsible for managing DSM
program performance and works collaboratively
with customers to promote and enhance the
programs offered by Idaho Power. Section 4 of
the 2008 IRP Update provides details on DSM
program performance which has exceeded the
expectations contained in the 2006 IRP.
Idaho Power plans to continue to pursue
cost-effective DSM in the IRP planng process.
The Customer.Relations and Energy Effciency
Departent wil also be involved as new
programs and enhancements to existing
programs are evaluated against supply-side
resources in the preparation of the 2009 IRP. A
more thorough analysis of the FCA pilot
Page 4 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
program will be included in the 2009 IRP as
requested in Idaho PUC Order No. 30281 which
accepted Idaho Power's 2006 IRP.
Dispatchable Customer
Generation
Idaho Power began an investigation into a
dispatchable customer generation program
durg the fall of 2006. As conceptualized by
the Company, the program would use
non-residential customers' standby generators
for up to 400 hours a year to help meet system
peak power demads. Customer generators
would operate in parallel with Idaho Power's
generation resources durg times of peak
energy demand and also provide back up for the
customer's facility when needed. The
customers' generators would be started remotely
by Idaho Power's dispatch center.
Idaho Power performed a feasibility analysis,
examining the varous costs involved in the
interconnection of back-up generators as well as
the resulting operations and maintenance costs.
Both intial generator installations and existing
retrofits were considered. The analysis
concluded that Idaho Power would have to
make a signficant infrastrcture investment.
Idaho Power determed that it was necessar to
do an in-depth analysis of the interconnection
costs, tageting generators of different sizes,
ages, and locations. Five Idaho Power
customers committed to the detailed analysis
and allowed the company to perform an on-site
interconnection analysis. The on-site analysis
provided a more accurate cost estimate and
determination of the program's potential
viability. Idaho Power concluded that it may be
economical to operate customers' generators
durg short periods of high energy demand.
Following the detailed analysis, Idaho Power
began investigating air quality and permtting
issues. If a customer generation program were
implemented, Idaho Power would most likely
dispatch customers' generators, almost all of
which utilize diesel fuel, at times of peak system
demand, which occurs most often on hot,
sumer afternoons ~ times when air quality
may already be reduced. In addition,
Idaho Power received concerns from the
environmental communty regarding air quality
issues associated with operating diesel
generators. Because of air quality and other
concern, Idaho Power recommended holding a
workshop to solicit input regarding the
implementation of a dispatchable customer
generation program in the Company's service
terrtory. On April 4, 2008, Idaho Power filed
an updated status report on the investigation
with the Idaho Public Utilities Commssion and
requested scheduling a workshop for the
purose of receiving input from interested
parties.
Wind Integration Study
Under the Public Utility Regulatory Policies Act
(PUR A), Idaho Power is required to offer
independent developers a power purchase
contract based on a standard avoided cost rate
for a qualifying facility with a monthy output of
10 aMW or less. Because a large number of
wind project developers came to Idaho Power
requesting PURA contrcts in early 2005,
Idao Power requested and the Idaho PUC
granted temporary relief from PUR A
requirements until the impact of wind
integration could be studied. The Idaho PUC
granted relief by temporarily reducing the
PUR A cap of 10 aMW to 100 kW for PUR A
wind projects.
On Febru 6, 2007, Idaho Power filed a wind
integration study report with the Idao PUC.
Idaho Power also filed a petition requesting
removal of the temporary restrction on the size
ofPURA wind projects and an adjustment to
the avoided cost rates to compensate for the
increase in system costs due to wind variability.
On March 15,2007, and June 20, 2007, public
workshops were held to present and discuss the
results of the wind integration study.
2008 Integrated Resource Plan Update Page 5
Idaho Power Company June 2008
Following negotiations to settle the case,
Idaho Power entered into a settlement
stipulation on October 2, 2007. The settlement
stipulation prescribed a methodology for
calculating a wind integration charge that wil
be applied to PUR A wind projects as well as
other provisions. The integration charge wil be
calculated as a percentage of the curent
20-year, levelized, avoided cost rate and be
subject to a cap of $6.50 per MW. On
Februar 20,2008, the Idaho PUC issued an
order approving the settlement stipulation and
returned the PURPA cap to 10 aMW.
FERC Relicensing Process
Idaho Power, like other utilities that operate
non-federal hydroelectrc projects on qualified
waterways, obtains licenses for its hydroelectrc
projects from the Federal Energy Regulatory
Commission (FERC). The licenses last for 30
to 50 years depending on the size, complexity,
and cost of the project. Idaho Power is actively
pursuing the relicensing of the Hells Canyon
Complex and Swan Falls projects.
The most significant ongoing 'relicensing effort
is the Hells Canyon Complex (HCC). The HCC
provides approximately two-thids of
Idaho Power's hydroelectrc generating capacity
and 40% of the company's total generating
capacity. The current license for the HCC
expired at the end of July 2005. Until the new
multi-year license is issued, Idaho Power
continues to operate the project under an annual
license issued by the FERC.
The license application was filed in July 2003
and accepted by the FERC for fiing in
December 2003. The FERC is now processing
the application consistent with the requirements
ofthe Federal Power Act (FPA), the National
Environmental Policy Act of 1969, as amended
(NEP A), the Energy Policy Act and other
applicable federal laws.
The license for the Swan Falls hydroelectrc
project expires in June 2010. On
March 10,2005, Idaho Power issued a Formal
Consultation Package (FCP) to the public
relating to environmental studies designed to
determine project effects for the relicensing of
the project. On September 21,2007,
Idaho Power submitted a drft license
application to the FERC for public review and
comment. The draft application is based on the
results of the environmental studies along with
agency and public consultation. Idaho Power
wil file a fial license application for the
Swan Falls hydroelectrc project with the FERC
in June 2008.
Failure to relicense any of the existing
hydropower projects at a reasonable cost wil
create upward pressure on the curent electrc
rates of Idaho Power customers. The
relicensing process also has the potential to
decrease available capacity and increase the cost
of a project's generation though additional
operating constraints and requirements for
environmental protection, mitigation, and
enhancement (PM&E) imposed as a condition
for relicensing. Idaho Power's' goal thoughout
the relicensing process is to maintain the low
cost of generation at the hydroelectrc facilities
while implementing non-power measures
designed to protect and enhance the river
environment.
No reduction of the available capacity or
operational flexibility of the hydroelectrc plants
to be relicensed was assumed as par of the
2006 IRP. If capacity reductions or reductions
in operational flexibility do occur as a result of
the relicensing process, Idaho Power wil adjust
futue resource plans to reflect the need for
additional capacity resources in order to
maintain the existing level of reliability.
Page 6 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
Renewable Energy Credits
(Green Tags)
A renewable energy credit (REC) or "green tag"
is a tradable commodity that is created for each
megawatt-hour of energy generated from a
qualified renewable energy project. Traditional
carbon emissions trading programs promote
low-carbon technologies by increasing the cost
of emitting carbon, while RECs create
incentives to develop carbon-neutral renewable
energy resources by providing a production
subsidy.
Idaho Power has enrolled in the Western
Renewable Energy Generation Information
System (WREGIS). WREGIS was developed
by the Western Electricity Coordination Council
(WECC) in cooperation with numerous utility,
governental and environmental groups to
provide a universal, independent, REC trackig
system. Since its inception in late 2007,
WRGIS has quickly become the trackig
system preferred by many western states and
regulatory agencies.
Idaho Power is receiving all the RECs from the
Elkorn Valley Wind Project over the 20-year
term of the power purchase agreement. Durg
initial star-up and testing of the project in late
2007, approximately 16,933 RECs were
generated and Idaho Power expects to receive
approximately 300,000 RECs from the Elkorn
Valley Wind Project each year beginng in
2008.
Idaho Power wil be receiving RECs from up to
3 MW of generation at the Raft River
Geothermal Project (Unit 1) when the actual
generation of the project exceeds 10 MW.
Idao Power expects to receive approximately
19,000 RECs each year thoughout the 25-year
term of the power purchase agreement. The
project is curently workig through intial star
up issues and has not routiely exceeded
10 MW. However, Idaho Power expects to
receive RECs from the Raft River project
staing later in 2008.
Idaho Power continues to review the eligibility
of the company's existing resources to create
RECs as well as the possibility of acquirg
RECs from qualifying facilities under existing
and futue PUR A contracts. Numerous
discussions have been conducted both internally
and with the Idaho PUC staff to gather input
regarding the development of an Idaho Power
REC Policy.
PURPA Contracts
Under the Public Utility Regulatory Policies Act
of 1978 (PUR A), Idaho Power is required to
offer independent developers a power purchase
contract based on a stadard avoided cost rate
for any qualifying facility with a monthly output
of 10 aMW or less. Because Idaho Power
cannot accurately predict the level of future
PUR A development, only contracts that are
curently signed and approved by the
Idaho PUC are included in Idao Power's
resource plans.
Since the 2006 IRP was published, the overall
expected nameplate rating of PUR A projects
has not changed materially. Changes that have
taen place include reductions of 26.9 MW from
two biomass projects, 19.5 MW from one wind
project and 10 MW from a geothermal project.
Additions since the 2006 IRP include 57.6 MW
from thee wind projects. These adjustments
result in a cumulative change in the contract
nameplate rating from 438.2 MW in 2006 to
439.4 MW today. Idaho Power curently has 94
signed and approved PUR A contrcts.
Idaho Power's 2006 IRP included more than
250 MW from PURPA contracts that had been
signed and approved by the Idaho PUC. The
timg of these resources included in the 2006
IRP was based on the estimated on-line dates
contained in the contracts. To date, none of
these PUR A projects have met the scheduled
operation date; a few are curently under
constrction, and 150 MW has been delayed
until 2010, or possibly indefintely. Because of
the uncertinty created by ths situation,
2008 Integrated Resource Plan Update Page 7
Idaho Power Company June 2008
Idaho Power plans to discuss the methodology
of accounting for PURP A projects with the IRP
Advisory Council as part of the 2009 IRP
process.
Wholesale Contracts
Idaho Power curently has one, fixed-term,
off-system sales contrct to supply 6 aMW to
the Raft River Rural Electrc Cooperative.
Since the 2006 IRP was published, the term of
the contract has been renewed anually and is
expected to continue to be renewed though the
end of September 2011.
The Raft River Cooperative is the electrc
distrbution utility serving Idao Power's former
customers in Nevada and the agreement was
established as a full-requirements contract after
being approved by the FERC and the Public
Utilities Commssion of Nevada.
The contract that Idaho Power had to supply
6 aMW to the City of Weiser expired at the end
of 2006. The expiration of ths contract was
anticipated in the 2006 Integrated Resource
Plan.
Idaho Power and Montana's NorthWestern
Energy negotiated a load-following agreement
in which Idaho Power provided NorthWestern
Energy 30 MW of load-following service.
Idaho Power did not renew the load-following
agreement at the end of 2007 because of
concerns regarding the integration of more than
350 MW of wind generation anticipated to be
interconnected on Idao Power's system.
NorthWestern has provided load following
services for the Salmon, Idaho area which is
located in the NorthWestern Balancing
Authority Area. Idaho Power and
NorthWestern are curently workig together to
move the Salmon area load into the Idaho Power
Balancing Authority Area.
Idaho Power continues to utilize its transmission
capacity on the Jefferson line to import power
from Montana durg the sumer months. At
present, Idaho Power purchases 83 MW durng
heavy load hours from June though August
from PPL Montana. Although the purchase
agreement expires in August 2009, Idaho Power
plans to continue to utilize the available
transmission capacity durg the summer
months. An RFP has been issued to supply
83 MW for the thee sumer months beginng
in June 2010 and proposals are due in
May 2008.
Page 8 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
3. PLANNING PERIOD
FORECASTS
Sales and Load Forecast
In addition to the biennal IRP process,
Idaho Power prepares a sales and load forecast
each calenda year as part of the company's
annual financial forecast. The sales and load
forecast is strongly influenced by the most
recently available economic forecast developed
by Idaho Economics, an independent consultant.
The forecast of the number of households and
employment projections, along with customer
consumption patterns, is used to develop
customer forecasts and load projections. The
projections were updated in August 2007 and
are the basis for the sales and load forecast for
the 2008 IRP Update.
Signficant factors influencing the 2008 IRP
Update sales and load forecast include:
. The sales and load forecast developed
for the 2008 IRP Update reflects the
addition of one new "Special Contrct"
customer. This customer plans to begin
operation in Januar 2009 and reach full
capacity by August 2009. The 2008 IRP
Update sales and load forecast includes
38 aMW with a peak demand of 43 MW
for ths customer. Although ths
additional load was included in the
updated forecast, Idaho Power and the
customer are stil in discussions and the
final load could eventually be more than
double these amounts.
· Demand-side management (DSM)
program performance has exceeded the
2006 IRP projections.
. The effect of code changes for
residential building practices, including
increased insulation requirements and air
conditionig unt effciency for new
constrction and replacement unts, has
lowered energy consumption
projections.
. New DSM programs proposed in the
2006 IRP were intially categoried as
supply-side resources. As proposed
programs are implemented, the progra
effects are integrated into existig DSM
and considered to be par of the load
forecast base which lowers the energy
and peak forecast. The 2008 IRP Update
sales and load forecast reflects the full
integration ofDSM program effects as a
reduction to the forecasttIe series as
well as the effects of new building codes
and air conditionig effciency
standards.
Customer and Load Growth
Customer growth is the priar factor leading
to Idaho Power's need for additional resources.
Population growth thoughout southern Idaho -
specifically in the Treasure Valley - requies
additional resources to meet both the
instantaneous peak and the sustained energy
needs of the new customers. As mentioned in
the 2006 IRP, new generation is often more
costly than electrcity produced at existig
facilities. Incorporatig new generation in
Idaho Power's rate base tends to increase
electrcity prices for all customers in all rate
classes.
In 1990, Idaho Power had approximately
290,000 retail customers. Today, Idaho Power
serves more than 480,000 retail customers in
Idaho and Oregon. Fir peak-hour load has
increased from less than 2,100 MW in 1990 to
nearly 3,200 MW in the sumer of2007. In
July 2007, the peak-hour load reached
3,193 MW, which was a new system record.
Average firm load has increased from
1,200 aMW in 1990 to 1,800 aMW at the end of
2007. A sumar ofIdaho Power's load and
customer data is shown in Table 1.
2008 Integrated Resource Plan Update Page 9
Idaho Power Company June 2008
The sales and load forecast anticipates that Table 1.Historical Data
Idaho Power wil add between 12,500 and (1990-2007)
13,000 new customers each year thoughout the Change inplannng period. The anual compound growth Customers
rate is approximately 2.1 %. The compound Average from
Peak Firm Firm Load Number of Previousgrowth rate results in expected customer growth Year Load (MW)(aMW)Customers Yearsfrom approximately 480,500 customers in 2007 1990 2,052 1,205 290,492 7,327to nearly 740,000 customers in 2027. Figure 1 1991 1,972 1,206 296,584 6,092shows a comparson of the 2006 and 2008 1992 2,164 1,281 306,292 9,708updated customer forecasts. Figue 1 shows that 1993 1,935 1,274 316,564 10,272there wil be a greater number of retail
1994 2,245 1,375 329,094 12,530customers than were forecast in the 2006 IRP -
nearly 26,000 more retail customers by 2027.1995 2,224 1,324 339,450 10,356
The additional 26,000 retail customers represent 1996 2,437 1,438 351,261 11,811
a change in total customers of almost 4% by the 1997 2,352 1,457 361,838 10,577
end of the 20-year plang period.1998 2,535 1,491 372,464 10,626
1999 2,675 1,552 383,354 10,890
The recent cyclical slowdown in customer 2000 2,765 1,653 393,095 9,741
growth, as indicated in the total number of 2001 2,500 1,576 403,061 9,966
customers for year end 2007 is approximately 2002 2,963 1,622 414,062 11,001
three tenths of a percent lower than forecast 2003 2,944 1,657 425,599 11,537
(0.3%). The effect of the cyclical downtu on 2004 2,843 1,671 438,912 13,313
the longer term trend wil be evaluated for the 2005 2,961 1,660 456,104 17,192
2009IRP.2006 3,084 1,745 470,950 14,846
2007 3,193 1,808 480,523 9,573
Figure 1. Retail Customers
(thousands of customers)
800
700
600
500
400
300
200
1000,- ,I I I j I I i i I I I i I I I I i I I I I I I I I
1990 1995 2000 2005 2010 2015 2020 2025 2030
-20061RP Forecast -20081RP Update Forecast - Historical
Page 10 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
Load Forecast
Alternate forecast scenarios for average load
and peak-hour load were developed for the
2006IRP. The two plang criteria, the 70th
percentile average load for energy plang, and
the 95th percentile peak-hour load for capacity
planing, have not been changed in the
2008 IRP Update.
The projected demand for electrcity by
customers in Idaho Power's service area is
bounded by high and low probabilistic load
forecasts. The boundary forecasts reflect the
range of load uncertainty associated with
alternate weather related assumptions. The
median forecast is between the two boundaries
and Idaho Power considers the median forecast
to represent the most likely outcome.
Both the average energy and the peak-hour load
forecasts have declined since the 2006 IRP. A
varety of factors have contrbuted to the load
forecast change. The customer forecast has
increased since publishig the 2006 IRP and the
customer increase leads to an increase in both
peak-hour and average energy. Offsetting the
energy increase are the effects of the DSM
programs and a forecast increase in retail
electrcity prices. Two factors affect the DSM
projections. Firt, the DSM programs have been
more effective than forecast in the 2006 IRP -
the DSM progr results have exceeded the
projections made in 2006. And second, is the
manner in which Idaho Power treats the DSM
projections in an IRP. In an IRP, new DSM
progras are added to the resource stack
meaning demand-side programs are treated
equally with supply-side resources. However,
when a demand-side program is intiated and
Idaho Power commts to the program, the
program effects are considered as par of the
load forecast. Unlike demand-side programs,
the effects of existing and committed supply-
side resources continue to be analyzed as par of
the resource stack. The final factor contrbuting
to the decline in the sales and load forecast is
that energy prices are forecast to increase
slightly faster than originally projected in the
2006 IRP, which is expected to result in a slight
reduction in energy consumption.
Average Load (Energy)
Table 2 sumarizes thee forecast outcomes of
Idaho Power's estimate of its anual system
load considerig median, 70th percentile and
90th percentile weather impacts on the expected
(median) load forecast. The 70th percentile
forecast is based on 70th percentile weather to
determe average monthy load which means
three years out of ten would exceed the forecast.
Idaho Power uses the 70th percentile forecast as
the basis for energy resource plang.
Therefore, the planng criteria for determing
Table 2. Range of System Load Growth
Forecasts (aMW) 2008 IRP Update
70th 90th
Year Median Percentile Percentile
2007 (Actual)1,810 1,810 1,810
2008 1,812 1,853 1,925
2009 1,880 1,921 1,994
2010 1,913 1,955 2,029
2011 1,941 1,984 2,059
2012 1,954 1,997 2,073
2013 1,976 2,020 2,097
2014 1,989 2,034 2,112
2015 2,008 2,053 2,132
2016 2,036 2,081 2,162
2017 2,051 2,097 2,178
2018 2,067 2,114 2,196
2019 2,096 2,144 2,227
2020 2,129 2,176 2,261
2021 2,163 2,211 2,297
2022 2,197 2,246 2,333
2023 2,231 2,280 2,368
2024 2,265 2,314 2,403
2025 2,301 2,351 2,441
2026 2,341 2,392 2,483
2027 2,380 2,432 2,524
Growth Rate
(2005-2027)1.4%1.4%1.4%
2008 Integrated Resource Plan Update Page 11
Idaho Power Company June 2008
(median) peak forecast. The 95th percentile
forecast uses the 95th percentile peak day
temperature to determine monthly peak-hour
Table 3.Change in System Load
Growth (aMW) 2008 IRP Update vs.
20061RP
70th 90th
Year Median Percentile Percentile
2008 -10 -11 -10
2009 23 22 22
2010 21 20 21
2011 23 23 23
2012 12 11 12
2013 -2 -3 -2
2014 -25 -25 -24
2015 -43 -44 -43
2016 -53 -54 -51
2017 -77 -77 -76
2018 -100 -100 -98
2019 -111 -111 -109
2020 -119 -119 -116
2021 -127 -127 -124
2022 -136 -135 -132
2023 -145--145 -142
2024 -154 -155 -152
2025 -163 .164 -160
2026 -168 -168 -165
2027 -175 -175 -172
% Change
(in 2027)-6.8%-6.7%-6.4%
the need for energy resources assumes 70th
percentile average load conditions. The
projected 20-year average annual compound
growth rate in the expected load forecast is
1.4% and average energy demand is forecast to
grow at about 30 aMW per year. Figue 2
ilustrates the 70th percentile average load
forecasts used in the 2006 IRP and
2008 IRP Update. The difference between the
two forecasts is shown in Table 3.
Peak-Hour Load
New housing growth and the associated increase
in air conditioning load in southern Idaho is
driving much ofIdaho Power's peak-hour load
growth. In the updated load forecast, the peak-
hour load is projected to grow by approximately
70 MW per year throughout the plang period,
which is 10 MW per year less than predicted in
the 2006 IRP. This reduction in the growth rate
is due to DSM. demand response programs, local
and federal effciency codes and stadards, and
reduced consumption due to higher prices.
Table 4 summarizes thee forecast outcomes of
Idaho Power's estimte of its annual system
peak considerig median, 90th percentile and
95th percentile weather impacts on the expected
Figure 2. Forecasted Firm Load - 70th Percentile
(average megawatts)
2,700
2,500
2,300
2,100
1,900
1,700
1,500
1,300
1,100900~700~iliillli
1975 1980 1985
~~~~~,.
~
I i I I i I I I I 1--1 I I Iii I i I I ¡Ii I I I I ¡Ii I I I i I I I I
1990 1995 2000 2005 2010 2015 2020 2025 2030
-Actual -20061RP -2008 IRP Update
Page 12 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
demand. Idaho Power uses the 95th percentile The projected 20-year average annual
forecast as the basis for peak resource plang.compound growth rate in the expected peak
Therefore, the plang criteria for detenning forecast is 1.8% as shown in Table 4. Figure 3
the need for peak-hour capacity assumes 95th ilustrates the 95th percentile system peak
percentile peak-day temperature conditions.forecasts used in the 2006 IRP and
2008 IRP Update. The difference between the
Table 4. Range of System Peak Growth two forecasts is shown in Table 5.Forecasts (MW) 20081RP Update
90Îh 9SÎh Table 5.Change in System Peak Growth (MW)
Year Median Percentile Percentile 2008 IRP Update
2007 (Actual)3,193 3,193 3,193 90Îh 9SÎh20083,099 3,240 3,284 Year Median Percentile Percentile
2009 3,193 3,338 3,383 2008 -28 -28 -28
2010 3,252 3,400 3,446 2009 11 12 11
2011 3,313 3,464 3,511 2010 4 4 4
2012 3,356 3,510 3,558 2011 5 5 5
2013 3,409 3,567 3,617 2012 -11 -12 -12
2014 3,454 3,615 3,666 2013 -30 -30 -30
2015 3,506 3,671 3,723 2014 -57 -58 -57
2016 3,572 3,740 3,793 2015 -83 -83 -82
2017 3,620 3,792 3,846 2016 -95 -96 -95
2018 3,672 3,847 3,901 2017 -127 -127 -126
2019 3,738 3,916 3,972 2018 -156 -156 -157
2020 3,808 3,990 4,047 2019 -172 -172 -172
2021 3,881 4,066 4,124 2020 -185 -185 -184
2022 3,955 4,143 4,202 2021 -197 -197 -197
2023 4,028 4,220 4,280 2022 -209 -209 -209
2024 4,103 4,298 4,359 2023 -223 -223 -223
2025 4,179 4,378 4,440 2024 -236 -236 -236
2026 4,262 4,464 4,527 2025 -249 -249 -249
2027 4,345 4,550 4,615 2026 -256 -256 -256
Growth Rate 2027 -265 -266 -265
(2008-2027)1.8%1.8%1.8%% Change
(in 2027)-5.7%-5.5%-5.4%
Figure 3. Forecasted Firm Summer Peak - 95th Percentile
(megawatts)
5,0004,700 ~
4,400
4,100
3,800
3,500
3,200
2,9002,600-
2,300
2,000 -'
1,700
1,400 ¡¡I i I I i I I I I I I i I I I I I I I i I I I I i I I I I i I I I I I I I Iii I i I I I Iii I I I i I i
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
-Actual -20061RP -20081RP Update
2008 Integrated Resource Plan Update Page 13
Idaho Power Company June 2008
Hydroelectric Generation
Forecast
In the IRP process, Idaho Power assesses
resource adequacy using the 70th percentile
water condition for average energy planng and
the more constrined 90th percentile water
condition for peak-hour plannng. Idaho Power
recognizes that water management issues in the
Snake River drainage wil continue to remain
the subject of debate for the foreseeable future
and the company wil adjust the hydroelectrc
resource projections in the IRP in response to
changing practices and conditions.
Water Issues in Idaho
Power generation at Idaho Power's
hydroelectrc projects on the Snake River is
dependent upon the state water rights held by
the company and the long-term sustainability of
the Snake River, trbutary spring flows and the
Eastern Snake Plain Aquifer that is connected to
the Snake River. Idao Power continues to
paricipate in the water management issues in
Idaho that may affect the company's water
rights and resources.
One of the main water rights issues facing
Idaho Power Company is the Snake River Basin
Adjudication intiated in 1987. The Snake River
Adjudication is a legal action containg both
judicial and administrtive proceedings. The
adjudication process wil allocate the
Snake River water between surace water users,
ground water users, in-stream non-consumptive
water users, senior water rights holders, and
junor water rights holders. The objective of the
Snake River Basin Adjudication is to reverse the
decline in river, sprig, and aquifer water levels
and to address the long-term water resource
needs of the state.
Idaho Power wil continue to vigorously defend
its water rights. None of the pending water
management issues are expected to impact
Idaho Power Company hydroelectric generation
in the near-term, but the company cannot predict
the ultimate outcome ofthe legal and
administrative water rights proceedings.
Idaho Power's ongoing participation in water
rights issues is to guarantee that sufficient water
is available for use at the company's
hydroelectric projects on the Snake River.
Flow Augmentation
Reports issued in 2007 by the Bureau of
Reclamation (August 2007) and NOAA
Fisheries Service (October 2007) suggest an
intent to explore shifting the delivery of flow
augmentation water from the months of July and
August to the sprig months of April, May and
June. A follow-up biological opinion report is
anticipated later in 2008.
Idaho Power has performed a prelimary
resource planng analysis to estimate the
impact of the shift in the timing of the flow
augmentation water. The analysis suggests that
under the 70th percentile water condition used
for energy resource plannng, generation levels
for the most energy constrined month (July)
are projected to decline by approximately
115 aMW. Idaho Power wil continue to
monitor the issue to ensure that generation
projections for its hydroelectrc facilities for the
2009 IRP are consistent with curent federal
flow augmentation practices and schedules.
Coal Price Forecast
The expected coal price forecast developed for
the 2006 IRP was an average ofIdaho Power's
coal forecasts for its Vahny and Jim Bridger
thermal plants. In addition, the 2006 IRP used a
Wyomig specific coal forecast for potential
generation resources located in Wyomig and a
regional coal price forecast for resources at
non-specific locations. The coal price forecasts
were created using coal and rail transporttion
market inormation, private forecasts, and the
Global Insight 2006 U.S. Power Outlook report.
The resultig costs in dollars perMMtu
represent the delivered cost of the coal,
including rail costs, coal costs, and use taxes.
Page 14 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
In general, coal prices have risen due to
increases in the cost of diesel fuel, explosives,
utilities, shipping and other consumables used in
minig. The coal price forecasts were not
updated as par of the 2008 IRP Update,
however, new forecasts wil be prepared in 2008
as part of the 2009 IRP process. A sumary of
both coal price forecasts used in the 2006 IRP
are shown in Table 6 and Figure 4.
Natural Gas Price Forecast
Idaho Power does not directly forecast natural
gas prices as par of the planng process.
Industr forecasts developed by outside
consultants are combined with forecasts from
published sources to create a composite
forecast. The expected gas price forecast used
in the IRP is derived from public and private
source forecasts including IGI Resources,
NYMEX, PIRA, EIA, NWCC, and u.s. Power
Outlook. The forecast from each source is
converted to nominal dollar and then converted
to dollars per MMBtu at the Sumas trading hub.
Each forecast is then weighted and used to
develop the composite forecast. Transporttion
costs are then added to the weighted average
price to develop a fial estimate of the delivered
cost in dollars per MMBtu. The transporttion
costs also include Nortwest Pipeline's fixed
and volumetrc charges as well as fuel gas.
Figure 4. 2006 IRP Fuel Forecast
(Nominal $/MMBtu)
$12
$11
$10
$9
$8
:: $7
åi
:: $6
~- $5
$4
$3
$2
$1
$0
200620072008200920102011201220132014201520162017 2018 2019 2020 2021 2022202320242025
-Sumas Natural Gas (Expected) -Henry Hub Natural Gas (Exected)
- - Henry Hub Natural Gas (High) -- - Henry Hub Natural Gas (Low)
-NWPCC Natural Gas (2007) -Wyoming Specific Coal
-Regional Coal
i- ..~ ..--i-I. ... ..--- .- .i--..-..~~..--,--- ¡.------
2008 Integrated Resource Plàn Update Page 15
Idaho Power Company June 2008
Idaho Power has not prepared an updated
natual gas price forecast for the
2008 IRP Update. However, the Northwest
Power and Conservation Council (NCC)
recently issued a revised natual gas price
forecast which is shown in Table 6 and Figue 4
along with the fqrecasts used in Idaho Power's
2006IRP. As shown in Figure 4, the new
forecast from the NWCC does not deviate
materially from Idaho Power's expected case
forecast used in the 2006 IRP.
Table 6. Coal and Natural Gas Forecasts
($/MMBtu Delivered-Nominal)
2007
20061RP 20061RP 20061RP 20061RP 20061RP NWPCC
Wyoming 20061RP Sumas Henry Hub Henry Hub Henry Hub Natural Gas
Specific Regional Natural Gas Natural Gas Natural Gas Natural Gas Price
Year Coai1 Coai2 (Expected)(Expected)(High)(Low)Forecast
2006 $1.24 $1.27 $8.23 $8.73 $11.16 $4.89
2007 $1.17 $1.32 $8.62 $8.79 $10.71 $4.86
2008 $1.13 $1.37 $8.00 $8.11 $10.43 $4.92 $7.58
2009 $1.11 $1.41 $7.91 $8.17 $10.36 $5.01 $7.20
2010 $1.05 $1.45 $5.90 $6.19 $9.79 $5.14 $6.80
2011 $1.03 $1.49 $5.95 $6.24 $9.48 $5.35 $6.38
2012 $1.06 $1.53 $6.04 $6.33 $9.18 $5.57 $6.23
2013 $1.07 $1.58 $6.24 $6.53 $9.00 $5.78 $6.30
2014 $1.14 $1.75 $6.42 $6.71 $8.90 $6.05 $6.30
2015 $1.15 $1.83 $6.64 $6.92 $9.01 $6.30 $6.53
2016 $1.19 $1.90 $6.92 $7.20 $9.20 $6.05 $6.82
2017 $1.22 $1.98 $7.23 $7.50 $9.43 $6.20 $7.10
2018 $1.29 $2.09 $7.49 $7.75 $9.60 $6.40 $7.44
2019 $1.34 $2.19 $7.86 $8.12 $9.87 $6.56 $7.71
2020 $1.40 $2.31 $8.16 $8.41 $10.16 $6.79 $8.00
2021 $1.39 $2.41 $7.51 $7.77 $10.45 $6.80 $8.28
2022 $1.43 $2.52 $7.79 $8.04 $10.76 $6.96 $8.58
2023 $1.45 $2.63 $8.14 $8.39 $11.08 $7.18 $8.89
2024 $1.52 $2.74 $8.38 $8.62 $11.40 $7.54 $9.22
2025 $1.56 $2.88 $8.70 $8.94 $11.74 $7.69 $9.54
1 Used in the 2006 IRP for a Wyoming Specific coal resource.
2 Used in the 2006 IRP for a non-location specific, regional coal resource.
3 NWPCC medium case (east-side delivered) inflated at 2.5%.
Page 16 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
4. DEMAND-SIDE
MANAGEMENT
Demand-Side Resources
Durng 2007, Idaho Power continued to expand
the programs that were implemented as a result
of the 2004 IRP. Idaho Power's 2006 IRP
included the addition of three new DSM
programs and the expansion of one program. In
addition to the DSM programs identified in the
IRP, Idaho Power has also continued to pursue
other customer-focused DSM intiatives,
including programs that preceded the 2004 IRP,
educational opportties, and regional market
transformation efforts. As par of new
regulatory intiatives, in 2007 Idaho Power
committed to enhance its efforts to promote
energy effciency.
Idaho Power's DSM activities thoughout 2007
were priarily focused on enhanced program
paricipation and. energy savings in the curent
programs, and design and implementation of
new programs. Idaho Power has also contiued
to integrate the company's field and support
personnel to increase customer awareness and
participation in the programs.
Program Performance
Demand-side management programs at
Idaho Power continue to grow as measured by
customer partcipation, energy savings, and
demand reduction. In 2007, paricipation in the
AlC Cool Credit program increased by 155%.
The Irgation Peak Rewards and AlC Cool
Credit programs resulted in an estimated
combined sumer peak reduction of 48 MW,
representing a 29% increase from 2006 results.
The four energy efficiency programs that were
identified in the 2004 IRP are the Custom
Efficiency (Industral), Building Efficiency
(Commercial), ENERGY STARtI Homes
Northwest (Residential), and Irrgation
Efficiency Rewards programs. The four
programs resulted in total anual savings of
over 45,000 MW in 2007, which was a 20%
increase over the 2006 energy savings of
approximately 38,000 MW for the same
programs. The energy efficiency programs that
originated as a result of the 2006 IRP are the
Heating and Cooling Effciency (Residential),
ENERGY STARtI Lighting (Residential), and
the Easy Upgrades (Commercial) programs. The
new programs resulted in annual savings of over
12,000 MW in 2007.
An expansion of the program formerly known
as the Industral Effciency program was also
identified in the 2006 IRP. The program was
expanded in 2007 and is now called the Custom
Efficiency program.
In addition to the IRP programs offered durng
2007, Idaho Power operated several other
energy efficiency programs tageting residential
customers: Weatherization Assistance for
Qualified Customers (WAQC), Energy House
Calls, Rebate Advantage, and Oregon
Residential Weatherization. The energy
efficiency progras added annual savings of
over 4,500 MW in 2007.
Residential Programs
Programs available to residential customers
include one demand response progra, seven
energy efficiency programs, and an educational
initiative program. The residential
demand response program is called "AlC Cool
Credit" and the program achieves peak-hour
demand reduction by cycling customers' central
air conditioners. The residential energy
efficiency programs include
Energy House Calls, ENERGY STARq¡ Homes
Nortwest, Oregon Residential Weatherization,
Rebate Advantage, ENERGY STARtI Lighting,
W AQC, and Heating and Cooling Effciency.
The Residential Energy Efficiency Education
Initiative began in 2007, which provided
educational outreach to Idaho Power residential
customers. In addition, the Heating and Cooling
2008 Integrated Resource Plan Update Page 17
Idaho Power Company June 2008
Effciency program and the Appliance program
were under development in 2007.
Idaho Power conducted approximately 20
regional events in parership with local
community retailers to educate and influence
consumer purchasing decisions relating to
ENERGY STARtI Lighting. Idao Power
increased residential program outreach efforts in
2007 through parerships with Home Depot,
Lowes, Wal-Mart, and other retailers. The
parterships were developed to educate
customers across Idaho Power's service area
about energy efficient lighting and increase the
adoption of energy effcient lighting by
residential customers.
Another addition in 2007 was the creation of the
ww.getpluggedin.com web site and related
radio and TV advertising. . The marketing
channels were designed to educate customers
about varous issues facing Idaho Power, and
specifically, energy efficiency and the role it
plays in planing and managing growth.
Residential Results
In 2007, residential customers were responsible
for a 10% increase in energy savings from 2006
with approximately 11,000 MW savings in
2006 and over 12,000 MW in 2007. The
peak-hour demand savings from residential
customers increased by 74% from 6.5 MW in
2006 to 11.4 MW in 2007. Customer
participation in the demand response programs
increased by 155% for 2007, and compact
fluorescent light (CFL) bulb sales increased by
23%.
Commercial and Industrial
Programs
Three programs targeting different energy
effciency activities are available to
Idaho Power's commercial and industral
customers. The newest program offered to these
customers, Easy Upgrades, was launched in
Idaho in February 2007 and in Oregon in
May 2007. The program is designed to deliver
energy effciency and demand-side savings to
all existing commercial and industral
customers. Easy.Upgrades offers a menu of
incentives for lighting, HV AC, motors, building
shell, plug loads, and grocery refrgeration.
With the launch of the Easy Upgrades program,
the Oregon School Effciency program was
discontinued since schools can now paricipate
in the Easy Upgrades program.
The Building Effciency program for new
constrction projects achieves energy savings
that are cost-effective at the time of
constrction. The program continues to offer
energy-saving improvements for lighting,
cooling, building shell, and energy control
effciency options. Both Building Efficiency
and Easy Upgrades paricipants can receive
incentives up to $100,000 for any projects
completed.
The Custom Effciency progra, formerly the
Industrial Efficiency progra, was expanded to
include large commercial customers in 2007.
The program is intended for larger custom
projects. Idaho Power continues to offer its
Oregon Commercial Audits program to medium
and small commercial customers.
Commercial and Industrial Results
Total anual energy savings for the commercial
and industral programs increased by
approximately 88%, from approximately
20,000 MW in 2006 to nearly 38,000 MW in
2007.
Irrigation Programs
Idaho Power curently offers two progras to
irgation customers: Irrgation Peak Rewards, a
demand response program designed to decrease
peak-hour demand, and Irrgation Efficiency
Rewards, an energy effciency program
designed to encourage replacement or
Page 18 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
improvement of ineffcient systems and
components.
Irrigation Results
The Irrgation Peak Rewards program provided
significant peak-hour reductions durg the
sumer of 2007 with an average peak load
reduction of nearly 29 MW and a maximum
sumer peak reduction of over 37 MW. The
maximum sumer peak-hour reduction was
approximately 18% higher in 2007 than in 2006.
The peak reduction is due to changes in the
program incentive strctue, which increased the
number of two- and thee-day-per week
participants.
The Irrgation Efficiency Rewards progra also
had strong participation in 2007. However, the
matuty of the program and the early adoption
of the menu options by irgators have caused a
leveling off of projects in 2007. Program
redesign, implemented in 2006, offered
increased incentive levels and provided a menu
option program that is popular with irgation
customers. The total energy savings for 2007
was over 12,000 MW on 819 projects across
Idao Power's service area.
DSM Future Performance
In 2008, Idaho Power plans to continue to
increase participation and energy savings from
existing progras, continue to implement new
energy efficiency programs, research possible
new demand response programs, complete a
new DSM potential study, and evaluate several
existing programs. Idaho Power also plans to
participate in the development of the Nortwest
Power and Conservation Council's (NCC)
Sixth Power Plan and to continue enhancing
consumer education on energy efficiency.
The effects of DSM programs, changes in Idaho
residential building codes, and the federal
residential air conditionig unt efficiency
standards have been integrated into both the
demand-side program forecast and the sales and
load forecast included in the 2008 IRP Update.
The demand-side programs and their expected
effects are addressed in more detail in the
company's Demad-Side Management
2007 Anual Report.
Figue 5 shows increased energy savings
thoughout the plang perod in a comparson
of the DSM program performance anticipated in
Figure 5. DSM Forecast Annual Savings
140
120
f 100~
i:800..Co::'C 60Q)i:::
ei 40Q)i:W
20
0
2008 2010 2012 2014 2016 2018 2020 2022 2024 2026
-All DSM (w/o code changes) - 20061RP
2008 Integrated Resource Plan Update Page 19
Idaho Power Company June 2008
the 2006 IRP and the 2008 IRP Update.
Idaho Power has increased the resources
dedicated to energy effciency and demand
response programs, resulting in greater expected
program effects. Idaho Power also expects to
introduce additional DSM programs throughout
the planng period that wil result in increased
energy savings. The new programs wil be
considered in the 2009 and subsequent resource
plans.
In the later years of the planng period, the
updated sales and load forecast shows reduced
peak-hour energy consumption resulting from
the 2006 IRP demand-side program savings.
The peak-hour reductions are mainy attbuted
to improved residential building codes and air
conditionig standards. For the forecast tie
period, the 2008 IRP Update forecast shows an
overall energy savings improvement of
approximately 18% over the earlier forecasts
included in the 2006 IRP. Tables 7 and 8 show
the effect ofDSM on the average and peak-hour
load forecasts for the 2008 IRP Update.
The peak-hour load reductions shown in Table 8
are constant from 2010 onward as the present
demand response programs reach full
implementation. After 2010, new partcipants
are expected to offset program participants who
elect to leave the programs. Idaho Power wil
consider additional demand response programs
in the 2009 and subsequent Integrated Resource
Plans.
Table 7. DSM Growth Forecast - 2008 IRP Update vs. 2006 IRP (aMW)
20081RP Update
All DSM
(w/o CodeYearChanges)Code Changes Total DSM 20061RP Diference
2008 16 1 17 7 10
2009 25 2 27 18 9
2010 32 3 35 28 8
2011 40 5 45 37 8
2012 48 6 54 44 10
2013 56 7 63 51 12
2014 64 8 72 57 15
2015 70 10 80 62 18
2016 77 11 88 67 21
2017 83 12 95 69 26
2018 88 14 102 71 31
2019 94 15 109 74 35
2020 99 17 116 76 40
2021 104 18 123 78 44
2022 109 20 129 81 48
2023 114 21 135 83 52
2024 118 23 142 85 56
2025 123 25 148 88 60
2026 123 27 149 n/a n/a
2027 123 28 151 n/a n/a
Page 20 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
Table 8.DSM Peak-Hour Savings - 2008 IRP Update vs. 2006 IRP (MW)
2008 IRP Update 20061RP Difference
Energy Demand Energy Demand Energy Demand
Effciency Response Effciency Response Effciency Response
2008 30 66 20 59 10 7
2009 46 78 26 73 20 5
2010 61 82 32 78 29 5
2011 76 82 37 78 39 5
2012 92 82 43 78 49 5
2013 107 82 48 78 59 5
2014 123 82 54 78 69 5
2015 135 82 54 78 81 5
2016 146 82 54 78 92 5
2017 157 82 54 78 103 5
2018 168 82 54 78 114 5
2019 179 82 54 78 125 5
2020 190 82 54 78 136 5
2021 200 82 54 78 146 5
2022 210 82 54 78 156 5
2023 219 82 54 78 166 5
2024 229 82 54 78 175 5
2025 239 82 54 78 186 5
2026 243 82 n/a n/a n/a n/a
2027 247 82 n/a n/a n/a n/a
2008 Integrated Resource Plan Update Page 21
Idaho Power Company June 2008
Page 22 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
5. SUPPLY-SIDE RESOURCES
Evander Andrews Peaking
Resource
Idaho Power began constrction of a thd
simple cycle combustion tubine at the
Evander Andrews Power Complex near
Mountain Home, Idaho in early 2007. The plant
began commercial operations on
March 11,2008. The combustion tubine
provides approximately 166 MW of capacity
during sumer peak-hour loads and up to
200 MW durg the winter.
Idaho Power received a Certificate of Public
Convenience and Necessity for the project from
the Idaho PUC on December 15, 2006. The
certificate included a power plant constrction
cost commitment estimate of $60 million. On
March 7, 2008, Idaho Power filed an application
with the Idaho PUC for authorization to place
$57,650,861 of plant investment into rate base.
The March 7, 2008 filing also included
$7,331,116 for investment in transmission and
interconnection facilities. These transmission
and interconnection facilities, which are
complete and in service, wil allow the new
Evander Andrews combustion tubine to operate
ths sumer. However, an additional
$19.5 millon of transmission and
interconnection facilities are scheduled to be
placed in service in October 2008 to improve
transmission reliability associated with the new
power plant.
Shoshone Falls Upgrade
On August 17,2006, Idaho Power filed a license
amendment application with the FERC allowing
the company to upgrade the Shoshone Falls
project from 12.5 MW to 62.5 MW. In
March 2007, Idaho Power received a drft
Environmental Assessment (EA) and Notice of
Ready for Environmental Analysis from the
FERC, which provided for a 60-day comment
period for interested entities. The FERC issued
a supplemental EA on December 4, 2007 and
Idaho Power expects that a license amendment
wil be issued in 2008. In conjunction with the
license amendment application, Idaho Power
has filed a water rights application which is
curently being reviewed by the Idaho
Departent of Water Resources (IDWR).
Horizon Wind Energy Power
Purchase Agreement
In Februar 2007, the Idaho PUC approved a
power purchase agreement with Telocaset Wind
Power Parters, LLC, a subsidiar of Horizon
Wind Energy, for 101 MW of nameplate wind
generation from the Elkorn Valley Wind
Project located in norteastern Oregon. The
Elkorn Wind project was constrcted durg
2007 and began commercial operations on
December 28, 2007.
U.S. Geothermal Power
Purchase Agreement
The 2006 IRP identified a need for Idaho Power
to acquire geothermal generation resources. An
RFP (Request for Proposals) for geothermal
energy was released on June 2, 2006.
Idaho Power identified U.S. Geothermal as the
successful bidder in March 2007 based on their
proposal to supply 45.5 MW of geothermal
energy. On Januar 9, 2008, the Idaho PUC
approved a power purchase agreement for
13 MW of nameplate generation from the
Raft River Geothermal Power Plant (Unit 1)
located in southern Idaho. Raft River Unit 1
began operatig at a lower capacity in
October 2007 under a PUR A contract.
Contract negotiations for the remainng
32.5 MW wil take place over the next several
months and are expected to include an
additional unt at the Raft River site and two
units at the Neal Hot Sprigs site located in
eastern Oregon. On-line dates for these thee
projects are uncertin and wil depend on the
2008 Integrated Resource Plan Update Page 23
Idaho Power Company June 2008
progress of development activities. However,
these projects are not expected to meet the 2009
on-line date identified in the 2006 IRP.
Wyoming Pulverized Coal
Resource
The 2006 IRP near-term action plan indicated
that an initial commtment to the constrction of
a coal-fired resource would be necessary before
the end of 2007 in order for a project to be
on-line in 2013. Idaho Power began screenig
and evaluating coal-fied resources in 2006.
The evaluation concluded in August 2007 and
the results indicated constrction costs had
escalated substantially since resource cost
estimates were prepared for the 2006 IRP.
Because the results of the screenig and
evaluation process were substantially different
than the assumptions used in the 2006 IRP,
Idaho Power re-evaluated the cost of a coal
resource against a combined cycle combustion
tubine (CCCT). In this updated analysis, a cost
estimate of $1,071 per kW was used for the
CCCT based on an estimate prepared by
Idaho Power in mid-2007 and $3,000 per kW
was used for the coal resource.
Figure 6 is a ''tipping point" char which shows
the levelized price of energy for both a
pulverized coal and a CCCT resource over a
range of carbon adder costs. A carbon adder of
$21 per ton of C02 is the "tipping point" where
a CCCT resource becomes a better choice than
pulverized coaL.
Figure 6. Levelized Price for Generating Resources vs. Carbon Adder
$110
$105
$100
¡:$95
i $90CD.g
Q.
'C $85CD.t:ãi;:CD..$80..
~co $75N
$70
$65
$60
$0 $5 $10
- SC Pulverized Coal ($3.000/kW)
- CCCT ($1 ,071/kW)
-SC Pulverized Coal ($3,OOO/kW)-w1$10 per MWh for Transmission
-CCCT ($1,071/kW) w/$2 per MWh for Transmission" I$15 $20 $25 $30 $35 $40
Carbon Adder ($/TON of CO2)
Page 24 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
In addition to comparig the resource costs,
Figure 6 also shows an estimate for both
resources accounting for the cost of
transmission to deliver the energy to
Idaho Power's main load center in southwestern
Idaho. For this comparison, $10 per MWh was
added to the cost of a pulverized coal facility
located in Wyomig while $2 per MWh was
used for a CCCT which could be built in
southwestern Idaho. After accounting for the
cost of transmission, Figure 6 shows the CCCT
is the best choice for any level of assumed
carbon adder.
In the fall of 2007, Idaho Power decided to no
longer pursue the development of the 2013
coal-based resource. In addition to considering
the cost of a coal-based resource, uncertainty
surounding the regulation of carbon emissions
and the ability to permt a new coal resource
were considered. Idaho Power continues to
evaluate other coal-fired resource opportnities,
including effciency improvements at its
jointly-owned facilities as well as monitoring
the development of clean coal technologies.
2012 Baseload Resource RFP
In light of the decision to not pursue the
development of a pulverized coal generation
resource, Idaho Power issued an RFP in
April 2008 for 250 to 600 MW of dispatchable,
physically delivered firm or unit contingent
energy. The energy is to be acquired though
either power purchase agreements, tolling
agreements or a self-build option being prepared
by Idao Power that wil be used as a
benchmark in the evaluation process. The range
from 250 to 600 MW reflects uncertinty
regarding additional load from several new large
customers that contacted Idaho Power after the
2008 IRP Update load forecast was prepared.
Idaho Power expects to notify bidders of the
final quantity of the RFP in the near futue.
Changes in the load forecast and updated
assumptions regarding existig and planned
resources included in the 2006 IRP were the
impetus for Idaho Power to analyze the
economic impact of adding a new resource in
2012 instead of2013. The Aurora Electrc
Market Model was used to analyze the
following scenarios with a 250 MW CCCT
coming on-line in 2012 and 2013:
. Base Case - Includes the updated load
forecast and all resources as presented in
the 2008 IRP Update
. Low Hydro - Idaho Power's hydro
generation was reduced to 70th
percentile conditions and other Pacific
Northwest hydro was reduced 20%
. No Transmission Upgrade - This
scenario examined the impact of the
Hemingway-Boardman transmission
project not being available in 2012 as
planned
. Low Hydro and No Transmission
Upgrade - This scenario included low
hydro conditions and the impact of the
Hemigway-Boardman trsmission
project not being available in 2012
For each of the four scenarios modeled, the
results indicated it was beneficial to have the
resource available in 2012 rather than 2013. A
summar of the modeling assumptions and
results are presented in Appendix B.
2008 Combined Heat and
Power RFP
A combined heat and power (CHP) project
burs natual gas in a combustion tubine to
generate electrcity and then uses the exhust
heat from the tubine to generate steam for an
industral process. CHP projects tyically result
in a higher overall effciency when compared to
burg natual gas solely to create steam for an
industrial process.
2008 Integrated Resource Plan Update Page 25
Idaho Power Company June 2008
The 2006 IRP included 50 MW ofCHP in 2010.
Idaho Power is in the process of workig with
industral customers to gauge the level of
interest in new CHP projects. Major account
representatives are using a specification sheet to
guide their discussions with Idaho Power's
industral customers and depending on the level
of interest, Idaho Power may issue an RFP later
in 2008.
Page 26 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
6. TRANSMISSION
RESOURCES
Idaho Power's transmission system is a key
element serving the needs of Idaho Power's
retail customers. Idaho Power relies on regional
markets to supply a significant portion of energy
and capacity. Idaho Power is especially
dependent on the regional markets durig peak
periods. Reliance on regional markets has
benefited Idaho Power customers durig times
of low prices because the costs of purchases, the
revenue from surplus sales, and fuel expenses
are shared with customers though the Power
Cost Adjustment (PCA) mechanism. The
following sections provide an update on
transmission related activities since the
2006 IRP was published.
Northern Tier Transmission
Group
The Northern Tier Transmission Group (NTTG)
was formed in early 2007 with an overall goal
of improving the operation and expansion of the
high-voltage transmission system that delivers
power to consumers in seven western states. In
addition to Idaho Power, other members include
Deseret Power Electrc Cooperative,
NorthWestern Energy, Rocky Mountain
PowerlPacifiCorp and the Uta Associated
Municipal Power Systems (UAMPS).
NTTG wil address and coordinate regional
transmission use and planng using workig
groups that are guided by a steerig commttee
of transmission owner executives and state
regulators. The workig groups are designed
around thee primary objectives: 1) improving
available transmission capacity, 2) expediting
the planng for transmission grid expansion,
and 3) collaborating on control area operations.
For each of the three objectives, NTTG has
encouraged participation and solicited input
from stakeholders including transmission
owners, customers, and state regulators.
Through a coordinated and collaborative
planng and implementation process, NTTG is
workig to maintain a robust trnsmission
system that supports an efficient regional
electrcity market.
Transmission Project Status
The 2006 IRP described five regional -scale
transmission projects that were included in the
resource planng process. The following
projects were included in the 2006 IRP as the
most viable transmission alternatives.
. McNar (Columbia River) to the Locust
Substation (Boise) via Brownlee
. Lolo (Lewiston area) to Oxbow
. Bridger, Wyoming to the Boise Bench
Substation via the Midpoint Substation
. Garrson or Townsend, Montana to the
Boise Bench Substation via the Midpoint
Substation
. Whte Pine, Nevada to the Boise Bench
Substation via the Midpoint Substation
Since the completion of the 2006 IRP,
Idaho Power has anounced plans for
constrction of two regional-scale transmission
projects. The Hemingway-Boardman project
(McNary to Locust) extends from norteastern
Oregon to the Boise area, and the Gateway West
project (Bridger, Wyoming to Boise Bench)
extends from centrl Wyoming to the Boise
area. The Hemingway-Boardman and the
Gateway West projects have both been
identified as "fast track" projects by NTTG
because both projects provide considerable
benefits to the regional transmission system.
NTTG has also identified NortWestern
Energy's proposed 500-kV Mountain States
Transmission Intertie (MSTI) between
southwestern Montana and Idaho Power's
2008 Integrated Resource Plan Update Page 27
Idaho Power Company June 2008
Borah or Midpoint substations as a beneficial
project. The MSTI project is simlar to the
Garrison-Townsend alternative discussed in the
2006IRP. NortWestern Energy expects the
MSTI line to be placed in service in 2013.
Expansion of other regional transmission
resources includes PacifiCorp's plan for a
500-kV line between the Hemingway substation
in Boise and the Bonnevile Power
Admnistration's Captain Jack substation in
southern Oregon. PacifiCorp anticipates an in-
service date of 20 14 for the Hemingway to
Captain Jack project. All of the transmission
projects reflect a collaborative, regional-scale
effort by NTTG to upgrade the region's
transmission resources in the face of continuing
population growt and the corresponding
growth in the demand for electrcity. The
following sections provide additional details on
the transmission projects Idaho Power is either
currently workig on or has completed since the
2006 IRP was published.
Borah-West Upgrade
The 2006 IRP discussed ongoing constrction to
upgrade the existing Borah-West path. The
transmission improvements to the Bora-West
path were intially identified in the 2004 IRP
and have been completed and were placed in
service in June 2007. Completion of the
upgrade has resulted in a 250 MW increase in
the east-to-west transfer capacity of the
Borah-West path which increases the path rating
to 2,557 MW. As discussed in the 2006 IRP,
the Borah-West improvements are critical to
serve load growt in the Boise area from any
new generation sited on the east side of
Idaho Power's service area.
Hemingway-Boardman Project
Consistent with Idahn Power's 2006 IRP and
the requirements of other trsmission
customers, Idaho Power is exploring alternatives
for the constrction of a 500-kV line between
southwestern Idao and the Pacific Nortwest.
Several electrc utilities, including Idaho Power,
have proposed development of a trnsmission
substation near Boardman, Oregon, which
would serve as the northwest termnal of the
project. The Idaho terminal would be the
proposed Hemingway substation located south
of Boise on the south side of the Snake River
between the towns of Melba and Murphy.
Idaho Power and a number of other utilities with
proposed regional transmission projects in the
Northwest have signed a letter agreeing to
coordinate techncal studies. The technical
studies and other plang and project
management activities have begun and the
Hemingway-Boardman transmission line could
be in service as early as 2012.
Gateway West Project
Idaho Power and PacifiCorp are jointly
explorig the Gateway West Project to build
two 500-kV lines between the Jim Bridger plant
in Wyoming and Boise. The lines would be
designed to increase electrcal trnsmission
capacity across southern Idaho in response to
increasing customer energy demand. The
Gateway West project has been submitted to the
Western Electrcity Coordinating Council
(WECC) for the intial phases of the ratigs
process. A review team has been established
from members of the WECC to analyze the
effects of the project on the existing
transmission system. When the study is
complete, necessar modifications wil be made
to the engineerig design and the final rating
wil be obtained prior to the beging of
constrction.
Plang and project management personnel
from both Idaho Power and PacifiCorp have
begu the intial work on the Gateway West
project. Idaho Power expects that the majority
ofthe project wil be completed between 2012
and 2014, depending on the amount of time
required for right-of-way acquisition, sitig and
permttg activities.
Page 28 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
7. RESOURCE PORTFOLIO
AND ACTION PLAN UPDATE
Over the past 90 years, Idaho Power has
developed a blended portfolio of generation
resources. Idaho Power believes a portolio of
diverse generation resources is the most cost
effective and lowest risk method to address the
increasing energy demands of its customers.
New customer growth is the primar drver
behind Idaho Power's need for the additional
resources identified in the 2006 IRP. Population
growt thoughout southern Idaho and
specifically, in the Treasure Valley, requires that
Idaho Power acquire new resources to meet both
the peak-hour and average energy needs of its
customers.
New supply-side generation resources,
demand-side programs and increasing the
transmission capacity to the Pacific Northwest
are the likely alternatives Idaho Power wil use
to meet the increasing energy demands of its
customers. Idaho Power's customers have
expressed a desire for a balanced resource
portfolio containg resources that are
financially, environmentally, and socially
responsible. Renewable energy and
demand-side programs are signficant
components of the resource portfolio selected in
the 2006 IRP and wil continue to be par of
Idaho Power's balanced approach to resource
planng.
Average Energy Load and
Resource Balance
Average energy surluses and deficiencies are
determined using 70th percentile water and 70th
percentile average load conditions, coupled with
Idaho Power's ability to import energy from
firm market purchases using reserved network
capacity. Figue 7 shows the updated monthly
average energy surpluses and deficits
accounting for the updated sales and load
forecast, forecast DSM program performance,
adjustments to the hydro generation forecast, the
curent level of PUR A development, and
changes in the timg and capacity of other
near-term resources identified in the 2006 IRP.
Figure 8 shows the surpluses and deficits after
accounting for the IRP resources, including the
new baseload resource in 2012. As shown in
Figue 8, energy deficits of approximately
400 aMW exist in July of2009-2011 and are not
alleviated until the 2012 baseload resource and
the Hemigway-Boardman project are added in
2012. The Aurora Electrc Market Model
analysis discussed on page 25 and summarized
in Appendix B indicates there is an economic
benefit of adding a CCCT resource in 2012 as
opposed to 2013. Based on the deficits in
Figue 8, the need for ths resource exists prior
to 2012, but the minimum time required for the
RFP process, permitting and constrction make
it improbable to complete prior to 2012.
Additional details on the average energy load
and resource balance are included in
AppendixC.
Peak-Hour Load and Resource
Balance
Peak-hour load deficiencies are determned
using 90th percentile water and 95th percentile
peak-hour load conditions, coupled with
Idaho Power's ability to import additional
energy on its transmission system to reduce any
deficits. In addition to these criteria, 70th
percentile average load conditions are assumed,
but the hydrologic, peak-hour load, and
transmission constraint criteria are the major
factors in determinng the peak-hour load
deficiencies. Peak-hour load planng criteria
are more stringent than average energy criteria
because Idaho Power's ability to import
additional energy is tyically limted durng
peak-hour load periods.
Figue 9 shows the updated monthy peak-hour
deficits accounting for the updated sales and
load forecast, forecast DSM program
performance, adjustments to the hydro
generation forecast, the curent level of PUR A
development, and changes in the timg and
capacity of other near-term resoures identified
2008 Integrated Resource Plan Update Page 29
Idaho Power Company June 2008
Figure 7.Monthly Average Energy Surplus/Deficits with Existing Resources (70th Percentile Water and
70th Percentile Average Load)
1,200
1,000
800
600
400
¡:200:i'"
0
-200
-400
-600
-800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Figure 8.Monthly Average Energy Surplus/Deficits with Existing and IRP Resources (70th Percentile
Water and 70th Percentile Average Load)
1,200
1,000
800
600
400
s:200:i'"
0
-200
-400
-600
-800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Page 30 2008 Integrated Resource Plan Update
Idaho Power Company June 2008
Figure 9. Monthly Peak-Hour Deficits with Existing Resources (90th Percentile Water and 95th Percentile
Peak-Hour Load)
100
o
-100
-200
-300
~-400
-500
-600
-700
-800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Figure 10 Monthly Peak-Hour Deficits with Existing and IRP Resources (90th Percentile Water and 95th
Percentile Peak-Hour Load)
100
0
i
I I-100
-200
-300
~-400
-500
-600
-700
-800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
2008 Integrated Resource Plan Update Page 31
Idaho Power Company
in the 2006 IRP. Figure 10 shows the remaining
deficits after adding the IRP resources,
including the new baseload resource in 2012.
Similar to the deficits shown for average energy,
the peak-hour analysis shows deficits of
approximately 150 MW in the near-term, but it
would not be possible to complete the 2012
baseload RFP process, design, permt and
constrct a new resource prior to 2012.
Additional details on the peak-hour load and
resource balance are included in Appendix C
Planning Reserve Margin
Idaho Power's futue resource requirements are
not based directly on the need to meet a
specified reserve margin. Idaho Power's
long-term resource planng is instead drven by
the objective to develop resources sufficient to
meet higher than expected load conditions,
under lower than expected water conditions,
which effectively provides a reserve margin. As
par of preparg the 2008 IRP Update,
Idao Power has calculated the capacity reserve
margin resulting from changes in the load
forecast and existing and planned resource
development.
Table 9 presents the capacity reserve margin
calculations which include using the 50th
percentile peak-hour load forecast and 50th
percentile hydro conditions. Table 9 also shows
thee transmission resources: Red Butte-
Borah/rady (75 MW, Pacific Nortwest
(115 MW and the proposed Hemingway-
Boardman project (225 MW' The 115 MW
from the Pacific Nortwest is based on network
set-asides for July of 2009 and is assumed for
all years though 2018. Whle Idaho Power
does not curently have long-term firm
purchases in place to utilize all of ths import
capability in all futue years, it is assumed ths
June 2008
capacity wil be utilized for market purchases.
The calculations presented in Table 9 show the
plannng reserve margin calculated with and
without utilizing this transmission import
capability.
The planng reserve margin for 2009 -2011,
assuming firm market purchases, ranges from
3.5% to 4.6%. In 2012, ths margin increases to
17.3 % with the addition of the 2012 baseload
resource and the Hemingway-Boardman
transmission line. While the planng reserve
margin increases substatially in 2012, Idaho
Power feels it is stil marginal given the manner
of day-to-day uses of this margin for operating
reserves, forced outages and de-ratings, higher
than anticipated loads and delays in anticipated
resource development.
Action Plan Update and
Portolio Comparison
The near-term action plan presented in the
2006 IRP proposed a schedule of events
associated with implementing the preferred
resource portfolio. Resource action plans are
expected to be flexible to accommodate the
uncertinty associated with acquirg resources
though an RFP process, and the uncertinty
associated with developing resources in
cooperation with other utilities. Idaho Power
has deviated from the action plan, as necessar,
to achieve the goal of acquirg suffcient
resources to reliably serve the growing demad
for energy with Idaho Power's service area
while continuing to balance cost, risk,
reliability, and environmental concerns. An
updated near-term action plan is presented in
Table 10 and a comparson of the preferred
portfolio from the 2006 IRP and the updated
portfolio is shown in Table 11.
Page 32 2008 Integrated Resource Plan Update
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Idaho Power Company June 2008
Table 10. Updated Near-Term Action Plan through 2010
Activity
2008
1. January - Issue RFP for 50-100 MW of geothermal
energy.
2. March - 170 MW Danskin expansion on-line.
3. March - Prepare and submit the 2007 Demand-
Side Management Annual Report.
4. April - Solicit expressions of interest from industrial
customers for CHP development.
5. April-Issue 2012 Baseload Resource RFP.
6. June - Submit 2008 IRP Update to the Idaho and
Oregon Commissions.
7. July - Begin the 2009 IRP process with the IRP
Advisory CounciL.
8. September - Announce successful bidder(s) in
the geothermal RFP process.
9. October - Bids due for the 2012 Baseload
Resource RFP.
2009
1.
2.
Conclude the 2012 Baseload Resource RFP process.
Continue DSM implementation plans with guidance
from the EEAG.
Continue working with industrial customers on CHP
development opportunities.
Complete the 2009 IRP and submit to the Idaho and
Oregon Commissions in June 2009.
Make final commitments on 225 MW Hemingway-
Boardman Transmission Project.
Make final commitments on 500 kV Gateway West
Transmission Project.
7. Activities associated with the 2012 Baseload Resource
RFP depending on the outcome of the RFP process.
3.
4.
5.
6.
2010
1. Continue DSM implementation plans with guidance
from the EEAG.
2. Issue RFP for wind generation depending on current
level of PURPA wind development.
Table 11. 2006 IRP Preferred Portfolio and Updated Portolio
2006 IRP Preferred Portolio Updated Portolio
Year Resource MW Year Resource MW
2008 Wind (2005 RFP)100 2008 Wind (2005 RFP) 1 100
2009 Geothermal (2006 RFP)50 2009 Geothermal (2006 RFP)2 50
2010 CHP 50 2010 CHP (2008 Solicitation)3 50
2011 Geothermal (2008 RFPt 50
2012 Wind 150 2012 Wind5 150
2012 Transmission McNary-Boise 225 2012 Trans. Hemingway-Boardman6 225
2012 Southwest Idaho CCCT7 250
2013 Wyoming Pulverized Coai7 250
2017 Regional IGCC Coal 250 2017 Regional IGCC Coal 250
2019 Transmission Lolo-IPC 60 2019 Transmission Lolo-IPC 60
2020 CHP 100 2020 CHP 100
2021 Geothermal 50 2021 Geothermal 50
2022 Geothermal 50 2022 Geothermal 50
2023 INL Nuclear 250 2023 INL Nuclear 250
Total Nameplate 1,585 Total Nameplate 1,635
Horizon Wind Energy Contract (100.65 MW) - Elkhom Valley Wind Project (on-line December 2007).
U.S. Geothermal Contract (45.5 MW) - Raft River #1 (13 MWon-line October 2007), Raft River #3 (6.5 MW) and Neal Hot Springs #1
(13 MW) and #2 (13 MW) are under development.
In April 2008, Idaho Power began soliciting industrial customers within its serviæ area for expressions of interest in the development of
combined heat and power projects at existing industrial facilties. Depending on the level of interest, a formal RFP may be issued in late
2008.
An RFP for 50 to 100 MW of geothermal energy was released in January 2008 to offset deficits resulting from PURPA contract
terminations.
Actual quantity wil depend on level of PURPA wind development.
Project was renamed once actual termination points were identified.
Due to escalating construction costs and continued uncertainty surrounding future GHG laws and regulations, Idaho Power has shifted itsfocus frOIl a conventional coal-fired resource to the development of a combined-cycle, natural gas resource located closer to its load
center in southern Idaho.
Page 34 2008 Integrated Resource Plan Update
Idaho Power Company
8. SUMMARY
The Idaho PUC and the Oregon PUC both asked
Idaho Power to file an IRP update and the
company believes the 2008 Integrated Resource
Plan Update meets the requirements of Idaho
Order 303017 and Oregon Order 07-002 by
addressing the following:
· Describe the actions that Idaho Power
has taken to implement the 2006 IRP.
· Provide an assessment of what has
changed since the 2006 IRP was filed in
the fall of 2006. In the 2008 IRP
Update, Idaho Power has discussed
various resource issues including load,
resource contracts, supply-side resource
additions and plans, demand-side
program implementation and
performance, and transmission resource
projects and plans.
· Explain deviations and changes that
have occured since the 2006 IRP was
fied in 2006.
One of the key strengths of Idaho Power's
plang process is that the IRP is updated on a
regular basis. Frequent planng and review
allows Idaho Power, the Idaho and Oregon
utility commssions, and concerned customers,
including the IRP Advisory Council, to revisit
the resource plan and make periodic adjustments
and corrections to reflect changes in technology,
economic conditions, and regulatory
requirements. Durg the period between
resource plan fiings, the public and regulatory
oversight of the activities identified in the
near-term action plan allows for discussion and
adjustment of the IRP as warrted.
2009 Integrated Resource Plan
Intial work on Idaho Power's 2009 IRP has
already begun and many of the issues outlined
in this update wil form the foundation for the
June 2008
2009 IRP. Idaho Power is planing to hold the
first 2009 IRP Advisory Council meeting in
mid-year 2008. The first meeting wil be an
educational session which wil be followed by
regular montWy meetings staing in the fall and
continuing though the winter. Idaho Power
anticipates having a drft version of the
2009 IRP available in the sprig and expects to
fie the resource plan with the Idaho and Oregon
utility commissions in June 2009.
Coordination with Other Idaho
Electric Utilities
In April 2007, Idaho Power requested a .
one-year delay in the filing of its next IRP until
June 2009 to coordinate the filing with Avista
and PacifiCorp's Integrated Resource Plans.
The Idaho PUC accepted the one-year IRP fiing
delay in Order 30317 issued on May 23, 2007.
The adjusted fiing schedule wil provide an
opportty for Idaho Power, Avista and . .
PacifiCorp to explore possibilities for the Joint
development of supply-side resources and
transmission projects. Idaho Power plans to
participate in A vista and PacifiCorp' s resource
plang process and wil invite representatives
from each utility to attend Idaho Power's IRP
Advisory Council.meetings.
2008 Integrated Resource Plan Update Page 35
Idaho Power Company June 2008 - Appendix A
Page 36 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix A
Appendix A
Sales and Load Forecast Data
2008 Integrated Resource Plan Update Page 37
Idaho Power Company June 2008 - Appendix A
Page 38 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix A
Expected Case Average Forecast Annual Growth Rates (%)
Sales
Residential Sales...............
Commercial Sales..............
Irrigation Sales...................
Industrial Sales... ..... ...........
Additional Firm Sales.........
Firm Sales..........................
System Sales.....................
Total Sales.........................
Loads
Residential Load................
Commercial Load...............
Irrigation Load....................
Industrial Load....................
Additional Firm Sales.........
Firm Load Losses... ....... .....
Firm Load...........................
System Load......................
Total Load..........................
Firm Requirement Load......
Peaks
Firm Peak...........................
System Peak......................
Total Peak..........................
Firm Requirement Peak.....
Winter Peak.......................
Summer Peak....................
Customers
Residential Customers.......
Commercial Customers......
Irrigation Customers...........
Industrial Customers..........
2008-2013 2008-2018 2008-2027
1.5
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1.3
2008 Integrated Resource Plan Update Page 39
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Idaho Power Company June 2008 - Appendix A
Expected Case Sales and Load Forecast Annual Summary
Biled Sales (MWh) . 50th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017Residential.. ..... ....... ..... ................. ..........5,272,077 5,381,084 5,466,252 5,559,713 5,611,397 5,667.256 5,703,306 5,741,952 5,84,664 5,883,023Commercial.............................................3,991,985 4,073,751 4.163,884 4.248,34 4,312,482 4,379,893 4,428,980 4,478,747 4,568,202 4,614,066Irrgation..................................................1,606,077 1,602,62 1,600,993 1,597,335 1,593,692 1,590,815 1,582,34 1,585,301 1,568,210 1,582,580Industial.................................................2,411,609 2,460,859 2,515,918 2,563,563 2,607,249 2.650,684 2,685,765 2,732,383 2,781,43 2,810.881Additional Finn.... ........... ................. .... .....1,168,602 1,472,472 1,509.783 1,512,208 1,468,718 1,466,45 1,462,890 1,463,064 1,466,036 1,45,239Finn Sales 14,450,350 14.990,809 15,256,830 15,481,163 15,593,53 15,755,103 15,863,280 16,001,447 16,244,54 16,34,789
System Sales 14,45,350 14,990,809 15,256,830 15,481,163 15,593,539 15,755,103 15.863,280 16,001,447 16,244,54 16,349.789
Finn Of-Sysem Sales. ...... .......... ...........0 0 0 0 0 0 0 0 0 0Total Sales 14,450,350 14,990,809 15,256.830 15,481,163 15,593,539 15,755,103 15,863,280 16,001,447 16.244,546 16,349,789
Generation Month Sales (MWh) . 50th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017Reidential..............................................5,297,677 5,387,54 5,73,222 5,563,755 5,633,969 5,670,071 5,706,137 5,748,742 5,862,441 5,885,934CommercaL............................................4.007,512 4,078,664 4,168,703 4,252,150 4,328,584 4,382,877 4,431,746 4,483,55 4,583,64 4.615,808Irrgation..................................................1,606,088 1,602,646 1,600,995 1,597,33 1,593.701 1,590,812 1,582,342 1,585,303 1,588,213 1,58,582Industral.................................................2,414,715 2,465,851 2,520,663 2,567,677 2,610,442 2,655,148 2,688,627 2,736,533 2,785,052 2,814,178Additional Finn...... ..... ...... .... ..... ...............1,168,602 1,472,472 1,509,783 1,512,208 1,468,718 1,466,45 1,462,890 1,463,064 1,466,036 1,459.239Finn Sales 14,494,594 15,007,180 15,273,365 15,93,126 15,635,415 15,765,363 15,871,743 16,017,192 16.285,383 16,357,740
System Sales 14,494,594 15,007,180 15,273,365 15,493.126 15,635,415 15,765.363 15,871,743 16,017,192 16,285,363 16.357,740
Firm Of-Sysem Sales............................0 0 0 0 0 0 0 0 0 0Total Sales 14,494,594 15,007,180 15,273,365 15,93.126 15,635,415 15,765,363 15,871,743 16,017,192 16,285,383 16,357,740
Loss.........................................................1,423,205 1,460.117 1,486,470 1,509.866 1,527.755 1,542,542 1,554,939 1,569,728 1,597,326 1,605,687Required Generation 15,917,799 16,67,297 16,759,835 17,002,992 17,163,169 17,307,905 17,426,682 17,586,921 17,882,709 17,963.427
Average Load (aMW). 50th Percentile
2008 2009 2010 2011 2012 2013 2014 . 2015 2016 2017Residential..............................................603 615 625 635 641 647 . 651 656 667 672COmmercial............................................456 466 476 485 493 50 506 512 522 527Irrgation..................................................183 183 183 182 181 182 181 181 181 181IndustriaL................................:..............275 281 288 293 297 303 307 312 317 321Aditional Finn... .................... ..................133 168 172 173 167 167 167 167 167 167Los.........................................................162 167 170 172 174 176 178 179 182 183Finn Load 1.812 1,880 1,913 1,941 1,954 1,976 1,989 2,008 2,036 2,051
UghtLoad..........................,.....................1,648 1,710 1,740 1,766 1,777 1,797 1,810 1,826 1,852 1,865Heavy Load............................................. 1,940 2.013 2.048 2,078 2,093 2,116 2,130 2,150 2,180 2,196System Load 1,812 1,880 1,913 1,941 1,954 1,976 1,989 2,008 2,036 2,051
Rnn Of-System Læd..............................0 0 0 0 0 0 0 0 0 0Total Load 1,812 1,880 1,913 1,941 1,954 1,976 1,989 2,008 2,036 2.051
Peak Load (MW) . 90th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017Energy Effciency (Mw). ....... ........... .........-3 -46 -61 -76 -92 -107 -123 -135 -146 -157Demand Reponse (Mw)........ ...... ...........-66 -78 -62 -82 -62 -62 -62 -82 -62 -62
Rnn Peak Load 3,240 3,338 3,00 3,464 3,510 3,567 3,615 3,671 3,740 3,792
System Peak (1 Hour)3,240 3,338 3,00 3,464 3,510 3,567 3,615 3,671 3,740 3,792
Finn Of-Sysem Peak............... ...... ..... ...0 0 0 0 0 0 0 0 0 0Los.........................................................0 0 0 0 0 0 0 0 0 0Total Peak Læd 3,240 3,338 3,400 3,46 3,510 3,567 3.615 3,671 3,740 3,792
Page 60 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix A
Expected Case Sales and Load Forecast Annual Summary
Biled Sales (MWh) . 50th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Residential... ................ ................. ..........5,925,711 6,015,087 6,119,743 6,227,718 6,336,936 6,445,662 6,55,914 6,665,539 6,785,280 6,901,45
CommerciaL...........................................4,64,002 4,739,205 4,841,226 4,94,104 5,055,592 5,166.266 5,281,491 5,398,87 5,519,360 5,639,58
Irrgation..................................................1,584,791 1,587,750 1,590,824 1,593,872 1.596,871 1,599,866 1,602.860 1,605,908 1,608,86 1,611,660
IndustraL................................................2,857,163 2,905,486 2.962,268 3,012,134 3,064,480 3,117.298 3,172,855 3,227,871 3,309.541 3,394,606
Additional Firm.... ..... ... ......... ............... .....1,458,939 1,458,839 1,461,536 1,45,039 1,453,139 1,443,139 1,445,036 1,432,339 1,421,239 1,411.239
Firm Sales 16,474,607 16,706.367 16,975,598 17,233,866 17,507,018 17,772,230 18,057,157 18,33,143 18,64,284 18,958,542
System Sales 16,74,607 16,706,367 16,975,598 17.233.866 17.507,018 17,772,230 18,057,157 18,330,143 18,644.284 18,958.542
Firm Of-8ysem Sales. .... ....... ...... .... ......0 0 0 0 0 0 0 0 0 0
Totl Sales 16,74,607 16,706,367 16,975,598 17,233,866 17,507.018 17,772,230 18,057,157 18.33,143 18,64,284 18,958,542
Generation Month Sales (MWh) - 50th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Residential...............................................5,931,730 6,022,095 6,146,44 6,234,970 6,34,126 6,452.85 6,582,711 6,672,866 6,792,338 6,908,179
CommerciaL...........................................4,652,673 4.744,250 4,860,039 4,951.318 5,060,836 5,171,55 5,301,600 5,403,851 5,524,660 5.644,803
Irrgation..................................................1,58,794 1,587,753 1.590.834 1,593,874 1,596,874 1,599,868 1,602,870 1,605,910 1,608,866 1,611,662
IndustraL................................................2,861,277 2,909,639 2,966,392 3,017,181 3,069,076 3,122,075 3,176,821 3,233,353 3,316,711 3,401,936
Additional Firm.... .............. ... ......... ...........1,45,939 1,458,839 1,461,536 1,45,039 1,45.139 1,44,139 1,445,036 1,432,339 1,421,239 1,411,239
Firm Sales 16,489,412 16.722,575 17,025,248 17,251,381 17.524.050 17,789,495 18,109,038 18,348,318 18,663,814 18,977,819
System Sales 16,489,412 16.722,575 17,025,246 17,251,381 17.524.05 17,789,495 18,109,038 18,348.318 18,683,814 18,977,819
Firm Of-Sysem Sales............................0 0 0 0 0 0 0 0 0 0
Totl Sales 16,489,412 16,722,575 17,025,246 17.251,381 17,524,050 17,789,495 18,109,038 18,348,318 18,663,814 18.977,819
Los.........................................................1,618,701 1,642,735 1,673,136 1,696.898 1,724,517 1,751,984 1,783,691 1,808,436 1,840,591 1,872,434
Required Generation 18,108,113 18,365,310 18,696.382 18,948,279 19,248,587 19,541,479 19,892,729 20,156,754 20,50,405 20,850,252
Average Load (aMW) . 50th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
ResidentiaL.............................................677 687 700 712 724 737 749 762 775 789
CommerciaL...........................................531 542 553 565 578 590 604 617 631 64
Irrgation..................................................181 181 181 182 182 183 182 183 184 184
Indus1rial..................................................327 332 338 34 350 356 362 369 379 388
Additional Firm.........................................167 167 166 166 166 165 165 164 162 161
Loss.........................................................185 188 190 194 197 200 203 206 210 214
Firm Lod 2,067 2,096 2,129 2,183 2,197 2,231 2,265 2,301 2,341 2,380
Ught Load................................................1,880 1,907 1,936 1,967 1,999 2,029 2,060 2,093 2,129 2,165
Heavy Load............................................. 2,214 2,245 2,279 2.315 2,353 2,389 2,425 2,464 2,507 2,548
System Load 2,067 2,096 2,129 2,163 2,197 2,231 2,265 2,301 2,341 2,380
Firm Of-System Load..............................0 0 0 0 0 0 0 0 0 0
Total Load 2,067 2,096 2,129 2.163 2,197 2,231 2,265 2,301 2.341 2,380
Peak Load (MW) - 90th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Energy Effciency (Mw).......... ............. .....-168 .179 -190 -200 -210 .219 -229 -239 -243 -247
Demand Response (Mw).......... .... ...........-82 -82 -82 -82 -82 -82 -82 -82 -82 -82
Rrm Peak Load 3,847 3,916 3,990 4,066 4.143 4.220 4,298 4,378 4,464 4,550
System Peak (1 Hour)3,847 3,916 3,990 4,066 4,143 4,220 4,298 4,378 4,464 4,550
Firm Of-8yslem Peak..,..........................0 0 0 0 0 0 0 0 0 0
Los.........................................................0 0 0 0 0 0 0 0 0 0
Totl Peak Lod 3,847 3,916 3,990 4,06 4,143 4,220 4,298 4,378 4,46 4,55
2008 Integrated Resource Plan Update Page 61
Idaho Power Company June 2008 - Appendix A
Page 62 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix A
70th Percentile Average Forecast Annual Growth Rates (%)
Sales
Residential Sales...............
Commercial Sales..............
Irrigation Sales...................
Industrial Sales...................
Additional Firm Sales.... .....
Firm Sales..........................
System Sales.....................
Total Sales.........................
Loads
Residential Load........ ........
Commercial Load... ............
Irrigation Load....................
Industrial Load....................
Additional Firm Sales.........
Firm Load Losses...............
Firm Load...........................
System Load......................
Total Load..........................
Firm Requirement Load......
Peaks
Firm Peak...........................
System Peak......................
Total Peak..........................
Firm Requirement Peak.....
Winter Peak............... ........
Summer Peak....................
Customers
Residential Customers.......
Commercial Customers......
Irrigation Customers...........
Industrial Customers..........
2008-2013 2008-2018
2008 Integrated Resource Plan Update Page 63
2008-2027
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2008 Integrated Resource Plan Update Page 83
Idaho Power Company June 2008 - Appendix A
70th Percentile Sales and Load Forecast Annual Summary
Biled Sales (MWh) . 70th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017ResidentiaL.............................................5,406.449 5,519,177 5,607,822 5,704,610 5,759.539 5,818,63 5,857,860 5,899,681 6,001,595 6,047,071CommercaL...........................................4,031,788 4,114,624 4.205,782 4,291,241 4,356.369 4,424,778 4,474,860 4,525,631 4,616.109 4,662,988Irrgation..................................................1,754,686 1,751.251 1,749,602 1,745,94 1,742,301 1.739,424 1,730,949 1,733,909 1,736,819 1,731,189IndustraL................................................2,411,609 2,460,859 2,515,918 2,563,563 2,607,249 2,650.684 2,685,765 2,732,383 2,781,43 2,810.881
Additional Firm.... ................ ... ....... ...... .....1,168,602 1,472,472 1.509,783 1,512,208 1,468,718 1,466,455 1,462,890 1,463,064 1,466,036 1,459,239
Firm Sales'4,773,134 15,318,384 15,56.906 15,817,567 15,934,177 16,099,974 16,212,324 16.35,669 16,601,993 16,711,367
System Sales 4,773,134 15,318,38 15,588,906 15,817,567 15,934,177 16,099,974 16,212,324 16,35,669 16,601,993 16,711,387
Firm Of-System Sales............................0 0 0 0 0 0 0 0 0 0
Totl Sales 4,773,134 15,318,384 15,588,906 15,817,567 15,934,177 16,099,974 16,212,324 16,35,669 16,601,993 16,711,367
Generation Month Sales (MWh) - 70th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
ResidentiaL...... ............ ...... ..... ......... .......5,432,748 5,525,803 5,614,938 5,708,787 5,782,778 5.821,569 5.860,805 5,906,581 6,024,035 6,050,076COmmercal.............................................4,047,538 4,119,613 4,210,673 4,295,119 4.372,701 4,427,833 4,477,699 4,530,509 4,631,795 4.664,803Irrgation..................................................1,754.697 1,751,254 1,749,603 1,745,94 1,742,310 1,739,421 1,730,951 1.733,912 1,736,822 1,731,190IndustriaL...............................................2,414,715 2,465,851 2,520,663 2,567,677 2,610,442 2,655,146 2.688,627 2.736,533 2,785.052 2,814,178Aditional Firm.........................................1,168,602 1,472,472 1,509,783 1,512,208 1,468,718 1,466,455 1,462,890 1,463.064 1,466,036 1,459,239
Firm Sales 4,818,299 15,33,994 15,605,660 15,829,736 15,976,950 16,110,426 16,220,972 16,370,598 16,643,741 16,719,486
System Sales 4,818,299 15,334,994 15,605,660 15,829,736 15.976.950 16,110,426 16,220,972 16,370,598 16,643,741 16,719,486
Firm Of-Sysem Sales............................0 0 0 0 0 0 0 0 0 0Total Sales 4,818,299 15,33,994 15,605,660 15.829,738 15,976,950 16,110,426 16,220,972 16,370,598 16,643.741 16,719,486
Loss.........................................................1,459,706 1,497,078 1,523,925 1,547,797 1,566,221 1,581,407 1,594,266 1,609,518 1,637,654 1,64,402
Require Generation 6,278,005 16,832,072 17,129,585 17,377,53 17.54,171 17,691,834 17.815,238 17,980,116 18,281.395 18,365,888
Average Load (aMW) . 70th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Residential........ ............. ....... ........... ........618 631 641 652 658 865 669 674 686 691COmmercial.............................................461 470 481 490 498 505 511 517 527 533Irrigation..................................................200 200 200 199 198 199 198 198 198 198IndustriaL...............................................275 281 288 293 297 303 307 312 317 321Additional Firm.........................................133 168 172 173 167 167 167 167 167 167Los.........................................................166 171 174 177 178 181 182 184 186 188Firm Lod 1,853 1.921 1,955 1.984 1,997 2,020 2,034 2,053 2,081 2,097
U9ht Load................................................1,686 1,748 1,779 1,804 1,817 1,837 1,850 1,867 1,893 1,907
Heavy Load.............................................1,984 2,058 2,093 2,124 2,139 2,163 2,178 2,198 2,228 2,246
System Load 1.853 1,921 1,955 1.984 1,997 2,020 2,034 2,053 2,081 2,097
Firm Of-Sysem Load................. ...... .......0 0 0 0 0 0 0 0 0 0
Total Load 1.853 1.921 1,955 1,984 1,997 2,020 2,034 2,053 2,081 2,097
Peak Load (MW) . 95th Percentile
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
En Effciency (MW).. .... ....... ...... ........-30 -46 -61 -76 .92 -107 -123 -135 -146 -157Demand Reponse (MW). ...... ............ .....-66 -78 -82 -82 -82 -82 -82 -82 -82 -82
Firm Peak Lod 3,284 3,383 3,44 3,511 3,558 3,617 3,666 3,723 3,793 3,84
System Peak (1 Hour)3,284 3,383 3,446 3,511 3,558 3,617 3,666 3,723 3,793 3,84
Firm Of-System Peak............... ...... ..... ...0 0 0 0 0 0 0 0 0 0Los.........................................................0 0 0 0 0 0 0 0 0 0Totl Peak Lod 3,284 3,383 3,44 3,511 3,55 3,617 3,666 3,723 3,793 3,846
Page 84 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix A
70th Percentile Sales and Load Forecast Annual Summary
Biled Sales (MWh) - 70th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
ResidentiaL.............................................6,092,896 6,185,469 6.293.33 6,404.538 6,517,008 6,629,038 6,741,617 6,855,549 6,978,555 7,098,019
CommerciaL............................................4,697,953 4,790.210 4,893,302 4,999,267 5,109,859 5,221.66 5.338.038 5,45,192 5,578,226 5,699,631Irrgation..................................................1,733,400 1,738,359 1.739,433 1,742,460 1.745,460 1,748,474 1,751,469 1,754,517 1,757,473 1,760,269
IndustriaL.................................................2,857,163 2,905,486 2.962.268 3,012,134 3,064,480 3,117,298 3,172,855 3,227,871 3,309,541 3,394,606
Additional Firm.........................................1,458,939 1,458,839 1,461,536 1,45,039 1,453,139 1,44,139 1.445,036 1,432,339 1,421,239 1,411,239
Firm Sales 6.840,351 17,076,364 17,349.871 17,612,45 17,889,966 18,159,612 18,449,015 18,726,468 19,045,034 19,363,764
System Sales 6,840,351 17,076,364 17,34,871 17,612,458 17,889,966 18,159,612 18,449,015 18,726,468 19,045,034 19.363,764
Firm Of-System Sales................. ...........0 0 0 0 0 0 0 0 0 0
Total Sales 6,840,351 17,076,364 17,349,871 17,612,458 17,889,966 18,159,612 18,449,015 18,726,468 19,045,034 19,363.764
Generation Month Sales (MWh) - 70th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
ResidentiaL.............................................6,099,009 6,192,588 6,320,697 6,11,872 6,524,277 6,63.308 6,770,076 6,862,937 6,985,669 7,104,797
CommerciaL............................................4,702,699 4,795,332 4,912,381 5,004,560 5,115,184 5,227,038 5,35,43 5,461,640 5.583,610 5.704,936
Irr9ation................,.................................1,733,402 1,736,361 1,739,443 1,742,483 1,745,482 1,748,476 1,751,479 1,754,519 1,757,475 1,760,271
IndustriaL.................................................2,861,277 2,909,639 2,966,392 3,017,181 3.069,076 3,122,075 3,176,821 3,233,353 3,316.711 3,401,936
Additional Firm..............................'...........1,45,939 1,45,839 1.461.536 1,45,039 1,453,139 1,44.139 1,44,036 1,432,339 1,421,239 1,411,239
Firm Sales 6,855,326 17,092,739 17,400.449 17,630,134 17,907.158 18.177.036 18,501,847 18,744.787 19,064,704 19,383,178
System Sales 6.855,326 17,092,739 17,400,449 17,630,134 17,907,158 18,177,036 18,501,847 18,744,787 19,064,704 19,383,178
Rrm Of-System Sales............................0 0 0 0 0 0 0 0 0 0
Totl Sales 6,855,326 17,092,739 17,400,449 17,630,134 17,907,158 18,177.036 18,501.847 18,744,787 19,064,704 19,383,178
Lo.........................................................1,659,878 1,684.385 1,715,335 1,739,502 1,767,607 1,795,567 1,827.850 1,853,015 1,885,664 1,918,006
Required Generation 8,515,203 18,777,124 19,115,784 19,369,636 19,674.785 19,972,603 20,329,697 20,597,803 20,950,368 21,301,184
Average Load (aMW) - 70th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
ResidentiaL.............................................696 707 720 732 745 758 771 783 797 811
CommerciaL...........................................537 547 559 571 584 597 610 623 637 651
Irrgation..................................................198 198 198 199 199 200 199 200 201 201
IndustriaL.................................................327 332 338 34 350 356 362 369 379 388
Additional Firm.........................................167 167 166 166 166 165 165 164 162 161
Los.........................................................189 192 195 199 202 205 208 212 215 219
Rrm Load 2,114 2,144 2,176 2.211 2,246 2,280 2,314 2,351 2,392 2,432
Ugh! Load................................................1,922 1,949 1,979 2,011 2,043 2,074 2,105 2.138 2,175 2,211
Heavy Load............................................. 2,264 2,296 2,33 2,367 2,405 2,442 2,478 2,518 2,561 2,603
System Load 2,114 2,144 2,176 2,211 2,246 2,280 2,314 2,351 2,392 2,432
Firm Of-System Load..............................0 0 0 0 0 0 0 0 0 0
Total Load 2.114 2,144 2,176 2,211 2,246 2,280 2,314 2,351 2,392 2,432
Peak Load (MW) . 95th Percentile
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Energy Effciency (MW)..... ..... .... ... ...... ....-168 -179 -190 -200 -210 -219 -229 -239 -243 -247
Demand Response (MW). ............ ...... .....-82 -82 -82 -82 -82 -82 -82 -82 -82 -82
Firm Peak Load 3,901 3,972 4,047 4,124 4,202 4,280 4,359 4,44 4,527 4.615
System Peak (1 Hour)3,901 3,972 4,047 4.124 4,202 4,280 4,359 4,44 4,527 4,615
Firm Of-System Peak..... .... ....................0 0 0 0 0 0 0 0 0 0
Loss.........................................................0 0 0 0 0 0 0 0 0 0
Totl Peak Load 3,901 3,972 4,047 4,124 4,202 4,280 4,359 4,440 4,527 4,615
2008 Integrated Resource Plan Update Page 85
Idaho Power Company June 2008 - Appendix A
Page 86 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix B
AppendixB
Aurora CCCT Analysis Assumptions
2008 Integrated Resource Plan Update Page 87
Idaho Power Company June 2008- Appendix B
Page 88 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix B
Aurora CCCT Analysis Assumptions
295.7 MW lx1 Combined-Cycle Natural Gas Plant
Heat rate
Heat rate at Min
Minimum Capacity
Minimum Up Time
Minimum Down Time
Variable Cost
Levelized Fixed Cost
7,300
8,300
50%
4 hours
1 hour
$1.94
$40,474,404
Natural Gas Prices
(Henry Hub - November 2007)
Year
2012
2013
Average Price
$7.45
$7.55
Hydro Conditions Base Case hydro condnions are defined at the 50th percntie for Idaho Power projects (Pacific Northwest
projects at Aurora default values). Low Hydro conditions are at the 70th percentile for Idaho Power projects
(27% energy reduction from the Base Case) and energy from other Pacific Northwest hydro projects is
reduced by 20% from Aurora default values.
Transmission The Base Case scenario includes the transmission upgrade from the southern Idaho node to the Oregon!
Washington NE node (225 MW additional transfer capacit). The "No Transmission Upgrade" scenari does
not include this addnional transfer capabiiny.
Forecast Load 2008 IRP Update Load Forecast
(50th Percntile)
Year
2012
2013
aMW
1,954
1,976
Summary of the Operational Difference of a 2012 vs. 2013 Online Date
The table below summarizes the portfolio differences by year wnh the CCCT online date as the variable. The diffrences in the Aurora model
sim ulations for each year are as follows:
2012 (CCCT in April 2012) - (No CCCT in 2012)
2013 (2012 CCCT All Year) - (CCCT in April 2013)
Fixed costs were calculated outside of the Aurora model and the results are in nominal dollars (in $OOO's).
Low Hydro & No
Base Case Low Hydro No Trans Upgrade Trans Upgrade
2012 Fewer Market Purchases $82,790 $106,229 $84,753 $103,727
2012 More Market Sales $25,853 $18,630 $25,989 $18,646
2012 (Greater) Resource Costs ~-$71,808 -$69,730 -$71,977
2012 Total Diffrence $40,108 $53,051 $41,012 $50.395
2013 Fewer Market Purchases $11,274 $32,531 $1,938 $39,000
2013 More (Fewer) Market Sales $16,441 -$1,154 $19,956 $3,594
2013 (Greater) Resource Costs -$24797 -$27,392 -$25,703 -$30,400
2013 Total Diffrence $2,918 $3,985 -$3,809 $12,195
Operational Value (All Years)$43,026 $57,036 $37,203 $62,590
Fixed Cost (All Years)-$34,808 -$34,808 -$34,808 -$34,808
Benefr of 2012 On-Line Date $8,218 $22,228 $2,395 $27,782
2008 Integrated Resource Plan Update Page 89
Idaho Power Company June 2008 - Appendix B
Page 90 2008 Integrated Resource Plan Update
Idaho Power Company June 2008 - Appendix C
Appendix C
Load and Resource Balance
2008 Integrated Resource Plan Update Page 91
Idaho Power Company June 2008 - Appendix C
Page 92 2008 Integrated Resource Plan Update
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