200806112007 IRP Update.pdf

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: ~~l~ouNTAIN 200a Jm¡ II Al'~ 9=19
201 South Main, Suite 2300
Salt Lake City, Utah 84111
June 11,2008
VI OVERNIGHT DELIVERY
Idaho Public Utilties Commission
472 West Washington
Boise, ID 83702
Attn: Jean Jewell, Commission Secreta
RE: Case No. PAC-E-07-11
PacifiCorp's 2007 Integrated Resource Plan (lRP) Update
Dear Ms. Jewell:
Enclosed are an originl and two (2) copies ofPacifiCorp's 2007 Integrted Resource Plan (IR)
Update. This 2007 IRP Update is documentation of the plan that was presented and discussed at
the Company's Februar 29, 2008, IR public input meeting. Copies of the report are available
electronically and will be posted on PacifiCorp's website, at ww.pacificoro.com. The
Company's 2007 IR was fied with the Idaho Public Utilities Commssion ("Commssion") on
May 30, 2007.
The 2007 IRP Update is submitted to the Commssion pursuat to the IR guidelines issued in
Order No. 27835, as modified by Order No. 30262. The Company plans on filing its 2009 IRP
no later than March 31, 2009.
The 2007 IR Update is being submitted for inormational puroses only. Since the Company
expects to file its next IRP in March 2009, it does not request acknowledgment of its 2007 IRP
Update.
It is respectfuly requested that all formal correspondence and Staff requests regarding ths filing
be addressed to the following:
By E-mail (preferred):dataequest(ßpacificoro.com
By Fax:[phone]
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
If there are informal inquiries concernng the filing, please contat Pete Waren, Manager
Integrated Resource Planng at [phone] or Ted Weston, Idaho Reguatory Affairs
Manager at [phone].
Sincerely,~K- ~f*'
Jeffey K. Larsen
Vice President, Reguation
Enclosures
PacifCorp - 2007 IRP Update
This 2007 Integrated Resource Plan Update (IRP) Report is based upon the best available
information at the time of preparation. The IRP action plan wil be implemented as described
herein, but is subject to change as new information becomes available or as circumstances
change. It is PacifiCorp's intention to revisit and refresh the IRP action plan no less frequently
than anually. Any refreshed IRP action plan wil be submitted to the State Commissions for
their information.
Formore information, contact:
PacifiCorp
IRP Resource Planing
825 N.E. Multnoirah, Suite 600
Portland, Oregon 97232
[phone]
IRP(fPacifiCorp.com
htt://ww.PacifiCorp.com
This report is printed on recycled paper
Cover Photos (Left to Right):
Wind: Foot Creek 1
Hydroelectric Generation: Yale Reservoir (Washington)
Demand side management: Agricultural Irrigation
Thermal-Gas: Currant Creek Power Plant
Transmission: South Central Wyoming line
PacifCorp - 2007 IRP Update
TABLE OF CONTENT
1. Introduction..............................................................................................................................................1 _
Natual Gas and Power Market Price Updates.........................................................................................1
Natual Gas Market Prices.. .... ................... ..... ......... .......... .............. ..................... ..... .... ... .......... .... ..... i
Electrcity Market Prices.............. ...... ...... ..... ... ......... .......... ............ ... ...... ............ ............. ........... ........2
Ination Rates ......... ........... .......... ......... ........ ................. ............. ............ ...... ...... ...... ............... .... ........ ....4
Carbon Dioxide Emission Costs and Compliance Assumptions .... ....... ............ .... .......... ........... .............4
2. Resource Needs Assessment Update .......................................................................................................5
Load Forecast...........................................................................................................................................5
Resources ..... ......... ... ....... ... ............... ......... ......... ... ....... ............ ............ ..... .... .......................................... 7
Significant Changes to Existing Resources........................ ............................... .... ............. .......... ........ 7
Significant Changes to Planed Resources ...........................................:.............................................. 7
Thermal............................................................................................................................................7
Wind Projects...................................................................................................................................8
Hydroelectric Plants.........................................................................................................................9
Kern River Recovered Energy Generation Project ............ .............. .............. ........ .... ...................... 9
Demand-Side Management Resources ..... ............. ........ ........... ...... ......................... ....... .......... ..... 10
Updated Capacity Balance .....................................................................................................................12
3. New Resource Assumptions .................................................................................................................. 17
Capital Costs. ...... ... ................................. .......... .......................... ....... ..... .......... ....... ..................... ......... 17
Treatment of Coal Resources ........ ...... ......... ................. ........ ........ .......... .... ....... ........... .......... ............... 17
Renewable Resources ..... ....... ....... ... ... ......... ............ ............. ....... ........... .... ....... .......... .......... ........ ........ 17
4. Transmission Resources......................................................................................................................... 17
5. Front Office Transactions ...................................................................................................................... 18
6. Business Plan Portfolio .......................................................................................................................... 19
7. Action Plan Update ................... ....... ....... .... ............. ..... ............. .......... ............. .......... .................. .........20
Action Plan Implementation ............ .......... .......... ....... .... ........... .... ... ... .... .......... ............ ........... .............25
Demand-Side Management.................. ..... ..... ............. .... ... ...... ... ............ ....... ............. ........ ...... ... ......25
Supply-Side Resource Procurement Activities ..................................................................................25
Renewable Request for Proposals (RFP 2008R) ...................................................................;.......25
Renewable Request for Proposal (RFP 2008R - I).............. ............. .... .............. ...... ................ .......25
Request For Proposal- 2008 All Source RFP ...............................................................................25
PacifCorp - 2007 IRP Update
INDEX OF TABLES
Table I - Inflation Rate Forecasts ................................................................................................................4
Table 2 - Anual Load Growth in Megawatt-hours Forecasted, 2008 through 2017...................................5
Table 3 - Forecasted Coincidental Peak Load in Megawatts .....:................................................................. 5
Table 4 - Anual Load Growth Change: October 2007 Forecast Less March 2007 Forecast...................... 6
Table 5 - Anual Coincidental Peak Growth Change: October 2007 Forecast Less March 2007 Forecast. 6
Table 6 - Thermal Upgrade Schedule...........................................................................................................8
Table 7 - Recent Wind Resource Additions .................................................................................................9
Table 8a - Demand-Side Resource Forecast Comparson by Year, 2008-2012......................................... 1 I
Table 8b - Demand-Side Resource Forecast Comparison by Year, 2013-2017......................................... 11
Table 9 - Load and Resource Capacity Balance.........................................................................................15
Table 10 - 2008 Business Plan Capacity Balance Less 2007 IRP Capacity Balance................................. 16
Table I I - Resource Supply Side Options Capital Cost Increases ............................................................. 17
Table 12 - 2008 Business Plan Supply-Side :Resource Portolio ...............................................................19
Table 13 _ Updated Action Plan .................................................................................................................21
INDEX OF FIGURES
Figure 1 - Henr Hub Natural Gas Prices (Nominal) ...................................................................................2
Figure 2 - Average Anual Flat Mid-Columbia Electrcity Prices............................................................... 3
Figue 3 - Average Anual Flat Palo Verde Electrcity Prices .................................................................... 3
Figure 4 - Capacity Position Comparson, 2007 IRP versus the 2008 Business Plan................................ 12
Figure 5 - System Coincident Peak Loads and Resources, 2008 Business Plan ........................................ 13
Figure 6 - East Coincident Peak Loads and Resources, 2008 Business Plan............................................. 13
Figure 7 - West Coincident Peak Loads and Resources, 2008 Business Plan............................................ 14
Figure 8 - Modeled Transmission System Topology ................................................................................. 18
11
PacifCorp - 2007 IRP Update
1. INTRODUCTION
This 2007 Integrated Resource Plan (IRP) update report chronicles integrated resource plannng
activities that occured subsequent to the filing of the 2007 Integrated Resource Plan on May 30,
2007, and that helped support the development of PacifiCorp's lO-year business plan for the
period 2008-2017 ("2008 business plan"). As part of this support, PacifiCorp performed capacity
expansion optimization modeling based on updated inputs and assumptions. The outcome of this
modeling work was a revised 2008-2017 resource portfolio.
This report first summarizes the significant changes made to inputs and assumptions relative to
the 2007 IRP and used for business plan development, covering (l) natural gas and power market
prices, (2) forecasted inflation rates, (3) carbon dioxide emission costs and regulatory
assumptions, (4) the long-term load forecast, (5) the coincident summer peak capacity load and
resource balance ("capacity balance"), (6) new resource assumptions, (7) the transmission
topology, and (8) front office transactions. The updated resource pòrtolio is then presented
along with associated changes to the 2007 IRP action plan.
NATURAL GAS AN POWER MARKT PRICE UPDATES
Natural Gas MarketPrIces
PacifiCorp's natual gas prices are a blend of market forwards and a fudamentals forecast of
long-term supply and demand. In both the 2007 IR and in the 2008 business plan, market
forwards are used through the first 72 months of the cure. Over this 72 month period, the 2007
IRP reflects market forwards as of August 31, 2006 and the 2008 business plan reflects market
forwards as of September 7, 2007. The long-term portion of the natural gas cure is based upon
a fudamentals-based projection from external sources. Each of the external price projections
are evaluated routinely to ensure that PacifiCorp' s natual gas price cure captues the best
available information at any given point in time. A range of factors are considered when
selecting the external~long-term price forecast. These factors include:
~ Underlying supply and demand fudarnental assumptions
. Forecast documentation
. Peer~to-peer forecast price comparisons
. Forecast release date
. Forecast horizon
Figue 1 show the Henr Hub natual gas prices used to develop delivered natual gas prices in
the 2007 IRP and in the 2008 business plan. Differences through about 2013 are driven largely
by movements in the forward markets between August 2006 and September 2007. Variations in
long-term prices beyond the market period reflect a migration from one external price forecast
issued in August 2006 to another external projection issued in July 2007 consistent with the
approach described above.
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PacifCorp - 2007 IRP Update
Figure 1- Henry Hub Natural Gas Prices (Nominal)
$13
$9
$12
$11
$10
$8
=
¡ $7¿
~ $6
$5
$4
$3
$2
$1
$0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
! -+ 2007 IRP -e 2008 Business Plan I
Electricity Market Prices
Electrcity prices are a blend of 72 months of market forwards and a fudamentals price
projection developed with MIDAS - an hourly chronological dispatch model for the Western
Electricity Coordination Council (WECC). As with natual gas prices, the 2007 IRP reflects
market forwards for electricity as of August 31, 2006 and the 2008 business plan reflects market
forwards as of September 7, 2007. Beyond the market portion of the electricity cure, the
MIDAS price forecast reflects the same fundamentals natual gas price projections described in
the Natual Gas Markets section above.
Figure 2 shows the average anual flat electrcity price at Mid-Columbia as used in the 2007 IR
and in the 2008 business plan. Figue 3 shows average anual flat electrcity prices at Palo
Verde. For both markets, price differences through about 2013 are driven largely by movements
in the forward electrcity markets between August 2006 and September 2007. Over this period,
the relative increase in electricity prices was larger than the increase in natual gas prices,
indicating growt in implied market heat rates. Variations in long-term prices beyond the market
period are largely influenced by the changes to long-term natUal gas prices between August
2009 and September 2007.
2
PacifCorp - 2007 IRP Update
Figure 2 - Average Annual Flat Mid-Columbia Electricity Prices
"j~~"VL~'" ..~~'~
::~ "/~
~
(5 ~A/
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
¡ ~ 2007 IR -e 2008 Business Plan :
Figure 3 - Average Annual Flat Palo Verde Electricity Prices
~~ $50
$40
$100 --------
$90
$80
$70
$60
$30
$20
$10
$0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
j ~ 2007 IR -e 2008 Business Plan I
3
PacifCorp - 2007 IRP Update
INFLATION RATES
Where price forecasts and associated escalation rates were not established by external sources,
IR simulations and price forecasts were performed with PacifiCorp's June 2007 infation rate
schedule (See Table 1 below).
Table 1 - Inflation Rate Forecasts
2007IR
Calendar Average Annual
Years Rate (%)
2007-2013 1.86
2014-2020 1.80
2021-2026 1.88
2008 Business Plan
Calendar Average Annual
Years Rate
2008-2014 1.96
2015-2021 1.90
2022-2027 1.90
CARBON DIOXIDE EMISSION COSTS AN COMPLIANCE ASSUMTIONS
For the 2008 business plan, the assumed carbon dioxide (C02) compliance mechanism for
resource portfolio analysis is a cap-and-trade system. Subsequent to the filing of the 2007 IRP,
PacifiCorp acquired a new module of the System Optimizer capacity expansion model that
includes representation of cap-and-trade regulatory policies. The cap-and-trade functionality was
used for business plan modeling.
Cap-and-trade assumptions include the following:
. Emissions peaking in 2011 (54.9 milion tons) and declining to 2007 emission levels by
2025, assuming straight-line anual decreases for modeling purposes
. Straight-line anual emissions decreasing to 1990 levels by 20301
. An initial CO2 allowance price of$8.62/ton staring in 2012 (in 2008 dollars), and increasing
at PacifiCorp's annual inflation rates
In comparison, for the 2007 IRP, PacifiCorp simulated both CO2 tax and cap-and-trade policies.
For stochastic production cost modeling, PacifiCorp modeled buying and sellng of CO2
emission allowances as an off-line set of spreadsheet calculations assuming a year-2000 emission
cap, a $4.14/ton (2008 dollars) allowance price staing in 2010, a $6.34/ton (2008$) allowance
price in 2011, and a $8.62/ton (2008$) allowance price in 2012, with prices escalated at
PacifiCorp's forecasted inflation rates.
i The emission cap in 2027, the last year ofthe 20-year study period, was 47.4 milion tons.
4
PacifCorp - 2007 IRP Update
2. RESOURCE NEEDS ASSESSMENT UPDATE
LOAD FORECAST
PacifiCorp updated its load forecast in October 2007. Relative to the 2007 IR load forecast
prepared in March 2007, PacifiCorp system sales and coincident summer peak are virtlly
unchanged from 2008 through 2016. 2017 and beyond sales and peak are revised slightly
downward. The main drvers of the change in 2017 and beyond are an increase in Demand-Side
Management (DSM) impacts and a decrease in the Wyoming new Industral forecast. Although
the Wyoming new Industrial forecast is stil very strong, there is a decrease from the March 2007
forecast because of a lower growth forecast for the oil and gas sector.
Tables 2 and 3 report the October 2007 anual load and coincidental peak load forecasts,
respectively. Tables 4 and 5 show the forecast changes relative to the March 2007 load forecast
used for the 2007 IR.
Table 2 - Annual Load Growth in Megawatt-hours Forecasted, 2008 through 2017
Year Total OR WA WY CA UT ID.2
2008 60,492,210 15,339,034 4,522,63 i 9,462,260 938,784 24,622,561 5,384,698
.2009 62,189,571 15,377,514 4,539,415 10,423,043 943,430 25,261,101 5,421,129
2010 63,271,762 15,334,009 4,565,640 1l,OI9,325 95I,074 25,719,727 5,456,965
2011 64,268,367 15,317,970 4,596,175 II,400,485 958,144 26,288,439 5,48I,831
2012 65,506,284 15,299,183 4,622,603 I I,938,797 965,419 26,929,I56 5,524,656
2013 .66,893,227 15,284,852 4,644,877 12,689,116 . 973,643 27,515,113 5,557,774
2014 67,930,143 15,267,788 4,685,033 13,067,586 983,053 28,103,923 5,593,585
2015 68.880,593 15,250,377 4,736,761 13,397,459 994,755 28,643,793 5,627,175
2016 69,789,986 15,228,100 4,762,639 13,553,616 1,006,312 29,349,829 5,659,I59
2017 70,464,218 15,213,956 4,786,162 13,606,094 I,018,537 29,936,986 5,672,OI I
.
AAG 1.7%(0.1)%0.6%4.1%0.9%2.2%0.6%2008-2017
AAG 1.%0.6%I.2%(0.1)%1.3%2.4%0.7%2017-2027
Table 3 -Forecasted Coincidental Peak Load in Megawatts
Year Total OR WA WY CA UT ID SE-ID
2008 9,776 2,422 731 1,167 147 4,419 578 331
2009 10,068 2,455 739 1,314 149 4,560 583 276
2010 10,276 2,477 744 1,378 151 4,656 584 305
2011 10,446 2,490 749 1,418 153 4,760 580 311
2012 10,745 2,502 757 1,485 148 4,975 576 367
2013 1 I,021 2,545 769 1,575 151 5,058 585 371
2014 11,239 2,598 778 1,614 153 5,182 586 355
2015 11,357 2,585 790 1,651 156 5,295 588 300
2 Idaho megawatt-hours include the Company's Southeast Idaho third-par load obligation.
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PacifCorp - 2007 IRP Update
Year Total OR WA WY ..CA UT ID SE-ID
2016 11,591 2,573 788 1,686 158 5,497 582 342
2017 11,758 2,643 805 1,664 154 5,602 583 365
AAG 2.1%1.0%1.1%4.0%0.5%2.7%0.1%1.1%2008-2017
AAG 1.8%1.2%1.8%(0.1)%1.8%2.7%0.6%0.4%2017-2027
Table 4 - Annual Load Growth Change: October 2007 Forecast Less March 2007 Forecast
(Avera2e Me2awatts)
Year Total OR WA WY CA UT ID
2008 489,083 564,893 (54,663)(573,071)OO,175)552,086 10,012
2009 365,301 564,458 (69,474)(734,001)(10,371)607,918 6,770
2010 (667,669)406,94 i (255,364)0,000,073)-(28,435)225,718 (16,456)
2011 0,370,049)276,015 (304,351)0,441,729)730,699)173,737 (43,022)
2012 (1,521,152)141,506 (321,503)0,409,041)(32,953)161,441 (60,603)
2013 (1,411,634)10,594 (344,090)(1,029,301)(34,527 61,262 (75,573)
2014 0,595,718)(124,029)(348,258)(923,515)(35,125 (71,261)(93,531)
2015 (1,895,830)(259,873)(340,928)(848,524)(33,610).(294,320)(118,575)
2016 (2,515,536)(401,472)(363,051)(1,158,557)(32,300)(395,836)(164,320)
2017 (3,465,022)(535,864)(387,954)0,632,102)(30,571)(663,950)(214,580)
AAG (0.6)%(0.8)%(0.7)%(0.6)% .(0.2)%(0.5)%(0.4)%2008-2017
Table 5 - Annual Coincidental Peak Growth Change: October 2007 Forecast Less March
2007 Forecast
(Me2awatts)
Year Total OR WA I WY CA UT il
2008 354 347 29 22 (0)10 (53)
2009 324 220 37 32 (0)140 (95)
2010 34 223 15 (38)10 (64)
.
(112)
2011 (28)176 (8)(55)25 (172)7
2012 (26)182 (9)(84)(7)2 (110)
2013 64 217 2 (38)(5)(3)(108)
2014 109 267 5 (34)(5)(2)(122)
2015 69 259 16 (18)(15)(42)(131)
2016 7 259 13 (47)(5)(50)(163)
2017 (291)253 7 (31)(8)(288)(124)
.
AAG (0.7)%(0.6)%(0.4)%(1.1)%(0.6)%(0.6)%(0.7)%2008-2017
6
PacifCorp - 2007 IRP Update
The primary drivers for load forecast growth changes by customer class are summarized below.
Residential
~ Increases in cooling load are expected, driven by central air conditioner saturation and larger
homes
. Where natual gas is available, decreases in heating saturation are forecasted
Commercial
. Increasing growth in the office and health care sectors are expected
Industral
. Wyoming oil and gas is stil forecasted to be the fastest growing sector, even though
PacifiCorp is expecting slower growth from the previous forecast
. The Wyoming industrial sales peak decreases slightly from 2017 to 2027 because several of
the oil and gas fields wil be depleted, and energy sales to those fields will be reduced
. New oil and gas industr growth is éxpected near Vernal, Utah
. Oregon sales to wood product sectors are weaker, but sales to specialty food manufactuing,
metal, and glass stil have a strong outlook
RESOURCES
Significant Changes to Existing Resources
For the 2008 business plan, PacifiCorp reclassified two renewable energy projects from the
planned to existing resource category due to these projects entering commercial service in 2007.
These projects include the Marengo I wind project, a 78 tubine wind facility near Dayton,
Washington with a capacity of 140.4-megawatts, and the Blundell geothermal expansion project,
an II-megawatt bottoming-cycle enhancement to the Company's existing geóthermal facility.
The other signficant resource change was removal of the 33-megawatt Cove Fort geothermal
power purchase agreement as an existing resource.
Significant Changes to Planned Resources
Thermal
In the company's effort to meet the growing demand for generation, and given the advancing
technological improvements in steam turbine design and manufactuing, the most recent "dense
. pack" tubine upgrade initiative is included in the 2008 business plan. This tubine upgrade
initiative is intended to further enhance PacifiCorp's overall generation capability and cycle
efficiency for each of the large thermal units in the generation fleet curently exceeding 300
megawatt in rated capacity.3 Table 6 shows the thermal upgrade schedule included in the 2008
3 Previous thermal plant upgrades pedormed by PacifiCorp over the last decade were referred to "aero-derivative
steam path" (ADSP) technology, and was installed in most of the same large thermal unts being considered for the
current dense pack tubine upgrades. The ADSP upgrades also introduced minor capacity upgrades and
improvement in effciency though advancement in tubine technology beyond original equipment design.
7
PacifCorp - 2007 IRP Update
business plan. The total increase in capacity from 2009 though 2013 is 202 megawatts. These
upgrades are scheduled to occur durng each unit's next major planed overhauL.
Table 6 - Thermal Upgrade Schedule
. Me2awatt Capacity Increase. .
Plant 2009 2010 2011 2012 2013
Hunter 19 12 19
Huntigton 18 18
Johnston 18
Naughton 21
Wyodak 9
Jim Bridger 17 17 i 7 17
Cumulative Total 21 57 113 185 202
The generation increase available by installing new dense pack-designed high-pressure /
intermediate-pressure tubines, and in some cases low pressure tubine components, is derived
entirely through more efficient utilization of existing steam inlet conditions entering each of
these turbine sections. Dense pack tubine technology until recently was only offered by a select
few tubine manutactuers. Technology refinements that have occurred since the initial.
introduction of the dense pack design have developed to a point that they are fairly robust and
considered a well established offering for large power tubine upgrades. These improvements
allow for an additional 1.5 percent to 2.5 percent improvement in generation over previous
upgrade designs for each applicable unit without requirng any increases in fuel consumption or
heat input in order to"achieve the additional generation. In as much as there is no requirement for
additional fuel consumption to achieve the capacity and efficiency improvements, emission
inventories remain unchanged and do not impact any of the existing environmeptal or regulatory
limits established for the candidate units.
Wind Projects
Table 7 profiles new wind generation projects that have been reclassified from generic IRP
resources to planned resources for the 2008 business plan. (Planed resources are those approved
by the MidAmerican Energy Holdings Company (MEHC) board for inclusion in a capital
budget.) Note that the expected in-service dates in table 7 reflect expectations at the time the
2008 business plan was prepared.
8
PacifCorp - 2007 IRP Update
c Table 7 - Recent Wind Resource Additions
Resource Nameplate Expeetealii-
Name Location .MW Servce Date
Goodnoe Hils Near Goldendale, Washington 99.0 2008
Marengo Near Dayton, Washington 70.2 2008Expansion
12 miles north of Glenrock, in Converse
Rollng Hils County, Wyoming (the Glenrock Mine site 99.0 2008
for the Dave Johnston plant)
12 miles north of Glenrock, in Converse
Glenrock County, Wyoming (the Glenrock Mine site 99.0 2008
for the Dave Johnston plant)
Seven Mile Hil
Eastern Carbon County near Medicine Bow,99.0 2008Wvoming
High Plains Spans Albany County and eastern Carbon 99.0 2009County, Wyoming
Hydroelectric Plants
Both the 2007 IR and 2008 business plan included upgrades to the Swift No. 1 hydroelectric
plant, totaling 75 megawatts by 2015. This project was reclassified from an existing resource to a
planed resource for reporting in PacifiCorp's capacity balance.
While PacifiCorp's hydro tubine generator overhaul program is expected to provide incremental
improvements to the overall generating capacity of the hydro portfolio, the upgrade potential at
the Swift NO.1 project has been identified as a significant opportity to provide an economic
alternative for. helping to address the expiring Mid-Columbia capacity and energy purchase
contracts. The Swift NO.1 project is also expected to be an increasingly importnt resource to
PacifiCorp, providing the majority of the system's load control and reserve support. This
upgrade project wil enhance the Swift NO.1 plant's ability to provide that support.
As envisioned, the project wil consist of a major hydraulic tubine overhaul with ruer
replacement, an electrical generator winding upgrade, a generator bus upgrade, generation step-
up transformer upgrades (two units), installation of dedicated generator breakers, possible civil
upgrades to the penstock and surge tank, and related plant system upgrades. This project will
increase the total generating capability of the Swift No. i hydroelectrc plant to 315 megawatts.
Kern River Recovered Energy Generation Project
PacifiCorp is teaming with Kern River Gas Transmission Company, a subsidiary of MEHC, to
develop waste heat recovery/electric generation facilities at several compressor stations along
Kern River's gas pipeline in southwestern Wyoming and Utah. The project wil employ the
ORMAT Energy Converter system (developed by ORMT Technologies, Inc.), an organic
Ranke cycle technology that produces no air emissions due to the closed-loop nature of the
9
PacifCorp - 2007 IRP Update
system. These combined heat and power facilities, expected to be in service by 2010, wil
provide 19 megawatts of nameplate generation capacity.
Demand-Side Management Resources
Two key DSM planning developments that occured after the filing of the 2007 IR was the
completion of a third-part system-wide demand-side resource potential assessment study made
available to PacifiCorp in June 20074, and the passage of Oregon Senate Bil 838, which created
an opportity for fuding increased amounts of cost-effective energy efficiency resources in the
State of Oregon. As a result of these developments, PacifiCorp made significant changes to the
forecasts for dispatchable load control (Class 1) and energy efficiency (Class 2) DSM programs
originally used for" the 2007 IR. These updated forecasts were incorporated in the 2008 business
plan.
For dispatchable load control programs, the new forecast is for 272 megawatts by 2012,
compared with 258 megawatts by 2013 for the 2007 IRP. To arrve at the new figues,
PacifiCorp used non-resource-specific, high-end estimates based on 2007 IRP modeling work.
Tables 8a and 8b report the original 2007 IRP annual Class 1 DSM program amounts along with
the incremental increases assumed for the 2008 business plan. (Cumulative and percentage
changes between the 2007 IR and 2008 business plan are shown at the bottom of the table.)
For energy efficiency programs, the new 2008 business plan load reduction forecast is 4.6
milion megawatt-hours by 2017, compared with 1.8 milion megawatt-hours for the 2007 IRP.
To arve at the adjusted forecast, PacifiCorp used the information provided in the DSM
potentials study and applied adjustments to account for recent program implementation
experience and market conditions. The Company first applied an economic screen to the energy
efficiency potential amounts based on the 2007 IR decrement values plus 15 percent.5 An
increase to the assumed achievable potential-from 55 percent to 70 percent-was also made, as
well as a slight acceleration in the 20-year acquisition timeline. For the Oregon targets, the
Company worked with the Energy Trust of Oregon to develop a revised forecast of energy
efficiency opportnities. Table 8a and 8b report the original 2007 IRP anual Class 2 DSM
program amounts along with the incremental increases assumed for the 2008 business plan.
(Cumulative and percentage changes between the 2007 IRP and 2008 business plan are shown at
the bottom of the table.) The Class 2 DSM targets are applied as decrements to the load forecast
as was done for the 2007 IRP.6
4 The DSM potentials study, conducted by Quantec LLC, provided PacifiCorp more information on the
opportnities for demand-side resource investments should they be found to be cost-effective through the 2008 IRP
modeling process.5 Preliminar resource screening for cost-effectiveness was performed as part of the original potentials estimation
project.6 Resource supply cures wil be used for portolio development for the 2008 IRP to determine the cost-effective
magnitude and value of energy effciency programs as compared to supply-side resource options.
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PacifCorp - 2007 IRP Update
Table 8a - Demand-Side Resource Forecast Comparison by Year, 2008-2012
2008 ..2009 ...2010 2011 2012
Class 1 Load Management - 2007 IRP 163 163 163 163 210
Incremental Additions (MW)37 47 57 67 62
Total Class 1 Load Management - 10-yr Plan 200 210 220 230 272
Class 2 Energy Effciency (MWh) - 2007 IRP 247,207 214,532 207,262 200,429 198,239
Class 2 Capacity Impact (MW)-2007IRP 47 41 39 38 38
Incremental energy effciency (MWh)103,018 178,967 242,914 273,487 288,029
Incremental capacity Impact (MW)20 34 46 52 55
Class 2 Total Energy Effciency (MWh) -10-yr Plan 350,225 393,499 450,176 473,916 486,268
Class 2 Capacity Impact (MW) -10-yr Plan 67 75 85 90 93
C I t F &P Cumu a ive orecasts ercent hanDe
Class 1 Load ManaQement (MW) 2007 IRP 163 163 163 163 210
Class 1 Load Management (MW) 10-yr Plan 200 210 220 230 272
% change capacity 23%29%35%41%30%
Class 2 energy effciency (MWh) 20071RP 247,207 461,739 669,001 869,430 1,067,669
Class 2 energy effciency (MW) 2007 IRP 47 88 127 165 203
Class 2 enerav.effciencv (MWh) 10-vr Plan 350,225 743,724 1,193,900 1,667,816 2,154,084
Class 2 energy effciency (MW) 10-yr Plan 67 142 227 317 410
% change forecast 42%61%78%92%102%
Table 8b - Demand-Side Resource Forecast Comparison by Year, 2013-2017
2013 2014 2015 2016 2017
Class 1 Load Management- 2007 IRP 258 258 258 258 258
Incremental Additions (MW)14 14 14 14 14
Total Class 1 Load Management -10-yr Plan 272 272 272 272 272
Class 2 Energy Effciency (MWh) - 2007 IRP 197,801 189,917 185,274 182,296 -
Class 2 Capacity Impact (MW)- 2007 IRP 37 36 35 35 -
Incremental energy effciency (MWh)288,467 296,350 300,994 303,971 487,144
Incremental capacity Impact (MW)55 56 57 58 92
Class 2 Total.Energy Effciency (MWh)- 10-yr Plan 486,268 486,267 486,268 486,267 487,144
Class 2 Capacity Impact (MW) -10-yr Plan 92 92 92 93 92
Cumulative Forecasts & Percent ChanDe
Class 1 Load ManaQement (MW) 20071RP 258 258 258 258 258
Class 1 Load Management (MW) 10-yr Plan 272 272 272 272 272
% change capacity 5%5%5%5%5%
Class 2 energy effciency (MWh) 2007 IRP 1,265,470 1,455,387 1,640,661 1,822,957 1,822,957
Class 2 energy effciency (MW) 20071RP 240 276 311 346 346
Class 2 enerav effciency (MWh)10-vr Plan 2,640,352 3,126,619 3,612,887 4,099,154 4,586,298
Class 2 energy effciency (MW) to-yr Plan 502 594 686 779 871
%. change forecast 109%115%120%125%152%
11
PacifCorp - 2007 IRP Update
UPDATED CAPACITY BALANCE
Figue 4 compares the anual capacity positions for the 2007 IR and the 2008 business plan.
Both positions assume a 12-percent plannng reserve margin (PRM). For the 2008 business plan,
the system capacity position becomes deficit two years earlier relative to the position reported in
the 2007 IRP. The early-year position differences are attibuted to the higher relative projected
loads in the Western Control Area. After 2010 the differences between the two capacity positions
are relatively smalL.
Figure 4 - Capacity Position Comparison, 2007 IRP versus the 2008 Business Plan
1,000 -
500 ~-!
0 -í"r-,.-~-r-r-,.--- --,rl,
(500)I---I-~---,
-
(1,000)--I-~--I-
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1ü~(1,500)------,
IIcici:i
(2,000)--I----'
,
(2,500)------'---
(3,000)----
(3,500)
~
D20071RP -
i .2008 Business Plan ,
(4,000)
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Figues 5 through 7 show the 2008 business plan's capacity peak load and resource gaps for the
system, Eastern Control Area, and Western Control Area, respectively. Table 9 reports the
detailed load and resource line items for the capacity balance.
12
PacifCorp -2007 IRP Update
Figure 5 - System Coincident Peak Loads and Resources, 2008 Business Plan
,,~ I
12,00 1
I
10,000 L
8,00 J~ .~ ¡ ....
4.00
... ..
Obligation + Reserves (12%)
2,000
o
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
~-------
Figure 6 - East Coincident Peak Loads and Resources, 2008 Business Plan
14.000
12,000
10,00
Eo;' Obi~"'o" r.~:":
..
8.000
3:::
.
6,000
4,000
2,000
o i2017 !2008 2009 2010 2011 2012 2013 2014 2015 2016
I
, i
I
I
I: i
13
PacifCorp - 2007 IRP Update
Figure 7 - West CoinCident Peak Loads and Resources, 2008 Business Plan
8,000
3:~
14.000
12,000
10,000
6,000
West Obligation + Reserves (12%)
1
4,000
2,000
o
2008 2014 2015 2017201620092010201120122013
14
PacifCorp - 2007 IRP Update
Table 9 - Load and Resource Capacity Balance
Planning Reserve Margin Target = 12%
Calendar Year 2008 2009 2010 "2011 2012 2013 2014 2015 2016 2017
East
Thermal 5,932 5,932 5,932 5,932 5,932 5,932 5,932 5,932 5,932 5,932
Hydro 135 135 135 135 135 135 135 135 135 135
DSM 163 163 163 163 163 163 163 163 163 0
Renewable 109 109 109 109 109 109 109 105 105 105
Purchase 704 828 648 668 493 493 493 493 472 472
OF 106 106 106 106 106 106 106 106 106 105
Interruptible 212 328 328 328 328 328 328 328 328 328
East Existing Resources 7,361 7,601 7,421 7,441 7,266 7,266 7,266 7,262 7,241 7,077
Load 6,547 6,725 6,975 7,130 7,404 7,612 7,782 7,827 8,147 8,208
Sale 836 752 766 756 745 745 745 745 745 659
East Obligation 7,383 7,477 7,741 7,886 8,149 8,357 8,527 8,572 8,892 8,867
Planning reserves (12%)756 739 792 807 860 .885 905 911 951 968
Non-owned reserves 71 71 71 71 71 71 71 71 71 72
East Reserves 827 810 863 878 930 955 976 981 1,022 1,040
East Obligation + Reserves 8,210 8,287 8,604 8,764 9,079 9,312 9,503 9,553 9,914 9,907
East Position (850)(686)(1,183)(1,323)(1,813)(2,046)(2,237)(2,291)(2,673)(2,830)
East Reserve Margin 0%3%(3%)(5%)(10%)(12%)(14%)(15%)(18%)(20%)
West
Thermal 2,046 2,046 2,046 2,046 2,046 2,046 2,046 2,046 2,046 2,046
Hydro 1,421 1,414 1,328 1,332 1,175 1,174 1,168 1,169 1,168 1,177
DSM 0 0 0 0 0 0 0 0 0 0
Renewable 118 118 118 118 94 94 94 94 94 94
Purchase 800 800 800 750 112 141 107 107 107 107
OF 40 40 40 40 40 38 38 38 38 38
West Existing Resources 4,425 4,401 4,314 4,268 3,450 3,493 3,454 3,455 3,453 3,441
Load 3,228 3,343 3,302 3,316 3,341 3,409 3,457 3,531 3,444 3,550
Sale 299 299 290 290 258 258 258 158 108 108
West Obligation 3,527 3,642 3,592 3,606 3,599 3,667 3,715 3,689 3,552 3,658
Planning reserves (12%)327 341 335 343 418 423 433 430 413 426
Non-owned reserves 7 7 7 7 7 7 7 7 7 8
West Reserves 334 348 342 349 425 430 439 436 420 434
West Obligation + Reserves 3,861 3,990 3,933 3,955 4,024 4,097 4,154 4,125 3,972 4,091
West Position 564 411 381 314 (575)(603)(700)(670)(518)(651)
West Reserve Margin 28%23%23%21%(4%)(4%)(7%)(6%)(3%)(6%)
System
Total Resources 11,786 12,002 11,735 11,710 10,716 10,760 10,721 0,717 10,695 10,517
Obligation 10,910 11,119 11,333 11,492 11,748 12,024 12,242 2,261 12,444 12,525
Reserves 1,161 1,157 1,204 1,227 1,355 1,385 1,415 1,417 1,442 1,473
BP Obligation + Reserves 12,071 12,276 12,537 12,719 13,104 13,409 13,657 13,678 13,886 13,998
BP System Position (294)(285)(813)(1,020) (2,398)(2,664)(2,950)(2,975)(3,202)(3,495)
Reserve Margin 9%10%5%3%(8%)(10%)(12%)(12%)(14%)(16%)
Table i 0 reports the anual line item differences between the capacity balances for the 2008
business plan and 2007 IRP. For the Eastern Control Area, significant changes included the
addition of a Public Service Company of Colorado exchange contract, modification to the
Monsanto interrptible load contract, and a decrease in the Wyoming load forecast. For the
Western Control Area, changes included an increase in forecasted loads and reclassification of
the Swift No. i upgrade and wind projects.
15
PacifCorp - 2007 IRP Update
Table 10 - 2008 Business Plan Capacity Balance Less 2007 IR Capacity Balance
Planning Reserve Margin Target = 12%
Calendar Year 2008 2009 2010 2011 2012 2013 2014 2015 2016
East
Thermal (9)(9)(9)(9)(9)(9)(9)(9)(9)
Hydro 0 0 0 0 0 0 0 0 0
DSM 0 0 0 ' 0 0 0 0 0 0
Renewable (0)(0)(0)(0)(0)(0)(0)(0)(0)
Purchase 25 50 100 125 150 150 150 150 150
OF 0 0 0 0 0 0 0 0 0
Interruptible (21)20 20 20 20 20 20 20 20
East Existing Resources (5)61 111 136 161 161 161 161 161
Load 32 68 (162)(159)(191)(126)(113)(199)(219)
Sale 25 50 100 125 150 150 150 150 150
East Obligation 57 118 (62)(34)(41)24 37 (49)(69)
Planning reserves (12%)6 6 (22)(21)(25)(18)(16)(26),(29)
Non-owned reserves 0 0 0 0 0 0 0 0 0
East Reserves 6 6 (22)(21)(25)(18)(16)(26)(29)
East Obligation + Reserves 63 124 (84)(55)(66)6 21 (75)(98)
East Position (68)(63)195 192 228 155 140 237 259
East Reserve Margin (1%)(1%)2%2%3%2%2%3%3%
West
Thermal 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 (25)(50)(75)(75)(75)(75)
DSM 0 0 0 0 0 0 0 0 0
Renewable 10 10 10 10 10 10 10 10 10
Purchase 0 0 0 0 0 0 0 0 0
OF 0 0 0 0 0 0 0 0 0
West Existing Resources 1.(7)(6)(32)(57)(64)(64)(64)(64)
Load 304 248 178 117 101 158 195 260 192
Sale 0 0 0 0 0 0 (0)(0)(0)
West Obligation 304 248 178 117 101 158 195 260 192
Planning reserves (12%)37 30 21 14 12 19 23 31 23
Non-owned reserves 0 0 0 0 0 0 0 0 0
West Reserves 37 30 21 14 12 19 23 31 23
West Obligation + Reserves 341 278 200 131 113 177 218 291 215
West Position (330)(285)(206)(163)(170)(241)(283)(356)(279)
West Reserve Margin (12%)(9%)(7%)(5%)(4%)(6%)(7%)(9%)(7%)
System
Total Resources 5 54 104 105 104 97 97 97 97
Obligation 361 366 116 83 60 182 232 211 123
Reserves 43 36 (1 )(7)(13)1 7 5 (6)
Obligation + Reserves 404 402 116 76 47 183 239 216 117
System Position (408)(358)(22)18 48 (101)(157)(133)(31)
Reserve Margin (4%)(3%)(0%)0%1%(0%)(1%)(1%)0%
16
PacifCorp - 2007 IRP Update
3. NEW RESOURCE ASSUMPTIONS
CA.PITALCOSTS
Capital costs for supply-side resources were adjusted to reflect recent escalation trends, and in
the case of coal, studies used to support benchmark resource development for the 2012 base load
Request for Proposals. Table 1 i shows the per-kilowatt and percentage increases in average
capital costs by technology tye relative to those costs assumed for the 2007 IRP.
Table 11 - Resource Supply Side Options Capital Cost Increases
Average Capital Increases by Resource Type
2008 Business Plan versus 2007 IRP
Type $/kW Percent
Coal 1,221.5 49%
Gas 87.4 12%
Renewables 459.9 21%
TREATMENT OF COAL RESOURCES
PacifiCorp excluded supercritical pulverized coal and Integrated Gasification Combined Cycle
(lGCC) as resource options for 2008 business plan portfolio modeling. This resource selection
constraint reflects PacifiCorp's view that for the 10-year business planing horizon, coal
resources are not viable resource options given (I) cost uncertainty associated with potential CO2
regulations, (2) new state energy policies in California, Oregon, and Washington, (3) permitting
issues and challenges, and (4) uncertainty regarding the availability and costs of clean coal
technologies.
RENEWABLE RESOURCES
The wind resources reflected in the 2007 IRP preferred portfolio, procured in the 2008 through
2013 period, were updated to match 2008 business plan assumptions for star dates, sites, and
capacities. These updated wind resources, totaling 1,270 nameplate megawatts, were fixed in the
System Optimizer modeL. These fixed wind resources are shown in the 2008 business plan
resource portfolio (Table 12).
4. TRASMISSION RESOURCES
Figue 8 shows the modeled transmission system topology used for 2008 business plan portfolio
modeling. This topology incorporates the Energy Gateway Transmission Expansion project as
anounced on May 30, 2007. The seven new transmission links associated with the expansion
project are identified with red arows in the topology diagram.
17
PacifCorp - 2007 IRP Update
Figure 8 - Modeled Transmission System Topology
\t.
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~ ContrctExchanges "' " ~ ~\
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Prnted on: 10/02106
5. FRONT OFFICE TRASACTIONS
For the 2008 business plan, a number of changes to front offce transaction assumptions were
made.7 These changes relate to the products selected as proxy resources in some of the markets,
and the annual maximum quantities available at each market. The changes-incorporated in the
System Optimizer model-were prompted' by an updated assessment of market product and
supporting transmission availability, as well as the impact of the Energy Gateway Transmission
Expansion project. The front office transaction specifications, by market area, are profied below.
. Mid-Columbia Market
Third-quarter, heavy-Ioad-hour (HLH) product (previously modeled as a flat annual
product for the 2007 IR)
Maximum annual amount: 400 megawatts for 2007-2026
7 Front offce transactions are proxy resources representing forward firm purchases used to help Pacificorp meet its
load and planing reserve requirements,
$18
PacifCorp - 2007 IRP Update
. California Oregon Border Market
Flat anual product
Maximum anual amount: 400 megawatts for 2007-2026
. Mona Market
Third-quarter HLH product
Maximum annual amount: 200 megawatts for 2007-2026
. Mead Market
Third-quarer HLH product
Maximum anual amount: 0 megawatts for 2007-2012,600 megawatts for 2013-2026
. F our Comers
Third-quaer HLH product
Maximum annual amount: 0 megawatts for 2007-2017, 500 megawatts for 2018-2026
6. BUSINESS PLAN PORTFOLIO
PacifiCorp used the System Optimizer to develop a resource portfolio based on the updated
inputs and assumptions described above. While 20-yèar optimizations were conducted, the focus
of portfolio development was to refine the selection and timing of gas resources and front office
transactions for the business plan time horizon, 2008-2017.
Table 12 shows the resulting supply-side resource portfolio that was used for development of the
2008 business plan. (The business plan DSM resources are shown in Tables 8a and 8b.) Note
that resources are shown by their in-service years rather than the years they first are available to
meet sumer peak load requirements. For example, most renewable resources are assumed to
enter commercial service by December of a given year.
Table 12 - 2008 Business Plan Supply-Side Resource Portfolio
Nameplate Capacity,MW11
Resource Type 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
East Upl!des - theral genertion Various cast coal-fired units -21 36 38 37 -----
Comhined cycle CT 2x i F class with duct finn!!----1,096 -----
Geothermal Blundell --35 -------
Comhined heat and Dower Generic east-wide --19 ---.---
Renewahle Wind, Wyoming 300 100 100 200 -200 ----
Front offce trnsactJons 'JJ Heavy load hour, 3rd quartr ----115 633 746 800 800 783
West Upgrdes - thermal ~enertion Jim Bridper coal-fired units -17 17 17 17 ----
Ummides - hvdro ~enertion Swift Hvdro -"---25 25 25 --
Renewable Wind, North-central Oregon --200 -100 -----
Renewable Wind, Southeast Washington 70 --------.
Front offce trnsactions 2/Flat annual product 400 400 389 389 400 400 400 388 338 400
Front offce trnsactions 1 Heavy load hour, 3rd cuarer --268 347 400 59 144 101 334 548
Annual Additions; Long Ten Resources 370 121 408 256 1,250 242 25 25 -.
Annual Additions, Shor Ter Resources 400 400 657 736 915 1,092 1,290 1,289 1,472 1,731
.T oial Annual Additions 770 521 1,065 992 2,165 1,334 1,315 1,314 1,472 1,731
II Resources are shown by their In-service date as opposed to the year for which they meet the system peak.
21 Front offce transaction amounts reflect purchases made for the year, and are not additive,
19
PacifCorp - 2007 IRP Update
7. ACTION PLAN UPDATE
This section proyides the updated IR Action Plan, modified as a result of 2008 business
planng activities. The Action Plan update is presented as Table 13. Changes to the original plan
have been highlighted. PacifiCorp's update to the 2007 IRP Action Plan covers Demand Side
Management, Resource Procurement, and IR Acknowledgement.
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24
PacifCorp - 2007 IRP Update
ACTION PLAN IMPLEMENTATION
Demand-Side Management
Since the May 2007 IRP filing, PacifiCorp began incorporating results from the DSM potential
study into the DSM program planning process, and, by the fall of 2007, identified opportities to
include in the 2008 business plan. The initial impact resulted in the resetting of the 2008 resource
targets identified in the 2007 IR by 23% for Class 1 load management resources and 42% for Class
2 energy efficiency resources. To assist in meeting 2009-2017 adjusted lO-year plan forecasts and
in anticipation of 2008 IRP refinements, work is underway on the development of a 2008 DSM
Request for Proposal (RFP) for new DSM programs. The RFP is expected to be released later this
summer (2008). The company's 2007 actual resource acquisitions against the 2007 IRP resource
tagets were exceeded by 22% for Class 1 load management resources and 18% for Class 2 energy
efficiency resources. The company stil needs to determine how to incorporate the potential
assessment of Class 3 DSM, price responsive programs, and Class 4 DSM, energy education into
the IRP planning process.
Supply-Side Resource Procurement Activities
To help address the resource needs identified in the 2007 IR, PacifiCorp issued a 2012 Base Load
Request for Proposals (RFP) on April 5, 2007. The Company identified a final short list of bids, and
is curently negotiating with short list bidders on final bid prices and terms. For 2008, PacifiCorp
has issued, or is planning to issue, thee additional RFPs to meet the resource needs identified in
both the 2007 IRP and 2008 business plan. These RFPs are described below.
Renewable Request for Proposals (RFP 2008R)
The purose of this RFP, issued January 31, 2008, is to support the acquisition of renewable
resources identified in the 2007 IRP (See Action Item no. 1 of Table 8.2, page 224). The scope of
this RFP is for system wide (Eastern Control Area and Western Control Area) new renewable
resources that are capable of delivery in or into PacifiCorp's network transmission system. The RFP
specifies a target quantity of up to 200 megawatts for 2008 and up to 100 megawatts for 2009.
Individual bids are limited to (1) less than 100 megawatts in generating capability, or (2) for a term
ofless than five years if greater than 100 megawatts in generating capability. Renewable categories
include wind energy, solar, hydrokinetic (wave, tidal, and ocean thermal energy), biomass/biomass
byproducts, geothermal, certified low-impact hydroelectrc energy, and waste gas/waste heat
captue or recovery. Bidders also have the option of submitting renewable resources with energy
storage, such as pumped hydro, compressed air, or battery technologies.
Renewable Request for Proposal (RFP 2008R-l)
This renewables RFP, curently being drafted, is intended as a "shelf' RFP under which subsequent
periodic RFPs wil be issued to comply with current regulatory rules, orders, aÌd any applicable
resource procurement state laws. The 2008R-l RFP is for renewable resources that can reach
commercial operation durng the 2008 through 201 i time period, and are limited in size to no more
than 300 megawatts.
Request For Proposal - 2008 All Source RFP
The "All Source RFP" was initiated on February 1, 2008 with a required pre-draft conference and
focus on procuring resources to fill need from 2012 though 2016 as stated in the 2007 IRP. The RFP
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PacifCorp - 2007 IRP Update
is seeking capacity and energy resources to serve PacifiCorp's entire system. Bidders may propose
any of seven different proposal strctues covering power purchase agreements, tollng agreements,
asset purchase and sales agreements, and purchases of existing facilities (load curilment,
Qualifying Facility, and geothermal and biomass projects are also covered.) The bid categories are
also separated into Base Load, Intermediate Load and Summer Peak resources.
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