HomeMy WebLinkAbout200511042004DSM Update.pdf;..
C:E\\jED
825 E. Mu/tnomah
Portland, Oregon 97232
(503) 813-5000
c,.
,,-
i r"
~,\ 0; i 5'-l'i h.
,.; ,
PACIFICORP
:UbLlC .
' '' (
55\0;,::' lJ
' "
PACIFIC POWER UTAH POWER
November 3, 2005
Idaho Public Utilities Commission
472 West Washington
Boise, ill 83702
Attn: Jean Jewell
Commission Secretary
Re:Docket No. P AC- E-05-
Update to PacifiCorp s 2004 Integrated Resource Plan (IRP)
Dear Ms. Jewell:
Enclosed are and original and six copies of PacifiCorp s update to its 2004 Integrated
Resource Plan (IRP). The Company s 2004 IRP was filed with the Commission on January
2005.
PacifiCorp recognizes that integrated resource planning is a continuous process rather than a
one-time or occasional event. The 2004 IRP stated (pg. 180) that it is "PacifiCorp s intention
to revisit and refresh the Action Plan no less frequently than annually." This IRP Update
Update ) satisfies that commitment.
This Update is being submitted for informational purposes. No further action of the
Commission is requested at this time.
Sincerely,
~ym
IRP Manager
Enclosure
" ,:('
"I\:'
, ,
G - 'j L'
"1 O. r.;i
, c '1 ,) i : P I jr'
, i' '
(~'
r.6;1~1ISS1011
, ,
L. , .,
" ,,-
,j 11
rAc E ~c6-(JL
Integrated R~i!.
";,..'
-"""-~C"-'
ji1i:;C';iYj,:
Assuring a blAj
1. PACIFICORP
PACIFIC POWER VTAH POWER
This 2004 Integrated Resource Plan (IRP) Update Report is based upon the best available
information at the time of preparation. The updated Action Plan will 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 Action Plan no less
frequently than annually. Any refreshed Action Plan will be submitted to the State Commissions
for their information.
For more information, contact:
PacifiCorp
IRP Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
(503) 813-5245
IRP~PacifiCorp.com
http://www.PacifiCorp.com
PacifiCorp 2004 IRP Update Table afContents
TABLE OF CONTENTS
Ex ec u ti ve Sum m a ry
............ ............. ..... .."..... ..........
...................... ..... ............................ ....................... ..... 1
Changes in The Marketplace and Fundamentals .............................................................................. 3
Natural Gas and Power Market Update..................................................................................................
Western Supply/Demand Balance .....................................".........................................................,.... 3
Natural Gas Markets. ......... ..........."..... ........
.......... .......... ........... .......... ........................,...... ..............
Climate Change Policy Update ...............................................................".............................................Impacts of the Energy Policy Act of 2005 .
......
,..................................................................................... 5
Transmission Siting ................... ................. ............ .................. .......... ..... ............. .................... ......... 5
Renewable Energy Production Tax Credit ..............................................................."....................... 6
Clean Coal Incentives......................................... ............... ........... ...... ......... ..... ........... ............. ......... 6
Hydropower .........................................,.............................................................................................
Mandatory Reliability Standards .........................
,.............................................................................
Conclusion..... ............... ........................ .............. ........................... ............ ........ ..... ........................... 8
Reso u rce Needs Assess m en t
.... ........... ................... .............................................................. ....... ..........
Introduction ........................................................"""""""""""""""""""""""""""..............................
Load Forecast........... .......... ..".......... .......... ........ ....................... ................... .................. ...... .................. 9
Resource Situation..................................................................................................................................
Changes to Existing Resources..........................................................................................................
New Contracts ......
....... ....... ........... .......... ...................... .......................".......... ............................
Treatment of Qualifying Facilities and Interruptible Load Contracts .......................................... 9
Hydroelectric Resources................................
""""""'" .............
.............. ...........,........ ............... 10
Demand Side Management......................................................................................................... 10
Renewable Resources..... ......... ......
...., ..................... ........
.....".......................... ....... ................... 10
Changes to Planned Resources ...................................................................................,....................
Front Office Transactions ...........................................................................................................
RFP Wind ...... .......... ............... ................. ............. ................................ ........ ......... ..................... 11
Topology Updates and Transmission Changes .................."................................................................ 12
Load and Resource Balance .................................................................................................................
Summary of Resource Changes Affecting the Load & Resource Balance...................................... 13
Capacity Charts ........ ......... ..".. ....... ........ .......... .................. ......... ........... ................. ........... ..... ........ 15
Updated Firm Capacity Position Charts .......................................................................................... 18
Summary Load & Resource Balance Observations......................................................................... 21
Integrated Gasification Combined Cycle Resource Update............................................................ 23
Technical Update..................................................................................................................................
Effects of Energy Policy Act Incentives............................................................................................... 26
IGCC State Policy Developments ........................................................................................................
Challenges to IGCC Development .......................................................................................................
Conclusion............................................................................................................................................
Po rtf olio An alysis ............ .................. ................. .................... ......................... ........ .................. .......... 31
Introduction................... .................................."...... ..........................,.. ..................
...... ....... ........... ......
Portfolio Descriptions.................. ................. ............. ..........,................
.............. """" ............... ...........
2004 IRP Preferred Portfolio .........................................................,.................................................
Portfolio 1: Deferral and Removal of Preferred Portfolio Resources.............................................. 33
Portfolio 2: Path-C Upgrade and Increased Share of Wyoming Coal Plant.................................... 33
Portfolio 3: Portfolio 2 with a Share of the Utah Coal Plant........................................................... 34
Portfolio 4: Portfolio 3 with Path-C Upgrade Removed ................................................................. 35
Portfolio Evaluation Results.................................................................................................................
Deterministic Simulations....... ................... ..............
.................... ......... .........,........ ........................
- J -
PacifiCorp 2004 IRP Update Table afContents
Preferred Portfolio Evaluation ......................,............................................................................. 37
Portfolio 1 Evaluation.................................................................................................................
Portfolio 2 Evaluation..................................................................................,.............................. 38
Portfolio 3 Evaluation................................................................................................................. 39
Portfolio 4 Evaluation... ........... .."...............
...... ............... ..... .....,.... ........... ..... ....... .....................
Deterministic Evaluation Conclusions .......................................................................................
Stochastic Simulation Results "",,""""""""""""""""""""""""""""""""""""...........................
Conclusions.... ............ ....... ...........
......................................................., ............. .......... .........................
Actio n Pia n Up date ........ ....... ............................... ............. .......... ..... ......................................... .......... 45
Summary of Updated Portfolio ................................................,........................................................... 45
Action Plan Update ................................................................"............................................................
Action Plan Implementation.................................................................................................................
Demand Side Procurement Program ..........................................."..................................................
Supply Side Procurement Program..................................................................................................
Supply Side RFP (formerly RFP 2009) ........................................................................."........... 47
Renewables RFP .. .......... ........................... ........ ..............,............. ....... ..........
...... .......................
Summary """""""""""""""""""""""""""............................,...........................................................
Appendix A - Ma in Assu mptions ............................................................................................................ 49
Study Period and Calendar Year Reporting Basis................................................................................ 49
Inflation Rates.... ................................................. ........
........................ ......... ................ ........................
Natural Gas and Wholesale Electric Price Projection Components .....................................................
Gas and Power Price Forecasts.............................................................................................................
Wholesale Electricity Prices .........
......, ....................... ......... ............... ...... ......., ....... ........................
Coal Price Forecasts ................................................................."........................."............................... 52
Contracts........................................................,......................................................................................
Stochastic Assumptions......................................................................,.................................................
Input Values Based on 100 Iterations.............................................................................................. 56
Updated Supply Side Options ..............................................................................................................
Appendix B - Portfolio Tables ................................................................................................................. 65
Updated Portfolio Capital Costs ................"...... ...........
..... ...... ............. ........... .................. ...................
Updated Portfolio Load and Resource Balances ................................................................................., 66
Portfolio Resource Addition Summary ................................................................................................
Portfolio Scorecard Results...... ......
......... ......
......................... ."..... ............... ................... .................... 68
Appendix C - IRP Benchmarking Study.............................................................................................,.. 69
Introduction .....................................................,.........................,..........................................................
Study Methodology.... ........ ................. ..".................
...... ..............................." ........ .......... ..... ......... .....
IRP Stakeholder Survey..... ..... ............... ............. .......... .......................... ........ .......... ................. .......... 72
IRP Common Practices .........................,.............................................................................................. 72
IRP Practices of Interest................. .........
...... ................... ......................................... ..... ..........
............ 80
Hydro Hedging Strategy Comparison ...........................................................,......................................
Conclusions .......................................................,..................................................................................
- ii -
PacifiCorp 2004 IRP Update Index of Tables
INDEX OF TABLES
Table ES.l - Key Elements ofthe Updated Action Plan.............................................................................. 2
Table 2.1 - Annual Megawatt Capacities for Targeted New RFP Wind Resources ..................................
Table 3.1 - IGCC and Conventional Pulverized Coal Emissions Comparison ..........................................
Table 4.1 - Preferred Portfolio from the 2004 IRP .....................................................................................
Table 4.2 - Impact of New Load & Resource Balance on 2004 Preferred Portfolio Planning Margin...... 32
Table 4.3 - Portfolio 1 Resources...............................................................................................................
Table 404 - Portfolio 2 Resources............................................................................................................... 34
Table 4.5 - Portfolio 3 Resources............................................................................................................... 35
Table 4.6 - Portfolio 4 Resources...............................................................................................................
Table 4.7 - PVRR Cost Components and Rankings by Portfolio............................................................... 36
Table 4.8 - PVRR Cost Components and Rankings: Portfolio 1 vs. 2004 IRP Preferred Portfolio........... 38
Table 4.9 - PVRR Cost Components and Rankings: Portfolio 2 vs. Portfolio 1........................................ 39
Table 4.10 - PVRR Cost Components and Rankings: Portfolio 3 vs. Portfolio 2...................................... 40
Table 4.11 - PVRR Cost Components and Rankings: Portfolio 4 vs. Portfolio 3......................................
Table 4.12 - Stochastic PVRR Performance Metrics by Portfolio ............................................................. 42
Table 5.1 - Summary of 2004 IRP Update Preferred Portfolio .................................................................. 45
Table 5.2 - Updated Action Plan ................................................................................................................
Table A.l - Inflation Rates .........................................................................................................................
Table A.2 - Coal Price Update ...................................................................................................................
Table A.3 - Contracts: Annual Maximum Megawatts per Contract by Year .............................................
Table A.3 - Contracts: Annual Maximum Megawatts per Contract by Year, Continued ..........."............. 55
Table Ao4 - Supply Side Options (East) ..................................................................................................... 59
Table Ao4 - Supply Side Options (W est)..................................................................................................
Table A5 - Supply Side Options - Resource Cost Sheet (East) ................................................................ 61
Table A.5 - Supply Side Options - Resource Cost Sheet (West)............................................................... 62
Table A.6 - Environmental Adders ...........................................................................................,................ 63
Table B.l - Portfolio Capital Costs
..........................................................................................................
Table B.2 - Load and Resource Capacity Report (MW) ............................................................................ 66
Table B.3 - Portfolio Resource Addition Summary ................................................................................... 67
Table B.4 - Portfolio Scorecard......
..............." .......". ......................, ...............".. ....... ............, ......".... .......
- iii -
PacifiCorp 2004 IRP Update Index of Figures
INDEX OF FIGURES
Figure 2.1 - PacifiCorp IRP Topology for the 2004 IRP Update ...............................................................
Figure 2.2 - System Coincident Peak Capacity Chart ................................................................................ 16
Figure 2.3 - West Coincident Peak Capacity Chart.................................................................................... 17
Figure 204 - East Coincident Peak Capacity Chart .....................................................................................
Figure 2.5 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for
PacifiCorp System.......................... ...... ......... ................ ..".. ...... .........., ................... ........... 18
Figure 2.6 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for PAC West......
Figure 2.7 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for PAC East....... 19
Figure 2.8 - West Energy Curves ...............................................................................................................
Figure 2.9 - East Energy Curves ................................................................................................................
Figure 3.1 - Real Levelized Cost for IGCC Technologies by CO2 Allowance Cost LeveL..................... 25
Figure 4.1 - Portfolio Rankings Based on Deterministic PVRR................................................................ 37
Figure 4.2 - Portfolio Comparison of High-End Risk Exposure ................................................................ 43
Figure 4.3 - Stochastic "Cost vs. Risk Trade-Off' .....................................................................................43
Figure A.l - Natural Gas and Wholesale Electric Price Curve Components ............................................. 50
Figure A.2 - Gas Price Forecast .................................................................................................................
Figure A.3 - Power Price Forecast .............................................................................................................
Figure Ao4 - Palo Verde Average Annual Electric Prices (100 Iterations) ................................................
Figure A.5 - Mid-Columbia Average Annual Electric Prices (100 Iterations) .......................................... 57
Figure A.6 - Average Annual West Natural Gas Prices (100 Iterations) ...................................................
Figure A.7 - Average Annual East Natural Gas Prices (100 Iterations)..................................................... 58
Figure A.8 - PacifiCorp IRP Topology for the 2004 IRP Update .............................................................. 64
- IV -
PacifiCorp 2004 IRP Update Executive Summary
EXECUTIVE SUMMARY
The integrated resource planning process supports PacifiCorp s objective of providing reliable
and least cost electric service to all of its customers while minimizing the substantial risks
inherent in the electric utility business. PacifiCorp s 2004 Integrated Resource Plan ("2004
IRP"
, "
IRP" or "Plan ) was filed on January 20, 2005. It described prudent future actions to
fulfill this objective, based on the best information known at the time. The 2004 IRP was
developed with considerable public involvement from customer interest groups, regulatory staff
regulators and other stakeholders. The IRP was submitted to all 6 States that regulate PacifiCorp
and was acknowledged in Idaho, Utah, and Washington which are three of the states with IRP
Standards and Guidelines containing an acknowledgement process. PacifiCorp has not yet
received an acknowledgement order in Oregon.
PacifiCorp recognizes that integrated resource planning is a continuous process rather than a
one-time or occasional event. The Plan stated (pg. 180) that it is "PacifiCorp' s intention to
revisit and refresh the Action Plan no less frequently than annually.This IRP Update
Update ) satisfies that commitment.
The 2004 IRP proposed the addition of significant new resources over the first 10 years of the
20-year study horizon. These new resources were identified in the 2004 IRP as the Preferred
Portfolio, and represented the best balanced mix of resource additions to meet future customer
needs. The 2004 IRP identified ten actions that include supply side, demand side, transmission
strategy and policy.
The 2004 IRP Preferred Portfolio proposed the addition of 177 Megawatts (MW) of Class
DSM and 2 629 MW of thermal generation capacity. In addition to the resources identified in
the Plan s Preferred Portfolio, PacifiCorp also committed to procuring up to 1 200 MW of
electricity market purchases. The Company may acquire up to 100 MW of capacity through
Qualified Facilities (QF) contracts, and will continue to procure the 1 400 MW of economic
renewable resources that were first identified in the 2003 IRP (this includes the 1 100 MW in
RFP 2003-B). Finally, 250 average MW (MWa) of energy efficiency will be acquired through
identified programs and an additional 200 MWa will be sought through the 2005 DSM RFP
which was issued on September 1 , 2005.
Since filing the 2004 IRP in January 2005, PacifiCorp has updated inputs and assumptions.
Updates to the latest resource forecast reveal that the gap between loads and resources is
diminishing. This reduction is primarily due to updates in the resource assumptions. With an
updated load and resource balance, the Preferred Portfolio now results in an average planning
margin of greater than 20 percent from CY 2009-2015. The target planning margin for this time
period is IS percent.
Portfolio modifications are necessary to align resources with requirements and the targeted
planning margin of 15 percent. This IRP Update includes a comparison of the results of an
updated Preferred Portfolio analysis which adjusts resources to maintain a 15 percent planning
margin. The changes in the Preferred Portfolio will result in resource modifications, including
delays in the online dates for resources currently in the 2004 IRP Preferred Portfolio, elimination
of some IRP resources, and the addition of new IRP resource alternatives. The changes in the
- 1 -
PacifiCorp
-,
2004 IRP Update Executive Summary
Preferred Portfolio will result in the elimination of the 2009 resource previously identified in the
Action Plan of the 2004 IRP.
Notwithstanding these resource-related changes, PacifiCorp continues to expect a gap in electric
supply resources to serve customer demand in coming years. PacifiCorp expects increases in
both customer peak use and basic demand. The expirations of purchase contracts and the
anticipated loss of generation capability due to hydro electric re-licensing will increase the gap
between demand and supply. Prompt and focused action continues to be needed to close this gap
and shield PacifiCorp and its customers from increasing cost, reliability concerns, and market
risk.
The table below outlines the Key Elements of the updated Action Plan and is based on the results
of the 2004 IRP Update Preferred Portfolio.
Table ES.l- Key Elements of the Updated Action Plan
Renewables - ursue 1,400 MW of economic renewable resources
DSM-
DSM - ursue 200 MWa of new cost effective Class 2 DSM
Distributed Generation - include CHP and standby generation as
eli ible resources in su I -side RFPs
Pursue Path C U ade for CY 2010
Transmission - actively participate in regional transmission initiatives
RMATS, Grid West, etc.
RFP 2003B currently underway.
Anticipate initiating a new procurement
activi in 2006.
Summer - Fall of2005
Summer- Fall of2005
Work with the Independent Evaluator
currently on retainer in Utah, to identify
the best way to procure this need given
the elimination of 2009 resource.
Transmission service requests have been
initiated.
Work with the Commissions, and the
Independent Evaluator currently on
retainer in Utah, to identify the best way
to procure this resource need given the
e of rox .
On- oin
Currentl
This updated information and analysis will also provide PacifiCorp and interested parties with a
new foundation for the 2006 IRP process, which begins December, 2005.
- 2-
PacifiCorp 2004 IRP Update Chapter 1 Changes in the Marketplace and Fundamentals
CHANGES IN THE MARKETPLACE AND FUNDAMENTALS
NATURAL GAS AND POWER MARKET UPD ATE
Since the 2004 IRP was completed, supply additions in the Western Interconnect have continued
apace with aggregate demand growth in the west. Although natural gas fired generation
continues to dominate recent supply additions, development of other generation sources is
beginning to take shape.
Western Supply/Demand Balance
New generation additions in 2005 of about 6 300 MW exceeded estimated aggregate demand
growth in the Western Interconnect. Projections of supply and demand growth by the Western
Electricity Coordinating Council (WECC) and others show a sufficient margin of generation
over demand through the end of this decade. About 83% of 2005 supply additions were natural
gas fired generation, as compared with about 94% gas since 2001. New coal-fired generation in
the Western Interconnect is gaining momentum, with 740 MW of additions under construction
and expected in the next three years, plus 7 900 MW of coal generation in various stages of
developrnent. Adding to the balance of supply additions are renewable resource generation
projects, primarily wind, spurred by incentives and portfolio standards; 5 350 MW ofrenewable
capacity are in various stages of development with target online dates by 2010.
Natural Gas Markets
North American natural gas markets grew tighter during 2005. A series of unfortunate events
over the last year have contributed to that tightness by reducing supply of natural gas and
increasing demand. These include hurricanes disrupting Gulf of Mexico production in 2004 and
2005 and hotter than normal weather increasing power generation demand for gas during the
summer of 2005. Also, an extreme dry water year in Spain resulted in lower hydroelectric
generation that increased natural gas power generation requirements and resulted in the diversion
of spot cargos of liquefied natural gas (LNG) that otherwise would have supplied the North
American market. Tight global crude oil and petroleum product markets continue to support high
short term natural gas prices. The gas price forecasts used for this 2004 Update are presented in
Appendix A.
The medium-term prospects for easing of North American natural gas markets continue to be
linked to the development of a robust LNG supply chain for North America. Steady progress
continues on development of upstream liquefaction facilities, a large fleet of LNG tankers, and
development and expansion of North American regasification capacity. As of mid-August 2005
19 new LNG regasification facilities or expansions have been permitted, with construction
underway on at least six of those. An additional 21 facilities are in the permitting stage and
another 19 in pre-permitting stages of development. The US Department of Energy s Energy
Information Administration forecasts LNG imports growing four-fold by 2010 (over 2004) and
almost doubling again by 2015, providing much-needed supply relief to North American
markets.
- 3 -
PacifiCorp 2004 IRP Update Chapter 1 Changes in the Marketplace and Fundamentals
Passage of major federal energy legislation and additional development of federal power plant
emissions regulations are two other market related events of the last year. These are described
elsewhere in this IRP Update.
The developments described above are generally supportive of the continued functioning of
healthy wholesale power markets, consistent with the broad assumptions of the 2004 IRP and are
reflected in the market price forecasts used in this IRP Update. These power market price
forecasts are presented in Appendix A.
CLIMA TE CHAN GE POLICY UPDATE
Since the 2004 IRP was issued, policies related to climate change have continued to develop
within the regional, national, and global arenas. Internationally, the Kyoto Protocol took effect
on February 16 2005 after Russian ratification in November. Without u.S. involvement, Russia
remained the final nation with the ability to push cumulative emissions over the 55% threshold
required to trigger the protocol's enactment. The 126 nations involved will now work to reduce
carbon dioxide emissions to 7% below 1990 levels by 2012. The United States will not
participate, and instead has joined the Asia-Pacific Partnership for Clean Development. This
partnership between Australia, Japan, China, India, and South Korea works to ease the transfer of
clean energy technologies, but lacks specific targets on greenhouse gases.
At the federal level, three major proposals were considered by Congress leading up to passage of
the energy bill. Once again, Senators McCain and Lieberman proposed a cap on emissions along
with a permit trading system. However, inclusion of incentives for nuclear energy eroded support
garnered in earlier votes, leading to a 38-60 defeat of the Climate Stewardship Act.
A similar, but less stringent, proposal came from Senator Jeff Bingaman. Originally offered as an
amendment to the energy bill, this proposal was based on work by the National Commission on
Energy Policy and would establish an economy wide greenhouse gas emissions intensity rate cap
starting in 2010. The proposal included a $7 per ton "safety valve" carbon price cap. Though the
Bingaman proposal did not reach a vote, it is expected to resurface in the future, as some
bipartisan support was evident. Through hearings and discussions on climate change, the Senate
acknowledged for the first time that greenhouse gases are contributing to global warming. In
another first, a subcommittee on climate change was created by Senator Ted Stevens, chair of the
Commerce Committee.
A third proposal led by Senator Chuck Hagel and cosponsored by Senator Mark Pryor offers
financial incentives for research and investments, as well as improvements in the transfer of
technology to developing countries, similar to the Asia-Pacific Partnership. Hagel's bill passed
the senate 66-, but is not expected to alter the climate landscape for utilities.
In the absence of strong federal guidance on the issue, policies at some regional and local levels
have matured over the past year. A Renewable Portfolios Standard was passed by initiative in
Colorado that requires 10% of state energy needs to be met by renewable energy by 2015.
Oregon developed a plan to reduce greenhouse gases, while California continued to investigate a
cap and trade system. A nine state partnership in the northeast, the Regional Greenhouse Gas
Initiative (RGGI), came closer to agreement on a plan to cap utility emissions of carbon dioxide
4 -
PacifiCorp 2004 IRP Update Chapter 1- Changes in the Marketplace and Fundamentals
at 150 million tons starting in 2009, with reductions beginning in 2015. Oregon, Washington
and California are discussing a similar regional structure for the west coast. North Carolina is
poised to become the first southern state to act on global warming after both chambers of
congress passed a bill to commission a state climate impact study.
While climate change policy continues to develop, the most likely policy scenarios continue to
support the timing and magnitude of PacifiCorp s existing carbon adder. The adder values
updated for the new inflation forecast, are reported in Appendix A.
IMP ACTS OF THE ENERGY POLICY ACT OF 2005
Congress passed the Energy Policy Act of 2005 (EP ACT2005 , or the Act) in July and the
President signed the bill on August 81\ 2005. The new Act, the first omnibus energy policy
legislation passed since 1992, includes a number of provisions that may impact generation
facility siting, hydropower relicensing, and emerging energy technologies. Many of the
provisions of EP ACT2005 will require rulemakings by various federal agencies (such as the
Department of Energy and the Federal Energy Regulatory Commission) before the impacts of
the Act can be fully assessed.
While EP ACT2005 sets a policy framework, many of the incentives require appropriations from
Congress in order to take affect. The availability of appropriations to fund these provisions is
highly uncertain given the reality of increasing federal deficits and pending budget priorities
such as the federal response to Hurricane Katrina. However, a number of provisions contained in
the EPACT2005 clearly have the potential to affect PacifiCorp s resource planning and are
discussed below.
Transmission Sitin2
Designation of National Interest Electric Transmission Corridors. The EP ACT2005 requires
the Department of Energy ("DOE") to periodically report on transmission congestion and
designate, as a "national interest electric transmission corridor , an area with inadequate
transmission that is adversely affecting consumers. The Federal Energy Regulatory Commission
FERC") is empowered to grant one or more permits for the construction of a new transmission
facility or the modification of an existing facility within in a national interest electric
transmission corridor, provided the FERC finds that state approval has been withheld or is not
possible, or that a state-granted approval is conditioned such that the construction or
modification will not significantly reduce transmission congestion in interstate commerce or is
not economically feasible. In addition, the FERC must determine that the facilities to
authorized will be used for the transmission of electricity in interstate commerce, the
construction or modification is consistent with the public interest, will significantly reduce
transmission congestion in interstate commerce and protect or benefit consumers, will enhance
energy independence, and will maximize the transmission capabilities of existing towers
structures.
Rights-Of-Way. If FERC grants a permit for the construction or modification of existing
transmission facilities within a national interest electric transmission corridor, the permit holder
can, where necessary, acquire a right of way over private lands within that corridor pursuant to
- 5 -
PacifiCorp 2004 IRP Update Chapter 1 Changes in the Marketplace and Fundamentals
eminent domain. Once acquired, the right of way cannot be used for any other purpose and will
terminate upon the termination of the use for which it was acquired.
Coordination of Federal Authorizations. The EP ACT2005 also tasks the DOE with the
responsibility of coordinating all applicable Federal authorizations, including such permits
special use authorizations, certifications, opinions, or other approvals as may be required under
Federal law, in order to ensure timely and efficient review and permit decisions for siting a
transmission facility. Such coordination would also include any related environmental reviews.
Each Federal land use authorization granted for an electricity transmission facility shall be issued
for a period of time commensurate with the anticipated use of the facility and with appropriate
authority to manage the right-of-way for reliability and environmental protection.
Interstate Compacts. EP ACT 2005 also suggests that three or more contiguous states may
enter into an interstate compact (subject to further congressional authorization) to establish a
regional transmission siting agency, and facilitate siting of future electric transmission facilities
within those states, other than those on Federal property. Typically, FERC will have no authority
to approve the siting of a transmission facility in a state that is a member of a regional
transmission siting agency, unless the members of the compact are in disagreement and certain
conditions are met.
Third-Party Financing of Transmission Facilities. Under certain circumstance, the Secretary
of Energy, acting through the Western Area Power Administration ("WAPA") and/or the
Southwestern Power Administration ("SWP A") may acquire existing facilities or construct new
facilities in the W AP A and SWP A service areas, if the Department of Energy determines that the
proposed project is located in a national interest electric transmission corridor and will alleviate
transmission congestion. EP ACT2005 also requires FERC to provide incentives (presumably in
the form of increased return on equity) for investments in new transmission facilities.
Renewable Ener2V Production Tax Credit
The renewable energy production tax credit (PTC), which was set to expire at the end of 2005
has been extended for another two years. Additionally, the eligibility period for power
production from open-loop biomass, geothermal, small irrigation, landfill gas and municipal
solid waste projects is increased from 5 to 10 years. Finally, incremental hydropower production
resulting from efficiency improvements or capacity expansion at existing dams was added to the
list of production technologies eligible for the PTC. PacifiCorp expects that extension of the PTC
should aid the procurement of new wind and other renewable resources since uncertainty about
the availability of the PTC has been a significant challenge for renewable energy suppliers.
Clean Coal Incentives
Title IV, Subtitle A of EP ACT2005 authorizes up to $200 million per year for fiscal years 2006
through 2014 to be appropriated for the Clean Coal Power Initiative, with 70 percent ofthe funds
to be expended on coal-based gasification technologies, including Integrated Gasification
Combined Cycle (IGCC). The bill requires the DOE to set technical milestones to reach the
efficiency and emissions levels spelled out for qualifying clean coal projects and upgrades to
existing projects. The Secretary of Energy is required to report on the progress of funded projects
in meeting the established milestones.
- 6-
PacifiCorp 2004 IRP Update Chapter 1 Changes in the Marketplace and Fundamentals
Specific language requires the Department of Energy, subject to the availability of appropriated
funds, to establish an IGCC project located in a western state at an altitude of at least 4 000 feet
to demonstrate the use of coal with an energy content of not more than 9 000 Btullb. If
economically feasible, the project can also demonstrate the ability to use coal mined in the west
of up to 13 000 Btullb. The project must also be capable of removing and sequestering CO2
emissions. Either loan guarantees or federal cost sharing would be available, subject to
appropriations.
Additionally, the act reauthorizes the Clean Air Coal Program and authorizes the Secretary of
Energy to expend up to $3 billion, subject to appropriations, to facilitate production and
generation of coal-based power, including gasification, and advance the deployment of pollution
control equipment to meet current and future obligations of coal-fired generation units regulated
under the Clean Air Act.
Title XVII of the Act provides loan guarantees for up to 80 percent of qualifying gasification and
other eligible technologies. Projects must meet certain emissions performance criteria in order to
qualify for the guarantees. Qualifying projects must have an assured revenue stream to cover
project capital and operating costs that is approved by the Secretary of Energy and relevant state
Public Utility Commissions (PUCs), and be designed to accommodate carbon capture
equipment. The title also provides an option for the project owner to pay for the federal cost of
scoring their loan guarantee, which will enable the program to provide guarantees even in the
absence of appropriations. There is no cap on the amount of loan guarantees available.
Title XII of the Act creates investment tax credits (ITC) available for IGCC, industrial
gasification, and advanced combustion facilities. IGCC projects may receive a 20 percent ITC
and the program may provide up to $800 million of credits. The available credits are to be
allocated roughly equally between projects that use bituminous, subbituminous, and lignite coal.
Other advanced coal-based projects may receive a 15 percent ITC and the program may provide
up to $500 million of credits. All projects must be certified by the Secretary of Treasury in
consultation with the Secretary of Energy.
These incentives and their potential impact on IGCC as a resource choice are discussed in
Chapter 3.
Hydropower
The bill contains a number of provisions relating to the hydro relicensing process. The bill
establishes a hearing process in which mandatory license conditions may be challenged and
provides applicants with the ability to propose alternative environmental conditions that provide
resource protection while reducing costs and/or improving electricity production.
Additionally, the bill authorizes incentives for new turbine installations at existing dam sites
where no modification to the impoundment or diversion structure is necessary as well as for
projects that improve efficiency at existing dams. These new installations or improvements must
occur within ten years of enactment of the bill and incentive payments are available for up to ten
years, subject to certain limitations and restrictions.
- 7 -
PacifiCorp 2004 IRP Update Chapter 1 - Changes in the Marketplace and Fundamentals
Mandatory Reliability Standards
EP ACT2005 seeks to improve electrical reliability by authorizing FERC to designate an
independent Electric Reliability Organization (ERO) to develop and enforce bulk power system
reliability standards. The ERG will propose reliability standards or modifications to existing
FERC standards to FERC, which will approve the standard if the Commission finds the
standards to be "just, reasonable, and not unduly discriminatory or preferential, and in the public
interest." The ERO will also conduct periodic assessments of the reliability and adequacy of the
North American bulk power system.
FERC can authorize the ERO to delegate authority to propose and enforce reliability standards to
a regional entity. Additionally, a regional advisory body may be formed to advise the ERO
regional entity, or FERC. FERC must establish a regional advisory body if at least two-thirds of
the states within a region accounting for more than one-half of the load within that region
petition the Cornmission to do so.
The language in the Act specifically states that the provision does not authorize the ERO or
FERC to require the construction of additional generation or transmission facilities. States retain
the authority to take action to ensure the safety, adequacy, and reliability of electric service. State
reliability regulations will not be preempted unless a state action is inconsistent with a federal
reliability standard.
The effect of this provision on PacifiCorp s resource planning effort is unknown at this time. It is
likely that reliability standards promulgated under this provision may impact the planning
reserve margin used by PacifiCorp or may affect the operation of the transmission system in a
manner that affects resource decisions, plant siting, or transmission requirements.
Conclusion
PacifiCorp is currently evaluating the provisions of the recently passed EP ACT2005 in order to
determine the impacts the new law may have on the economics of new resource alternatives. As
many of the incentive provisions of the law are subject to the availability of appropriations it is
not yet known if they will actually impact the economics of new resource options, and if so, to
what degree. PacifiCorp will continue to follow these policy developments and federal
appropriations to ensure that the IRP process is well-informed with the most accurate
assumptions about infrastructure availability and resource costs.
- 8 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
2. RESOURCE NEEDS ASSESSMENT
INTRODUCTION
This chapter presents the results of the updated analysis ofPacifiCorp s Load & Resource (L&R)
Balance. This information serves as the basis for evaluating the sufficiency of the 2004 IRP
Preferred Portfolio to meet any changes in the resource deficit outlook for the IRP planning
horizon. The chapter first covers the load and resource status, presenting revisions to system
modeling assumptions that impact the L&R Balance. Modeling assumptions related to existing
PacifiCorp resources are covered first, followed by assumptions for Planned Resources; that is
resources included in the L&R Balance that PacifiCorp is currently taking actions to acquire.
Finally, updated L&R Balance results are presented showing modifications to resource
requirement forecasts, along with observations concerning how the 2004 IRP Preferred Portfolio
is impacted. (Note that all data in the 2004 IRP Update are reported on a Calendar Year basis
unless noted otherwise.
LOAD FORECAST
The load forecast used in the IRP is updated every two years and is a 20-year hourly forecast of
expected loads. This forecast represents energy and demand use by customers for each load
center on PacifiCorp s system. The last forecast was prepared in March 2004, and was used for
both the 2004 IRP and this 2004 IRP Update. The next load forecast is scheduled for release in
March 2006. PacifiCorp is in the process of adopting new end-use forecasting models to support
the IRP and other forecasting requirements: the Residential End-Use Energy Planning System
(REEPS) and the Commercial End-Use Planning System (COMMEND), both developed by the
Electric Power Research Institute (EPRI).
RESOURCE SITUATION
Chan2es to Existin2 Resources
Existing Resources are defined as resources currently in operation or for which procurement
contracts have been signed.
New Contracts
There have been several new contract procurements since the 2004 IRP filing, totaling 354 MW
of capacity. Of this total, 164 MW are Qualifying Facility (QF) contracts, and 65 MW are
renewables. Details concerning these new contracts are provided in Table A.3 of Appendix A.
The total amount of new Front Office Transactions for the 2006 - 2009 period is 1 000 MW.
Treatment of Qualifying Facilities and Interruptible Load Contracts
In response to public comments received on the 2004 IRP, PacifiCorp changed its assumption
regarding the handling of QF and interruptible contract extensions. All QF and interruptible
contracts are now assumed to be extended to the end of the study period. The impact is discussed
in the loads and resources section of the report. This assumption better reflects the expectation
that QF and interruptible contracts will likely be renewed once they expire.
- 9-
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Most of the QF contracts were considered firm resources and thus were included in calculation
of both the capacity and energy positions of the L&R Balance. However, the Tesoro, Kennecott
and MagCorp QF contracts are considered non-firm and, as such, were omitted from the capacity
position calculation because they cannot be relied upon at the peak periods. However, these three
contracts were included in the calculation of the monthly energy positions for the L&R Balance.
At the time of the 2004 IRP filing, these planned contracts were represented as firm since the
service type (firm or non-firm) of the contracts was unknown. Since it is now known that these
contracts are non-firm, omitting them from the capacity position of the L&R Balance is
appropriate and prudent.
Thermal Plant Lives
PacifiCorp changed its assumption regarding retirement dates for most of PacifiCorp s thermal
stations. PacifiCorp is now using plant life extension as a proxy for resource replacement.
Thermal plants are modeled to operate past the IRP's 2006-2025 study period, with the
exception of the following units:
Carbon 1 & 2 - retirement at year-end 2020; no change from the 2004 IRP
Little Mountain 1 - retirement in 2012 pending evaluation of steam contract expiration; the
2004 IRP assumed retirement in 2006
Gadsby 1 3 - retirement at year-end 2017; no change from the 2004 IRP
Note this new assumption is not meant to presume a particular replacernent strategy based on
economics or regulatory factors, or to establish different extension dates from what was reported
in PacifiCorp s 2002 Depreciation Study. Changes at plants intended to prolong their lives will
be done in accordance with applicable law.
Hydroelectric Resources
The hydro forecast is officially updated semi-annually. The IRP has been updated for the May,
2005 forecast which, over the 20 year study period, reflects an approximate 7% decline in
generation. This was mainly attributed to improved Mid-C information, a better understanding of
the updated Grant contract, and updated operational constraints.
Demand Side Management
A new Class 1 DSM program for Utah, called Load Lightener, has been added as an Existing
Resource. This 10-year program starts in 2005 , and is forecasted to build to a total of 30 MW of
curtailable load by summer of 2008. The program is targeted to commercial and industrial
customers with significant lighting requirements, and provides steady electricity energy savings
in addition to the ability to curtail load further during system peak load conditions. The load
reduction uses EnergySaverTM technology to decrease the power supplied to ballasted lighting
systems without abrupt voltage changes or noticeably affecting visible light. For modeling
purposes, the curtailable load is available for 250 hours during the daily peak period (2 - 8
on weekdays) for the summer months.
Renewable Resources
A line item for renewable resources was added to the load and resource balance for this 2004
IRP Update (Appendix B). Resources included in this category include the Blundell geothermal
plant and wind projects for which PacifiCorp owns or holds the output rights to: Foote Creek 1
- 10-
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Rock River and Combine Hills. In addition, it includes the wind energy storage contracts such as
Foote Creek 2-4 and Stateline.
Adding to this list of renewable resources is a newly signed power purchase agreement for the
output of a 64.5 MW wind-powered electric generating project to be built about 10 miles
southeast of Idaho Falls, Idaho. The 20-year agreement is with Wolverine Creek Energy LLC
owned and operated by Invenergy, a developer, owner and operator of power generation and
energy delivery assets headquartered in Chicago.
This 64.5 MW wind resource is modeled in the Goshen bubble for the IRP Update model
topology. Applying the 20% peak capacity credit assumption for wind resources, the Wolverine
Creek resource will add 13 MW of firm capacity during peak load hours. The Planned Resources
section below will describe how the "RFP Wind" resources were adjusted to reflect the addition
of this planned wind resource.
Chane:es to Planned Resources
The second resource group in the resource base data is referred to as Planned Resources. This
group is comprised of resources that PacifiCorp has firmly decided to pursue and is taking
actions to acquire. For the 2004 IRP Update, they include 1 300 MW of RFP Wind from the
2003 IRP (adjusted downward from 1 400 MW to account for the Wolverine Creek wind
contract), up to 1 200 MW of Front Office Transactions and 100 MW of Utah Qualifying
Facility contracts.
Front Office Transactions
No change was made to the annual maximum Front Office Transactions (FOT) amount for the
2004 IRP Update; it remains up to 1 200 MW. However, for 2006 through 2009, the transaction
amounts have been adjusted to account for completed transactions (See Table B.2 in Appendix B
for the annual FOT planning targets). In addition, they were adjusted down slightly in the west in
the early years because the new L&R Balance did not require the same level of transactions.
In addition to the change in the amount of Front Office Transactions, the modeling methodology
has been updated. In the 2004 IRP, Front Office Transactions were dispatched only if all of the
capacity was needed; that is, if the system was long, zero energy was dispatched, and if the
system was short, full capacity was dispatched. PacifiCorp has changed the modeling of these
transactions to reflect dispatching in 50 MW increments to represent market price interaction
with incremental dispatch decisions.
RFP Wind
RFP Wind resources were modeled as Planned Resources that serve as proxies for PacifiCorp
expected acquisition of 1 400 MW of wind resources through 2012. As discussed in the section
on Existing Resources, PacifiCorp recently signed a 20-year agreement to purchase the output of
the 64.5 MW Wolverine Creek wind project. This was modeled for the IRP Update as an
Existing Resource, and thus a 100 MW block of the RFP Wind resources was removed to reflect
this addition. The adjustment of 100 MW (vs. 64.5 MW) was necessary because the RFP Wind
resources were modeled in 100 MW increments. As further adjustments are made to reflect
future wind acquisitions, it is expected that the total adjustments will closely reflect total
- II -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
acquisitions. Table 2.1 below shows the annual capacities of the RFP Wind resources as modeled
for both the 2004 IRP and the 2004 IRP Update.
Table 2.1- Annual Megawatt Capacities for Targeted New RFP Wind Resources
fA~ofj5I~ ~t;ijJ2qO'~~ ;~b(j:O7~fi !ritiiyb~~j;: ~!2oJN.1!! kTI;i~Qi'ql 1I~'(j'l4~ tf.a:Qi:~(;100 300 500 700 900 1 100 1 400 1,400
200 400 600 800 1 000 1 300 1 300
TOPOLOGY UPDATES AND TRANSMISSION CHANGES
Figure 2.1 shows the updated model transmission topology. The IRP model underwent three
significant topology changes since the 2004 IRP. These changes include the addition of two new
bubbles and a new transmission link between existing bubbles. Primary among these changes is
the new bubble named BPAlTA, which was added to contain the "BPA Peaking" and
TransAlta" contracts. This change was made in order to represent the transmission components
of these contracts separately frorn the other transmission constraints of the region.
The second significant addition is the Montana bubble. This bubble was added to allow the
energy from the Colstrip units to serve load in Goshen as well as in West Main.
Finally, the third topology change is a transmission link added to provide more detailed
modeling of loads and resources in the Southeast Idaho area. PacifiCorp has recently added a
wind resource in this area and additional wind resources are expected in the future (as Qualifying
Facilities and/or via renewable resource procurement processes).
Figure 2.1 - PacifiCorp IRP Topology for the 2004 IRP Update
PacifiCorp IRP
Topology
(2004 IRP Update)
lood
..
G.".,."'"
C!J) Pu";'RsoiSo'. """'.~
Com_~,t,,"....
+--+
0.."... T,.,..mls&'onon P,,'"Coop
+--+
0"","" T"",-,ml..lono"o"'"
I Figure 2.1 is also shown in Appendix A (Figure A.8) in a larger version for readability.
- 12 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
LOAD AND RESOURCE BALANCE
This section presents the changes that have occurred to the PacifiCorp Load & Resource Balance
since the 2004 IRP was filed. The factors causing the changes are discussed first, followed by
charts showing the degree and timing of the L&R changes. Finally, the implications of these
L&R changes for this IRP Update are discussed.
Summary of Resource Chan2es Affectin2 the Load & Resource Balance
There are several resource changes that were made to the L&R Balance and which, in aggregate
provide a different outlook concerning PacifiCorp s resource situation relative to that of the 2004
IRP. The resource changes can be classified into the following four categories:
Counting differences. In response to regional planning initiatives, PacifiCorp reevaluated
the way that it treats Hydro resources in the calculation of capacity positions for this IRP
Update. However, its treatment in calculating the monthly energy positions did not change.
Resource additions. As outlined above, new Planned Resources were added to the L&R
Balance, such as the Wolverine Creek wind contract. These had a direct effect on both the
capacity and energy positions of the L&R position.
Changes due to public comments. A number of suggestions were received from the public
in the course of the 2004 IRP, and were incorporated into the assumptions underlying this
L&R Balance. Notable among these was the suggestion that existing Interruptible and QF
contracts be extended to the end of the IRP study period. Extending the Interruptible
resources affects the capacity position significantly, but has a lesser effect on the energy
position. Extending the firm QF resources affects both. Extending the non-firm QF resources
only impacts the energy position.
Reconciliation to PacifiCorp s GRID model. Earlier this year a detailed reconciliation
between the IRP and GRID models was performed.2 The reconciliation resulted in a number
of long-term sales and purchase contracts being reconfigured in both models in order to keep
the two models synchronized. These contract changes affect both the capacity and energy
positions of the L&R Balance.
Below are summaries on the change status of the capacity positions of each L&R Balance line
item relative to that of the 2004 IRP. The associated average MW amount differences are shown
for most line items. These average differences cover the ten-year period from 2006 through
2015.
Thermal- There were no changes to the aggregate total capacity. On the east, the Desert Power
QF was taken out and put into the new QF line item so that the annual MW values are less by 90
MW. (Desert Power was rated at 90 MW in the 2004 IRP; for this IRP Update, it is rated at 95
MW.
2 The GRID model is PacifiCorp s in-house regulatory decision support model. Its main function is to generate Net
Power Cost estimates for rate case filings and other purposes.
- 13 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Hydro - Hydro resources changed in this L&R Balance. As mentioned above, this is due to the
change in how hydro resource capacities were counted. For the 2004 IRP, they were counted by
expected generation which is computed by the VISTA model prior to being entered into the IRP
model. For this IRP Update, this assumption was changed to count Hydro by the maximum
capacity that is operationally sustainable for one hour before reserves (Hydro Availability). This
resulted in a slight increase in the east of 6 MW. In the west, owned hydro (mostly Swift I and
Merwin) increased by 239 MW while Mid-C contracts increased by 84 MW. This change in how
Hydro resources are counted impacts capacity positions but has no impact on the energy
positions of the L&R Balance.
DSM - DSM increased in the east by 28 MW due to the addition of the new Utah Class 1 DSM
program (Load Lightener).3 There were no DSM changes in the west. These changes impact both
the capacity and energy positions of the L&R Balance.
Renewable - Renewable resources increased in the east due to the addition of the 64.5 MW
Wolverine Creek wind contract. Applying the assumed 20% capacity credit for wind resources
this contract added 13 MW of peak load carrying capacity for the capacity L&R balance. Energy
position was affected by amounts reflecting the nameplate capability. This addition resulted in a
reduction of the RFP Wind resources, which will be described shortly. There were no changes in
this line item on the west.
Purchase - Long-term purchases and exchanges increased in the east in the early years due
the completion of Front Office Transactions. However, there were decreases in the east (83 MW)
and west (59 MW) in the later years due to the IRP/GRID model reconciliation. These changes
had a similar impact on the monthly energy positions as they did on the annual capacity
positions.
QF - Since the 2004 IRP one firm QF resource (ExxonMobil) was added to the L&R Balance.
In response to public comments PacifiCorp changed IRP modeling assumptions and extended all
QF contracts to the end of the study period. The firm QF contract additions and
extensions increased QF capacity by 122 MW in the east and 15 MW in the west. This has an
impact on both the annual capacity and monthly energy positions since the QF contracts are flat
annual products. Additionally, there were three QF contracts (Kennecott, Tesoro and USMag)
that were considered non-firm and thus did not count towards the annual capacity positions.
However, they did impact the monthly energy positions.
Interruptible - There was a 185 MW increase in Interruptible resources in the east due to the
assumed contract extensions, as well as the inclusion of the 125 MW MagCorp contract that, for
the 2004 IRP, was assumed to expire in 2004. There were no Interruptible resource changes in
the west. As with QF resources, this assumption change was made in response to public feedback
during the 2004 IRP process. This assumption change had a significant impact on annual
capacity positions but had a comparatively small impact on monthly energy positions since
Interruptible load contracts are executed over a relatively small nurnber of hours.
Transfers - There was no change in the assumption of a net west-to-east transfer of 454 MW.
3 The 28 MW average reflects the phase-in of the capacity, reaching the annual peak of 30 MW by 2008.
- 14 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
RFP Wind - There was no change in RFP Wind resources in the east. However, in the west
amounts were adjusted based on the Wolverine Creek wind purchase. It is noteworthy that the
Wolverine Creek purchase is executed in the east (Goshen). RFP Wind was adjusted in the west
because the west is where the earliest blocks of the planned wind resources were modeled in the
2004 IRP and the 2004 IRP Update. This change had a larger impact on monthly energy
positions than annual capacity positions because ofthe 20% capacity contribution assumption for
wind resources.
Front Office Transactions - These were reduced in the early years in the east since transactions
have been executed. They were adjusted down slightly in the west in the early years because the
new L&R Balance did not require the same level of transactions. These changes impacted
monthly energy positions and annual capacity positions similarly in the west because they are
flat annual products. In the east the third-quarter energy positions were affected similarly to the
annual capacity positions since they are third-quarter products.
QF Planned - There were no changes to the Planned QF resources on either side of the
PacifiCorp system.
Load - This IRP Update uses the same March 2004 load forecast as was used in the 2004 IRP.
Thus, there were no changes to these line items.
Sale - Due to the IRP/GRID model reconciliation, there was a decrease in sales (50 MW) in the
east and an increase (17 MW) in the west. These changes impact the annual capacity positions
and monthly energy positions in a similar way.
It can be seen frorn the foregoing discussion that the trend of the net changes in the various
resource categories is towards a longer position on both sides of the PacifiCorp system. This will
be illustrated in the next section where peak-hour obligations and resources are compared to
reveal the new annual resource positions for this IRP Update.
Capacity Charts
Capacity Charts show the peak obligation (load plus sales) plus the planning margin requirement
as compared to the available resources for the peak load hour. They were constructed by
determining the system coincident peak hour for each of the first ten years of the planning
horizon (2006-2015), and determining the available resources for those hours. Existing resources
are composed of the following resource categories:
Existing Resources Thermal Hydro Class DSM Renewable Purchase QF
Interruptible Transfers
Purchase and Renewable resources (except wind) are determined by model dispatch.
Wind resources are determined by multiplying the nameplate capacity by the assumed 20% peak
capacity contribution factor. The rest of the resources are determined by maximum capacity. The
peak obligation is equal to load plus sales. All of the capacity charts assume a coincident peak
planning margin of 15%. The Planned Resources, which include renewable resources ("RFP
Wind"), Front Office Transactions and some QF contracts, are stacked above the Existing
- 15 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Resources at the top of each chart. The gap between the peak obligation and PacifiCorp s total
available resources represents the annual capacity deficit.
Figures 2.2 through 2.4 present the various capacity charts developed for the updated Load &
Resource Balance. In the System and West Capacity Charts there are a few noticeable declines in
resources and loads in the 10-year period, mostly caused by the expiration of existing contracts.
For example, the BPA Peaking contract expires August 2011 and thus causes the decline in
capacity in 2012. Similarly, the expiration of the Clark County Load Service contract causes the
drop in capacity and obligation in 2008.
Figure 2.2 - System Coincident Peak Capacity Chart
000
14,000
12,000
10,000
OOO
:IE
000
000
2006 2007 200B 2009 2010 2011 2012 2013 2014 2015
Calendar Year
- 16-
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Figure 2.3 - West Coincident Peak Capacity Chart
~ 5 000
Calendar Year
Resources
Obligation+15%
10,000
000
000
000
000
000
000
000
000
2006 2007 2009 2011 2012 2014 2015201320082010
Figure 2.4 - East Coincident Peak Capacity Chart
~ 5,000
Calendar Year
10,000
000
Peak Obligation + Planning Margin
---
000
000
000
000
000
000
000
2006 2007 2009 2010 2011 2013 2014 201520122008
- 17 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
In Figure 2.4, the increase in existing resources in 2007 is due to the startup of the Lake Side
project. The decrease in capacity in 2008 is caused by the expiration of the West Valley Lease.
Updated Firm Capacity Position Charts
The preceding three charts illustrate PacifiCorp s updated firm capacity position for 2006-2015.
To understand how the L&R balance has changed, it is instructive to compare these to the same
charts provided in the 2004 IRP. Thus, Figures 2.5 through 2.7 provide bar chart comparisons of
the annual firm capacity positions for the 2004 IRP and those derived from the updated L&R
Balance. Figure 2.5 shows the comparison for the PacifiCorp system, while Figures 2.6 and 2.
show the comparisons for the east and west control areas, respectively. These position
comparisons illustrate how the resource changes outlined above result in a general increase in
firm capacity position for the PacifiCorp system. The system position underwent an average
increase of 593 MW over the first ten years of the study period. For the west and east sides of the
PacifiCorp system, the average increase in firm capacity position was 247 MW and 346 MW
respectively.
Figure 2.5 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for
PacifiCorp System
Calendar Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
__--
__m__-
-- -,-- -,..- ---....--....,--....---..'- ,-,.._-, -- ..-- -- - - --....-,-..- - - - - ..,......,---_..,.. ,...... --,--
500
-500
1000
:IE -1500
2000
2500
3000 0 IRP System Position. Update System Position
-3500
- 18 -
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Figure 2.6 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for
PAC West
Calendar Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
400
200
200
:E -400
-600
-800
1000
C IRP West Position. Update West Posilion
1200 ..--..,
--..-,-..,..,..------,.------...-..--'---------..,"'....-'--,----,----
_.....,_,..--m__,..,..,,__mm..
..____,--,-,..,..'.'_
Figure 2.7 - Comparison of 2004 IRP Update and 2004 IRP Firm Capacity Positions for
PAC East
Calendar Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
500
200
100
-400
700
1000
1300
1600
1900
2200 e IRP East Position. Update East Position
2500
- 19-
PacifiCorp -2004IRP Update Chapter 2 - Resource Needs Assessment
Enerev Curves
Figures 2.8 and 2.9 represent the energy curves for each side of PacifiCorp s system. These
curves show the net position by month for On-Peak and Off-Peak hours for each Control Area.
The On-Peak hours are weekdays and Saturdays, hour ending 7:00 am to 10:00 pm; Off-Peak
hours are all other hours. The net position is resources minus obligation and includes average
monthly outages and the WECC reserve requirement. Results are shown net of area transfers.
Figure 2.8 - West Energy Curves
500 1"
000 '
500
000
500
::0
(500)
000)
500)
000)
\,I
PAC West Off-Peak
- - - PAC West On-Peak
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 0 0 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~
9 9 2 2 9 9 2 2 9 9 2 2 9 9 2 2 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ r ~ ~~ ~~ 8~ ~~ 8~~~ 8~~ ~ 8 ~~~ 8~~~ 8~ ~~8~ ~~ 8~~~ 8~~ ~
Figure 2.9 - East Energy Curves
500
000
;or
..', '
500
000
...
500
-",
::0
(500)
000)
500)
(2,000)
I I
-PAC East Off-Peak
- - -PACEastOn-Peak
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 0 0 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ & ~ r
~; ~ ~
~; ~ r ~ ; ~ r ~; ~ r ~; ~ r
~ ;
~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0 ~ ~ ~ 0
- 20-
PacifiCorp 2004 IRP Update Chapter 2 - Resource Needs Assessment
Summary Load & Resource Balance Observations
The impact of the resource changes is to decrease the resource deficit relative to that projected in
the 2004 IRP, with a capacity deficit emerging in 2010 for the eastern side of the system. The
consequence is that the Preferred Portfolio identified in the 2004 IRP is no longer optimal from
resource quantity or timing perspectives. For example, the 2004 IRP Preferred Portfolio now
results in a planning margin that averages about 21.8% for the 2009-2015 time period, compared
to 16% using the 2004 IRP L&R balance.
In conclusion, the new L&R Balance indicates a system-wide need for approximately 2 000MW
in 2014 compared to the 2 800 MW need identified in the 2004 IRP.
4 The annual target planning margin assumed for both the 2004 IRP and the 2004 IRP Update is 15%.
- 21 -
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
3. INTEGRATED GASIFICATION COMBINED CYCLE RESOURCE
UPDA TE
Emerging clean coal technology continues to gain attention as a potential means to add new coal-
based generating resources while offering reduced emissions compared to a new conventional
coal plant. These emerging technologies also offer the potential to more economically capture
carbon dioxide (CO2) for beneficial reuse or geologic sequestration than conventional coal
technology. Recent developments in the power supply industry related to Integrated Gasification
Combined Cycle (IGCC) technology have created a groundswell of interest in this clean coal
technology. In addition, incentives for IGCC and other clean coal technologies included in the
Energy Policy Act of 2005 have the potential to reduce the cost differential between IGCC and
other generation sources.
Within its 2004 IRP, PacifiCorp considered IGCC as a resource option in numerous candidate
resource portfolios and included the best information available at that time on expected cost and
performance. However, based on cost projections for IGCC as compared to other resource
alternatives, such as conventional coal generation, the resulting Preferred Portfolio did not
includeIGCC.
Recognizing the potential of IGCC, PacifiCorp has continued to explore IGCC technology since
the 2004 IRP was filed through discussions with suppliers and completion of a preliminary
engineering study of the expected costs of an IGCC plant located at the Hunter site. The study
results indicate that IGCC remains more costly than conventional pulverized coal, though the
estimated cost gap has narrowed since the 2004 IRP. The results of PacifiCorp s preliminary
IGCC study are presented below, along with discussions on EP ACT2005 investment incentives
state IGCC policy developments, and the technical and regulatory challenges faced by emerging
technology such as IGCc.
TECHNICAL UPDATE
PacifiCorp contracted with Parsons E&C in late 2004 to perform a preliminary engineering study
of the expected cost of installing an IGCC plant on the Hunter site. This study represents
Parsons' conceptual level analysis of the expected cost and performance of the two commercial
gasifier options available at that time, GE- Texaco and ConocoPhillips E-Gas. The study is not
equivalent to a Feasibility Study, which would develop the most reliable engineering and cost
information necessary to make a decision regarding selection of the best IGCC technology. The
study used Utah coal with an identical quality to the coal used in previous Hunter pulverized coal
technology studies. This coal is a Utah bituminous low-sulfur coal with an average heat content
of 11 500 Btullb (HHV).
The Parsons study developed a conceptual engineering, procurement and construction (EPC)
price estimate for an IGCC plant. PacifiCorp then adjusted these costs to include other site-
specific costs as derived from previous Hunter 4 studies of the cost of a new pulverized coal unit.
These adjusted cost estimates included allowances for additional coal handling, construction
management, water, spare parts, PacifiCorp personnel, and financing charges. Based on these
adders the projected cost to install a 519 MW gasification system on the Hunter site was
expected to be approximately $1 957/kW in 2005 dollars. This compares to the subcritical
- 23-
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
pulverized coal boiler estimate of $l ,687/kW and the supercritical boiler cost estimate
735/kW used in the 2004 IRP.
This IGCC estimate does not include provisions for future inclusion of carbon capture
equipment. The additional costs of making an IGCC facility "carbon capture ready" consist of
providing space for the installation of future CO2 separation process steps and providing larger
equipment sizing to accommodate these future additions. Larger equipment sizing is necessary to
enable the plant to produce the same electricity output as a plant without carbon capture
equipment installed. While equipment to capture carbon can be added to an IGCC facility in the
future without these up-front provisions, the overall cost of such a facility is expected to be lower
with the initial planning of these additions. Including these costs would increase the initial IGCC
cost estimate to $2 153/kW.
An IGCC facility at the Hunter site would have a projected design heat rate of 8 405 BtulkWh
HHV. Converting this design heat rate to an average annual heat rate yields a value of 8 657
Btu/kWh. A coal-based design that uses a supercritical boiler would have an estimated annual
average heat rate of 9 129 Btu/kWh. Operation and maintenance (O&M) estimates for an IGCC
were also developed for comparison with those for a pulverized coal unit. A supercritical unit
would be expected to have a fixed O&M cost of $33.77/kW-yr with a variable O&M cost of
$O.99/MWh, while the IGCC would be expected to have a fixed O&M cost of $62.01/kW-
with a variable O&M cost of $0.27/MWh. Overall, this results in an O&M cost for IGCC of
about 1.5 times the expected cost of supercritical pulverized coal technology.
Based on the above results, the Total Resource Cost in 2005 dollars (as calculated for the IRP) to
produce power from a supercritical pulverized coal boiler is estimated at approximately
$39.35/MWh. By comparison, the Total Resource Cost of power for an IGCC plant, without
carbon capture provisions, is estimated at about $43.90/MWh (11.6 percent higher) and
$46.00/MWh (16.9 percent higher) if carbon-capture provisions (but not carbon separation or
sequestration) are included in the initial project.
The cost differential between the technologies is particularly important since the consistent
primary policy direction of the states in which PacifiCorp operates is to procure resources with
the lowest reasonable cost. For example, in the recently-passed Utah Energy Resource
Procurement Act, although the Utah Public Service Commission may take into consideration
factors such as long- and short-term impacts, risks, reliability, financial impacts on the utility, or
other factors determined relevant by the commission when deciding whether to approve a
resource
, "
lowest reasonable cost" is the first criterion listed.
Figure 3.1 illustrates the Total Resource Cost in 2012 dollars of different generation technologies
under different assumptions of potential future carbon-related costs. The graph illustrates that
a CO2 allowance cost of approximately $35 per ton is imposed, IGCC (with carbon capture and
sequestration) becomes "least cost" under an assumed cost for sequestration of $lO/MWh. It is
important to note that accurate cost estimates for CO2 sequestration do not exist and that the
$10/MWh figure reflects a carbon sequestration research program goal established by the
Department of Energy.
5 Carbon Sequestration Technology Roadmap and Project Plan 2005, U.S. Department of Energy, National Energy
Technology Laboratory, May 2005.
- 24-
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
Figure 3.1 - Real Levelized Cost for IGCC Technologies by CO2 Allowance Cost Level
IGCC Carbon Ready Comparison in 2012 $
Varying CO2 Emission Costs at 90% CF and $10/MWh Sequestration
$100
$40
$90
.r. $80
:ii
;;;
$70
'ii
...
iii $60
$50
$30
$ITon for CO,
-SCPC (no C Capture)PC (no C Capture)
-IGCC (no Capture C Ready)- . - SCPC (C Capture)
--IGCC (no C Capture)
. . - IGCC (C Capture)
The Parson study also developed emissions performance estimates for IGCC technology. The
study results and PacifiCorp s experience lead to the following estimates (Table 3.1) for IGCC
emissions performance as compared to subcritical and supercritical pulverized coal.
Table 3.1 - IGCC and Conventional Pulverized Coal Emissions Comparison
It is important to note that new conventional coal plants, required to be equipped with Best
Available Control Technology (BACT), also have very low emissions on a tons-per-year basis.
Therefore, the emissions performance of IGCC reflects improvement on an already substantially
reduced emissions profile as compared to emissions from a coal plant that is not equipped with
BACT controls. With the improved emissions performance of new conventional coal plants, the
potential for IGCC to offer more economic CO2 capture as compared to conventional coal plants
- 25 -
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
represents the most compelling environmental reason to employ the technology for power
generation.
PacifiCorp s next steps for IGCC analysis will include an update of the Parsons (now
WorleyParsons) study to investigate the cost of an IGCC plant using Powder River Basin (PRE)
and Jim Bridger coals. Current engineering understanding suggests that gasifier systems for
lower rank coals would most efficiently use a dry coal feed instead of the slurry feed systems of
GE and E-Gas. Additionally, PRB coals would most likely be used at plant sites at greater
elevation than the Hunter site and this effect should also be studied.
If the conceptual level studies indicate that IGCC merits further consideration, feasibility studies
would be necessary to further refine the estimated cost and performance characteristics of the
competing commercial offerings. Feasibility studies would be undertaken by the commercial
vendors and would take a minimum of between 4 to 6 months to complete. Each vendor
feasibility study would cost approximately $300 000 to $500 000. These studies would focus on
technology comparisons and indicative pricing in order to determine which commercial vendor
offers the most attractive technology and price for PacifiCorp s specific sites and coals.
Whereas detailed engineering design and construction cost estimates for conventional coal plants
can be obtained through studies that cost approximately $500 000 to $l million, a similar level of
detail for an IGCC plant currently requires a Front End Engineering Design (FEED) study to be
conducted. Due to the developmental nature of IGCC, such a study would currently cost between
$10-$15 million dollars and require 10 to 14 months to complete. The expected end result would
be a firm money EPC cost estimate suitable for contract execution. Due to its high cost, a FEED
study would only be undertaken after a decision to move ahead with a specific IGCC project was
reached.
EFFECTS OF ENERGY POLICY ACT INCENTIVES
The Energy Policy Act of 2005 contains Investment Tax Credit (ITC) provisions and loan
guarantees for qualifying IGCC facilities. Since PacifiCorp currently holds a relatively strong
credit rating, loan guarantees provide little incentive. The lTC, although only applicable to the
gasifier portion of the IGCC plant, therefore is the key economic subsidy available.
The exact impact of the investment tax credits is difficult to assess due to uncertainty regarding
the availability of the credits (other projects further along could exhaust the available pool of
$800 million of tax credits) and PacifiCorp s tax position. Oregon s passage of Senate Bill 408
creates additional uncertainty about how to incorporate these tax incentives into an evaluation.
However, as an example, if an IGCC project at the Hunter site could take full advantage of the
lTC, the estimated cost of energy for IGCC in 2012 could be reduced by approximately
$3.00/MWh-about half the currently estimated price differential between carbon capture-ready
IGCC and supercritical boilers.
IGCC STATE POLICY DEVELOPMENTS
Some power providers have announced their interest in developing IGCC facilities and have
begun preliminary activities towards that end. Companies with projects that have been publicly
- 26-
PacifiCorp 2004IRP Update Chapter IGCC Resource Update
announced with a reported substantial level of commitment include American Electric Power
(through its subsidiaries Ohio Power ahd Columbus Southern Power), Excelsior Energy,
Steelhead Energy, and Cinergy (through its subsidiary Public Service of Indiana) in partnership
with Vectren Corporation.
As detailed above, IGCC remains a higher-cost option than either subcritical or supercritical
pulverized coal generation. The cost gap is even greater for IGCC that is configured to
accommodate future CO2 separation processes and greater still when adding the estimated costs
of carbon separation and sequestration operations. This cost gap presents a challenge for the
technology that is difficult to overcome in a "least-cost/least-risk" planning framework-even
one that includes a methodology that assumes a future cost for CO2 emissions. The projects that
are advancing at this time appear to be doing so for reasons related to public policy support for
the technology that deviates from the least cost/risk-balanced requirement as currently applied in
PacifiCorp s planning process.
In the case of American Electric Power (AEP), which is considering a 600 MW IGCC plant, the
technology offers the state of Ohio the opportunity for local economic development through the
ability to use high-sulfur eastern coal. Through a probabilistic analysis, AEP made a case to its
regulators that IGCC may be least-cost compared to pulverized coal when considering a range of
possible carbon regulatory regimes. AEP is seeking assured cost recovery for the project and
accelerated cost recovery of engineering and financing costS.6 AEP has indicated that cost
recovery must be assured before it will proceed with construction. The Ohio PUC is expected to
rule on the application by the end of the year and AEP has initiated a FEED study with GE-
Bechtel.
The development of Excelsior Energy s Mesaba Energy Project, a 531 MW IGCC plant
scheduled to come online in 2011 , has been furthered by legislation (MS 216B.1693-1694)
passed in Minnesota in 2003 that provides significant support for the project. This support
includes tax incentives, streamlined development, and regulatory benefits that incorporate an
exemption from certificate-of-need proceedings and the right to a long-tenn power purchase
agreement from Xcel Energy. In addition, $10 million in renewable development funds have
been provided by the State and the project is receiving $36 million in Federal grant money
through the Department of Energy s Clean Coal Power Initiative.
Steelhead Energy s Southern Illinois Clean Energy Center is a combined 615 MW power and 86
MMSCFD synthetic natural gas plant scheduled to come on line 2010. The first phase of a two
part FEED study was launched in April 2005 and was completed in October. The development of
the project has been supported by $5 million in funding from the State of Illinois to perform the
first phase of the FEED study. Additionally, the project benefits from legislation passed in
Illinois this summer (SB 90) that sets a price for synthesis gas produced from a coal gasification
facility using Illinois coal and permits gas utilities to enter into 20-year supply contracts with any
synthesis gas producer. The legislation declares those synthesis gas contracts to be prudent and
recoverable subject to certain price constraints. Additional Illinois legislation (SB 1814) passed
6 Application and Direct Testimony of Bruce H. Braine on behalf of Columbus Southern Power Company and Ohio
Power Company before the Public Utilities Commission of Ohio, Case No. 05-376-EL-UNC, March 18 2005 and
May 5, 2005, respectively.
- 27-
PacifiCorp 2004IRP Update Chapter IGCC Resource Update
concurrently with SB 90 provides economic incentives, including tax exemptions and credits
and low-cost financing for innovative coal gasification projects.
Cinergy and Vectren Corporation have been working on Feasibility Studies for a 600 MW IGCC
plant in Southwestern Indiana. This project benefits from legislation passed in Indiana this year
(HB 1245) that establishes an investment tax credit for an IGCC facility that primarily serves
Indiana customers. In addition to providing needed power, the project is viewed as an economic
development opportunity that will encourage the use of Indiana coal. Cinergy recently
announced their intention to proceed with a FEED study with GE-Bechtel.
Other states are encouraging the development of IGCC through legislation that provides
incentives for the technology. West Virginia passed legislation (HB 2813) earlier this year that
allows power companies to file for PSC certificates of public convenience and necessity for new
plants concurrently with applications for other required permits and licenses. The legislation was
designed to speed up the regulatory process for approving new power plants in the hope of luring
AEP's proposed IGCC facility.
In each ofthese examples above the proposed IGCC project would use eastern bituminous coals.
Interest in eastern bituminous coal arises, in part, because Clean Air Act requirements since 1990
have encouraged the use of low-sulfur western coals even in eastern plants with a resulting
chilling effect on the coal extraction industry in the mid-west and east. The status of IGCC
development for eastern coals is also more advanced than applications for western coals and
substantial engineering and design work on the gasifier and coal feed must be completed for
IGCC applications on western coals. This potentially introduces additional technology risk. The
Energy Policy Act provision for a western coal facility demonstrates the less advanced state of
development for IGCC using western fuels. Additionally, for each of the projects referenced
above, there has been no final commitment to build a facility. This commitment typically is not
considered until after the completion of a FEED study.
CHALLENGES TO IGCe DEVELOPMENT
While IGCC has gained much attention, there are many issues that remain to be resolved before
a definitive cost, risk and technology comparison can be made to conventional coal-fired
generation. Additionally, the least-cost/least-risk regulatory framework presents challenges for
near-term development of the technology. A few of these issues and challenges to development
are listed below:
A very dynamic environment exists around IGCC and many claims about the
technology s cost and performance are being made that cannot be verified until FEED
studies are completed and the first reference plants are in operation. FEED studies
typically take 10-14 months. For example, AEP's FEED study will take 12 months, cost
millions of dollars, and will not be completed before late 2006.
. A number of consortia have publicly stated that they are prepared to provide performance
guarantees or "wraps" covering the entire IGCC generating island. However, at the
present time no final, signed contracts have been entered into for the construction of
IGCC plants, so the precise terms of those wraps are yet to be made available. Thus, it is
- 28-
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
difficult to assess the risk posed by this newer technology. The information presented
above includes an inherent assumption that such wraps are available and/or the
technology performs as advertised.
Because of the developing nature ofIGCC technology, considerable up-front engineering
must be performed through a FEED study to develop detailed cost and performance
estimates necessary to make a final decision to proceed and award an EPC or other
contract. As indicated, a FEED study necessary to develop an EPC price costs around
10-15 million dollars which, absent cost-recovery assurances, a utility may be unable to
justify without knowing if those costs are recoverable.
As discussed earlier, perhaps the most compelling environmental reason to pursue IGCC
is its potential to economically capture CO2. Within the current planning framework, the
following information is needed to determine ifIGCC is the clear choice as compared to
other generation resources:
valid and accurate cost estimates for future CO2 sequestration (which currently do
not exist), and
sufficient estimates of the probability, timing, and stringency of potential future
carbon constraints.
Without this information, it is difficult to assess the currently estimated additional costs
ofIGCC on a risk-adjusted basis to determine if the technology is least-cost/least-risk as
required by the current regulatory framework.
' '
Schemes for commercial-scale carbon sequestration are unproven, and a regulatory
framework has yet to be developed for certifying and indemnifying permanent
sequestration.
In order for IGCC technology to advance in the near term, cost recovery schemes must be
developed that will provide an assured future cash flow to pay for the required engineering
design studies and, ultimately, demonstration of the technology. This will reduce the risk that
must be shouldered by the utility compared to the risk borne when it chooses a proven
technology. Alternatively, there must be clear and consistent policy direction from states and
regulators that emerging technology such as IGCC, despite its higher cost and uncertainty about
its performance, is preferred over conventional coal generation technology due to its
environmental attributes and/or potential to economically capture CO2.
CONCLUSION
As indicated, announced IGCC projects appear to be advancing as a result of state policy
decisions that support IGCC technology even though it may not be least cost. These state policy
decisions are intended to advance state-specific energy and environmental goals as well as
economic developrnent interests. These incentives have been necessary because IGCC is more
expensive than conventional coal generation and remains unproven at the scale proposed for
these commercial power production applications. This presents technology risk, financing
difficulties, and other attendant risks within current regulatory frameworks. Significantly, for
PacifiCorp and its customers, additional technical challenges remain to be addressed for the
application ofIGCC using western coals.
- 29-
PacifiCorp 2004 IRP Update Chapter IGCC Resource Update
PacifiCorp recognizes the significant potential of IGCC to help mitigate fuel price risk and
reduce carbon risk while also offering reduced emissions of criteria pollutants. In light of this
PacifiCorp will continue its efforts to closely follow the technology development and available
commercial offerings. Additionally, PacifiCorp will initiate a preliminary engineering study
an IGCC facility located at the Jim Bridger site using PRB coal. This study will provide updated
information about the cost, performance, and viability of IGCC application at the Jim Bridger
site.
However, until IGCC technology is more fully developed and becomes more cost competitive, as
documented by a publicly available detailed FEED or actual commercial installation, the absence
of consistent state policy and cost recovery direction among PacifiCorp s states in favor of
emerging clean coal technology, such as IGCC, will likely retard its development. In the interim
the integrated resource planning process must follow currently established standards and
guidelines set forth by the states and, as a result, will continue to prefer a least-cost/least-risk
portfolio based on established commercial technologies. At present, based on information
currently available, PacifiCorp s planned portfolio incorporates conventional coal-fired
generation.
- 30-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
4. PORTFOLIO ANALYSIS
INTRODUCTION
The purpose of this chapter is to describe the resource portfolios developed to address the
updated system capacity positions outlined in the previous chapter, and present the deterministic
and stochastic simulation results for the new portfolios. The general analytic approach used for
the 2004 IRP Update consists of the following steps:
Update the IRP model database to reflect updated base assumptions and characteristics for
existing and IRP candidate resources.
Determine the impact of the updated Load & Resource Balance on the size and timing of
2004 IRP Preferred Portfolio resources.
Develop a set of alternative portfolios that better align with the updated L&R Balance and
thereby meet or exceed the associated 15% annual system-wide Planning Margin targets.
Conduct both deterministic and stochastic 20-year simulations for the original 2004 IRP
Preferred Portfolio and the alternative resource portfolios. The simulation study period was
from January 1 2006 through December 31 2025.
Derive Present Value of Revenue Requirements (PVRR) results for the simulations, and rank
the portfolios according to PVRR performance and stochastic risk metrics.
PORTFOLIO DESCRIPTIONS
This section describes the original 2004 Preferred Portfolio-highlighting changes to resource
assumptions and the impact of the new L&R Balance-and introduces four alternative portfolios
that address the new capacity position requirements. PacifiCorp considered alternative mixtures
of gas, coal, and Front Office purchase transactions that represented appropriate Action Plan
resource acquisition paths and reflected the latest information regarding resource opportunities.
The rationale for structuring the portfolios in this way was to define alternative resource
solutions in the event that the path to one portfolio does not materialize.
2004 IRP Preferred Portfolio
Table 4.1 shows the resource type, location, MW capacity, and timing of the 2004 IRP'
Preferred Portfolio proxy resources. Due to updated resource assumptions used for the portfolio
analysis, attributes of some of the proxy resources used in the original Preferred Portfolio were
modified. Nevertheless, the modified Preferred Portfolio will still be referred to as the "Preferred
Portfolio" in subsequent discussions. Table 4.1 reflects the relevant resource type and capacity
modifications for the 2004 IRP Preferred Portfolio (Resource characteristics for all candidate
IRP resources are reflected in Tables A.4 and A.5 of Appendix A.) The major modifications
associated with the Preferred Portfolio include the following:
Pulverized coal resources in the Preferred Portfolio and alternative portfolios model a
supercritical boiler design as opposed to a subcritical design specified for resources in the
7 No changes were made to the DSM proxy resources included in the Preferred Portfolio.
- 31 -
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
2004 IRP. The supercritical boiler design results in a slightly higher per-kilowatt capital cost
and slightly lower heat rate compared to the subcritical design.
Due to expected elevation of the west-side CCCT resource, PacifiCorp modified the
configuration of this resource to be similar to an east-side CCCT with a similar elevation.
The result was a capacity reduction from 586 MW reported in the 2004 IRP to 561 MW now
shown in Table 4.
The capacity of the east-side Dry Cool CCCT increased by 10 MW-from 525 to 535 MW.
This change reflects experience with the new Currant Creek plant.
The modified Preferred Portfolio will still be referred to as the "Preferred Portfolio.
Table 4.1 - Preferred Portfolio from the 2004 IRP
Cool CCCT wi DF
Greenfield Wet Cool CCCT wi DF
Brownfield Coal Su ercritical
Brownfield Coal, Su ercritical
DSM, Summer Load Control
DSM, Summer Load Control
Greenfield Wet Cool CCCT wi DF
DSM, Summer Load Control
DSM. Summer Load Control
575
383
561
As mentioned in the previous chapter, PacifiCorp analyzed the impact of the updated Load &
Resource Balance on the need and timing of Preferred Portfolio resources. Table 4.2 shows the
updated annual system-wide total resources, obligations, and resulting Planning Margins
associated with the Preferred Portfolio.
Table 4.2 - Impact of New Load & Resource Balance on 2004 Preferred Portfolio Planning
Margin
New Obli ation
17%
ca"'3'S '"""1MW"
New Total Resources
Existin + Planned + IRP Prox
Beginning in 2009, the system has a 24% Planning Margin; this represents an additional 880
MWs over the amount needed to meet the 15% Planning Margin target. Consequently, a
common element for developing alternative portfolios was to defer or eliminate the 2009 east-
side 535 MW CCCT. Resource combinations that enable a further capacity reduction in 2011
was another common portfolio development element, given that removing the 2009 east-side
CCCT resource still resulted in a 19% Planning Margin by 20 II.
- 32-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Portfolio 1: Deferral and Removal of Preferred Portfolio Resources
Using the Preferred Portfolio as the starting point, PacifiCorp deferred or removed proxy
resources to address the excess planned capacity situation for the 2009-11 timeframe. Table 4.
shows the resulting modifications Preferred Portfolio resources in order to meet the 15%
planning margin. (To assist in identifying changes relative to the Preferred Portfolio, Table 4.
and subsequent portfolio resource tables include arrows indicating resource deferrals and shaded
cells signifying resources that are new or have been removed or resized.
Portfolio 1 embodies the following changes:
Deferring of the 2009 east-side 535 MW CCCT resource from 2009 to 2011.
Deferring of the 575 MW brownfield pulverized coal resource from 2011 to 2013.
Removing the 2013 east-side 561 MW CCCT resource.
The net impact of these changes to the Preferred Portfolio was to reduce the average annual
Planning Margin from 21.5% to 16.4% for the 2009 - 2015 period, and reduce the total
cumulative portfolio MWs by 16.5% (2 792 to 2 331 MW).
Table 4.3 - Portfolio 1 Resources
575 575
383 383
561 561
231
Portfolio 2: Path-C UP1!rade and Increased Share ofWvomin2 Coal Plant
The main purpose of this portfolio was to evaluate the impact of Mid-American Energy Holdings
Company s (MEHC) commitment to upgrade Path-Co The proposed expansion in the MEHC
transaction entails a 300 MW upgrade to increase Path-C transfer capability from southeastern
Idaho to northern Utah by 2010. In combination with an assumed additional purchase of
transmission service on Idaho Power s system (Bridger to southeastern Idaho), this upgrade
among other things, is intended to enhance system flexibility by enabling more Bridger
generation to be utilized in the East.
This portfolio has two resource changes. First, the portfolio includes an increase in PacifiCorp
share of the 2014 Wyoming coal plant-from 383 to 500 MW. The reasons for increasing the
coal plant share as a portfolio resource option include:
Optimizing transmission upgrades for delivering power from southeast Idaho to Utah'
Wasatch Front by increasing Bridger output.
- 33 -
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Accommodating Idaho Power s interest (as reported in their most recent IRP) in expanding
its coal resources in 250 MW increments.
Using the advantage of scale economies in building a larger coal plant.
Second, the portfolio includes the phase-in of a 300 MW west-side seasonal resource (100 MW
increments in 2011 , 2013 , and 2014). The seasonal resource, modeled as a must-run product
priced at California-Oregon Border (COB) market prices, is intended to compensate for
increased west-to-east transfers resulting from the Path-C transmission upgrade, thus avoiding a
capacity-short situation in the west beginning in 2011.
These resource additions enable removal of both east-side CCCT resources as well as the
deferral of the Utah coal resource (modeled as a Hunter 4 brownfield unit) from 2011 to 2012.
Total cumulative portfolio capacity is 2 113 MW, and results in an average annual Planning
Margin of 15.3% for the 2009 - 2015 period. Table 404 shows the size and installation timing
the Portfolio 2 resources.
Table 4.4 - Portfolio 2 Resources
500
561
100 100 100
575
500
561
300
113
Portfolio 3: Portfolio 2 with a Share of the Utah Coal Plant
Portfolio 3 represents an incremental modification to Portfolio 2 in order to evaluate the impact
of PacifiCorp acquiring a partial share of an east-side 2012 pulverized coal resource. The Utah
coal resource was reduced from 575 to 340 MW. To offset the reduced capacity, three 87 MW
IC Intercooled aero-derivative Single-Cycle Combustion Turbine (IC Aero SCCT) units were
added in 2013. These changes result in a total cumulative portfolio capacity of 2 139 MW by
2015 and an average annual Planning Margin of 15.1% for the 2009 - 2015 period. Table 4.
shows the sizes and installation timing of the Portfolio 3 resources.
- 34-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Table 4.5 - Portfolio 3 Resources
261 261
340
500 500
561 561
100 100 100 300
139
Portfolio 4: Portfolio 3 with Path-C Upe:rade Removed
The purpose of Portfolio 4 is to evaluate the impact of the Path-C upgrade using the coal
resource shares allocations assumed for Portfolio 3. The resource changes relative to Portfolio 3
include the following:
Removing the 300 MW Path-C upgrade.
Removing the 300 MW phased-in west-side seasonal resource.
Decreasing the east-side IC Aero SCCT capacity from 261 MW to 174 MWs, and moving
the installation forward three years from 2013 to 2010.
Adding back the east-side 561 MW CCCT in 2013 that was originally in the 2004 IRP
Preferred Portfolio.
The net impact of these changes is to increase the cumulative portfolio capacity for Portfolio 4
by 174 MW relative to Portfolio 3 (2 139 to 2 313 MW). The average annual Planning Margin
for the 2009 - 2015 period is 16.3%. Table 4.6 shows the sizes and installation timing of the
Portfolio 4 resources.
Table 4.6 - Portfolio 4 Resources
500
561
174
340
500
561
313
174
561
- 35-
PacifiCorp -20041RP Update Chapter 4 - Portfolio Analysis
PORTFOLIO EVALUATION RESULTS
Deterministic Simulations
Table 4.7 shows the breakdown of each portfolio s PVRR by variable and fixed cost
components, as well as the relative portfolio rankings for total net variable, levelized fixed cost
components, and total PVRR.8 Figure 4.1 shows portfolio PVRRs in bar chart form. Cost and
resource utilization performance observations for each of the portfolios follow. The section
entitled "Portfolio Scorecard Results" in Appendix B presents PVRR and capital costs, as well as
additional portfolio performance information for 2015 , such as market sales and purchases
capacity factors by unit type, and control area transfers.
Table 4.7 - PVRR Cost Components and Rankings by Portfolio
Variable Cost
Total Fuel Cost 567 957 12,261 365 796,099 12,098 987 12,545,325
Total Variable O&M Cost 004 235 901 536 784 687 851,773 942,728
Total Emissions Cost 152 946 107 797 100,549 743 110,573
Total Start-u Cost 23,687 23,770 222 011 22,957
L T Contracts and FOTs 320,437 4,407 537 619,770 624 829 4,406,324
S ot Market Balancin
Sales 021,423
Purchases 261,452
Total Net Variable Cost 959 721 157 750 007 035 14,315,932 267 936
Rank
Real Levelized Fixed Cost 524 125 008 383 997,415 826,196 060 397
Rank
Total PVRR 16,483,846 166,133 004,450 16,142 128 16,328,333
Rank
8 PVRR captures the discounted, levelized sum of annual nominal-dollar revenues required for system operations
and the capital costs for new IRP proxy resources.
- 36-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Figure 4.1- Portfolio Rankings Based on Deterministic PVRR
16.
16.
16.40
S 16.
16.
e. 16.
0::
~ 16.
D.. 15.
15.
15.
Preferred
Portfolio
Portfolio 1 Portfolio 2 Portfolio 3 Portfolio 4
Preferred Portfolio Evaluation
The PVRR for the Preferred Portfolio analysis is $16.48 billion, which is about 25% higher than
the PVRR of$13.15 billion for the original 2004 IRP Preferred Portfolio analysis. The difference
is due mainly to higher forecasted fuel prices; the commodity gas price is higher by about 43%
on an average annual basis relative to the forecast used in the 2004 IRP. Coal and forward
electricity prices also are higher.
In addition to the overall PVRR increase for the Preferred Portfolio, there are two other
significant differences between the cost results for the two Preferred Portfolio analyses. First
spot market sales are significantly higher under the updated Preferred Portfolio-by about 70%
or $2.55 billion-attributable to the excess economic capacity available for serving the spot
market. Second, the emission cost experiences a swing of $593 million, from a credit of $440
million under the original Preferred Portfolio to a cost of $153 million under the updated version.
This swing stems from the assumption change for coal plant retirements. The coal plant life
extensions assumed for this IRP Update results in several years of net positive CO2 emission
costs beginning in 2022 as opposed to net negative costs (credits) caused by coal plant
retirements assumed for the original Preferred Portfolio.
Portfolio 1 Evaluation
Portfolio I consists of deferrals of the Preferred Portfolio s first east-side coal and gas resources
by two years, along with rernoval of the second gas resource. As expected, the changes reduce
the PVRR-the overall impact is a 1.9% drop from $16.484 billion to $16.166 billion. Table 4.
presents a side-by-side comparison ofPVRR results for Portfolio I and the Preferred Portfolio
indicating absolute and percentage differences for each of the cost categories.
The greatest impact on PVRR is the fixed cost savings tied to the two-year deferral of the coal
and gas resources. This cost savings-$516 million-more than offsets a relative increase in
- 37-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
total variable costs, which is itself driven largely by higher spot market purchase costs and a
decrease in spot market sales revenues.
The gas plant removal and resource deferrals under Portfolio 1 improve utilization of
PacifiCorp s existing gas-fired resources relative to the updated Preferred Portfolio. The average
annual capacity factor for the CCCT units, consisting of Currant Creek, Lake Side, and
Henniston I and 2, increases from 78.2% to 79.5%. The average annual capacity factor for
PacifiCorp s SCCT units increases from 5.4% to 7.6%.
Table 4.8 - PVRR Cost Components and Rankings: Portfolio 1 vs. 2004 IRP Preferred
Portfolio
Variable Cost
Total Fuel Cost
Total Variable O&M Cost
Total Emissions Cost
Total Start-u Cost
L T Contracts and FOTs
S at Market Balancin
Sales
Purchases
Total Net Variable Cost
261 365
901 536
107 797
770
4,407 537
567 957
004 235
152 946
23,687
320,437
Total PVRR
Real Levelized Fixed Cost 008 383 524 125
166 133 16,483,846
306 592 2.4
102 700
148 29.
0.4
100
315 362
249 924 23.
198 029 1.4
(515,742)(20.4)
(317 713)(1.
Portfolio 2 Evaluation
Portfolio 2 includes resources designed to complement the MERC Path-C transmission upgrade
commitment. This portfolio results in a PVRR improvement of $479.4 million relative to the
Preferred Portfolio, and an improvement of $161.68 million compared to Portfolio 1. Portfolio 2
ranks second among all portfolios for both total net variable cost and real levelized fixed cost
and is lowest-cost on a total PVRR basis. Table 4.9 presents a side-by-side comparison of PVRR
results for Portfolios 2 and 1 , indicating absolute and percentage differences by cost category.
- 38 -
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Table 4.9 - PVRR Cost Components and Rankings: Portfolio 2 vs. Portfolio 1
Variable Cost
Total Fuel Cost
Total Variable O&M Cost
Total Emissions Cost
Total Start-u Cost
L T Contracts and FOTs
S ot Market Balancin
Sales
Purchases
Total Net Variable Cost
997,415
261 365 465,266
901 536 116,849
107 797 248
770 452
4,407 537 212 232
875 778 88,049
331 523 137 914
157 750 (150,715)
008 383 (10,968
166 133 (161 683)
796 099
784 687
100,549
222
619 770
Real Levelized Fixed Cost
Total PVRR 16,004,450 (1.
The elimination of the two eCCT resources from the portfolio reduces fuel costs appreciably.
The relative fuel cost reduction of $465.27 million (from $12.26 billion to $11.80 billion) is the
main driver for this portfolio s superior PVRR performance. Partially offsetting the relative gains
from production cost savings is greater utilization of both long term contracts and Front Office
Transactions. For Portfolio 2, generation attributable to long-term contracts is higher than that
for Portfolio 1 by 6.2%; for FOTs, the generation is 3.5% higher. The net increase in the "L T
Contracts and FOTs" cost category is $212.23 million, largely reflecting the expenditures tied to
the phased-in 300 MW west-side seasonal resource. Less spot market sales and greater purchases
combine to contribute $226 million in additional costs.
Portfolio 2's smaller amount of IRP proxy resource capacity compared to that of Portfolio
113 MW for Portfolio 2 versus 2 231 MW for Portfolio 1) results in an overall increase in
thermal resource utilization relative to that of Portfolio 1. The average annual capacity factor for
all thermal resources is higher by about 2 percentage points.
Portfolio 3 Evaluation
Portfolio 3 represents a variant of Portfolio 2: reducing the share of the 575 MW Utah coal
resource and making up the difference with gas-fired IC Aero SeCTs. This change in resources
yields a large increase in fuel costs of $302.89 million relative to the amount accrued under
Portfolio 2, and results in Portfolio 3 having the highest net variable cost of all the portfolios.
However, Portfolio 3 also has the lowest levelized fixed cost of all the portfolios at $1.826
billion, driven by the lower capital cost of the IC Aero SeeTs relative to that of the Utah coal
resource that it partially replaces. The net result is that Portfolio 3 has a higher PVRR than that
for Portfolio 2 (by $137.68 million, or 0.9%), and ranks second ahead of Portfolios I and 4 on an
overall total PVRR basis. Table 4.10 presents a side-by-side comparison of PVRR results for
Portfolios 3 and 2, indicating absolute and percentage differences by cost category.
- 39-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Table 4.10 - PVRR Cost Components and Rankings: Portfolio 3 vs. Portfolio 2
Variable Cost
Total Fuel Cost 098,987 796,099
Total Variable O&M Cost 851,773 784 687
Total Emissions Cost 743 100,549
Total Start-u Cost 011 222
L T Contracts and FOTs 624 829 619 770
S at Market Balancin
Sales
Purchases
Total Net Variable Cost
Real Levelized Fixed Cost 826,196 997,415 (171,219 (8.
Total PVRR 142 128 004,450 137 678
The increase in Portfolio 3's fuel cost relative to that of Portfolio 2 parallels higher relative
utilization of gas resources; the average annual capacity factor for all gas resources is 1.
percentage points higher for Portfolio 3. (Recall that 261 MWs of IC Aero SCCT capacity is
displacing coal-based capacity.
Portfolio 4 Evaluation
Portfolio 4 represents a variant of Portfolio 3 in which the Path-C transmission upgrade is
removed, and the associated 300 MW west-side seasonal resource is replaced with both CCCT
and IC Aero SCCT capacity. The PVRR results indicate that the Path-C-related generation and
transmission resources of Portfolio 3 produce a net benefit of $186.21 million relative to the gas
resource mix and associated transmission employed for Portfolio 4. Table 4.11 presents a side-
by-side comparison of PVRR results for Portfolios 4 and 3, indicating absolute and percentage
differences by cost category.
As shown in Table 4., the replacement of the west-side seasonal resource with the gas plants
increases fuel costs by $446.34 million, and increases variable O&M and emission costs as well.
However, a decrease in contract-related variable costs and spot market purchase costs, combined
with an increase in spot market sales revenues, results in a net $48 million reduction in total net
variable costs. The driving factor for Portfolio 4's higher overall PVRR is the levelized fixed
cost, which is $234.2 million greater than that for Portfolio 3, mainly a result of adding back the
561 MW east-side CCCT. Portfolio 3 ranks fourth among the five portfolios for both net variable
costs and reallevelized fixed costs.
Regarding comparative resource utilization with respect to Portfolio 3 , Portfolio 4 has a slightly
lower average annual capacity factor for both existing SCCT and CCCT resources. The capacity
factors for existing coal plants are nearly identical.
40 -
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Table 4.11 - PVRR Cost Components and Rankings: Portfolio 4 vs. Portfolio 3
Variable Cost
Total Fuel Cost
Total Variable O&M Cost
Total Emissions Cost
Total Start-u Cost
L T Contracts and FOTs
S ot Market Balancin
Sales
Purchases
Total Net Variable Cost
545 325
942 728
110 573
957
4,406,324
098 987
851 773
77,743
011
624 829
Real Levelized Fixed Cost 060 397 826,196 234 201 12.
Total PVRR 16,328,333 142 128 186 205
Deterministic Evaluation Conclusions
The deterministic PVRR results indicate that Portfolio 2 performed the best among the five
portfolios. Although Portfolio 2 did not have the lowest net variable or fixed cost components
the combination of the two resulted in the lowest overall PVRR. It achieved this performance
despite having the least exposure to spot markets. Spot market balancing revenues came in at
$4.32 billion, compared to $5.1 billion for the Preferred Portfolio--the highest amount among
the portfolios-and $4.36 billion for Portfolio 3.
Consistent with the findings from the 2004 IRP portfolio analysis, the PVRR range for IRP
portfolios is narrow. The difference between the highest total PVRR (Preferred Portfolio) and
lowest total PVRR (Portfolio 2) is $479.4 million, or 3%. The standard deviation for the five
PVRRs is $184.83 million.
Stochastic Simulation Results
PacifiCorp performed stochastic simulations on each of the five portfolios, running 100 model
iterations for each. The methodology used was the same as that employed for the 2004 IRP;
however, certain stochastic parameters were updated for gas and electricity prices to reflect the
6/30/05 forward price projections (See the section entitled "Stochastic Parameters" in Appendix
A for details). This section presents the results for stochastic portfolio performance, focusing on
key cost and risk measures for portfolio screening.
Table 4.12 shows for each portfolio the stochastic performance results, which include the
following cost and risk metrics:
Stochastic average PVRR. Defined as the sum of the stochastic average variable cost (for
100 iterations) plus the deterministic fixed cost, this measure represents the expected
value of total PVRR based on stochastic operating cost inputs.
- 41 -
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Fifth and ninety-fifth percentile PVRRs. The PVRR values corresponding to the iteration
out ofthe 100 that represents the fifth and ninety-fifth percentiles, respectively. These
metrics represent snapshot indicators of low-risk and high-risk stochastic outcomes.
Upper-tail average stochastic PVRR.This metric is the mean of the five highest-PVRR
iterations, and represents a measure of high-end volatility risk exposure. It is a form of
Conditional Value at Risk (CVaR).
Difference between the upper-tail average stochastic PVRR and the stochastic average
PVRR. This metric is another measure of high-end volatility risk exposure. It represents
the maximum expected loss (additional portfolio cost) up to the level defined by the
upper-tail average stochastic cost.
Average Energy Not Served (ENS). This metric is the average number of GWh unserved
for the 100 stochastic simulation iterations. ENS is the amount of load that is not met by
system resources or purchases. It represents a measure of supply resource-related system
reliability .
Table 4.12 - Stochastic PVRR Performance Metrics by Portfolio
Preferred Portfolio 15,288 12 237 17 778 18,427Portfolio 1 14 946 11,987 17 549 18,093Portfolio 2 14 703 11,742 17,290 17,724Portfolio 3 14 874 11 866 17,485 17,975Portfolio 4 15,058 12,023 17 682 18,184
1 Calculated as the sum of the stochastic average variable cost plus the deterministic fixed cost
2 Mean of the five highest-PVRR iterations (stochastic variable cost plus deterministic fixed cost)
139
146
021
101
126
132
182
178
173
174
Portfolio performs the best on all stochastic cost and risk measures except average ENS, due
to this portfolio having the lowest amount of IRP proxy gas-fired resource capacity at 561 MW.
The PrefeITed Portfolio has the lowest average ENS at 132 GWh, corresponding to the highest
planning margin among the portfolios at 21.8% for 2009 through 2015. The ENS for the other
four portfolios averages 177 GWh with a range of nine GWh. Portfolio 2 ranks third out of the
five portfolios with an average ENS of 178 GWh.
Figure 4.2 shows portfolio bar chart rankings on the basis of the "upper-tail minus average" risk
exposure metric, which is viewed by PacifiCorp as the principal portfolio risk screening metric
for this IRP Update.
- 42-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
Figure 4.2 - Portfolio Comparison of High-End Risk Exposure
~ ~ 3.
Q) CC) 0
cu ,-;:= 3.
:::. a:I
c:( ~ ~ 3.
... :::::.
c..0 ~ 3.
Q) ...
Q) Q)~ ~ 3.Q) a:I '
::)
,- 2.
Preferred
Portfolio
Portfolio 1 Portfolio 4Portfolio 2 Portfolio 3
Since one of the IRP portfolio evaluation objectives is to weigh portfolio cost against risk, Figure
3 is used to illustrate this tradeoff by showing how each portfolio perfonns relative to the
others given its combination of stochastic average PVRR and "upper-tail minus average" risk
exposure. On the graph, points which are further to the left signify a lower overall cost, while
points closer to the bottom of the graph signify lower cost risk. Portfolio 2 lies closest to the
origin, indicating that it is the least-cost/least-risk portfolio on the basis of these combined
stochastic screening metrics.
Figure 4.3 - Stochastic "Cost vs. Risk Trade-Off'
f! It:Q) It:
:::. :::-
c( Q.
f! C)Q) f!
:::. Q) ~ 3.
:::.
c c( cQ) _.2 3.
Q) .-
~ ~ ~ 3.ID ~
Q) Q.
:;:)
Q) 't:J
... C
III
Portfolio 1 Preferred Portfolio
.....
)f( Portfolio 4
Portfolio 3
Portfolio 2
...
14.14.15.15.15.15.15.4014.14.
Stochastic Average PVRR (Billion $)
- 43-
PacifiCorp 2004 IRP Update Chapter 4 - Portfolio Analysis
To confinn whether these cost/risk tradeoff results are statistically valid, paired-difference
statistical tests were perfonned on the stochastic average PVRR and the upper-tail/overall
average PVRR difference. For the stochastic average PVRR, the t-statistics for the paired
differences indicate that all portfolios have statistically different values.
For the upper-tail/overall average PVRR difference, the paired-difference tests were also
conducted. The test results indicate that most of the differences are not statistically significant.
The statistically significant differences were between portfolios I and 2 and portfolios 2 and 4.
The other pairings with portfolio 2 were close, but not significant at the 5% confidence level.
CONCLUSIONS
Portfolio 2 has been deemed as having the lowest combination of overall cost and risk based on
the PVRR and risk screening metrics selected for this portfolio analysis. As discussed above, the
detenninistic PVRRs of the portfolios are all relatively close-within a range of 3%.
Consequently, the IRP proxy resources used in the other alternative portfolios still remain viable
portfolio resource options if needed.
9 The t-statistic detenTIines to what degree two means are statistically different. The smallest t-statistic value, 5.
was for the Portfolio l/Portfolio 3 pair. The difference in the stochastic average PVRRs for these two portfolios is
statistically significant with a confidence level greater than 99.9%.
- 44-
PacifiCorp 2004 IRP Update Chapter 5 - Action Plan Update
5. ACTION PLAN UPDATE
This chapter identifies changes to the Action Plan that are warranted by the new infonnation
provided in this IRP Update, and provides a status or update on both the new and original Action
Items.
SUMMARY OF UPDATED PORTFOLIO
The results of the portfolio analysis (Chapter 4) confinn that modifications to the Preferred
Portfolio are necessary to align resource decisions with changes in the latest resource forecast.
PacifiCorp considered alternative mixtures of gas, coal, and Front Office purchase transactions
that represented suitable Action Plan resource acquisition paths and reflected the latest
infonnation regarding resource opportunities. Although the results of the updated portfolio
analysis revealed that the difference in the results were very close, PacifiCorp will update the
Action Plan using the portfolio that was both least cost and least risk - Portfolio 2. For purposes
of this summary, Portfolio 2 will be called the 2004 IRP Update Preferred Portfolio.
Table 5.1 is a summary of the total MW, timing and proxy cost associated with specific
resources contained in the 2004 IRP Update Preferred Portfolio.
Table 5.1 - Summary of 2004 IRP Update Preferred Portfolio
East
West
Class 1 DSM - Summer Load Control
Class 1 DSM - Summer Load Control
2008
2008
East Path-C Upgrade 300 2010
West Seasonal Resource 100 2011Utah Brownfield Coal Plant 575 2012
WMAIN CCCT 561 2012East Class 1 DSM - Summer Load Control 44 2013
West Class 1 DSM - Summer Load Control 45 2013West Seasonal Resource 100 2013
West Seasonal Resource 100 2014
Wyoming Brownfield Coal Plant 500 2014
* All resources are planned to be commercially operable by the summer of the installation year.
** "
Capital Cost" refers to the capital cost that was used as a proxy for resource cost during the planning process. Actual costs
may vary. Transmission capital costs associated with specific proxy resources, as well as fixed program costs for DSM, are not
included.
997
378
976
ACTION PLAN UPDATE
This section provides an overview of the updated IRP Action Plan, presented as Table 5.
Changes to the original plan have been highlighted. The "Status" column summarizes specific
progress or infonnation updates to each action.
45 -
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ch
a
p
t
e
r
5
-
Ac
t
i
o
n
P
l
a
n
U
p
d
a
t
e
Ta
b
l
e
5
.
2
-
U
p
d
a
t
e
d
A
c
t
i
o
n
P
l
a
n
Co
n
t
i
n
u
e
t
o
a
g
g
r
e
s
s
i
v
e
l
y
p
u
r
s
u
e
c
o
s
t
-
e
f
f
e
c
t
i
v
e
Ex
e
c
u
t
e
d
6
5
M
W
W
o
l
v
e
r
i
n
e
C
r
e
e
k
P
r
o
j
e
c
t
o
n
l
i
n
e
b
e
f
o
r
e
2
0
0
6
,
Su
p
p
l
y
-
Si
d
e
IR
e
n
e
w
a
b
l
e
s
I
F
Y
2
0
0
6
-
2
0
1
5
I
1
,
40
0
I
Sy
s
t
e
m
I
W
i
n
d
Ir
e
n
e
w
a
b
l
e
r
e
s
o
u
r
c
e
s
t
h
r
o
u
g
h
c
u
r
r
e
n
t
a
n
d
f
u
t
u
r
e
Cu
r
r
e
n
t
l
y
p
u
r
s
u
i
n
g
2
0
0
6
i
2
0
0
7
I
R
P
t
a
r
g
e
t
f
o
r
R
e
n
e
w
a
b
l
e
RF
P
(
s
)
,
re
s
o
u
r
c
e
s
o
f
4
0
0
M
W
(
2
0
0
M
W
e
a
c
h
y
e
a
r
)
,
Us
e
d
e
c
r
e
m
e
n
t
v
a
l
u
e
s
t
o
a
s
s
e
s
s
c
o
s
t
-
e
f
f
e
c
t
i
v
e
b
i
d
s
i
n
10
0
M
W
DS
M
R
F
P
(
s
)
,
A
c
q
u
i
r
e
t
h
e
b
a
s
e
D
S
M
(
P
a
c
i
f
i
C
o
r
p
a
n
d
pa
c
i
f
i
c
o
r
p
i
s
s
u
e
d
a
c
o
m
p
r
e
h
e
n
s
i
v
e
2
0
0
5
D
S
M
R
F
P
o
n
DS
M
IC
l
a
s
s
2
!F
Y
2
0
0
6
-
2
0
1
5
I
4
5
0
M
W
a
Sy
s
t
e
m
ID
e
c
r
e
m
e
n
t
s
a
t
ET
a
c
o
m
b
i
n
e
d
)
o
f
2
5
0
M
W
a
a
n
d
u
p
t
o
a
n
a
d
d
i
t
i
o
n
a
l
S
e
p
t
e
m
b
e
r
1
20
0
5
,
T
h
i
s
R
F
P
c
o
n
t
a
i
n
s
1
9
d
i
f
f
e
r
e
n
t
t
y
p
e
s
o
f
va
r
i
o
u
s
l
o
a
d
s
h
a
p
e
s
2
0
0
M
W
a
i
f
c
o
s
t
-
ef
f
e
c
t
i
v
e
p
r
o
g
r
a
m
s
c
a
n
b
e
f
o
u
n
d
DS
M
p
r
o
g
r
a
m
s
t
h
a
t
b
i
d
d
e
r
s
c
a
n
c
h
o
o
s
e
t
o
b
i
d
o
n
,
th
r
o
u
g
h
t
h
e
R
F
P
p
r
o
c
e
s
s
,
Dis
t
r
i
b
u
t
e
d
FY
2
0
1
0
(
s
u
m
m
e
r
o
f
C
Y
2
0
0
9
)
a
n
d
~o
4
5
M
W
u
n
i
t
s
In
c
l
u
d
e
C
H
P
a
s
e
l
i
g
i
b
l
e
r
e
s
o
u
r
c
e
s
i
n
s
u
p
p
l
y
-
s
i
d
e
Co
n
t
i
n
u
e
t
o
p
u
r
c
h
a
s
e
C
H
P
o
u
t
p
u
t
p
u
r
s
u
a
n
t
t
o
P
U
R
P
A
Ge
n
e
r
a
t
i
o
n
C
H
P
FY
2
0
1
~
3
(
C
Y
2
0
I
U
)
ni
a
Sy
s
t
e
m
us
i
n
g
N
R
E
L
c
o
s
t
RF
P
s
,
re
g
u
l
a
t
I
o
n
s
,
W
o
r
k
w
I
t
h
I
E
t
o
d
e
t
e
"
"
l
n
e
h
o
w
C
H
P
g
e
n
e
r
a
t
o
r
s
c
a
n
es
t
I
m
a
t
e
s
be
a
c
c
o
m
m
o
d
a
t
e
d
l
n
a
s
u
p
p
l
y
S
I
d
e
R
F
P
,
In
c
l
u
d
e
a
p
r
o
v
i
s
i
o
n
f
o
r
S
t
a
n
d
b
y
G
e
n
e
r
a
t
o
r
s
i
n
s
u
p
p
l
y
-
Dl
S
t
n
b
u
t
e
d
St
a
n
d
b
y
FY
2
0
1
0
(
S
U
m
m
er
O
f
C
Y
2
0
0
9
)
a
n
d
\7
5
M
W
Wo
r
k
w
l
t
h
l
E
t
o
d
e
t
e
"
"
l
n
e
h
o
w
C
H
P
g
e
n
e
r
a
t
o
r
s
c
a
n
b
e
ta
In
t
a
SI
e
s.
n
v
e
s
l
t
g
a
t
e
w
i
t
IT
u
a
I
t
y
Ic
l
a
s
,
t
e
Ge
n
e
r
a
t
I
O
n
Ge
n
e
r
a
t
o
r
s
F
Y
20
1
~
3
(
C
Y
2
0
1
U
)
ac
c
o
m
m
o
d
a
t
e
d
I
n
a
s
u
p
p
l
y
S
I
d
e
R
F
P
.
vi
a
I
I
t
y
0
t
I
S
re
s
o
u
r
c
e
o
p
t
I
O
n
.
Pa
c
i
f
i
C
o
r
p
p
r
o
c
u
r
e
d
3
0
M
W
a
s
p
a
r
t
o
f
a
c
o
m
m
e
r
c
i
a
l
l
i
g
h
t
i
n
g
,
'
co
n
t
r
o
l
p
r
o
g
r
a
m
(
L
o
a
d
L
i
g
h
t
e
n
e
r
)
,
P
a
c
i
f
i
C
o
r
p
i
s
s
u
e
d
a
DS
M
IC
l
a
s
s
I
IF
Y
2
0
0
9
(
s
u
m
m
e
r
o
f
C
Y
2
0
0
8
)
50
Ut
a
h
I
~
m
g
a
t
l
~n
L
o
a
d
~u
r
:
~
o
s
~e
f
f
e
C
t
l
v
e
s
u
~;;
;
~
~
l
o
a
d
c
o
n
t
r
o
l
p
r
o
g
r
a
m
co
m
p
r
e
h
e
n
s
i
v
e
2
0
0
5
D
S
M
R
F
P
o
n
S
e
p
t
e
m
b
e
r
1
,
20
0
5
,
T
h
i
s
on
t
r
o
In
t
a
y
t
e
s
u
m
m
e
r
0
RF
P
c
o
n
t
a
i
n
s
1
9
d
i
f
f
e
r
e
n
t
t
y
p
e
s
o
f
D
S
M
p
r
o
g
r
a
m
s
t
h
a
t
b
i
d
d
e
r
s
ca
n
c
h
o
o
s
e
t
o
d
e
v
e
l
o
p
,
I'
'
L
d
pr
o
c
u
r
e
c
o
s
t
-
e
f
f
e
c
t
i
v
e
s
u
m
m
e
r
l
o
a
d
c
o
n
t
r
o
l
p
r
o
g
r
a
m
Pa
c
i
f
i
C
o
r
p
i
s
s
u
e
d
a
c
o
m
p
r
e
h
e
n
s
i
v
e
2
0
0
5
D
S
M
R
F
P
o
n
ID
S
M
IC
l
a
s
s
I
!F
Y
2
0
0
9
(
s
u
m
m
e
r
o
f
C
Y
2
0
0
8
)
50
OR
i
W
A
I
C
A
:~
~
~
~
n
o
a
in
O
r
e
g
o
n
,
W
a
s
h
i
n
g
t
o
n
,
a
n
d
l
o
r
C
a
l
i
f
o
r
n
i
a
b
y
t
h
e
Se
p
t
e
m
b
e
r
I
,
2
0
0
5
,
~i
s
R
F
P
co
n
t
a
i
n
s
1
9
d
i
f
f
e
r
e
n
t
t
y
p
e
s
o
f
su
m
m
e
r
o
f
2
0
0
8
,
DS
M
p
r
o
g
r
a
m
s
t
h
a
t
b
I
d
d
e
r
s
c
a
n
c
h
o
o
s
e
t
o
d
e
v
e
l
o
l
"
I~
:~
:
:
'
~~
~
:
'
~F
Y
2Q
I
Q
(,
u
m
m
e
r
a
f
C
Y
2Q
Q
9
)
IJ
I
o
I
t
GG
b
'
I
'
I:
:
:
:
:
:
;
:
e
::
~
~
~
:
,
~
,
.
i
n
a
r
~e
l
i
.
.
.
~
\
a
ah
Re
m
o
v
e
d
,
Tr
a
n
s
m
i
s
s
i
o
n
s
e
r
v
i
c
e
r
e
q
u
e
s
t
s
h
a
v
e
b
e
e
n
i
n
i
t
i
a
t
e
d
t
o
d
e
t
e
"
"
i
n
e
th
e
c
o
s
t
a
n
d
f
e
a
s
i
b
i
l
i
t
y
o
f
u
p
g
r
a
d
e
.
P
a
c
i
f
i
C
o
r
p
j
o
i
n
e
d
o
t
h
e
r
en
t
i
r
i
e
s
t
o
f
o
"
"
t
h
e
S
S
G
-
WI
r
e
g
i
o
n
a
l
t
r
a
n
s
m
i
s
s
i
o
n
p
l
a
n
n
i
n
g
te
a
m
,
T
h
e
t
e
a
m
i
s
c
o
m
p
l
e
r
i
n
g
a
w
e
s
t
-
wi
d
e
p
l
a
n
n
i
n
g
d
a
t
a
b
a
s
e
a
n
Tr
a
n
s
m
i
s
s
i
o
n
t
a
t
h
-
FY
2
0
1
t
(
s
u
m
m
e
r
o
f
C
Y
2
0
1
0
)
30
0
JD
i
U
T
pa
t
h
-
C
U
de
IS
u
e
u
p
g
r
a
d
e
o
f
t
r
a
n
s
f
e
r
c
a
p
a
b
i
l
i
t
y
f
t
o
m
I
d
a
h
o
t
o
~
2
0
1
5
r
e
f
e
r
e
n
c
e
c
a
s
~ f
o
r
u
s
e
i
n
f
u
t
u
r
e
s
c
e
n
a
r
i
o
a
n
a
l
y
s
e
s
.
P
A
C
Up
g
r
a
d
e
pg
r
a
Ut
a
h
,
IS
a
l
s
o
p
a
r
t
i
c
I
p
a
t
i
n
g
I
n
N
T
A
C
,
a
n
d
f
a
c
I
l
i
t
a
t
i
n
g
W
E
C
C
'
s
m
o
v
e
t
o
a
n
e
w
l
e
a
d
e
r
s
h
i
p
r
o
l
e
f
o
r
W
e
s
t
e
r
n
I
n
t
e
r
c
o
n
n
e
c
t
i
o
n
t
r
a
n
s
m
i
s
s
i
o
n
ex
p
a
n
s
i
o
n
p
l
a
n
n
i
n
g
.
P
a
c
i
f
i
C
o
r
p
t
o
g
e
t
h
e
r
w
i
t
h
o
t
h
e
r
r
e
g
i
o
n
a
l
en
t
i
r
i
e
s
c
o
m
p
l
e
t
e
d
b
e
n
e
f
i
t
a
n
a
l
y
s
i
s
o
f
G
r
i
d
W
e
s
t
a
n
d
i
s
w
o
r
k
i
n
g
to
e
n
s
u
r
e
a
p
o
s
i
r
i
v
e
o
u
t
c
o
m
e
i
n
D
e
c
i
s
i
o
n
P
o
i
n
t
2
,
Pu
l
v
e
r
i
z
e
d
C
o
o
l
pr
o
c
u
r
e
a
h
i
h
c
a
a
c
i
t
y
f
a
c
t
o
r
r
e
s
o
u
r
c
e
i
n
o
r
d
e
l
i
v
e
r
e
d
WO
r
k
w
i
~h
t
h
e
I
n
d
e
p
e
n
d
e
n
t
E
v
a
l
u
a
t
o
r
c
u
r
r
~n
t
\
y
o
n
~
t
a
i
n
e
r
i
n
Su
p
p
l
y
-
SI
d
e
IC
o
a
l
r
e
s
o
u
r
c
e
I
F
Y
2
0
1
~
3
(
s
u
m
m
e
r
o
f
C
Y
2
0
I
U
)
60
0
I
Ut
a
h
I
p
l
U
h
b
~
P
fC
Y
2
0
1
+
2
U
t
a
h
to
I
d
e
n
t
I
f
y
t
h
e
b
e
s
t
w
a
y
t
o
p
r
o
c
u
r
e
t
h
I
S
n
e
e
d
g
i
v
e
n
t
h
e
an
t
to
t
a
y
t
e
s
u
m
m
e
r
0
eli
m
i
n
a
t
i
o
n
o
f
2
0
0
9
r
e
s
o
u
r
c
e
.
Pa
c
i
f
i
C
o
r
p
j
o
i
n
e
d
w
i
t
h
o
t
h
e
r
r
e
g
i
o
n
a
l
e
n
t
i
t
i
e
s
t
o
f
o
"
"
t
h
e
Co
n
t
i
n
u
e
t
o
w
o
r
k
w
i
t
h
o
t
h
e
r
r
e
g
i
o
n
a
l
e
n
t
i
t
i
e
s
t
o
S
S
G
WI
r
e
g
i
o
n
a
l
t
r
a
n
s
m
i
s
s
i
o
n
p
l
a
n
n
i
n
g
m
o
d
e
l
i
n
g
t
e
a
m
,
T
h
e
T
'
Re
g
i
o
n
a
l
Y
2
0
1
d
b
Tr
a
n
s
m
i
s
s
i
o
n
f
r
o
m
de
v
e
l
O
P
G
r
i
d
W
e
s
t
.
C
o
n
t
i
n
u
e
t
o
a
c
t
I
v
e
l
y
p
a
r
t
i
c
i
p
a
t
e
te
a
m
i
s
c
u
r
r
e
n
t
l
y
w
o
r
k
i
n
g
o
n
t
b
e
S
S
G
-
WI
r
e
g
i
o
n
a
l
t
r
a
n
s
m
i
s
s
i
o
n
ra
n
s
m
l
S
S
l
o
n
T
r
a
n
s
m
i
s
s
i
o
n
F
3
a
n
e
y
o
n
no
ys
t
e
m
Wy
o
m
i
n
g
t
o
U
t
a
h
in
r
e
g
i
o
n
a
l
t
r
a
n
s
m
i
s
s
i
o
n
i
n
i
t
i
a
t
i
v
e
s
(
e
,
g,
R
M
A
T
S
,
st
u
d
y
.
P
a
c
i
f
i
C
o
r
p
t
o
g
e
t
h
e
r
w
i
t
h
o
t
h
e
r
r
e
g
i
o
n
a
l
en
t
i
t
i
e
s
NT
A
C
)
co
m
p
l
e
t
e
d
b
e
n
e
f
i
t
a
n
a
l
y
s
i
s
o
f
G
r
i
d
W
e
s
t
a
n
d
i
s
w
o
r
k
i
n
g
t
o
en
s
l
i
r
e
p
o
s
i
t
i
v
e
o
u
t
c
o
m
e
o
f
D
e
c
i
s
i
o
n
P
o
i
n
t
2
.
10
II
R
P
P
r
o
c
e
s
s
I
M
o
d
e
l
i
n
12
0
0
6
I
R
P
nia
ni
a
nia
In
c
o
r
p
o
r
a
t
~
C
a
p
a
c
i
t
y
E
x
p
a
n
s
i
o
n
M
o
d
e
l
i
n
t
o
p
o
r
t
f
o
l
i
o
Mo
d
e
~
h
a
s
b
e
e
~ v
a
l
i
d
a
t
e
d
a
n
d
t
e
s
t
e
d
.
P
a
c
i
f
i
C
o
r
p
i
s
p
r
e
p
a
r
i
n
g
t
o
an
d
s
c
e
n
a
n
o
a
n
a
l
)
'
s
l
S
,
us
e
t
h
I
S
m
o
d
e
l
I
n
t
h
e
2
0
0
6
I
R
P
,
-
4
6
-
PaciflCorp 2004 IRP Update Chapter 5 - Action Plan Update
ACTION PLAN IMPLEMENTATION
As mentioned in the 2004 IRP, PacifiCorp intends to implement many elements of the Action
Plan with a fonnal and transparent procurement program. The IRP detennined the need for
resources with considerable specificity, and identified the desirable portfolio and timing of need.
However, flexibility in light of changing conditions is an essential element of the plan. The IRP
has not identified specific resources to procure, or detennined a preference between asset
ownership versus power purchase contracts. These decisions will be made subsequently on a
case-by-case basis via the procurement process including, when appropriate, competitive bidding
with an effective request for proposal (RFP) process.
Demand Side Procurement Proe:ram
IRP Action Plan Items 2, 5 , and 6 concentrate on acquiring more Class 1 and Class 2 DSM
resources. During 2005, PacifiCorp has launched programs in Washington that were originally
started in Utah, filed new programs in Idaho and California, and made improvements to existing
programs particularly the Energy FinAnswer program. In addition, the Company
comprehensive 2005 DSM RFP was issued on September 1 , 2005. This RFP contains 19
different types of DSM programs that bidders can choose to develop. A well attended pre-bid
workshop was held on September 15 , 2005 to review the RFP package and answer potential
bidders' questions. Bids were due in mid-October and are currently being -evaluated. This RFP is
on schedule to have new cost effective programs available in the spring/summer of 2006.
Supply Side Procurement Proe:ram
Supply Side RFP (formerly RFP 2009)
The update to PacifiCorp s load and resource forecast eliminates the need for a 2009 resource. In
expectation, and in light of multiple concurrent dockets, PacifiCorp recommended to the Oregon
Washington, and Utah commissions that the RFP review process be initially delayed. The 2004
IRP Update Preferred Portfolio consists of eliminating the 2009 natural gas resource in Utah and
identifying the need for a resource in 2012 rather than 2011. The evaluated proxy for the 2012
resource is a coal plant that can make deliveries in Utah. The amount of the need in 2012 is about
600 MW.
PacifiCorp will work with the Commissions and the Independent Evaluator (IE) currently on
retainer in Utah to identify the best way to procure this need given the type of proxy used in the
IRP. This may result in "RFP 2009" being converted into "RFP 2012". Such a procurement
process would remain subject to applicable commission acceptance. It is not anticipated at this
time that such a procurement process would be limited by fuel type. However, certain resources
or bidders may not meet minimum procurement requirements in tenns of operating
characteristics and/or adequate credit assurances.
The long lead time necessary to construct the IRP proxy (a conventional coal plant) requires that
engineering and construction contracts be awarded in 2007. Due to the developing nature of
IGCC technology and uncertainty about the costs of an IGCC plant, PacifiCorp anticipates
exploring with the Commissions and IE how to incorporate the IRP proxy as a potential next best
alternative (NBA) in such a RFP based procurement process,
- 47-
PacifiCorp 2004 IRP Update Chapter 5 - Action Plan Update
Renewables RFP
The Renewable Request for Proposal (RFP) was initially issued in February 2004. The Company
received a strong response to the RFP, with more than 50 proposals totaling over 6 000 MW of
capability. About 2 000 MW fell to the shortlist. Events moved rapidly after the Production Tax
Credit (PTC) passed in October 2004. Wind turbine costs took a sharp jump due to increases in
steel prices, the falling dollar, and ultimately a scarcity of the turbines themselves, At the same
time, oil and natural gas prices put significant upward pressures on wholesale electric prices.
PacifiCorp s goal is to move forward on projects that are detennined to be cost effective as
measured against forward price projections (adjusted on a project-specific basis) and that are
consistent with 2004 IRP assumptions. Of the eight short listed proposals for 2005, four fell
away within a few weeks with two being withdrawn at the bidders' request. The remaining four
soon became two due to the inability of bidders to complete projects in 2005. One of the
remaining two projects experienced extreme difficulty obtaining wind turbines and ultimately
could not proffer an economic offer, even with support from the Energy Trust of Oregon.
As discussed in Chapter 2, PacifiCorp completed negotiations on a 64.5 MW wind project to be
completed by the end of 2005 in southeastern Idaho. The project was originally to be larger, but
was limited due to wind turbine availability. The new project, Wolverine Creek wind fann, is to
be built and financed by Invenergy,
With the extension of the PTC, to include 2006 and 2007 , negotiations with bidders continue
with a focus on Projects that can be on line prior to December 31 , 2007. Current discussions with
short listed bidders continue. The feasibility of these Projects will depend on their economics
turbine availability and transmission.
Following completion of negotiations for 2006 and 2007 projects, and barring some
unanticipated market event (such as new or revised production tax credit provisions), PacifiCorp
currently anticipates bringing RFP 2003B to a close and starting a new renewable resource
procurement process.
SUMMARY
This IRP Update is based on the best infonnation available at the time of the filing. It will be
implemented as described, but is subject to change as new infonnation becomes available or as
circumstances change.
The IRP Action Plan is the primary driver for PacifiCorp s resource procurement going forward.
In implementing the Plan, all resource options will be compared to alternative resource options
(either from the market or from other existing potential electricity suppliers). The proposed
Procurement Program will also ensure consistency with anticipated ratemaking requirements
including industry restructuring implementation in Oregon.
48 -
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
APPENDIX A - MAIN ASSUMPTIONS
This appendix covers tables from Appendix C of the 2004 IRP filed in January 2004. Only the
tables that were updated appear here.
STUDY PERIOD AND CALENDAR YEAR REPORTING BASIS
PacifiCorp currently operates on a Fiscal Year but for IRP modeling purposes has changed to
Calendar Year beginning on January I to December 31. The study period covers a 20-year period
beginning January 2006 to December 2025.
INFLATION RATES
Table A.1 - Inflation Rates
;'e" ",
)', '
'f01;,"""",;:
Calendar Y e.aJ;'S)/,,lhfiatio~.R~te:,
" :V'S/f, , ,
, ,'; ":~"
24%2004,,2010
2011-2020 2.48%
..
2021 ~2030'"0:'58%
NATURAL GAS AND WHOLESALE ELECTRIC PRICE PROJECTION COMPONENTS
Since the price forecast used in the 2004 IRP, several revised Forward Price Projections have
occurred with some refinements in the methodology. The wholesale electric market prices are
comprised of several distinct forecasts that are combined to fonn the final price forecast. The
distinct components of the price forecast are labeled: Market, Blending, Fundamentals, and
Extrapolation. The combined price forecast is defined as the Market forecast for 6 years, Blending
for one year, Fundamentals for 13 years and Extrapolation for the next 13 years. The Blending
period (Year 7) prices are calculated as the average of corresponding adjacent Market and
Fundamentals forecasts. The first year will begin in the month after the official price forecast date
(e.g. July through August equal year 1).
49 -
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Figure A.I - Natural Gas and Wholesale Electric Price Curve Components
For Illustration Purposes
Blending
....- , - - -
;::-:damentals
Market
- -
r--.----r-
Years 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33
GAS AND POWER PRICE FORECASTS
Both the gas and power price forecasts have been updated to reflect recent market fundamentals
changes as discussed in Chapter I. The shape of the curves follows the updated blending
methodology. Prices shown are in nominal 2005 dollars. Gas and electric prices are consistent with
PacifiCorp official market price projections, dated June 2005.
Natural Gas Prices
Natural gas prices on the west are an average of the Sumas, Stanfield and Opal market hub prices
with a $0.03/MMBtu variable transportation adder, and a $0.55/MMBtu demand transportation
adder escalating at inflation. Gas Prices on the east side are based upon Opal with a $O.lO/MMBtu
variable transportation adder, and a $0.26/MMBtu demand transportation adder escalating at
inflation.
- 50-
PacifiCorp 2004 IRP Update
12.
Figure A.2 - Gas Price Forecast
~ 6.
10.
Appendix A Base Assumptions
-=-~ ~ ~ ~ ::? ~ ::?
:t
::? .:!? :::: .::!! ::? & ~ ~
0l ~ &
ct' ct' ct' ct' ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
Calendar Year
'---
-West(2004IRP) -East(2004IRP) --West Update --East Update
Wholesale Electricity Prices
Figure A.3 shows the flat product ("7 x 24") electricity price curves for each of the four market
hubs.
- 51 -
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Figure A.3 - Power Price Forecast
$90
$80
....
$70
$60
$50
t--
:g $40
$30
$20
$10
$0
& ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ & ~ ~ & ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
Calendar Year
- - .
COB Update PV Update . MidC Update FC Update
- . - . COB (2004 IRP) PV (2004 IRP) - - MidC (2004 IRP) FC (2004 IRP)
COAL PRICE FORECASTS
Table A.2 represents PacifiCorp s estimate of delivered coal costs for proposed coal plant
additions in Wyoming and Utah. These estimates remain sensitive to supply and demand and
transportation costs. PacifiCorp has not included the costs of its generation fleet. Rather these
costs are reflective of PacifiCorp s actual and projected contract costs rather than as a market
indicator for future generating potential. Prices are in nominal dollars.
- 52-
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Table A.2 - Coal Price Update
" ,
20041RPUpdate '
VVyqml"!Q t&;' ::':x'.'i'.JafJ." ,
. ($~M.MB!uJh;;'
(:';
($/MM I3tlJr'
148 $ 1.306
147 $ 1.267
176 $ 1.261
199 $ 1.275230 $ 1.313259 $ 1.365290 $ 1.445321 $ 1.523351 $ 1.558399 $ 1.573
1.434 $ 1.613
1.470 $ 1.654507 $ 1.696546 $ 1.739585 $ 1.783
625 $ 1.828
666 $ 1.874708 $ 1.921753 $ 1.970796 $ 2.020
~1'!,~ndar IT
hv.~ar" i:"
2006;/
' $
2007 i;, $
2008
; $
2009
.. $
2010~
'2011
:" $
'.2012
2M3;2014'
02015
2016,
/ $
i:;2017,
" $
2018.
; $
2019"
, $
2020 '
'" $
2021,,
;' $
2022
) 2023,,
; $
;2024 2025
CONTRACTS
A number of contracts were modeled in the IRP analysis. Table A.3 shows the basic infonnation
for each contract by classification. Values shown are maximum annual values. The table now
includes new categories for Front Office Transactions, Qualifying Facilities, and Renewables.
Refinements to contract modeling continues and in this IRP Update some of the drivers for
change included moving from Fiscal Year to Calendar Year with contracts ending in 2005 being
removed. The addition of the new categories broke out contracts from purchases, sales and
exchanges providing clarity surrounding types of contracts. Interruptible and Qualifying
Facilities contracts were extended to the end of the planning period, for modeling purposes only,
at the request of public participants.
- 53 -
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
Ta
b
l
e
A
.
3
-
C
o
n
t
r
a
c
t
s
:
A
n
n
u
a
l
M
a
x
i
m
u
m
Me
g
a
w
a
t
t
s
p
e
r
C
o
n
t
r
a
c
t
b
y
Y
e
a
r
IY
e
a
r
Ar
e
a
Co
u
n
t
e
r
p
a
r
t
y
De
s
c
r
i
p
t
i
o
n
En
d
D
a
t
e
I
20
0
6
20
0
7
20
0
a
l
20
0
9
1
20
1
0
20
1
1
20
1
2
1
20
1
3
1
20
1
4
20
1
5
20
2
0
20
2
5
1 V
a
r
i
o
u
s
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
Va
r
i
o
u
s
59
2
r
60
0
20
0
25
0
,
,
2 A
l
c
o
a
P
o
w
e
r
G
e
n
e
r
a
t
i
n
g
I
n
c
.
Hy
d
r
o
E
x
c
h
a
n
g
e
-
T
a
k
e
Ju
n
2
0
1
1
3 A
l
c
o
a
P
o
w
e
r
G
e
n
e
r
a
t
i
n
g
I
n
c
,
Hy
d
r
o
E
x
c
h
a
n
g
e
-
R
e
t
u
r
n
Ju
n
2
0
1
1
(8
2
)
(8
2
)
(8
2
)
(8
2
)
(8
2
)
(5
5
)
4 B
o
n
n
e
v
m
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Re
t
u
r
n
P
o
r
t
i
o
n
o
f
E
x
c
h
a
n
g
e
Au
9
2
0
1
1
(5
7
5
)
(5
7
5
)
(5
7
5
)
(5
7
5
)
(5
7
5
)
(5
7
5
)
5 B
o
n
n
e
v
m
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Ta
k
e
P
o
r
t
i
o
n
o
f
E
x
c
h
a
n
o
e
Au
o
2
0
1
1
57
5
57
5
57
5
57
5
57
5
57
5
6 G
e
m
S
t
e
t
e
(
I
d
a
h
o
F
a
l
l
s
)
Po
w
e
r
P
u
r
c
h
e
s
e
A
g
r
e
e
m
e
n
t
Au
g
2
0
2
3
7 T
r
i
.
Sta
t
e
G
e
n
e
r
a
t
i
o
n
a
n
d
T
r
a
n
s
m
i
s
s
i
o
n
Po
w
e
r
P
u
r
c
h
a
s
e
A
9
r
e
e
m
e
n
t
De
e
2
0
2
0
8 C
o
w
1
i
l
z
C
o
u
n
t
y
,
P
U
D
N
o
.
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
t
20
3
6
9 D
o
u
l
a
s
C
o
u
n
t
y
P
U
D
N
o
.
Se
t
t
l
e
m
e
n
t
A
o
r
e
e
m
e
n
t
Au
o
2
0
1
8
10
G
r
a
n
t
C
o
u
n
t
y
P
U
D
N
o
.
Dis
p
l
a
c
e
m
e
n
t
E
n
e
r
g
y
Se
p
2
0
1
1
11
G
r
a
n
t
C
o
u
n
t
y
P
U
D
N
o
.
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
GT
C
12
M
i
d
-
Co
l
u
m
b
i
a
H
y
d
r
o
(
V
a
r
i
o
u
s
)
Va
r
i
o
u
s
M
i
d
.
Co
l
u
m
b
l
a
H
v
d
r
o
Va
r
i
o
u
s
29
2
30
3
30
2
30
4
25
9
25
6
19
8
19
5
19
4
19
2
13
9
14
8
.
.
13
M
a
g
n
e
s
i
u
m
C
o
r
p
o
r
a
t
i
o
n
o
f
A
m
e
r
i
c
a
In
t
e
r
r
u
p
t
i
b
l
e
A
g
r
e
e
m
e
n
t
De
e
2
0
0
9
12
5
12
5
12
5
12
5
12
5
12
5
12
5
12
5
12
5
12
5
12
5
12
5
14
M
o
n
s
a
n
t
o
In
t
e
r
r
u
p
t
i
b
l
e
A
g
r
e
e
m
e
n
t
De
c
2
0
0
6
15
N
u
c
o
r
In
t
e
r
r
u
p
t
i
b
l
e
A
o
r
e
e
m
e
n
t
De
e
2
0
0
6
16
A
r
i
z
o
n
a
P
u
b
l
i
c
S
e
r
v
i
c
e
C
o
m
p
a
n
y
Ex
c
h
a
n
g
e
A
g
r
e
e
m
e
n
t
Oc
t
2
0
2
0
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
(4
8
0
)
17
A
r
i
z
o
n
a
P
u
b
l
i
c
S
e
r
v
i
c
e
C
o
m
p
a
n
y
Ex
c
h
a
n
o
e
A
o
r
e
e
m
e
n
t
Oc
t
2
0
2
0
57
5
57
5
57
5
57
5
57
5
57
5
57
5
57
5
57
5
57
5
57
5
18
B
o
n
n
e
v
m
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
So
u
t
h
I
d
a
h
o
E
x
c
h
a
n
g
e
GT
C
39
9
40
2
41
7
41
7
41
7
41
7
41
7
44
5
44
5
44
5
46
2
46
2
19
B
o
n
n
e
v
m
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
So
u
t
h
I
d
a
h
o
E
x
c
h
a
n
g
e
GT
C
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
(7
9
)
20
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Re
t
u
r
n
P
o
r
t
i
o
n
o
f
E
x
c
h
a
n
g
e
De
c
2
0
1
3
(2
5
3
)
(2
5
3
)
(2
5
3
)
(2
5
3
)
(2
5
3
)
(2
5
3
)
(2
5
3
)
(2
5
3
)
21
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Ta
k
e
P
o
r
t
i
o
n
o
f
E
x
c
h
a
n
o
e
De
e
2
0
1
3
24
5
24
5
24
5
24
5
24
5
24
5
24
5
24
5
22
C
i
t
y
o
f
R
e
d
d
i
n
g
Ex
c
h
e
n
g
e
A
g
r
e
e
m
e
n
t
No
v
2
0
1
5
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
(5
0
)
23
C
i
t
y
o
f
R
e
d
d
i
n
g
Ex
c
h
a
n
g
e
A
g
r
e
e
m
e
n
t
No
v
2
0
1
5
24
S
a
c
r
a
m
e
n
t
o
M
u
n
i
c
i
p
a
l
U
t
i
l
i
t
y
D
i
s
t
Ex
c
h
a
n
g
e
A
g
r
e
e
m
e
n
t
De
c
2
0
1
4
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
(1
0
0
)
25
S
a
c
r
a
m
e
n
t
o
M
u
n
i
c
i
a
l
U
t
i
l
i
t
y
D
l
s
t
Ex
c
h
a
n
o
e
A
o
r
e
e
m
e
n
t
De
e
2
0
1
4
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
26
T
r
l
.
Sta
t
e
G
e
n
e
r
a
t
i
o
n
&
T
r
a
n
s
m
i
s
s
i
o
n
C
o
.
Ex
c
h
e
n
g
e
A
g
r
e
e
m
e
n
t
Ma
r
2
0
0
7
27
T
r
i
-
Sla
t
e
G
e
n
e
r
a
t
i
o
n
&
T
r
a
n
s
m
i
s
s
i
o
n
C
o
,
Ex
c
h
a
n
o
e
A
o
r
e
e
m
e
n
t
Ma
r
2
0
0
7
(4
8
28
A
V
I
S
T
A
C
o
r
p
I
C
o
l
s
t
r
l
p
O
w
n
e
r
s
Se
r
v
i
c
e
A
g
r
e
e
m
e
n
t
Oc
l
2
0
0
8
29
C
l
a
r
k
C
o
u
n
t
y
P
U
D
N
o
.
Fo
r
c
e
d
O
u
t
a
g
e
R
e
s
e
r
v
e
De
e
2
0
0
7
30
C
l
a
r
k
C
o
u
n
t
y
P
U
D
N
o
.
Ba
s
e
C
a
p
a
c
i
t
y
De
e
2
0
0
7
66
1
66
1
31
C
l
e
r
k
C
o
u
n
t
y
P
U
D
N
o
.
Lo
a
d
S
e
r
v
l
c
i
n
n
Ex
c
h
a
n
n
e
A
n
r
e
e
m
e
n
t
De
e
2
0
0
7
r2
2
0
12
2
8
32
D
e
s
e
r
e
t
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
GT
C
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
10
0
33
P
o
r
t
l
a
n
d
G
e
n
e
r
a
l
E
l
e
c
t
r
i
c
Co
v
e
R
e
p
l
a
c
e
m
e
n
t
P
o
w
e
r
34
T
r
a
n
s
A
l
i
a
E
n
e
r
g
y
M
a
r
k
e
t
i
n
g
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
Ju
n
2
0
0
7
38
9
38
9
35
H
e
r
m
i
n
s
t
o
n
G
e
n
e
r
a
t
i
n
g
C
o
m
o
a
n
v
Po
w
e
r
P
u
r
c
h
a
s
e
A
o
r
e
e
m
e
n
t
Ju
n
2
0
1
6
23
8
23
8
23
8
23
8
23
8
23
8
23
8
23
8
23
8
23
8
-
5
4
-
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
Ta
b
l
e
A
.
3
-
C
o
n
t
r
a
c
t
s
:
A
n
n
u
a
l
M
a
x
i
m
u
m
Me
g
a
w
a
t
t
s
p
e
r
C
o
n
t
r
a
c
t
b
y
Y
e
a
r
,
C
o
n
t
i
n
u
e
d
Ar
e
a
Co
u
n
t
e
r
p
a
r
t
y
De
s
c
r
i
p
t
i
o
n
I
E
n
d
D
a
t
e
20
0
6
1
20
0
7
20
0
8
20
0
9
T
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
2
0
1
20
2
5
1
36
B
i
o
m
a
s
s
O
n
e
L
.
P
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
De
c
2
0
1
1
De
s
e
r
t
P
o
w
e
r
L
P
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
De
c
2
0
2
5
38
D
.
R
,
J
o
h
n
s
o
n
L
u
m
b
e
r
C
o
m
p
a
n
y
I
n
c
.
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
l
(
O
F
)
De
c
2
0
0
6
EX
X
O
N
M
O
B
I
L
P
r
o
d
u
c
t
i
o
n
C
o
m
o
a
n
v
Po
w
e
r
P
u
r
c
h
a
s
e
A
Q
r
e
e
m
e
n
l
i
O
F
i
De
c
2
0
0
6
Sim
p
l
o
t
P
h
o
s
p
h
a
t
e
s
-
(
W
A
S
S
F
P
h
o
s
p
h
a
t
e
s
)
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
De
c
2
0
0
5
41
O
F
S
m
a
l
l
E
a
s
t
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
Va
r
i
o
u
s
42
O
F
S
m
a
l
l
W
e
s
t
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
Va
r
i
o
u
s
43
S
u
n
n
"
'
i
d
e
C
o
n
e
n
e
r
a
t
i
o
n
A
s
s
o
c
i
a
t
e
s
Po
w
e
r
P
u
r
c
h
a
s
e
A
o
r
e
e
m
e
n
t
i
O
F
Ma
r
2
0
2
3
Ke
n
n
e
c
o
h
U
t
a
h
C
o
p
p
e
r
C
o
r
p
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
De
c
2
0
0
5
45
T
e
s
o
r
o
R
e
f
i
n
i
n
g
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
(
O
F
)
De
c
2
0
0
5
46
M
a
n
n
e
s
i
u
m
C
o
r
a
o
r
a
t
i
o
n
o
f
A
m
e
r
i
c
a
r
u
s
M
a
o
)
Po
w
e
r
P
u
r
c
h
a
s
e
A
o
r
e
e
m
e
n
t
i
O
F
\
De
c
2
0
0
9
47
E
W
E
B
,
B
P
A
F
o
o
t
e
C
r
e
e
k
I
Fo
o
t
e
C
r
e
e
k
I
G
e
n
e
r
a
t
i
o
n
C
o
n
t
r
o
l
/
S
t
o
r
a
g
e
/
D
e
l
i
v
e
r
y
Ap
r
2
0
2
4
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(1
3
)
48
F
o
o
t
e
C
r
e
e
k
I
Fo
o
t
e
C
r
e
e
k
I
O
w
n
e
r
s
h
i
p
S
h
a
r
e
GT
C
49
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Fo
o
t
e
C
r
e
e
k
I
I
W
i
n
d
E
x
c
h
a
n
o
e
Ju
n
2
0
1
4
50
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Fo
o
t
e
C
r
e
e
k
I
I
W
i
n
d
E
x
c
h
a
n
g
e
Ju
n
2
0
1
4
(1
)
(1
)
(1
)
(1
)
(1
)
(1
)
(1
)
(1
)
(1
)
51
P
u
b
l
i
c
S
e
r
v
i
c
e
C
o
o
f
C
o
l
o
r
a
d
o
Fo
o
t
e
C
r
e
e
k
I
I
I
G
e
n
e
r
a
t
i
o
n
C
o
n
l
r
o
l
/
S
t
o
r
a
g
e
l
D
e
l
i
v
e
r
y
Au
g
2
0
1
4
52
P
u
b
l
i
c
S
e
r
v
i
c
e
C
o
o
f
C
o
l
o
r
a
d
o
Fo
o
t
e
C
r
e
e
k
I
I
I
G
e
n
e
r
a
t
i
o
n
C
o
n
t
r
o
l
/
S
t
o
r
a
g
e
l
D
e
l
i
v
e
r
y
Au
g
2
0
1
4
(2
5
)
(2
5
)
(2
5
)
(2
5
)
(2
5
)
(2
5
)
(2
5
)
(2
5
)
(2
5
)
53
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Fo
o
t
e
C
r
e
e
k
I
V
G
e
n
e
r
a
t
i
o
n
C
o
n
t
r
o
l
/
S
t
o
r
a
ae
l
D
e
l
i
v
e
r
v
l
U
F
T
A
o
r
e
e
m
e
n
t
Oc
t
2
0
2
0
54
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
Fo
o
t
e
C
r
e
e
k
I
V
G
e
n
e
r
a
t
i
o
n
C
o
n
t
r
o
I
l
S
t
o
r
a
g
e
/
D
e
l
i
v
e
r
y
/
U
F
T
A
g
r
e
e
m
e
n
t
Oc
t
2
0
2
0
(g
)
(9
)
(g
)
(9
)
(9
)
(9
)
(9
)
(g
)
(g
)
(9
)
(8
)
55
C
o
m
b
i
n
e
H
i
l
l
s
I
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
t
-
W
i
n
d
De
c
2
0
2
3
56
R
o
c
k
R
i
v
e
r
I
Po
w
e
r
P
u
r
c
h
a
s
e
A
g
r
e
e
m
e
n
l
-
W
i
n
d
De
c
2
0
2
1
57
S
e
a
t
t
l
e
C
i
t
y
L
i
h
t
Win
d
E
x
c
h
e
n
a
e
Fe
b
2
0
1
2
58
S
e
a
n
t
e
C
i
t
y
L
i
g
h
l
Win
d
E
x
c
h
a
n
g
e
Fe
b
2
0
1
2
(5
5
)
(5
5
)
(5
5
)
(5
5
)
(5
5
)
(5
5
)
(5
5
)
Wo
l
v
e
r
i
n
e
C
r
e
e
k
Po
w
e
r
P
u
r
c
h
a
e
e
A
g
r
e
e
m
e
n
t
-
W
i
n
d
De
c
2
0
2
5
60
B
l
a
c
k
H
i
l
l
s
C
o
r
p
o
r
a
l
i
o
n
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
l
De
c
2
0
2
3
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
(4
2
)
61
B
l
a
n
d
i
n
g
C
i
t
y
C
o
r
p
o
r
a
l
i
o
n
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
t
Ma
r
2
0
0
7
(2
)
(2
)
62
B
o
n
n
e
v
i
l
l
e
P
o
w
e
r
A
d
m
i
n
i
s
t
r
a
t
i
o
n
-
F
l
a
t
h
e
a
d
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
t
Se
p
2
0
0
6
~~
:
)
63
F
l
a
t
h
e
a
d
E
l
e
c
t
r
i
c
C
o
o
n
e
r
a
t
i
v
e
,
I
n
c
,
Po
w
e
r
S
a
l
e
.
A
c
r
e
e
m
e
n
l
Se
D
2
0
0
6
64
G
r
a
n
t
C
o
u
n
t
y
P
U
D
N
o
,
2
CE
A
E
A
Oc
l
2
o
1
1
(1
3
)
(1
3
)
(1
3
)
(1
3
)
(4
)
(4
)
65
P
u
b
l
i
c
S
e
r
v
i
c
e
C
o
o
f
C
o
l
o
r
a
d
o
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
t
De
c
2
0
1
1
(1
7
6
)
(1
7
6
)
(1
4
1
)
(1
0
7
)
(7
1
)
(3
6
)
66
R
T
S
A
L
o
s
s
e
s
-
I
d
a
h
o
P
o
w
e
r
C
o
.
RT
S
A
l
o
s
s
e
.
-
ID
P
o
w
e
r
C
o
,
GT
C
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
(1
5
)
67
S
i
e
r
r
a
P
a
c
n
i
c
P
o
w
e
r
C
o
m
o
e
n
v
Po
w
e
r
S
a
l
e
s
A
n
r
e
e
m
e
n
l
Fe
b
2
0
0
9
i7
5
i7
5
i7
5
i7
5
Uta
h
A
s
s
o
c
i
a
t
e
d
M
u
n
i
c
i
p
a
l
P
o
w
e
r
S
y
s
t
e
m
s
Po
w
e
r
S
a
l
e
s
A
g
r
e
e
m
e
n
t
Oc
t
2
0
0
7
(2
)
(2
)
Uta
h
M
u
n
i
c
i
p
a
l
P
o
w
e
r
A
g
e
n
c
y
Po
w
e
r
S
a
l
e
e
A
g
r
e
e
m
e
n
l
Ju
n
2
0
1
7
(8
8
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
(7
5
)
70
C
i
t
y
o
f
H
u
r
r
i
c
a
n
e
Po
w
e
r
S
a
l
e
s
A
n
r
e
e
m
e
n
t
Av
g
2
0
0
7
(1
)
71
1
L
E
A
S
E
C
O
, a
w
h
o
l
l
y
o
w
n
e
d
s
u
b
s
i
d
i
a
r
y
o
f
P
P
M
IL
e
a
s
e
o
f
G
e
n
e
r
a
t
i
o
n
a
t
W
e
s
t
V
a
l
l
e
y
U
t
a
h
Ma
y
2
0
0
8
19
9
,
19
9
19
9
No
t
e
s
*
C
o
n
t
r
a
c
t
s
a
d
d
e
d
s
u
b
s
e
q
u
e
n
t
t
o
t
h
e
f
i
l
i
n
g
o
f
t
h
e
2
0
0
4
I
R
P
.
GT
C
:
G
o
o
d
T
i
J
I
C
a
n
c
e
l
e
d
-
5
5
-
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
STOCHASTIC ASSUMPTIONS
The methodology for determining the volatilities for market price, natural gas price, loads
thennal outages, and hydro availability did not change from the methodology used in the 2004
IRP. The initial values of the short-tenn volatilities and long-tenn volatilities for market prices
and natural gas prices were unchanged from the values used in the 2004 IRP. The adjustments
made to the short-tenn and long-tenn volatility parameters reflecting the "Samuelson effect" 10
changed from the 2004 IRP due to perceived changes in marketplace volatilities. The change in
the adjustments had the effect of increasing volatility for market and natural gas prices. There
were no changes in the mean reversion parameters from those used in the 2004 IRP.
The volatilities and other related stochastic parameters for load, thennal outages, and hydro
availability did not change from what was used in the 2004 IRP.
Slight correlation changes were made from those used in the 2004 IRP. The long-tenn
correlations between each pair of gas and electric prices, gas and gas prices, and electric and
electric prices were assumed to be approximately between 0,87 and 0., reduced from between
94 and 0.98 used in the 2004 IRP. These changes were made as a result of perceived changes
in marketplace correlations. There were no changes made to the short-tenn correlation values
from those used in the 2004 IRP.
Input Values Based on 100 Iterations
The input values of market electric price and natural gas prices are shown in the following
graphs, Figures AA and AS illustrate the range of wholesale electric prices used in the stochastic
analysis for the Palo Verde and Mid-Columbia markets for calendar years 2006 through 2025.
10 The Samuelson Effect refers to the behavior of price volatility given the tenTI structure of a futures contract; a
distant contract (a longer time to maturity) is less sensitive to underlying shocks than a nearby contract (a shorter
time to maturity). This effect is discussed on page 91 of the 2004 IRP Technical Appendix.
- 56-
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Figure A.4 - Palo Verde Average Annual Electric Prices (100 Iterations)
$400
$350
$50
$300 --
$250
$200
$150
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Year
Figure A.5 - Mid-Columbia Average Annual Electric Prices (100 Iterations)
$50
$300
$250
$200
$150
$100
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Year
Figures A.6 and A.7 illustrate the 100 iterations for the west and east natural gas prices used in
the stochastic analysis on a calendar year basis.
- 57 -
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Figure A.6 - Average Annual West Natural Gas Prices (100 Iterations)
$30
$25
$20
$15
$10
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Yea,
Figure A.7 - Average Annual East Natural Gas Prices (100 Iterations)
$30
$25
$20
$15
$10
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Yea,
- 58 -
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
UP
D
A
T
E
D
S
U
P
P
L
Y
S
I
D
E
O
P
T
I
O
N
S
Ta
b
l
e
s
A
.
4
a
n
d
A
.
5
s
h
o
w
p
l
a
n
t
c
o
s
t
a
n
d
t
e
c
h
n
o
l
o
g
y
i
n
f
o
n
n
a
t
i
o
n
f
o
r
e
a
c
h
r
e
s
o
u
r
c
e
c
o
n
s
i
d
e
r
e
d
f
o
r
i
n
c
l
u
s
i
o
n
i
n
t
o
a
p
o
r
t
f
o
l
i
o
.
Co
s
t
s
a
n
d
pe
r
f
o
n
n
a
n
c
e
r
e
f
l
e
c
t
a
s
s
u
m
p
t
i
o
n
s
a
s
o
f
J
u
n
e
2
0
0
5
.
N
o
t
e
s
f
o
r
t
a
b
l
e
e
n
t
r
i
e
s
a
r
e
lo
c
a
t
e
d
a
f
t
e
r
T
a
b
l
e
A
.
5
.
Ta
b
l
e
A
.
4
-
S
u
p
p
l
y
S
i
d
e
O
p
t
i
o
n
s
(
E
a
s
t
)
Un
i
t
S
i
z
e
M
W
1s
t
De
s
i
g
n
Pla
n
n
i
n
g
Fo
r
c
e
d
Ma
i
n
!
.
An
n
l
l
!
\
l
I
Em
i
s
s
i
o
n
s
Ca
i
t
a
l
C
o
S
l
-
SI
k
W
I
Av
e
r
a
g
e
MW
s
Ye
a
r
Ap
p
r
o
x
i
m
a
t
e
Pl
a
n
t
L
i
f
e
Ma
r
g
i
n
Ou
t
a
g
e
Ou
t
a
g
e
He
a
t
R
a
t
.
I
S0
2
NO
x
1
11
g
CO
2
Un
i
t
De
s
e
r
i
n
t
i
o
n
Ca
n
, (
M
W
)
Av
a
i
l
.
Av
a
i
l
.
Lo
e
a
t
i
o
n
in
Y
e
a
r
s
Co
n
t
r
i
b
n
t
i
o
n
RO
l
e
Ra
t
e
BT
U
I
k
W
h
I
Ib
s
I
M
M
B
T
U
(
H
g
'
I
b
s
f
T
h
n
,
)
Co
s
t
'1
J
i
)
~
$
t
(
$
f
4
~
L
Q
i
l
f
!
~
!
\
"
J
~
$
9
9
J
)
;
;
~
,
j
'
:,
,
:
;*
J
i
l
l
1
i
i
1
:
'
-
-
,g
f
"
'l
i
'
~
;
J
Co
a
l
PC
S
u
b
e
r
i
t
i
e
a
l
57
5
91
%
20
1
2
Uta
h
10
0
%
94
8
3
05
9
07
2
0.
6
0
0
20
5
,
51
,
68
7
PC
S
u
n
e
r
e
r
i
t
i
e
a
l
.
57
5
91
%
20
1
2
Uta
h
10
0
%
12
9
05
9
07
2
60
0
20
5
.
73
5
Gre
e
n
f
i
e
l
d
P
C
57
5
91
%
20
1
2
Uta
h
10
0
%
48
3
05
9
07
2
60
0
20
5
,
72
9
IG
C
C
I
n
o
C
a
r
b
o
n
n
r
e
n
a
r
a
t
i
o
n
)
51
9
89
%
20
1
3
Uta
h
10
0
%
86
5
7
01
6
01
1
0.4
7
0
20
5
,
95
7
IG
C
C
I
C
a
r
b
o
n
n
r
e
n
a
r
a
t
i
o
n
)
51
9
89
%
20
1
3
Uta
b
10
0
%
65
7
01
6
01
1
47
0
20
5
,
52
,
15
3
lG
C
C
I
C
a
r
b
o
n
n
r
c
o
o
r
a
t
i
o
n
)
51
9
89
%
20
1
3
Uta
b
10
0
%
65
7
01
6
01
1
0.4
7
0
20
5
,
52
1
5
3
Br
o
w
n
f
i
e
l
d
P
C
S
u
b
e
r
i
t
i
e
a
l
57
5
91
%
20
1
2
Wv
o
m
i
n
e
10
0
%
99
5
7
05
9
07
2
0.6
0
0
21
0
.
51
,
89
8
Br
o
w
n
f
i
e
l
d
P
C
S
u
o
e
r
e
r
i
t
i
e
a
l
'
57
5
91
%
20
1
2
Wv
o
m
i
n
e
10
0
%
58
6
05
9
07
2
60
0
21
0
,
51
,
95
2
Na
t
u
r
a
l
G
a
s
Mi
e
r
o
t
u
r
b
i
n
e
s
98
%
20
0
8
Uta
h
10
0
%
32
1
00
1
10
1
25
5
11
8
,
52
,
4
2
9
Fu
e
l
C
e
l
l
s
22
5
98
%
20
0
8
Ut
a
b
10
0
%
56
8
8
11
8
,
51
.
5
7
6
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
c
r
o
90
%
20
0
9
Ut
a
h
10
0
%
22
5
00
1
01
8
25
5
11
8
,
56
9
9
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
e
o
o
l
e
d
A
c
r
o
S
C
C
T
.
90
%
20
0
9
Ut
a
h
10
0
%
90
7
00
1
01
1
25
5
11
8
,
56
0
5
Gr
e
e
n
f
i
e
i
d
i
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
e
i
n
e
s
16
5
92
%
20
0
9
Ut
a
h
10
0
%
87
0
0
00
1
02
0
25
5
11
8
.
56
4
9
Gr
e
e
n
f
i
e
l
d
S
C
C
T
F
r
a
m
e
12
Fr
a
m
e
"
28
1
92
%
20
0
9
Ut
a
h
10
0
%
11
0
5
2
00
1
03
2
25
5
11
8
,
54
2
9
Gre
e
n
f
i
e
l
d
C
C
C
T
12
x
I)
.
I
W
e
t
C
o
o
l
i
n
e
)
'
45
1
92
%
20
1
0
Ut
a
h
10
0
%
71
8
6
00
1
01
1
25
5
11
8
,
57
8
7
Gr
e
e
n
f
i
e
l
d
C
C
C
T
-
W
e
t
D
u
c
t
F
i
n
n
o
2x
l
o
r
l
x
l
"
11
0
92
%
20
1
0
Ut
a
h
10
0
%
86
8
00
1
Oi
l
25
5
11
8
,
52
0
9
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
I
-
lO
r
v
C
o
o
l
i
n
e
)
43
0
92
%
20
1
0
Ut
a
h
10
0
%
7,4
6
2
0.
0
0
1
01
1
25
5
11
8
,
58
0
7
Gre
e
n
f
i
e
l
d
C
C
C
T
D
~
C
o
o
l
-
D
u
c
t
F
i
n
n
e
2
x
I
10
5
92
%
20
1
0
Ut
a
h
10
0
%
51
2
00
1
01
1
25
5
11
8
.
52
1
0
Gr
e
e
n
f
i
e
l
d
C
C
C
T
Ilx
I)
-
I
W
e
t
C
o
o
l
i
n
o
'
21
8
92
%
20
1
0
Uta
h
10
0
%
24
6
00
1
01
1
25
5
11
8
.
58
5
3
Gr
e
e
n
f
i
e
l
d
W
e
t
C
C
C
T
-
D
u
c
t
F
i
r
i
n
e
r
1
x
92
%
20
1
0
Uta
h
10
0
%
86
8
00
1
01
1
25
5
11
8
,
52
0
9
Bro
w
n
f
i
e
l
d
C
C
C
T
ID
r
v
2x
I
)
'
43
0
92
%
20
1
0
Uta
h
10
0
%
46
2
01
1
25
5
11
8
.
57
8
6
Br
o
w
n
f
i
e
l
d
C
C
C
T
-
D
u
c
t
F
i
r
i
n
e
10
5
92
%
20
1
0
Uta
h
10
0
%
51
2
01
1
25
5
11
8
.
52
1
0
Oth
e
r
-
R
e
o
e
w
a
b
l
e
s
Win
d
N/A
20
0
8
Ea
s
t
20
%
N/
A
N/A
N/A
51
,
4
8
1
Ge
o
t
h
e
r
m
a
l
l
B
l
u
n
d
e
l
l
E
x
o
a
n
s
i
o
n
)
97
%
20
0
9
Ea
s
t
10
0
%
N/A
65
0
Pu
m
o
e
d
S
t
o
r
a
c
e
20
0
N/
A
20
1
0
Ea
s
t
10
0
%
N/A
N/
A
13
9
2
4
10
0
Q.4
0
0
00
0
20
4
,
58
9
3
Co
m
p
r
e
s
s
e
d
A
i
r
E
n
c
r
~
S
t
o
r
a
o
e
(
C
A
E
S
)
32
3
92
%
20
1
0
Wv
o
m
i
n
e
10
0
%
36
3
00
1
01
1
25
5
11
8
,
57
9
9
Cu
s
t
o
m
e
r
O
w
n
e
d
S
t
a
n
d
b
v
G
e
n
c
r
a
t
i
o
n
10
0
%
20
0
6
Ea
s
t
10
0
%
N/A
N/
A
50
0
N/
A
N/
A
N/
A
N/
A
51
3
8
So
l
a
r
20
0
N/
A
20
1
1
Uta
h
67
%
N/A
N/
A
N/A
55
,
28
2
-
5
9
-
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
Ta
b
l
e
A
.
4
-
S
u
p
p
l
y
S
i
d
e
O
p
t
i
o
n
s
(
W
e
s
t
)
Un
i
t
S
i
z
e
M
W
1s
t
De
s
i
g
n
Pl
a
n
n
i
n
g
Fo
r
c
e
d
Ma
i
n
!
.
An
n
u
a
l
Em
i
s
S
I
o
n
s
I
C
a
e
i
t
a
l
C
o
"
.
5/k
W
Av
e
r
a
g
e
MW
s
Ye
a
r
'W
~
'
.
~
Pla
n
t
L
i
f
e
Ma
r
g
i
n
Ou
t
a
g
e
Ou
t
a
g
e
He
a
t
R
a
t
e
I
SO
2
I
NO
.
CO
2
Un
i
t
De
s
c
r
i
p
t
i
o
n
Ca
p
,
(
M
W
)
Av
a
i
l
.
Av
a
i
l
.
Lo
e
a
t
i
e
n
in
Y
e
a
r
s
Co
n
t
r
i
b
u
t
i
o
n
_R
a
t
e
BT
U
/
k
W
h
r
Ib
s
l
M
M
B
T
U
(
l
I
g
:
I
b
s
I
T
b
t
u
)
Co
s
t
it
t
%
'
%
f
u
\
f
j
~
;
,
'~
.
:
w
.
,
~li
~
!
i
!
J
1
r
p
n
!
J
.
g
)
j
8
f
l
~
$
i
)
0
:
1
' -.IT
:
"
~!
"
,
Na
t
u
r
a
l
G
a
s
Mi
c
r
o
t
u
r
b
i
n
e
s
0.
0
2
98
%
20
0
8
No
r
t
h
w
e
s
t
10
0
%
14
3
2
1
00
1
10
1
25
5
11
8
,
$2
.
17
4
Fu
e
l
C
e
l
l
s
22
5
98
%
20
0
8
No
r
t
h
w
e
s
t
10
0
%
68
8
11
8
,
57
6
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
c
r
e
90
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
22
5
00
1
01
8
25
5
11
8
,
55
9
5
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
c
o
o
l
e
d
A
c
r
o
S
C
C
T
90
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
89
0
7
00
1
01
1
25
5
11
8
,
55
4
1
Gr
e
e
n
f
i
e
l
d
S
C
C
T
F
r
a
m
e
12
Fr
a
m
e
"
31
5
92
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
11
M
2
00
1
03
2
25
5
11
8
,
53
8
4
Gre
e
n
f
i
e
l
d
I
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
.
i
n
e
s
16
5
92
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
87
0
0
00
1
02
0
25
5
11
8
,
56
4
9
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
.
I
.
IW
e
t
Co
e
l
i
n
a
)
.
50
4
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
18
6
00
1
01
1
25
5
11
8
.
57
0
4
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
.
2
.
I
.
IW
e
t
Co
o
l
i
n
g
)
12
3
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
86
8
00
1
01
1
25
5
11
8
,
51
8
7
Gr
e
e
n
f
i
e
l
d
C
C
C
T
Il
x
l
)
.
IW
e
t
Co
o
l
i
n
g
)
24
3
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
24
6
00
1
01
1
25
5
11
8
,
57
6
3
Gre
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
g
I
x
I
.
(
W
e
t
C
o
o
l
i
n
a
)
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
86
8
00
1
01
1
25
5
11
8
,
51
8
7
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
I
.
f
D
r
v
C
o
o
l
i
n
g
)
48
1
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
7,
4
6
2
00
1
01
1
25
5
11
8
,
57
2
2
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
g
2
x
I
.
(
D
r
v
C
o
o
l
i
n
a
)
11
7
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
51
2
00
1
01
1
25
5
11
8
,
51
8
8
Ot
h
e
r
-
R
e
n
e
w
a
b
l
e
s
Wi
n
d
50
I
NI
A
I
20
0
8
T
No
r
t
h
w
e
s
t
I
20
%
NI
A
NIA
51
,
47
4
Ge
o
t
h
e
r
m
a
l
3
1
94
%
20
0
9
No
r
t
h
w
e
s
t
I
10
0
%
NI
A
31
0
Co
m
n
r
e
s
s
e
d
A
i
r
E
n
e
r
g
v
S
t
o
r
a
g
e
(
C
A
E
S
)
36
1
~~
2
5
10
0
0
/
li
i
l
i
r
o
Ol
8
11
8
.
rlk
1
\
-
.
i
f
i
w
,
J
1
~
l
!
~
I
~
~
\
;
Q
I
i
t
J
!
r
!
i
8
~
(
$
~
j
t
i
i
%
Y
&t
I
~
j
g
~
,
:;
'0
'
Na
t
u
r
a
l
G
a
s
Mi
c
r
o
t
u
r
b
i
n
e
s
98
%
20
0
8
No
r
t
h
w
e
s
t
10
0
%
32
1
00
1
10
1
25
5
11
8
,
$2
.
06
5
Fu
e
l
C
e
l
l
s
22
5
98
%
20
0
8
No
r
t
h
w
e
s
t
10
0
%
68
8
11
8
.
57
6
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
c
r
e
90
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
22
5
00
1
01
8
25
5
11
8
,
55
6
6
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
e
o
o
l
e
d
A
e
r
o
S
C
C
T
10
2
90
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
90
7
00
1
01
1
25
5
11
8
,
55
1
4
Gr
e
e
n
f
i
e
l
d
S
C
C
T
F
r
a
m
e
12
Fra
m
e
"
33
1
92
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
05
2
00
1
03
2
25
5
11
8
,
53
6
5
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
o
i
n
e
s
16
5
92
%
20
0
9
No
r
t
h
w
e
s
t
10
0
%
70
0
00
1
02
0
25
5
11
8
,
56
4
9
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
I
-
IW
e
t
Co
o
l
in
.
)
.
53
1
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
18
6
OO
t
01
1
25
5
11
8
,
56
6
9
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
.
2
x
I
-
IW
e
t
Co
o
l
i
n
.
)
12
9
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
86
8
00
1
01
1
25
5
11
8
,
51
7
7
Gr
e
e
n
f
i
e
l
d
C
C
C
T
Ilx
l
)
.
IW
e
t
Co
o
l
i
n
g
)
25
6
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
24
6
00
1
01
1
25
5
11
8
,
57
2
5
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
g
I
x
I
-
IW
e
t
Co
o
l
i
n
g
)
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
86
8
00
1
01
1
25
5
11
8
.
51
7
7
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
l
-
f
D
r
v
C
o
o
l
i
.
.
)
50
6
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
46
2
00
1
01
1
25
5
11
8
,
$6
8
6
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
r
i
n
g
2
x
I
-
(
D
r
y
C
o
o
l
i
n
g
)
12
4
92
%
20
1
0
No
r
t
h
w
e
s
t
10
0
%
51
2
00
1
01
1
25
5
11
8
,
$1
7
9
Ot
h
e
r
-
R
e
n
e
w
a
b
l
e
s
Win
d
NI
A
20
0
8
No
r
t
h
w
e
s
t
20
%
NIA
NI
A
$1
,
47
4
Co
m
b
i
n
e
d
H
e
a
t
&
P
o
w
e
r
I
C
H
P
)
85
%
20
0
6
No
r
t
h
w
e
s
t
10
0
%
10
%
22
0
00
1
08
7
25
5
11
7
.
$6
4
5
Cu
s
t
o
m
e
r
O
w
n
e
d
S
t
a
n
d
b
v
Ge
n
e
r
a
t
i
o
n
10
0
%
20
0
6
Nn
r
t
h
w
e
s
t
10
0
%
NI
A
NI
A
50
0
NI
A
NI
A
NI
A
NI
A
$1
3
8
Cn
m
n
r
e
s
s
e
d
A
i
r
E
n
e
r
g
v
S
t
o
r
a
g
e
(
C
A
E
S
)
38
0
92
%
20
0
8
No
r
t
h
w
e
s
t
10
0
%
12
,
36
3
00
1
01
8
25
5
11
8
,
$6
7
9
-
6
0
-
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
Ta
b
l
e
A
.
5
-
S
u
p
p
l
y
S
i
d
e
O
p
t
i
o
n
s
-
R
e
s
o
u
r
c
e
C
o
s
t
S
h
e
e
t
(
E
a
s
t
)
Ta
b
l
e
A
.
5
r
e
p
r
e
s
e
n
t
s
a
n
e
s
t
i
m
a
t
e
o
f
t
h
e
f
i
r
s
t
-
ye
a
r
r
e
a
l
l
e
v
e
l
i
z
e
d
c
o
s
t
p
e
r
M
W
h
o
f
r
e
s
o
u
r
c
e
s
,
s
t
a
t
e
d
i
n
J
u
n
e
2
0
0
5
d
o
l
l
a
r
s
,
b
a
s
e
d
u
p
o
n
t
h
e
re
s
o
u
r
c
e
s
b
e
i
n
g
p
l
a
c
e
d
i
n
s
e
r
v
i
c
e
i
n
J
u
n
e
2
0
0
6
.
c.
i
"
I
C
o
"
S/k
W
Fi
x
e
d
C
O
S
I
Co
n
v
e
n
t
o
M
i
l
l
s
Va
r
i
a
b
l
e
C
o
s
"
To
,
,
1
To
t
a
l
P.y
m
"
'
t
Ao
o
"
,
1
P
m
!
I
Fi"
d
O
&
M
S
/
k
W
.
Tli
F
i
"
d
C.p
.
d
t
y
TII
F
i
"
d
Le
v
e
l
i
"
d
F
u
e
l
mil
l
s
l
k
W
h
Re
s
o
u
r
c
e
C
o
s
t
De
s
c
r
i
p
t
i
o
n
Ca
p
C
o
s
t
Fa
c
t
o
r
S~
W
.
O&
M
Oth
"
To
l
o
'
S/k
W
.
F"
l
o
r
MiI
I
.
/
k
W
h
I/m
m
B
t
u
MiI
I
"
"
W
h
I
O&
M
I
F
"
t
l
O
t
h
"
Tu
C
r
"
"
"
E"
'
r
n
o
~
o
"
1
(M
i
l
l
s
l
k
W
h
)
fi
W
S
"
r
,
(
SJ
I
t
~
l
O
d
(
l
~
t
i
'
:
i
!
l
~
Co
a
l
PC
S
u
b
c
r
i
t
i
c
a
l
6R
7
R5
%
$
13
2
.
4
4
32
.
37
,
16
9
,
91
%
21
.
2
R
12
2
.
11
.
6
4
1.0
2
39
,
PC
S
u
o
e
r
e
r
i
t
i
c
.
l
.
73
5
R5
%
S
13
6
,
33
,
3R
,
17
4
,
91
%
21
.
9
5
12
2
,
11
.
2
1
39
.
Gr
e
e
n
f
i
e
l
d
P
C
72
9
85
%
S
13
5
,
42
,
47
,
lR
3
,
91
%
22
,
12
2
.
11
.
6
4
1.
0
2
5.4
1
41
.
0
4
IG
C
C
In
o
Ca
r
h
n
n
n
r
e
n
a
r
.
t
i
o
n
)
19
5
7
85
%
$
15
3
.
6
4
62
,
67
.
22
0
,
89
%
28
.
12
2
.
10
,
43
,
IG
C
C
(
C
.
.
b
o
n
n
r
~
a
r
a
t
i
n
n
)
I
I
21
5
3
85
%
S
16
9
,
62
,
67
,
23
6
.
R9
%
30
.
12
2
,
1M
3
45
.
IG
C
C
(
C
.
.
b
o
n
o
r
e
n
"
a
t
i
o
n
)
2
1
15
3
77
%
S
14
5
,
62
,
67
.
21
2
,
89
%
27
.
3
1
12
2
,
10
,
42
,
Br
o
w
n
f
i
e
l
d
P
C
S
u
b
c
r
i
t
i
c
a
l
89
R
85
%
$
14
9
.
42
.
47
.
19
6
,
91
%
24
,
1\
0
,
10
,
1.1
9
42
.
Bro
w
n
f
i
e
l
d
P
C
S
u
n
e
r
e
r
i
t
i
c
a
l
0
95
2
85
%
$
15
3
,
44
,
49
,
20
2
.
91
%
25
.
11
0
,
10
.
5
7
1.1
5
42
,
Na
t
u
r
a
l
G
a
,
Mic
r
n
t
u
r
b
i
n
~
'
24
2
9
11
.
3
6
%
$
27
5
,
45
5
,
45
5
.
73
1
.
0
2
98
%
85
,
56
5
,
80
,
18
4
.
Fu
e
l
C
e
l
l
,
15
7
6
46
%
S
13
3
.
56
.
61
.
5
0
19
4
.
9R
%
22
,
56
5
,
32
.
1.9
4
1.7
0
60
,
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
e
r
o
69
9
24
%
$
64
,
13
,
1.3
5
14
,
79
.
18
%
50
.
56
5
.
57
,
3.
4
9
11
8
,
Gr
e
e
n
f
i
e
l
d
I
n
t
o
r
c
o
n
l
e
d
A
e
r
o
S
C
C
T
.
60
5
24
%
S
55
.
1.3
5
64
,
18
%
40
,
56
5
,
50
.
3
3
10
1
.
2
7
Gre
e
n
f
i
e
l
d
I
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
.
i
n
e
,
64
9
24
%
$
60
,
12
,
1.3
5
14
.
74
.
92
%
56
5
.
49
,
69
,
Gr
e
e
n
f
i
e
l
d
S
C
C
T
F
"
m
e
12
F"
m
e
"
F'"
42
9
97
%
$
34
,
11
.
2
4
1.
3
5
12
,
46
,
18
%
29
.
56
5
,
62
,
5.4
8
3.4
8
10
4
,
Gr
e
e
n
f
i
e
l
d
CC
C
T
l
h
l
\
.
I
W
e
t
Co
o
l
i
n
o
\
0
7R
7
24
%
$
64
,
1.
3
5
10
.
75
,
52
%
16
,
56
5
,
40
,
65
,
Gre
e
n
f
i
e
l
d
C
C
C
T
.
W
e
t
D
u
c
t
F
i
r
i
n
.
Ih
l
or
1
x
1
\
)
20
9
24
%
S
17
,
1.
3
5
21
.
4
0
16
%
15
,
56
5
,
50
,
71
.
2
5
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
l
ID
.
.
.
Co
o
l
i
n
o
)
80
7
24
%
S
66
.
4
2
10
,
1.
3
5
12
,
7R
,
52
%
17
,
56
5
,
42
,
3.3
5
67
,
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
r
v
C
o
o
l
-
D
u
c
t
F
i
r
i
n
'
2
x
l
21
0
24
%
$
17
,
1.3
5
21
.
6
6
16
%
15
.
4
5
56
5
,
53
,
75
,
Gr
e
e
n
f
i
e
l
d
C
C
C
T
(
1
x
l
\
.
I
W
e
t
C
o
o
l
i
n
.
)
85
3
24
%
$
70
,
13
,
1.3
5
14
.
84
.
52
%
18
.
56
5
.
40
,
67
.
Gr
e
e
n
f
i
e
l
d
W
e
t
C
C
C
T
.
D
u
c
t
F
i
r
i
n
e
(
1
x
l
\
20
9
24
%
S
17
,
1.3
5
21
.
4
0
16
%
15
,
56
5
,
50
.
71
.
2
5
Br
o
w
n
f
i
e
l
d
C
C
C
T
0
.
.
.
2
x
1
\
.
7R
6
24
%
$
64
.
1.3
5
70
,
52
%
15
.
5
6
56
5
.
42
,
65
,
Br
o
w
n
f
i
e
l
d
C
C
C
T
-
D
u
c
t
F
i
r
i
n
g
21
0
24
%
$
17
.
1.3
5
21
.
6
6
16
%
15
.
56
5
,
53
,
75
.
4
9
Oth
e
r
-
R
e
n
e
w
a
b
l
e
,
Wi
n
d
48
1
9.
3
2
%
S
13
7
,
41
.
6
4
42
,
18
0
,
33
%
62
.
3
0
(2
0
,
26
)
46
.
Ge
o
t
h
e
r
m
.
l
(
B
l
u
n
d
e
l
l
E
x
n
a
n
s
i
o
n
)
3
1
65
0
14
%
$
11
7
.
80
,
1.3
5
81
.
5
2
19
9
.
4
0
97
%
23
,
21
.
0
9
2.3
4
20
,
26
)
26
.
Pu
m
o
e
d
S
l
o
,
,
'
e
89
3
24
%
$
73
,
10
,
1.
3
5
11
.
8
6
R5
.
4
0
16
%
60
,
45
,
0.5
4
10
9
.
4
4
Co
m
o
r
e
s
s
e
d
A
i
r
E
n
"
"
,
,
v
S
t
o
r
a
.
e
IC
A
E
S
79
9
56
%
$
76
.
1.
3
5
R3
,
25
%
3R
,
45
,
1.4
1
88
.
Cu
s
t
o
m
o
r
O
w
n
e
d
S
l
o
n
d
b
v
G
e
n
o
r
a
t
i
o
n
13
8
15
,
52
%
$
21
.
4
0
21
.
4
0
12
2
,
83
6
,
87
,
20
.
4
8
23
0
,
So
l
a
r
5,
2
8
2
14
%
S
37
7
.
3
7
43
,
43
,
42
0
.
63
%
76
,
76
,
-
6
1
-
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
A
Ba
s
e
A
s
s
u
m
p
t
i
o
n
s
Ta
b
l
e
A
.
5
-
S
u
p
p
l
y
S
i
d
e
O
p
t
i
o
n
s
-
R
e
s
o
u
r
c
e
C
o
s
t
S
h
e
e
t
(
W
e
s
t
)
C,
i
t
a
l
C
o
S
!
S
I
k
W
Fi
x
e
d
C
o
s
t
Co
n
v
e
r
t
t
o
M
i
l
l
s
Va
n
a
b
l
e
C
o
s
t
s
To
t
a
l
To
t
a
l
P'y
m
"
'
t
A"
,
u
o
l
P
m
l
I
Fi"
d
O
&
M
SIk
W
.
Ttl
F
i
"
d
Ca
p
o
o
i
t
y
Tt
l
F
i
"
"
Le
v
e
l
i
z
e
d
F
u
e
l
mi
l
l
s
l
k
W
h
Re
s
o
u
r
c
e
C
o
s
t
De
s
c
r
i
p
l
i
o
n
Ca
p
C
o
s
t
Fa
c
t
o
r
""
W
-
O&
M
0'"
"
To
t
a
l
""
W
.
Fo
o
l
o
,
Mil
l
"
"
W
h
I/
m
m
B
t
u
Mi"
"
"
W
h
O&
M
F"
I
I
O
I
'
"
I
T
~
C~
d
i
"
T
"
"
'
,
,
a
m
m
o
l
(M
i
l
l
s
I
k
W
h
)
_i
~
X
Q
i
;
W
i
J
;
'
(
$
I
i
!
~
Q
p
t
J
J
\
j
1
'
s
i
i
:
1
~
~
Na
t
u
r
a
l
G
a
s
MiC
l
O
t
u
r
b
i
n
e
s
17
4
11
.
36
%
S
24
6
,
40
7
.
40
7
.
65
4
.
98
%
76
.
57
4
.
82
.
17
9
,
Fu
e
l
C
e
l
l
s
57
6
8.
4
6
%
S
13
3
.
56
,
61
.
5
0
19
4
,
98
%
22
,
57
4
.
32
.
1.7
0
62
,
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
e
l
O
59
5
24
%
S
55
,
11
.
9
3
1.
3
5
t3
,
68
,
18
%
43
,
57
4
.
58
.
11
4
.
Gr
e
e
n
f
i
e
l
d
I
n
t
m
o
o
l
e
d
A
e
l
O
S
C
C
T
54
1
24
%
S
50
.
1.
3
5
57
,
18
%
36
.
57
4
,
51
.
1
7
99
,
Gre
e
n
f
i
e
l
d
S
C
C
T
F
r
a
m
e
12
Fr
a
m
e
"
F'"
38
4
97
%
$
30
,
10
,
1.
3
5
11
.
4
1
42
,
18
%
26
,
57
4
,
63
,
6.
3
7
3.4
8
10
4
.
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
i
n
e
s
64
9
24
%
5
53
.
4
6
12
,
1.3
5
14
,
67
.
92
%
57
4
,
49
,
5.5
0
2.7
1
71
.
5
8
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
,
1
.
IW
e
t
C
o
o
l
i
n
,
\
'
70
4
24
%
$
57
,
1.3
5
9.4
6
67
,
60
%
12
,
57
4
,
41
.
2
9
63
.
4
1
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
.
2
x
1
-
I
W
e
t
C
o
o
l
i
n
.
'
18
7
24
%
$
15
,
1.3
5
19
.
16
%
13
,
57
4
.
50
,
72
.
6
6
Gre
e
n
f
i
e
l
d
C
C
C
T
I
I
x
I
'
-
(
W
e
t
C
o
o
l
i
n
.
'
76
3
24
%
5
62
.
11
.
7
6
1.3
5
13
,
75
.
60
%
14
,
57
4
,
41
.
6
3
65
.
4
2
Gre
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
,
I
x
I
-
IW
e
t
Co
o
l
i
n
,
'
18
7
24
%
5
15
.
3
8
1.3
5
19
,
16
%
13
,
57
4
,
50
,
72
.
6
6
G,e
e
n
f
i
e
l
d
C
C
C
T
2
x
l
.
lo
"
,
C
o
o
l
i
n
,
'
72
2
24
%
5
59
.
4
3
1.3
5
11
.
1
0
70
,
60
%
13
.
4
2
57
4
.
5
1
42
,
2.
3
0
65
,
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
8
2
x
I
-
(
D
r
y
C
o
o
l
i
n
,
)
18
8
24
%
5
15
,
1.3
5
19
,
16
%
\3
,
57
4
.
5
1
54
,
5.4
8
77
.
Ot
h
e
r
.
R
e
n
e
w
a
h
l
e
,
Wi
n
d
1.4
7
4
1
32
%
5
13
7
.
30
.
30
I
5
0.
5
0
I
$
30
,
80
I
5
16
8
.
17
1
63
,
99
1
12
0
.
26
)
1
48
.
4
8
Ge
o
t
h
e
r
m
a
l
3
/
31
0
14
%
5
16
5
,
03
1
$
93
.
4
7
1
$
1.3
5
1
5
94
,
82
1
S
25
9
.
85
1
94
%
1
31
.
7
2
1
21
.
0
9
1
$
34
1
12
0
,
26
)
1
1
$
34
.
Co
m
p
r
e
s
s
e
d
A
i
r
E
n
e
r
g
y
S
t
o
r
a
g
e
(
C
A
E
S
)
71
5
1
56
%
$
68
,
36
1
$
95
1
$
1.3
5
30
1
$
74
,
66
1
25
%
1
34
.
09
1
45
,
10
I
s
1.
2
7
1
84
1
$
84
,
19
a
.
-
$
h
~
l
Na
t
u
r
a
l
G
a
s
Mi
c
r
o
t
u
r
b
l
n
e
s
06
5
11
.
3
6
%
$
23
4
,
38
6
.
38
6
,
62
1
.
3
7
98
%
72
.
3
8
57
4
.
5
1
82
,
17
4
,
Fu
e
l
C
e
l
l
s
15
7
6
46
%
$
13
3
,
56
,
61
.
5
0
19
4
,
98
%
22
.
7
0
57
4
.
32
,
1.7
0
62
.
Gr
e
e
n
f
i
e
l
d
S
C
C
T
A
e
r
o
56
6
24
%
$
52
.
11
.
3
3
1.3
5
\2
,
64
.
18
%
41
.
2
0
57
4
.
5
1
58
,
1\2
.
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
e
o
o
l
e
d
A
e
r
o
S
C
C
T
51
4
24
%
$
47
.
5
\
1.3
5
54
,
18
%
34
,
57
4
,
51
.
1
7
97
,
Gre
e
n
f
i
e
l
d
S
C
C
T
F
r
a
m
e
12
F"
m
e
"
36
5
97
%
29
,
9.
5
6
1.
3
5
10
,
39
,
18
%
25
,
57
4
.
5
1
63
,
3.4
8
10
3
.
4
6
Gr
e
e
n
f
i
e
l
d
I
n
t
e
r
n
a
l
C
o
m
b
u
s
t
i
o
n
E
n
.
i
n
e
s
64
9
24
%
60
,
\2
,
1.
3
5
14
.
74
.
92
%
57
4
.
5
1
49
,
72
.
3
9
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
I
.
lW
e
i
Co
o
l
i
n
.
' ,
66
9
24
%
S
55
,
1.3
5
64
.
60
%
\2
,
57
4
,
41
.
2
9
62
,
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
a
2
x
I
.
IW
e
t
C
o
o
l
i
n
"
17
7
24
%
S
14
,
2.4
4
1.3
5
18
,
\6
%
13
,
57
4
.
5
1
50
,
72
.
0
2
Gr
e
e
n
f
i
e
l
d
C
C
C
T
(Ix
l
)
.
IW
e
t
Co
o
l
i
n
a
'
72
5
24
%
S
59
,
11
,
1.3
5
12
,
72
.
2
0
60
%
13
.
57
4
,
41
.
6
3
64
.
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
,
l
x
l
-
IW
e
t
C
o
o
l
i
n
.
'
\7
7
24
%
$
14
,
2.4
4
1.3
5
18
,
16
%
13
,
57
4
.
50
_
72
,
Gr
e
e
n
f
i
e
l
d
C
C
C
T
2
x
I
.
IO
N
Co
o
l
i
n
.
'
68
6
24
%
$
56
.
1.3
5
10
.
67
.
60
%
12
.
57
4
,
42
.
2.
3
0
65
.
Gr
e
e
n
f
i
e
l
d
C
C
C
T
D
u
c
t
F
i
n
n
.
2
x
I
-
(
D
r
v
C
o
o
l
i
n
.
)
17
9
24
%
$
14
.
1.3
5
18
.
16
%
13
,
57
4
.
5
1
54
.
76
.
4
5
Oth
e
r
-
R
e
n
e
w
a
b
l
e
,
Win
d
1,4
7
4
9.
3
2
%
5
13
7
,
30
.
3
0
30
.
16
8
,
30
%
63
.
12
0
,
48
.
Co
m
b
i
n
e
d
H
a
a
t
&
P
o
w
e
r
I
C
H
P
\
64
5
10
.
78
%
$
69
.
5
3
23
,
27
,
96
.
85
%
12
,
57
4
.
52
.
74
.
3
9
Cu
s
t
o
m
e
r
O
w
n
e
d
S
t
a
n
d
b
v
Ge
n
e
"
t
i
o
n
13
8
15
,
52
%
5
21
.
4
0
21
.
4
0
\2
2
,
83
6
.
87
,
20
.
4
8
23
0
,
Co
m
p
r
e
s
s
e
d
A
i
r
E
n
e
r
g
y
S
t
o
"
g
e
(
C
A
E
S
)
67
9
56
%
$
64
,
1.3
5
70
,
25
%
32
.
4
2
35
,
1.2
2
73
,
-
6
2
-
PacifiCorp 2004 IRP Update Appendix A Base Assumptions
Notes for the Supply Side Option Tables A.4 and A.
1/ Without 20% ITC tax benefit
2/ Under carbon preparation, an estimated 70% of the IGCC cost is eligible for a 20% ITC tax
benefit, but is limited to a total of $800 million available for first projects completed.
3/ Cost estimate based on 2004 IRP and currently under review.
Resources selected for a portfolio. Capacity Factor for these resources is based on average
IRP results.
** Customer-owned standby generation capital costs only include the costs to interconnect to
PacifiCorp s system.
Costs are expressed as reallevelized $/MWh costs in CY 2004 dollars.
Table A.6 - Environmental Adders
pc: Pulverized Coal
CCCT: Combine Cycle Combustion Turbine
SCCT: Simple Cycle Combustion Turbine
IGCC: Integrated Gasification Combine Cycle
Brownfield: New facilities at a location with existing infrastructure and plant equipment.
Greenfield: Facilities constructed at a new site with minimal or no existing infrastructure and
plant equipment.
- 63 -
Pa
c
i
f
i
C
o
r
p
20
0
4
I
R
P
U
p
d
a
t
e
Ap
p
e
n
d
i
x
B
Po
r
t
f
o
l
i
o
T
a
b
l
e
s
Fi
g
u
r
e
A
.
8
-
P
a
c
i
f
i
C
o
r
p
I
R
P
T
o
p
o
l
o
g
y
f
o
r
t
h
e
20
0
4
I
R
P
U
p
d
a
t
e
Pa
c
i
f
i
C
o
r
p
I
R
P
To
p
o
l
o
g
y
(2
0
0
4
1
R
P
U
p
d
a
t
e
)
Lo
a
d
..
Ge
n
e
r
a
t
i
o
n
Q:
)
Pu
r
c
h
a
s
e
/
S
a
l
e
M
a
r
n
e
l
s
Co
n
t
r
a
c
t
s
/
E
x
c
h
a
n
g
e
s
II
I
Ow
n
e
d
T
r
a
n
s
m
i
s
s
i
o
n
o
n
P
a
c
i
f
i
C
o
r
p
Ow
n
e
d
T
r
a
n
s
m
i
s
s
I
o
n
o
n
o
t
h
e
r
s
Ch
o
n
a
E
x
p
o
r
t
Du
m
m
y
B
u
b
b
l
e
II
T
h
i
s
i
s
t
h
e
s
a
m
e
f
i
g
u
r
e
a
s
i
n
C
h
a
p
t
e
r
2
o
n
l
y
l
a
r
g
e
r
(
F
i
g
u
r
e
2
.
1
o
n
P
a
c
i
f
i
C
o
r
p
I
R
P
T
o
p
o
l
o
g
y
f
o
r
t
h
e
2
0
0
4
I
R
P
U
p
d
a
t
e
)
.
-
6
4
-
PacifiCorp 2004 IRP Update Appendix B Portfolio Tables
APPENDIX B - PORTFOLIO TABLES
UPDATED PORTFOLIO CAPITAL COSTS
Table B.l shows the estimated capital costs for each of the portfolio generation resources in
millions of 2005 dollars. The capital costs are derived by multiplying the Capital Cost ($/kW) by
the MW capacities from Table AA (Supply Side Options). This capital cost represents the
estimated ratebase addition resulting from building the generation resource and its accompanying
switchyard. The capital costs for transmission reflect the estimated transmission investment
necessary to interconnect the plant switchyard to the Grid along with any additional investment
necessary to deliver the resource to the load center. The actual capital costs will vary.
Table B.1 - Portfolio Capital Costs
2004 IRP Preferred Portfolio
ResoUjoije.tw.JWtW1iWif?~-Reiikiri'(;,ifu iYM2006 iiff2OQ7:09;~09;2009 VO:2010 0Wi2011 ?4!t'201:2 WJ:i'201i3 #,~(t1.8,t:ao1~W;\TC)bd.:C~
Dry Cool CCCT wi Utah-369 369
Greenfield Wet Cool CCCT wi Utah-377 377
Brownfield Coal, Suoercritical Utah-997 997
Brownfield Coal, Sunercritical Wvomino 748 748
Greenfield Wet Cool CCCT wi OF WMAIN 377 377
Generation 3691 9971 377 377 7481 867
Transmission 1501 691 1891 495
Total $5191 0671 3871 4541 9371 363
Portfolio 1
Resi:\1!iiiiI-ReokiriW~:ImV2006 ,"N1j'2OO7,
",:
1')2008 :'iw/2009 12J:2010 iillih'2011 \T1!1i2O12Kw1:201a i1t&2i11a iWfJ20JIi w.1t0ta~
DrYCoOl CCCT wi Utah-369 369
Brownfield Coal, Supercritical Utah-997 997
Brownfield Coal, Suoercritical Wvomina 748 748
Greenfield Wet Cool CCCT wi WMAIN 377 377
Generation 369 3771 997 748 491
Transmission 150 101 691 189 418
Total $150 369 3871 0661 937 909
Portfolio 2
ResOU rJ!iik~4!W_%'ii:R_&ir$0Ji1j!.Reakiri1$#-:::"20 '11:1\2007,it'10"2008\ '/8),2009 0!!J2010 09;'2011 IgW2~2 -;2013 '%$12014 1_f2015 ffit\tol8l!~&iit
Brownfield Coal, Supercritical Utah-997 997
Brownfield Coal, Suoercritical Wvomina 976 976
Greenfield Wet Cool CCCTwl OF WMAIN 377 377
Generation I 1 374 9761 350
Transmission 215 2841 578
Tatal$215 1,453 260 928
Portfolio 3
ResOUiCiiW'ReiilOiit,;;W\\2006 '$3\200.7:!i\'.iti2008 12J2009 fh2010 ii!!82011 '8;1;2012 '\-5,2013 illf;'12014 %\Ki20"M1K*.,.OtaI!COii
IC Aero SCCT Utah-158 158
Brownfield Coal, Supercritical Utah-664 684
Brawnfield Coal, Suoercritical Wvamina 976 976
Greenfield Wet Cool CCCT wi WMAIN 377 377
Generatian 0401 158 976 174
Transmlssian 2151 791 284 578
Total $2151 1191 158\ 1 260 752
Portfolio 4
Resource.ffi:IWi1it_b1WfWfi1i\1l01i0?1i0'ffii0.RiinlOiib'Wi 10%1.20061'0:';1\20070012008 LWC2009 %%\12010 \);8'2011 ,uw.i2012 w;J/201i3 WX:;:2014 09;\2015 ;ji;rbl81"'~
Greenfield Wet Coal CCCT wi OF Utah-377 377
IC Aero SCCT Utah-105 105
Brownfield Coal, Supercritical Utah-664 684
Brownfield Coal, Supercritical Wvomino 976 976
Greenfield Wet Cool CCCT wi WMAIN 377 377
Generation 105 040 377 976\498
Transmission 150 791 2841 590
Total $255 1 1 119 454 2601 088
- 65 -
PacifiCorp 2004 IRP Update Appendix B Portfolio Tables
UPDATED PORTFOLIO LOAD AND RESOURCE BALANCES
Table B.2 - Load and Resource Capacity Report (MW)
Calendar Year
949 949 949
Hydro 108 108 110 107 107 107 106 106 103
DSM 143 153 163 163 163 163 163 130 100
Renewable
Purchase 408 459 109 108 (92)(92)(92)(92)(98)
' 275 274 274 274 274 274 274 274 274
Interruptible , 252 252 252 252 252 252 252 252 252
Transfers ::: 454 454 454 454 454 454 454 454 454
East Existing Resources 295 894 366 362 162 162 161 127 088
RFP Wind 120 120 140 140 140 140
Front Office Transactions 300 450 700 700 700 700 700 700
100 100 100 100 100 100 100 100 100 100
East Planned Resources 140 140 480 630 920 920 940 940 940 940
East Resources 7,435 034 846 992 082 082 101 101 067 028
Load 121 331 602 895 107 368 567 837 091 359
Sale 273 261 237 141 120
East Obligation 394 592 839 036 227 7,467 644 914 168 8,436
East Obligation x PM*353 581 865 091 311 587 790 101 393 701
Update East Position 453 (19)(99)(229)(505)(689)000)(1,326)673)
Hydro 354 326 249 206 237 193 141 138 131 129
DSM
Renewable
Purchase 329 054 770 770 770 720 111 (23)
Transfers (454)(454)(454)(454)(454)(454)(454)(454)(454)(454)
West Existing Resources 561 257 656 613 644 551 858 882 742 840
RFP Wind 120 120 120 120 120
Front Office Transactions 100 400 400 500 500 500 500 500
West Planned Resources 140 480 480 620 620 620 620 620
West Resources 561 297 796 093 124 171 3,478 502 362 3,460
Load 529 649 110 162 214 253 295 360 3,448 516
Sale 166
West Obligation 695 745 206 258 301 340 378 3,443 531 599
West Obligation x PM*249 307 687 747 796 841 885 960 061 139
Update West Position 311 (10)109 346 328 330 (407)(458)(699)(680)
Planned Resources 140 180 620 110 1,400 540 560 560 560 560
Total Resources 996 331 11,642 12,085 206 253 579 603 11,428 11 ,487
Obligation 10,089 337 10,045 10,294 10,527 806 022 357 699 035
Obligation x PM*603 11,887 552 838 107 12,427 675 061 13,454 13,840
Update System Position 393 444 247 100 (175) (1 096)(1,458) (2 025) (2 353)
66 -
PacifiCorp 2004 IRP Update Appendix B Portfolio Tables
PORTFOLIO RESOURCE ADDITION SUMMARY
Table B.3 - Portfolio Resource Addition Summary
Portfolio:Preferred Portfolio
Resource Additions (MW)623 623 198 759 2,409 2,792 792
Net Reserves (MW)907 994 685 2,414 302 644 316 655 522 245
Net Reserves % Of Obligation 19%19%17%23%22%24%21%23%22%19%
Portfolio:Portfolio 1
Resource Additions (MW)623 184 848 231 231
Net Reserves (MW)907 994 685 879 767 069 741 094 961 684
Net Reserves % Of Obligation 19%19%17%18%17%19%16%18%17%14%
Portfolio:Portfolio 2
Resource Additions (MW)188 324 513 113 113
Net Reserves (MW)907 994 685 879 767 634 881 759 843 566
Net Reserves % Of Obligation 19%19%17%18%17%15%17%15%16%13%
Portfolio:Portfolio 3
Resource Additions (MW)188 089 539 139 139
Net Reserves (MW)907 994 685 879 767 634 646 785 869 592
Net Reserves % Of Obligation 19%19%17%18%17%15%15%16%16%13%
Portfolio:Portfolio 4
Resource Additions (MW)262 262 163 813 313 313
Net Reserves (MW)907 994 685 879 941 708 720 059 043 766
Net Reserves % Of Obligation 19%19%17%18%18%16%16%18%17%15%
- 67-
PacifiCorp 2004 IRP Update Appendix B Portfolio Tables
PORTFOLIO SCORECARD RESULTS
Table 804 - Portfolio Scorecard
PREFERRED CANDIDATE PORTFOLIOS
PORTFOLIO Portfolio I Portfolio 2 Portfolio 3 Portfolio 4
VALUE MEASURE
Comparalive PVRR Ranking
Present Value Rev. R"'I t (20 Year $000)16,483,846 16,166,133 16,004 450 16,142 128 16,328,333
Percent Greater Than Lowest PVRR 995%1.010%000%860%024%
IncremenLaI Net Variable Power Cost 13,959,721 157 750 007,035 315 932 267,936
Incremental Real Levelized Fixed Cost 524 125 008 383 997 415 826,196 060,397
Gen. Ca ilal Cost (2004$-millions)
Transmission Cost (2004$-millions)
867
495
174
578
498
590
Emissions (2006-2025 PVRR $000)152,946 107,797 100,549 77,743 110,573
CO, (thousand tons 2010-2025)961 482 950,026 947,970 941 363 950 166
CO, (% of cap) 113%112%112%111%112%
SO, (thousand tons 2006-2025)958 959 957 960 959
SO, (%ofcap) 65%65%65%65%65%
, (thousand tons 2012-2025)016 017 013 016 017
(%ofcap)93%93%92%93%93%
IIg (thousand tons 2010-2025)0026 0026 0026 0026 0026
IJg(%ofcap)55%55%55%54%54%
Market Purchases
2015 HLH
PAC East (% ofload)
PAC East Averaee MW
PAC West (% ofload)4.4%
PAC West Averaee MW
2015 LLH
PAC East (% ofload)
PAC East Avera.e MW
PAC West (% of load)
PAC West Average MW
Market Sales
2015 HLH
PAC East (% of owned Generation)
PAC East Avera.e MW 452 444 451 442 451
PAC West (% of owned Generation)8.4%
PAC West Averaee MW 220 213 207 210 219
2015 LLH
PAC East (% of owned Generation)7.3%
PAC East Avera.e MW 361 360 359 359 360
PAC West (% of owned Generation)
PAC West Average MW 151 153 151 177 178
Unit Capacity Factors
2015
Existin. Coal East 87,87.5%86,88.88.
Existine CCCT East 56.58,55,62.59.4%
Existine SCCT East 10,
IRP Coal East 99.4%99.98,98,98,
IRP CCCT East 14,14,26,
lRP SCCT East 10.
IRP Other East 61.6%61.6%61.6%61.6%61.6%
Existine Coal West 97.97,97,97,97,
Existin. CCCT West 91.5%91.6%91.8%91.7%91.7%
IRP Coal West 97,97,96,97,96,
IRP CCCT West 41.0%42.3%39,48,48,
IRP SCCT West
IRP Other West 61.0%61.0%61.0%61.0%61.0%
Transfers (MWa)
2015
East-West Transfer 5 I
West-East Transfer 2461 283 I 409 I 432 I 3681
. Capacity factors reflect a represenLative dispatch solution constrained by finn transmission rightS, This
is a conservative market modeling assumption.
- 68-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
APPENDIX C - IRP BENCHMARKING STUDY
INTRODUCTION
The purpose of PacifiCorp s IRP benchmarking study, completed in July 2005 , was to critique
PacifiCorp s 2004 IRP against other electric utilities' IRPs and to fonn a picture of the state-of-
the-art concerning IRP modeling and analysis activities. In doing so, PacifiCorp sought to
identify common and notable practices among the IRPs examined, as well as current issues and
challenges for long tenn resource planning. This study also served as the means to compile
useful IRP reference material.
This study is organized into six sections. The "Study Methodology" section describes the
benchmarking study methodology and profiles the companies selected for detailed IRP analysis.
The "IRP Stakeholder Survey" section describes the results of a benchmarking survey question
given to PacifiCorp s IRP stakeholders as part ofa broader satisfaction survey conducted in the
spring of2005, The section "IRP Common Practices" presents observations on various aspects of
the organizations' IRPs , grouped by topic area. The section "IRP Practices of Interest" profiles
IRP methods and reporting elements from the IRPs examined that are of interest for potential use
by PacifiCorp in future IRPs. The section "Hydro Hedging Strategy Comparison" provides a
detailed comparison of hydro modeling hedging strategies employed in a number of IRPs. The
last section
, "
Conclusions , presents an overall assessment of how PacifiCorp s IRP fares against
other utility IRPs and highlights the main areas of distinction,
STUDY METHODOLOGY
The approach taken for the study was to examine in detail eight publicly available electric utility
IRPs consisting of a mix of company characteristics, and to also conduct a cursory review of
other IRPs included in PacifiCorp s IRP inventory. (IRPs were gathered mainly by downloading
them from company and utility commission Web sites; direct requests were made to a number of
organizations as well.) One of the findings from the IRP document search is that relatively few
companies make their IRPs readily available or describe their IRP process on their company
Web site.
A number of criteria were applied to select IRPs for detailed review. The main goal was to
analyze IRPs from a mix of utility types and regions, as well as target IRPs from the western
states. Some of the specific objectives were to obtain an IRP from:
A large multi-state utility,
At least one of the California investor-owned utilities
A utility with a size and structure similar to PacifiCorp.
Although a number of resource plans from organizations other than utilities were gathered and
reviewed (i., California Energy Commission and the Northwest Power and Conservation
Council), only electric utilities were targeted for the detailed IRP reviews. Below are brief
profiles of each utility selected, including the reasons for IRP selection.
- 69-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Public Service Company of Colorado (Xcel Energy), 2003 IRP
Statistics: Installed Capacity - 3 847 MW; Annual Sales - 31 718 GWh; 1.3
million customers
This single state utility, a subsidiary of Xcel Energy, compares to our planning
practices on resource acquisition, resources considered, and the extent of
detenninistic/scenario modeling. Also, PacifiCorp conducts business with this
utility. This company was selected for. their diversified need and alternate
planning methods.
Northern States Power - Minnesota (Xcel Energy), 2004 IRP
Statistics: Installed Capacity - 6 255 MW; Annual Sales - 40 006 GWh; 1.4
million customers
Northern States Power (NSP) was selected for its multi-state territory and similar
planning objectives. It operates in five states and must file IRPs in each of these
states. They also use multiple models for portfolio evaluation. Finally, NSP has a
diverse mix of resources in their portfolio, including Nuclear.
Portland General Electric (2002/2004)
Stats: 975MW; Annual Sales - 18 425 GWh; 1.5 million customers
PacifiCorp s level of interaction with Portland General Electric (PGE) and similar
OPUC requirements makes this plan good for comparison purposes. PGE'
portfolio also includes similar base resources (Coal, Gas, Hydro) to PacifiCorp
although on a smaller overall scale.
Puget Sound Energy, 2005 IRP
Statistics: Installed Capacity - 1 868 MW; Annual Sales - 19 591 GWh; 1.2
million Gas/Electric customers
This April 2005 plan is the newest plan available to PacifiCorp, and therefore
reflects the latest input and market assumptions. Although a smaller electric
utility, Puget Sound Energy (PSE) provided an IRP document with
comprehensive infonnation. Its stakeholder process is also similar to PacifiCorp
in that 10 fonnal meetings were held. Of interest is that the public process also
involved two main advisory groups to cover different aspects of their least-cost
planning process.
Idaho Power, 2004 IRP
Statistics: Installed Capacity - 3 085 MW; Annual Sales - 12 980 GWh; 425 000
customers
PacifiCorp and Idaho Power have joint ownership of plants. Idaho Power also
files their IRP in multiple states (ID, OR), and has a heavy reliance on hydro
- 70-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
resources. With PacifiCorp s resource similarities and close ties, Idaho Power
represents a useful IRP to include in the study.
Southern California Edison, 2003 IRP
Statistics: Installed Capacity - 10 207 MW; Annual Sales - 52 229 GWh; 4.
million customers
Size, modeling software used, and active promotion of policy discussions, makes
Southern California Edison (SCE) a good IRP to include in the study. Some other
items of interest include the following.
This IRP is the first post-energy crisis long-tenn resource plan, and provides a
good example of how California investor-owned utilities are handling the
planning function after a major energy crisis.
. SCE provided an interim plan to "bridge the gap" to acknowledged resolution
of the prefelTed plan which carries the bulk of proposed resources.
. SCE used the same modeling software and consultants (Global Energy
Decisions) to conduct their planning.
LG&E Energy Corporation, 2005 IRP
Statistics: Installed Capacity - 7 065 MW; Annual Sales 28 190 GWh; 855 000
customers
This Company s IRP Uointly filed by LG&E's two operating companies
Louisville Gas & Electric and Kentucky Utilities) was selected due to both
corporate and IRP similarities:
. LG&E Energy s IRP is comprehensive and detailed, and is therefore similar to
PacifiCorp s IRP with respect to the volume ofinfonnation provided.
The amount of installed plant capacity is similar to PacifiCorp s (7,610 MW
net summer capability for LG&E Energy versus 7 987 net plant capability for
PacifiCorp ).
Like PacifiCorp, LG&E Energy has two utility operating companies which are
integrated for IRP modeling purposes (Louisville Gas & Electric and
Kentucky Utilities).
Like PacifiCorp, LG&E Energy is owned by a foreign company: RON AG, a
German company.
Georgia Power/Southern Company Services, 2004 IRP
Statistics (Georgia Power only): Installed Capacity - 13 980 MW; Annual Sales -
000 MWh; 2.1 million customers
The IRP from Georgia Power/Southern Company Services fulfills the requirement
for including an IRP from a "top-ten multi-state utility system. Southern
Company Services is the support organization for Georgia Power and the other
Southern Company operating companies. For IRP preparation, it was tasked with
providing a system-wide resource mix study that was distributed to the operating
companies for IRP and resource allocation decisions,
- 71 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
IRP STAKEHOLDER SURVEY
PacifiCorp distributed an IRP Stakeholder Satisfaction Survey in March 2005. One of the
questions was designed to gauge stakeholder opinion on how PacifiCorp s IRP ranked on overall
quality with respect to other IRPs with which respondents were familiar. The question was
worded as follows:
Given your knowledge about other organization s IRPs, how does PacifiCorp
IRP generally compare in terms of quality?
Respondents were asked to rank PacifiCorp s IRP as: I = Very Unfavorably, 2 = Somewhat
Unfavorably, 3 = The Same, 4 = Somewhat Favorably,S = Very Favorably. PacifiCorp received
a response from 17 of the 20 respondents that completed the survey, The average raw score for
the 17 respondents was 4.29 (out of a maximum score of 5). On a percentage basis, the score was
86 percent. The table below shows the frequency distribution of rankings. Almost 60 percent of
the respondents judged PacifiCorp' s IRP "very favorably" with respect to other IRPs.
:~uall
Very Unfavorably
Somewhat Unfavorably
The Same
Somewhat Favorably
Very Favorably
TOTAL COUNT
IRP COMMON PRACTICES
This section summarizes common practices across the IRPs examined based on various subject
areas, and highlights similarities and differences with respect to PacifiCorp s IRP.
Portfolio Robustness
A number of the IRPs examined refer to portfolio "robustness" or "resiliency . This can be
defined as the ability of a portfolio to do well on cost with respect to other portfolios given a
broad range of future conditions. While nearly all utilities conducted sensitivity analysis using
alternative risk factor values to calculate portfolio cost impacts, few attempted to provide a
systematic quantitative measure of portfolio robustness that combined all infonnation gleaned
from the alternative futures investigated. Some of the IRPs described a rank-order methodology
for assessing comparative resource technology costs, portfolio cost perfonnance, or other
perfonnance measures. For example, Central Vennont Public Service Corporation perfonned a
rank order analysis for eight portfolios against four scenarios using five portfolio perfonnance
measures, Average rank orders and rank "volatilities" were computed for each portfolio across
the scenarios and for each perfonnance measure. The rank orders and rank volatilities for each
portfolio were then plotted for analysis.
Cost-versus-Risk Tradeoff Analysis
- 72-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
PacifiCorp, A vista, and the Northwest Power and Conservation Council (NWPCC) documented
in detail a quantitative cost vs. risk trade-off analysis.12 The NWPCC refers to the concept of the
feasibility space , which represents the population of expected stochastic cost and risk values
for a portfolio given a large distribution of futures assembled from random draws of several
forecast variables, The NWPCC's Portfolio Model reports the "efficient frontier" from such a
feasibility space, basically deriving the least-cost portfolio for each level of risk. These concepts
are shown graphically in the figure below.
..",
Increasma COst ------
Frequency of IRP Filings
With the exception of SCE, all companies submit IRPs on a regular basis, typically every two
years. The next common frequency was a triennial filing, A number of the companies advocated
a three-year IRP cycle to more closely align with their general rate case cycles.
General Modeling Approach
IRPs fell into two general camps regarding modeling approaches used: manual portfolio
development combined with detailed production cost simulation or market simulation models
(for example, PacifiCorp and SCE), and automated portfolio development using capacity
expansion models. All companies relied on detenninistic scenarios for risk or sensitivity
analysis, while about half also incorporated stochastic simulation into the modeling approach.
The two tables below show the production cost simulation and capacity expansions models used
by each organization (PacifiCorp is indicated by light blue shading).
Production Cost/Market Forecasting Models Used for Resource Portfolio Analysis
12 Avista s 2005 IRP, released on July 27 as a draft, adopted the NWPCC's efficient frontier analysis approach as
part of their portfolio optimization modeling effort.
- 73 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Idaho Electric Power AURORA Electric Market Model- EPIS, Inc.
Avista Corporation (2003/2005 IRPs)AURORA Electric Market Model- EPIS, Inc.
Califomia Energy Commission MUL TISYM - Global Energy Decisions
San Diego Gas & Electric RISKSYM - Global Energy Decisions
Southern Company PROSYM - Global Energy Decisions
Pacific Gas & Electric GenTrader- Power Costs Inc. (Generation asset optimization)
PacifiCorp MARKETSYM/PROSYM - Global Energy Decisions
Capacity Expansion Models Used for Resource Portfolio Analysis
Decisions
Reserve Planning Margin
For IRPs that reported a target or minimum reserve Planning Margin, the most common value
was 15% as shown in the table below. Values ranged from a high of 20% to a low of 11 %, with
the average at exactly 15%. Of interest is that the three utilities that assumed a relatively low
Planning Margin-Portland General Electric (12%), Nevada Power (12%) and Idaho Power
(11 % )-had the smallest amounts of installed capacity among those utilities listed in the table.
. .
' TargetReserye PlanrnngElectric Utili ' Marin %Florida Power & Li ht Southern California Edison Duke Power
Public Service Com an of Colorado Northern States Power Avista Co oration PacifiCo San Die 0 Gas & Electric 15*Southern Com an LG&E Ener Portland General Electric Nevada Power Idaho Power
*Planning Margin allowed to vary in 15%-17% range until 2006; set to 15% for 2006-14.
A number of the utilities, including PacifiCorp, conducted economic/Loss of Load Probability
studies to detennine the cost of reducing unserved energy at various Planning Margin levels. A
simple-cycle CT was used as the basis for the carrying cost of building incremental capacity.
These studies supplemented the Planning Margin selection process. For example, Southern
Company pointed out that corporate perceptions of acceptable risk, industry experience, and
operator input were also factors in their decision to select a 15% Planning Margin,
Stochastic Simulation and Risk Measurement
Only a number of companies utilized stochastic simulation in their modeling processes. In
addition to PacifiCorp, stochastic modeling via Monte Carlo simulation was used by four of the
- 74-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
utility companies-PSE, NSP, SCE, and PGE-as well as NWPCC. (A vista also incorporated
Monte Carlo simulation for their 2005 IRP released in late July.) NSP only modeled its load
forecast as a stochastic parameter, while the rest of the organizations that conducted stochastic
simulations modeled at a minimum load, gas prices, and electricity prices as stochastic
parameters. NWPPC and PSE used the same modeling approach and risk measure: TailVaR9o,
defined as the average value for the worst 10 percent of outcomes.
Resource Screening
The majority of IRPs reviewed used a levelized bus bar cost analysis to help screen supply-side
technologies for more detailed evaluation in resource portfolios. The level of detail in describing
resources and the justification for including them in portfolio analysis was mixed. PacifiCorp
excelled at reporting each technology s cost and perfonnance attributes, but was less clear than
some of the other IRPs in describing its technology selection process.
Nearly all companies relied on consideration of qualitative factors to help select resource
candidates. Typically, the screening consisted of a cost screening followed by a feasibility
screening that considered a set of qualitative factors. The most often cited qualitative factors
included technology maturity and environmental impacts. Others cited include construction risk
(lead-time requirements), operational risk, operational flexibility, and the need to meet state or
corporate resource goals (i., Renewable Portfolio Standards). One utility, Puget Sound Energy,
excluded all resources defined as "emerging technologies" or whose economics were driven
predominately by project-specific assumptions.
Modeling of CHP Resources
Those utilities that modeled CHP resources as a supply-side option did so by expressing CHP as
a block resource based on a target or maximum achievable MW potential for the service
territory. PacifiCorp s CHP modeling is consistent with this approach. Puget Sound Energy did
not evaluate CHP projects because they depend on project-specific economic assumptions and
are therefore not suitable for comparison with generic technologies. LG&E Energy evaluated
CHP, standby generation, and other distributed generation technologies as DSM resources using
a qualitative screening process that was followed by a program cost-effectiveness evaluation
using EPRI's DSManager screening model. Noteworthy is that none ofLG&E's CHP/distributed
generation resource options made it to the cost-effectiveness screening phase.
few utilities provided extensive discussion of CHP development issues in their service
territories. PGE identified the following current hurdles to CHP projects: (I) long-tenn
commitment of a steam host, (2) adequate funding capability, (3) investment required to meet
FERC interconnection standards, (4) requirement for finn power guarantees, and (5) contract
provisions needed to account for cost risks of dispatching variability. Nevada Power mentioned
that a high penetration of CHP can be expected to lower their system load factor and increase
average costs to serve remaining load.
Resource Diversification Strategy
Several IRPs explicitly stated that a main portfolio development goal was to have a diversified
mix of resources or to increase fuel diversity. Parallels with the general investment strategy of
spreading investments to reduce risk were cited (e., PGE). For most IRPs that didn't rely on a
portfolio optimization model, the resource diversification criterion was the primary detenninant
for developing portfolios manually for detailed evaluation. Several companies analyzed
- 75-
PacifiCorp
--:
2004 IRP Update Appendix C - IRP Benchmarking Study
bookend" portfolios composed of one resource type (i., all market purchases, coal, CCCT
etc.) to show the comparative benefit of new resource diversification. In PacifiCorp s IRP, most
portfolios were evaluated for incremental impacts of single resource changes as opposed to a
complete bookends analysis. A few utilities cited the goal of developing a resource mix with
different "commitment" lengths.
Coal versus Gas Resources
For IRPs that included candidate coal resources in their portfolio evaluations, coal resources
were generally cited as the least-cost baseload resource under expected and high gas price
scenarios. Notably, Southern Company Services concluded that CCCTs were the resources
choice for incremental additions based on their model assumptions. A number of utilities cited
the ability of coal resources to mitigate the cost volatility of gas-intensive portfolios.
Virtually all the IRPs discussed the risks of future carbon control costs. However, it was not
possible to glean from the IRPs what influence it had on the makeup of resources in each utility'
preferred portfolio. Although NSP considered coal to be the least-cost resource, it noted that
portfolio modeling could not distinguish a clear economic winner between baseload gas (CCCT)
and coal, and that non-cost factors would tip the balance.
Transmission Resources
All IRPs included a discussion on existing transmission infrastructure and transmission planning
to meet forecasted load obligations. While several other IRPs provided a more comprehensive
discussion of their transmission systems, PacifiCorp was one of the few companies that provided
a significant amount of detail on how transmission is modeled, as well as transmission costs
associated with supply-side resource alternatives.13 None of the IRPs analyzed transmission
projects as alternative supply-side options, such as transmission built to access markets rather
than serve a specific supply-side resource. Some of the utilities factored in the costs of
transmission projects to derive the portfolio cost, with costs fixed for all portfolios. Four IRPs-
PacifiCorp, Puget Sound Energy, Southern Company, and Avista (2005 IRP)-each ran one
transmission-related portfolio scenario. PSE and Avista constructed simple RTO/regional
planning scenarios with a priori assumptions regarding RTO benefits (accelerated transmission
availability and/or lower transmission pricing). Avista's scenario assumed a transmission capital
cost reduction of 30 percent. Southern Company constructed an "increased transmission
constraint" scenario to look at impacts on export capability.
Regarding transmission planning and availability issues, many IRPs cited transmission
constraints as a foremost problem with respect to resource planning. Of interest was NSP'
statement that transmission interconnection request and Transmission Service Request (TSR)
processes make portfolio planning difficult, and are not well-suited to the IRP or RFP processes.
It cited the long lead-time for completing the transmission studies and the complications and
delays caused by many generation bidders submitting interconnection requests to the Midwest
Independent System Operator (MISO).14 NSP cited the cost recovery and allocation implications
of making investments in regional transmission projects as opposed to local projects.
13 Idaho Power also reported transmission investment costs for each resource.14 In response to these problems, MISO submitted to the FERC a "group study" proposal that bypasses queue order
considerations to support the state-wide competitive bid process. Although initially rejected by FERC, the group
study concept was later resurrected.
- 76-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Wind Resource Modeling
Most of the organizations that modeled wind resources specified them as fixed quantities based
on corporate or state-level mandated targets (i., Renewable Portfolio Standards), and then
conducted sensitivity analysis, such as assuming lower or higher penetration levels with respect
to the targets. For example, San Diego Gas & Electric s portfolio includes a fixed amount of
wind and other renewables to meet the 20% electric generation RPS target. The timing and
technology mix was based upon infonnation obtained from its 2002 renewable Request for Offer
(RFO) process, other sources, and corporate judgment. The renewable costs were based on
existing long tenn contract pricing, and discussions with renewable developers, PSE modeled
four portfolios that assume a state RPS is in place, consisting of one with fixed renewable
resources at 10% of load by 2013 and three with renewable resources at 15% of load by 2020.
Idaho Power tested portfolios using a small number of fixed wind capacity levels: 1 000 MW (50
MW capacity credit), 350 MW (18 MW capacity credit), and 100 MW (5 MW capacity credit).
In the case of SCE, they assumed a general renewables supply shape without distinguishing a
specific mix of technology types.
For those utility IRPs that discussed percentage capacity contributions for wind, PacifiCorp was
near the top at 20%. A vista, for their 2005 IRP, used a value of 25%. The next highest level after
PacifiCorp was NSP at 13.5%, Idaho Power used a 5% contribution, while LG&E Energy
assumed no contribution. Average annual capacity factors ranged from 27% (SCE) to 35%
(Idaho Power and PSE), with PacifiCorp at 28.9%.
NSP provided an extensive discussion of wind resource modeling, given that they are
aggressively pursuing wind projects due to several state legislative mandates to incorporate wind
resources into their system. NSP modeled wind in three steps using the PROVIEW optimization
module. After optimizing a portfolio with thennal-only resources, they developed a reference
case portfolio by optimizing wind resources up to annual limits defined by NSP's Renewable
Energy Objective.ls They found that the addition of wind caused in-service dates of intennediate
load resources to be pushed back, while the dates for peaking resources were pushed up. Next
NSP allowed the model to optimize wind resources subject to only a "penetration" cap of 15% of
peak load. The company found that the more restrictive conditions of the REO increased the
portfolio PVRR by about $95 million. Finally, they conducted scenario analysis assuming wind
contributes 50% and 75% of new installed capacity under various assumptions concerning PTC
renewal and externality costs. Some of more interesting conclusions are as follows:
In lock-step with PacifiCorp s view, NSP believes that it is important to gain operating and
market experience before making any decisions to go higher than their current plan to push
wind generation to 15% of annual peak load.
Transmission availability and continuation of the PTC are critical success factors for meeting
NSP's aggressive wind development targets.
15 The Renewable Energy Objective stems from a 2001 state law requiring utilities to make a good faith effort to
acquire at least one percent of retail sales from renewables, and to increase the amount by one percent each year
until 10% is reached.
- 77-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
They cite a weakness of using Strategist for evaluating wind resources: it can t evaluate
dispatch costs at the hourly level, and therefore underestimates portfolio PVRR.
Most of the IRPs cited adequate transmission resources as a limiting factor or major concern for
wind development. For example, PGE stated that transmission issues were a significant factor in
all wind projects proposed under their RFP.
Demand Side Management Resource Modeling
A minority of utilities chose to directly model DSM resources along with supply-side resources
in their portfolio evaluations. Even some of the utilities that used a resource optimization model
for their IRPs declined to integrate DSMprograms into the optimization runs, For example
PSCo did not model DSM at all using their PROVIEW optimization model. The reasons for the
decision to exclude DSM were (1) the lack of standard DSM program cost and perfonnance data
that were comparable to supply-side resources, and (2) the need to limit resource options due to
optimization processing time, In lieu of DSM resource modeling, PSCo intended to evaluate
DSM as part of the solicitation process mandated by the Colorado Commission. In the case of
LG&E Energy, the Company conducted a manual portfolio building process somewhat similar to
PacifiCorp s; supply-side resources were deferred and DSM programs added to detennine if
PVRR was reduced. If the DSM program reduced PVRR, it was then included in the preferred
resource plan. The rationale for this approach was that the principal benefit of DSM is to delay
supply-side expansion and "not reorder it"
For utilities that directly evaluated supply- and demand-side options in their resource
optimization models, the typical approach was to pre-screen DSM programs for cost-
effectiveness, and then include the program winners into integrated supply- and demand-side
optimization runs. For example, Southern Company built an optimal "benchmark" supply-side
resource plan for the combined operating companies using the PROVIEW optimization model
and then added pre-screened DSM resources for final optimization runs.
Disclosure of IRP Infonnation
A number of IRPs that were made publicly available had some infonnation withheld (redacted).
For example, three of the eight IRPs included for the detailed analysis had data redacted from the
public version of their IRPs, For PacifiCorp s entire inventory of23 IRPs, 7 (or almost one-third)
had data redacted. Although fuel prices and technology cost assumptions were the most
frequently withheld, a few companies, such as SCE and Southern Company Services , withheld
nearly all numerical assumptions and inputs, as well as the preferred portfolios themselves.
Load Forecasting
A number of utilities detennined optimal portfolios for differing load growth assumptions. (In
contrast, PacifiCorp does not currently model the influence of load forecast variations on
resource selection). For example, LG&E Energy stated that the type, timing, and size of
resources are significantly influenced by the load forecast. Consequently, they use base, low, and
high load forecast sensitivities in capacity expansion model runs.
Resource Flexibility
16 The implication is that an hourly dispatch model is needed to more accurately estimate the costs impacts of wind
on a resource portfolio.
- 78-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
A few of the utilities mentioned the benefit of developing their preferred portfolios with smaller
short lead-time resources as a hedge against the risks associated with large plants and immediate
investment commitments. For example, Idaho Power stated that it largely followed the advice of
its IRP Advisory Council which recommended such a strategy, Portland General Electric also
cited its preference to acquire five- to IO-year fixed price power purchase agreements to provide
time in which to evaluate developments in natural gas supply (including the development of
West Coast LNG facilities), renewable project costs, and coal resources. Notably, none of the
IRPs that championed the "smaller is better" resource strategy directly quantified the relative
benefits and risks of such a strategy. Idaho Power itself referred to resource timing and
commitment as a qualitative risk factor.
CO2 Mitigation Costs
Nearly all the IRPs discuss the risks and current status of CO2 mitigation initiatives. About half
of the IRPs conduct sensitivity analysis with varying CO2 adder levels, while a minority of them
assume a non-zero CO2 externality cost as the base case assumption for portfolio cost
comparison. The table below shows the IRP base case CO2 cost values for selected companies,
Com an IRP
Idaho Power
Public Service Com an
LG&E Ener
PacifiCorp
Miscellaneous
IRPs cited portfolio costs in dollars, dollarslMWh, or both; the unit cost method was cited in
one IRP as a superior cost measure because it accounts for portfolios with different MW
SIzes.
For portfolio cost comparisons, LG&E Energy considered portfolios to be economically
equivalent with their least cost portfolio if their PVRRs were within 0.5 percent of the
minimum PVRR. Coincidently, PacifiCorp used the same PVRR difference criterion as one
of the factors for selecting the portfolios for risk analysis.
Southern Company assumed the same capacity size for all resources modeled using their
portfolio optimization model (300 MW), Their rationale was that with different sized units
the PROVIEW optimization module would be biased towards those units with sizes that
meets or slightly exceed the reserve margin constraint. That is, a smaller, higher incremental
cost unit would be selected over a larger, less costly unit because the smaller unit more easily
meets the reserve margin constraint.
- 79-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
IRP PRACTICES OF INTEREST
This section, organized by company, presents IRP procedures, modeling methods, and report
elements that stand out from others analyzed, or are of interest for potential use by PacifiCorp in
future IRPs.
LG&E Energy Corp
Planning Margin/Resource Adequacy Evaluation
LG&E Energy used the StrategistTM portfolio optimization model to analyze the cost/risk
tradeoff for various planning reserve margin levels, It conducted numerous portfolio
optimizations with a range of input variables. The reserve margin was selected based on the
frequency of least-cost optimizations associated with each reserve margin level. LG&E Energy
modeling approach was as follows:
1. They developed 24 "key variable" scenarios with a combination of the following input
sensitivities: coal unit availability, baseload combustion turbine availability, load forecast
unserved energy cost per kWh , and availability of market purchases (200 MW of week-day on-
peak). For the unit availability sensitivities, the Equivalent Forced Outage Rates (EFOR) for coal
and CT units were reduced by 5% and 10% respectively to derive the "Low" availability
scenarios,
The table below, extracted from the IRP, shows the combinations of inputs being tested.
Ui ti eKe v . bl E IetttOD o.
~,.
ana va gate
I i...'ombustioIJ.U~.:I 5"-1.
(;4)liIUllil Turbin~UJoid EDct8Y Purclra~
Series h Avp;hbilitv Aval1a1ri)itv ForCQIst CoS! ($/..WI11 Modeled
Sa....bag )110
8ase Base
I'IAse Bas;c.
I.n,o.'BB!Ot
I"""Rose
lHN Base II QBt,
Higb
B,...:Hlith
Hi;!)
!..ow Base
Ba2 lAw 0......
\...In.'OaK.
~....
11-Ii-Ye.
11-YI;!;
Base Ye.
L....,Base Ye.
8woc Yti5
tow Bose a....Yes
aal't II...!:lip Yes
Base !'i-H;(iIi
Base Dase High
Low Vt,.
IAJw'&so Yes
Bag Low Yes
17 LG&E Energy used the same EPRI study that PacifiCorp cited for the "Bathtub" chart (Appendix N, page 221).
The derived average unserved energy cost was $11 000/MWh.
- 80-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
2. The Company then conducted resource mix optimizations using the same input combination
series ) for minimum reserve margin levels starting at 7% and finishing at 18% in 1%
increments. A total of 288 optimizations were conducted: 24 series x 12 reserve margin levels.
3, A frequency distribution of the PVRRs of the lowest-cost resource mixes for each reserve
margin level was developed. Lowest-cost mixes were defined as those with PVRRs within 0.
of the least-cost mix (the "economically equivalent range ). The table below shows the
frequencies of low-cost PVRRs for each series by minimum reserve margin level.
Total Number of Times Reserve l\'
Ide,ut16ed In ~nomjcall~' Equivalent Range
(AJI
Mitij~~t.MM uoain
7%\8%9'Y9IHYVo 11%tZ%1;3%14%15%16%11"/;,1$%
NQMm~t .o
WjIt!M~/:1 1.1
Total (All)112
4. The optimal reserve margin range was detennined at 12%-14% based on the frequency
distribution. A reserve margin of 14% was selected as the IRP planning criterion because it
results in higher system reliability with an insignificant increase in cost.
Cost-Effective DSM Screening
LG&E Energy provided a detailed discussion on how cost-effective DSM targets were
established. The Company conducted a two-stage DSM evaluation. The flTst phase, qualitative in
nature, involved a DSM advisory group and outside participants to assess potential programs
using four criteria: customer acceptance, technical reliability, cost-effectiveness of energy
conservation, and cost-effectiveness of peak demand reduction. These criteria were weighted at
25%, 15%, 25%, and 35%, respectively. More than 100 programs were evaluated in the
qualitative screening. The 23 programs that passed the qualitative assessment were subjected to a
two-phase quantitative assessment using EPRI's DSManager program evaluation modeling
system: Phase I - Calculate Participant and Total Resource Cost metrics assuming only one
participant and no administrative costs (cost-effectiveness test); Phase 2 - For those programs
passing Phase 1 , calculate Participant and Total Resource Cost metrics adding administrative
costs and expected penetration levels (program design test).
DSM programs that passed both phases were then included in the optimal supply-side portfolio
for comparative assessment against the optimal supply-side portfolio without DSM programs. If
including the DSM programs resulted in a lower PVRR, then the programs were included in the
overall optimal portfolio. Only one program, the Residential New Construction Program, made it
into the overall optimal portfolio,
- 81 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Southern Company
Ratepayer Impact Analysis
Southern Company perfonned a portfolio sensitivity analysis with the goal of selecting resource
options that minimize rates, This is accomplished by adding capacity that lowers rates using
declining revenue requirements for the first year it is added. This case was simulated by doing a
year-by-year analysis that committed to a capacity addition decision each year rather than
optimizing over the entire study period horizon. Although specifics on methodology and results
are not provided, they indicate that the resulting resource mix has more SCCTs and less CCCTs
than their reference case.
Resource Selection Sensitivity Analysis
Southern Company Services conducted the widest variety of sensitivity ("scenario ) analyses
among the companies included in the detailed IRP evaluation. The following is a complete
inventory of sensitivity study types perfonned.
Load growth (high, low, none relative to reference level)
Speculative "third-party" CCCT capacity added in a given year
Unit availability (increase, decrease relative to reference level)
Five-year unit retirement date extension
Gas/oil prices (high, low relative to reference level)
Low fuel prices (low coal, gas, and oil prices)
Higher cost of capital
Combined cycle installed cost (lower, higher relative to reference)
Additional economy peak power purchases
Future SO2/NUX/mercury environmental compliance
CO2/ton adder
Future environmental compliance with nuclear option
Rate impact minimization
CCCT-only through 2012; all-resource optimization thereafter
SCCT-only through 2012; all-resource optimization thereafter
Reduce installed coal unit cost to point where coal is competitive
Increase gas price to point where coal is competitive
Oil/gas generation limit
All F-Type CCCTs (to show impact of transition to H-type)
Reduce transmission capacity to outside control areas
Reduce/increase Active Demand Response capacity level by one-half
These sensitivity runs were prepared to examine the robustness of the base Southern Company
system resource plan. They also appear to have been used by the operating companies in
risk/uncertainty analysis of their individual IRPs, Southern Company did not provide specifics
on how these sensitivity runs were used in the decision process.
Puget Sound Energy
- 82-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Risk Management Background
PSE devoted a chapter in their 2005 IRP to "energy portfolio management . The Company
discussed long-tenn risk management goals and strategies (hedging, cost exposure reduction
fundamentals analysis, etc,), tools and controls, and organizational structure devoted to power
supply risk management. This chapter was infonnative because it described the linkage between
resource planning/acquisition activities and their risk management process. PSE also briefly
described a market research initiative aimed at gathering infonnation on the value that retail
ratepayers place on reducing rate volatility.
Portland General Electric,
Portfolio Analysis with RFP Bid Infonnation
PGE conducted portfolio evaluations that included short-listed energy product bids from its 2003
RFP.18 They constructed 26 portfolios that met criteria for "diversification of fuels and
technologies" and included at least two of the RFP products along with a minimum of 75 MW
(27 MWa) of RFP wind bids. The bid products were selected to represent a mix of tenn lengths
, 10 , and 30-year deals). PGE also conducted a bookends portfolio analysis assuming that
all new resource additions are met with a single resource type and capacity size (650 MW) with
prices based on the short-listed RFP bids. The resource types included market purchases, CCCT
units, coal, and wind (2 150 MW installed capacity).
Public Service Company of Colorado
Contingency Plan
There are a number of elements of PSCo s contingency plan that were effective. First, the plan
presented an historical RFP contract negotiation success rate as well as examples of successful
use of contingency planning measures during past procurement initiatives. Second, the IRP
presented a hierarchical table of altemative corrective actions to take based on the time
discover the need for a corrective action, the duration of the contingency (delay versus
pennanent loss of a resource), and the magnitude of the contingency. The table describes the
contingency scenarios typically associated with the correction action. The table of contingency
plan alternatives is shown below.
18 Puget Sound Energy also used cost data from recent procurement for capital costs, power transmission project
development and gas fuel transportation, among others.
- 83 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Short te.fIU capacity Save for "late breaking" contingencic$ for which there,
purchases mi,ght not be linre to use orm of Ole follov,.ing
con-ocli\'c. actions
Use n.l K':fnmive bid..If Ole contingency becomes kJI0v,11 oofore PSCo has
rolea.~d bids fmm their obligation, PSCo would use
this oorre,ctive action.This rorrc",-ti\'c action is most
appropriate for fl-'Placing I" winning bids thm drop out
.$COn alle.r selection or do not reAch SUcre......I'tll contract
rompletion,
Acl"eJerale in sm'ice dale If lhl~ contingency becomes known sulTidentl)' ahead
of resources for which of lime.. negotiate IIfI earlier in 5l-"'fviL'C date for a
contrllctshavc, ooen resource phulI1oo for Illter in the acquisition period.
exocl.1ted This oorrective action is most appropriate for a one to
two year delay in lIfIoOler resource,
Is!'.ue an e111e.rgency RH'If the contingency becomes known sufficiently ahe8.d
for a ~cific resource of time and it is not p:)Ssiblc to accelerate a pln.nned
resource or it is che.!lp3r to prccure a replarernenl than
acre1erme.. issue an RFP for a specilic msource to
ll1IU1.'I.ge the contingency,This action m1gbt be used if
a selected reSOlJK".e drops out afle:r standby bids ha\'e
teen relellSC,d or if newer forecasts show significant
increases over this L~'s forecnst.Needed
1J:lIfIsmission improvements may impede \his oorredive
action.
I'SCo build..Iffue contingency becomes known atle.r a time wl-rn
PSCo could issue IIfI RFP to manage the contingency,
but in time for PSCo to build its OVt'fi facility, PSCo
eQuId sdf -build a faciHt)' to cover the contillge'J1C)'
a...sumi ng quick approval by the Commission.PSCo
may l1a"c a time advantage OOC'.lUSC it has existing
l!Cl1t',mtion siles avuilable luld no time is fi.'Quired for
- 84-
PacifiCorp 2004 IRP Update
Sole sourl'C with reliable
supplier
Install Temrorary
Genemllon
Implernentintelim Load
Management or Customer
Gene mtion programs
Reduced reserve margi n
Northern States Power Company (Xcel)
Wind Integration Cost Study
Appendix C - IRP Benchmarking Study
l'J;Jntrad negotiation v.tlll II new supplier. Needed
tmnsmi1',sion improvements may impede thIs ro.rrective
action.
This option l'J,1uld substitute for an emergency RH) or
PSCo stepping into the brMd1.. Effectively, PSCo
v.uuld approach l1I1 inde~J1denL lD""er prcduror ",1th
whom it Iw; had I:J good 1,I;'Ol'king re1.!ltiol1ship and sole
source a new supply. PSCo could u~ this rorroctive
action if it deemed an RFP would take too long, it had
problem.... pln\'iding the corrective /lction itself or l1I1
lPP had a plan reAdy to go and it appeared competitive
with other options. Tb.is might include moili1)'iJ~g the
contracts of existing suppliers..
This measure C.!lll re implemented with romcwhaUess
1M d.time than the instaUatIon of new p.::rmanent
gencmtion by the Company or an Independent Power
projurer and It is well suited to cover a generation
project or trnnsmisslon de1.!ly that may last a year or
possibly tv.u.
Similar 10 the instAllation of temlUrary ,generation, tbis
ITIeASUre Cilll be implemented in 11 relatively sbortlcad-
time (e.g. within 6 months) and is well suiled to
address resource dela)'S.
U' the mnll ngency became known too hde 10 add new
resources in time and insufftcientshort term .purchases
were a\'niJable. 10 cove.!' the contingency. PSCo could
re forced to let its reserve margin slip II bit for II
summer SeaJ!Ol1 until one or II romblnntion oflhe, other
con~live actions rould be put into pl~"C.
This has considerably les... reJillbilily lisk with a 17%
reserve margin than with a 13% resen'e margin.
NSP discusses the results of a consultant's 2004 wind integration study that was mandated by the
Minnesota legislature, This study was one of the most recent available from the IRP'
examined , and represents an extensive application of both statistical and simulation
methodologies. The study s objective was to quantify integration costs and reliability impacts of
500 MW of additional wind in NSP's Minnesota control area for a 2010 study year. The study
looked at impacts for regulation, load following (ramping), and scheduling/unit commitment.
The consultant, EnerNex Corporation, used time series statistical analysis of system load and
wind unit output data (two-week interval at 4-second granularity) to derive forecasted
incremental reserve requirements and costs. For scheduling and unit commitment impacts
hourly load and generation data over a two-year period was used.
19 PSE also included the results of a recent wind integration study in their 2005 IRP. This study was conducted by
Golden Energy Services.
- 85-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Main findings include the following:
The total integration cost was estimated at $4.60/MWh with a mean absolute error of 15% or
less.
The cost of acquiring reserve capacity to support regulation was $0.23/MWh.
Due to load variability exceeding wind variability, the cost for load following was judged as
negligible.
The scheduling and unit commitment cost was estimated at $4,37/MWh.
The Effective Load Carrying Capability was estimated at 26% (400 MW against 1 500 MW
total installed capacity).
NSP concluded that 1 500 MW can be reliably integrated into their system, but cautions that
the study results should not be assumed to apply to non-NSP control areas.
A vista Corporation
Stochastic Wind Modeling
For its 2005 IRP (draft version), Avista documented a new stochastic wind modeling approach.
The utility gathered and analyzed hourly Northwest wind speed data from Oregon State
University to develop statistical distributions for five wind sites. These distributions were then
combined into a single monthly average distributionfor the entire Northwest. The company used
a stochastic model that accounts for serial correlation to create a variable daily wind generation
pattern, and then shaped the daily generation values using the wind speed shape. The wind speed
shape was based on hourly data from 1985 through 2000.
Graphical Display of Portfolio Resource Mix over Time
For its 2003 IRP' Avista Corporation used a radar-type chart to display the percentage portfolio
resource mix over time. The figure below, from the results section of the A vista IRP (Section 7
page 44) shows the mix for three years at lO-year intervals. This display fonnat is a compact and
convenient way to display a small number of annual data snapshots,
Cha... 7.
Utility Re$OtU'c:e Mh: (al\tW)
2004 2013. and 2023
IIJH'td.. IJCc.(1lrads D&.. 1M.......! BGio.-I'irOM! .'Mod I
- 86-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Northwest Power and Conservation Council
Risk-Constrained Least Cost Planning Framework
NWPCC uses an Excel-based spreadsheet tool to detennine the least-cost portfolio for various
risk levels. The tool, called the Portfolio Model, uses add-in packages to perfonn stochastic
simulation and optimization functions.2o This methodology is of interest because it integrates the
concepts of automated capacity expansion modeling with stochastic cost/risk trade-off analysis.
The model first calculates a distribution of portfolio costs (20-year Net Present Value cost) for a
resource portfolio based on load, fuel price, CO2 tax, and forced outage variables,21 A total of
750 futures for each portfolio are calculated. The model then calculates the mean cost and a risk
measure from the cost distribution of the 750 futures. The risk measure used is called TailVaR9o,
which is defined as the average value for the worst 10 percent of outcomes. The NWPCC favors
this measure over others evaluated,
The optimizer package then tests an arbitrary portfolio to detennine if its TailVaR9o is within
lower and upper bounds specified by the model user. If the portfolio has a TailVaR9o value less
than the upper-bound constraint, then the optimizer tests other portfolios that have equal or less
risk, but a lower cost. If the portfolio s TailVaR9o is greater than the upper-bound constraint, then
another portfolio is tested for the TailVaR9o constraint. The model stops when the least-cost
portfolio is found for the upper-bound TailVaR9o level. The following figure, extracted from
NWPCC's resource plan , shows this two-loop optimization process.
Look for_-
Lower CDst
look for pr." wIltI
Lower Ri.k
20 The Spreadsheet incorporates the Crystal BallCID add-in package to perfonTI Monte Carlo simulations, and the
OptiQuestTM add-in package to perfonTI stochastic optimization for detenTIining the least-cost resource mix.
21 Note that a capacity-based planning margin is not modeled as a constraint or fixed target. Rather, the model uses a
load-resource "cross-over" point as a decision criterion for new resource selection. The user can specify an energy
reserve margin as one of the inputs to the load requirement calculation.
- 87 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
The decision criterion built into the model to select supply-side resources for cost minimization
is to first address the resource-load balance and then to use plant valuation based on forward gas
and electricity prices to make the resource choices. For conservation programs, the model'
decision criterion employs a cost-effectiveness price combined with a price adjustment that
detennines additional conservation beyond what is cost-effective based on the Model's least-cost
solution.
HYDRO HEDGING STRATEGY COMPARISON
This section presents a summary of the hydro hedge strategies documented in three of the
company IRPs for which a detailed evaluation was perfonned: Portland General Electric, Puget
Sound Energy, and Idaho Power Company. PacifiCorp s hydro hedge strategy is provided as
well.
Portland General Electric (2002-4 IRP)
Initially Portland General Electric (PGE) proposed planning for hydro under poor conditions by
acquiring additional long-tenn supply. In the Final Action Plan, PGE moved from "poor" to
average" hydro conditions after further evaluation. Going long on the energy position is
proposed by looking 18 months ahead at region resources, before spot market, and acquiring
option premiums which would be included in annual net power cost reviews, to hedge poor
hydro. This modest ongoing annual fixed cost increase could reduce replacement cost volatility
by capping the replacement cost for the lost hydro generation. Alternatively PGE proposed the
use of their currently available CCCT with duct firing, if economically justifiable, to hedge poor
hydro. This use of CCCTs could be used to shape winter peaks.
Puget Sound Energy (2005 IRP)
Puget Sound Energy (PSE) used a scenario analysis approach using three models, Aurora
Portfolio Simulation Model (PSM), and Conservation Screening Model (CSM). The PSM
provided the "Dynamic" analysis or risk measure (90% confidence interval) and the Aurora
model provide the "Static" or incremental portfolio costs. PSE modeled risk by varying
hydroelectric generation stochastic parameters in Monte Carlo simulation runs in the PSM
system. The variability of hydroelectric generation and correlation with power prices was held at
the same values used in the 2003 Least Cost Plan. The following table (Exhibit X-6) shows the
Monte Carlo input assumptions. Annual variability is calculated as the standard deviation
divided by the mean, expressed as percent.
Exhibit X-6
Monto Carlo Inoot AssumDtions
Variability
and Correlations
DIstribution
Gas Price Power Price Hydro
Gas Price 53%
Loa nannal
Povi0r Price "36%1.0Loa nonnal
Mid-C Hydro Nonnal
West Side Hydro 12%
Nonnal
- 88 -
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Idaho Power Company (2004 IRP)
Idaho Power models hydroelectric generation as a stochastic parameter in Monte Carlo
simulation runs of the Aurora modeling system, They use scenario analysis to understand the
effects of water and load (both peak and energy) on energy resources, The scenarios included:
70% water/70% Load (main scenario), 90%/70%, and with additional one at 50%/50%. The
scenarios used were due to the public input to the planning process Idaho Power Company
developed a resource plan based upon a lower-than-median level of water. Beginning with the
2002 resource plan, Idaho Power Company began using the 70th percentile water conditions and
load conditions for resource planning. The 2004 Integrated Resource Plan is the second resource
plan wherein Idaho Power Company is using the 70th percentile water and load conditions.
Idaho Power does not assume any reductions of capacity or operational flexibility for relicensing
of any plants. Nor does it associate any future costs of licensing in their 2004 IRP, They will
have better infonnation for the 2006 IRP concerning relicensing impacts.
The 2004 IRP hydro data is based on a 1992 hydrological record of the Idaho Department of
Water Resources (IDWR) which Idaho Power Company believes to be overstated. The
overstatement is due to the increased water use and lower spring fed contributions to the system.
IDWR is in the process of updating the computed hydrologic record,
PacifiCorp (2004 IRP)
PacifiCorp models hydroelectric generation as a stochastic parameter in Monte Carlo simulation
runs of the MARKETSYMIPROSYM modeling system. Hydroelectric generation risk
parameters were taken from Global Energy Decisions (Henwood), based on the work they
performed for the Planning Margin study. The risk parameters were estimated to simulate hydro
distribution patterns developed by PacifiCorp, The distributions were based on PacifiCorp
belief as to all possible outcomes of hydro events. These distributions were developed from
hydroelectric generation forecasts for its owned and contracted units under varying levels of
precipitation. PacifiCorp layered on top of that the probability of occurrence of each level of
precipitation and developed data on weekly hydroelectric generation for the Western area under
various levels of exceedence. (See the figure below.
- 89-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
PacifiCorp West Hydroelectric Generation by Percent Exceedence
700
650
500
450
800
750
400
350
300
250
200
150
100
50 I
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
M ~
~ ~ ~ ~ ~ -
~ a M ~ 0 ~ ~ ~ ~ a ~ ~ 0
~ ~ -
~ m
~ ~
S ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ g ~ ~
Date
CONCLUSIONS
The analysis indicates that PacifiCorp s IRP could serve as a standard for IRP reporting based on
the sample of publicly available IRPs included in the study. This conclusion is bolstered by the
response to the quality assessment question on PacifiCorp s Stakeholder Satisfaction Survey,
where 60% of respondents ranked the PacifiCorp IRP "very favorably" with respect to other
IRPs. Areas in which the PacifiCorp IRP excelled include the following:
Level of detail on model inputs: PacifiCorp was one of a handful of utilities that broadly
documented their modeling inputs, and went far beyond what was required by state resource
planning requirements. While some provided as much detail for certain modeling areas, none
matched PacifiCorp s overall coverage. Areas in which PacifiCorp excelled included supply-
side resource cost/perfonnance attributes, transmission resource costs, stochastic parameters
and emission allowance costs.
Application of stochastic analysis:While a few other utilities perfonned stochastic analysis
PacifiCorp applied the greatest number of stochastic portfolio perfonnance measures, and is
the only one that provided an extensive discussion of stochastic modeling methodology and
results. PacifiCorp s IRP also did a superior job describing how those results were integrated
into the overall portfolio evaluation process.
Cost vs. Risk Tradeoffs: PacifiCorp is only one of two utilities that explicitly used and
documented a cost vs, risk tradeoff analysis for resource selection and portfolio decision
making. The other was Avista for their 2005 IRP. NWPCC is the one non-utility
organization that did so as well.
- 90-
PacifiCorp 2004 IRP Update Appendix C - IRP Benchmarking Study
Discussion on the portfolio selection decision-making process: The IRPs in general focused
on presenting numerical modeling results; few did a good job of documenting the decision
trail that led to a preferred portfolio. For example, as part of risk and assumption sensitivity
analysis, utilities presented the results of scenario model runs that determine the cost impact
of alternative load, price, and environmental cost forecasts. However, only a handful
utilities, including PacifiCorp, discussed how these results actually factored into resource
selection decisions.
The analysis did not reveal any substantial weaknesses of PacifiCorp s IRP with respect to the
others. Other utilities provided more background on certain subjects than PacifiCorp, such as
transmission planning, risk management, environmental policy and impacts, contract details
technology screening, alternative technology descriptions (particularly renewab1es), financing
considerations, and profiles of existing generating units and DSM programs.
Other general observations from the IRP analysis include the following:
There was no dominant modeling technology used by the utilities. Detailed production cost
simulation tools (along with manual portfolio development) and portfolio optimization tools
were used about equally.
In many cases, non-modeling or "qualitative" factors played a key role in determining IRP
preferred resource plans. Overall, the utilities did not provide a correspondingly detailed
picture of how the non-modeling factors impacted the planning outcomes.
Along with costs and risk considerations, many utilities used portfolio robustness22 and/or
resource diversification as broad guidelines for portfolio resource selection.
22 As discussed earlier in this study, robustness refers to consistently favorable portfolio cost performance under
different planning assumptions and futures.
- 91 -