20051020Load Growth Report compliance filing.pdf

825 E. Multnomah St.
Portland OR 97232
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October 20, 2005
VIA FEDERAL EXPRESS
Idaho Public Utilities Commission
472 West Washington
Boise, ID 83702-5983
Attn:Jean D. Jewell
Commission Secretary
Re:Case No. PAC-O2-
PacifiCorp s Petition to Initiate Investigation of Inter-Jurisdictional Issues
Submission of PacifiCorp s Load Growth Report - Compliance Filing
PacifiCorp submits for filing an original and seven (7) copies ofPacifiCorp s Load Growth Report. As
part of the ratification of the Revised Protocol, there was a requirement on the Company, in consultation
with other participants, to file a Load Growth Report with each of the State Commissions that ratified the
Revised Protocol, no later than nine months after the filing of the Company s 2004 Integrated Resource
Plan. As the Integrated Resource Plan was filed with the Idaho Commission on January 20 2005, the
deadline for filing the Load Growth Report was established as October 20 2005.
In accordance with this requirement, the Company respectfully submits its Load Growth Report (as a
compliance filing) to the Idaho Commission, who ratified the Revised Protocol on February 28 2005/
Order No. 29708. This report reflects the Company s conclusions of the discussions and work carried out
by the MSP Load Growth Workgroup and the MSP Standing Committee, who held a number of meetings
between March 2005 and October 2005.
It is respectfully requested that all formal correspondence and staff requests regarding this matter be
addressed to:
By E-mail (preferred):datarequest(illpac ificorp. com
By Fax:[phone]
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 800
Portland, OR 97232
2acifiCorp
October 20, 2005
Case No. PAC-02-
Page 2
Informal inquiries may also be made to Greg Duvall (at 503 813 7069) or Sue Rolfe (at 503 813 6878).
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D. Douglas Larson
V ice-President, Regulation
Enclosure
cc: Service List
CERTIFICATE OF SERVICE
I hereby certify that on this 20th day of October, 2005 I caused to be served, via
Federal Express, a true and correct copy ofPacifiCorp s Load Growth Report.
Eric L. Olsen
Racine, Olson, Nye, Budge &
Bailey
201 E. Center
O. Box 1391
Pocatello, ID 83204-1391
Randall Budge
Racine, Olson, Nye, Budge &
Bailey
201 E. Center
O. Box 1391
Pocatello, ID 83204-1391
James R. Smith
Monsanto Company
Highway 34 North
Soda Springs, ID 83276
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
Sue Rolfe
MSP Administrative Coordinator
825 NE Multnomah, Suite 300
Portland, OR 97232
James F. Fell
Stoel Rives LLP
900 SW 5th Ave
Portland, OR 97204
Andrea Kelly
Director Regulation
PacifiCorp
825 NE Multnomah
Portland, OR 97232
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Peggy
Regulat ry OperatIons CoordInator
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Multi-State Process
PacifiCorp
Load Growth Report
October 20 , 2005
Multi -State Process
PacifiCorp s Load Growth Report
October 20, 2005
Section
Table of Contents
Title
Executive Summary
Overview
PacifiCorp s Conclusion
Introduction
PacifiCorp s Recommendation
Requirements Under Revised Protocol and MSP State Orders
1 PacifiCorp s Studies to Measure Cost Shifts
Track Key Factors
Develop Structural Protection Mechanisms
Identify Process for Implementation of Structural Protection
Mechanisms
Relevant Factors
Consultation with MSP Standing Committee
File a Load Growth Report
Process
Formation of the Load Growth Workgroup
Load Growth Workgroup Work Plan
Load Growth Workgroup Meetings
PacifiCorp s Load Growth Studies and Analysis
PacifiCorp s Load Growth Study Approach and Assumptions
Page #
Page 1
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Page 2
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Page 4
Page 5
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Page 6
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Page 7
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Page 8
Page 8
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Page 9
Page 10
Page 1 0
Page 11
Page 12
Page 12
Page 1
Page 14
Page 14
PacifiCorp s Load Growth Study Results
June 2004 Forecast Studies
March 2005 Forecast Studies
Comparison to PacifiCorp s Previous Load Growth Studies
3.4 Additional Findings
Other Analysis
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Load Growth Report
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PacifiCorp s Load Growth Report
October 20,2005
Section Title Page #
Tracking Key Factors Page 14
Purpose of Tracking Key Factors Page 14
Description and Source of Factors Page 1
Historical Relative Load Growth Rate Page 1 5
Forecast Relative Load Growth Rate Page 1 5
Cost of New Resources Compared to Cost of Existing Page 16
Resources
2.4 Market Prices Page 1 6
Forecast Demand Side Management Compared to Actual Page 16
Demand Side Management
Rate Design Changes Page 1 7
Structural Protection Mechanisms Page 17
General Discussion Page 1 7
Evaluation Criteria and Ranking Process Page 1 8
Ranking of Structural Protection Mechanisms Page 1 9
5.4 Description of Structural Protection Mechanisms Page 20
Preferred SPM Pro osals Page 20
5.4.Embedded Cost Differential Method EGO Alternative Page 21
5.4.Embedded Cost Differential Method ECD Alternative 2 Page 21
Other SPM Pro osals Page 22
5.4.Hybrid Page 22
5.4.Tiered Allocation - Tiered Alternative Page 24
5.4.Tiered Allocation - Tiered Alternative 2 Page 25
SPM Pro osals Not Pursued Page 26
5.4.Structural Separation Page 26
5.4.Seasonal Resources Page 26
PacifiCorp s Structural Protection Mechanism Recommendation Page 26
Process for Implementing Recommended Structural Protection Page 27
Mechanism
PacifiCorp s Conclusions and Recommendation Page 28
Multi-State Process
October 20, 2005
Page ii PacifiCorp
Load Growth Report
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PacifiCorp s Load Growth Report
October 20,2005
Appendix
List of Appendices
Title
"',
Abbrevi ations. and Definitions Used in this Report
Key Assumptions of PacifiCorp s Load Growth Studies (Base Case Using
June 2004 Forecast and March 2005 Forecast)
Page #
Page 30
Page 32
Page 35
Page 39
Page 40
Page 41
Page 42
Page 43
Page 46
Page 50
Page 51
Page 53
Page 59
Page 72
Page 81
Page 85
List of PacifiCorp s Load Growth Studies
Load Growth"Workgroup Scope and Work Plan
Key Assumptions of PacifiCorp s Load Growth Studies (Base Case Using
June 2004 Forecast and March 2005 Forecast) with Utah Growing at the
Average of the Other States
Preferred Portfolio E with DSM and Preferred Portfolio E with OSM
Adjusted to Maintain Consistent IRP Planning Margins
Comparison of March 2005 Forecast (or CG27) and June 2004 Forecast
(or CG24) of Market and Natural Gas Prices
ECO Alternative 1 Paper
ECD Alternative 2 Paper
Lump Sum Transfer Paper
EGO Alternative 1 Compared to ECD Alternative 2
List of PacifiCorp s Hybrid Studies and Results
Tiered Alternative 1 Paper
Tiered Alternative 2 Paper
1i ered Alternative 1 Compared to Tiered Alternative 2
Ranking Criteria
Multi-State Process
October 20,2005
Page PacifiCorp
Load Growth Report
Multi -State Process
PacifiCorp s Load Growth Report
October 20,2005
Table
List of Tables
Title Page #
Page 12Percentage of Load Growth Cost Allocated by State (Revised Protocol)
(Adjusted to Maintain Consistent IRP Planning Margins) (Load Growth
Workgroup Meeting - August 10, 2005)
Page 20
Page 24
Page 32
Page 33
Page 33
Page 34
Page 53
Page 55
Page 56
Page 57
Page 57
PacifiCorp s Ranking of Structural Protection Mechanisms
Percentage of Load Growth Cost Allocated by State (Hybrid - Case 3b1
(Load Growth Workgroup Meeting - October 11, 2005)
Percentage of Load Growth Cost Allocated by State (Revised Protocol)
(Load Growth Workgroup Meeting - June 29, 2005)
Percentage of Load Growth Cost Allocated by State (Revised Protocol)
(Portfolio Q) (Load Growth Workgroup Meeting - June 29, 2005)
Percentage of Load Growth Cost Allocated by State (Revised Protocol)
(Adjusted to Maintain Consistent IRP Planning Margins) (Load Growth
Workgroup Meeting - August 10, 2005)
Percentage of Load Growth Cost Allocated by State (Hybrid - Case 3b1
(with Intra-Control Area Equity Measures) (Load Growth Workgroup Meeting
- October 11 , 2005)
Resource Matrix for Hybrid Studies
Hybrid Cases 1 and 2 - Percentage Difference in NPV Revenue
Requirement from Revised Protocol using June 2004 Forecast (Hybrid
Workgroup Meeting - June 28, 2005)
Hybrid Case 1 Variations - Percentage Difference in NPV Revenue
Requirement from Revised Protocol using March 2005 Forecast with Intra-
Control Area Equity Measures (Hybrid Workgroup Meeting - July 18, 2005)
Hybrid Cases 1 a and 1 b - Percentage Difference in NPV Revenue
Requirement from Revised Protocol using March 2005 Forecast with Intra-
Control Area Equity Measures (Hybrid Workgroup Meeting - August 24,
2005)
Hybrid Cases 3, 3a and 3b - Percentage Difference in NPV Revenue
Requirement from Revised Protocol using March 2005 Forecast with Intra-
Control Area Equity Measures (Hybrid Workgroup Meeting - August 24
2005)
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PacifiCorp s Load Growth Report
October 20 2005
Table Title Page #
Hybrid Case 3b Variations - Percentage Difference in NPV Revenue
Requirement from Revised Protocol using March 2005 Forecast with Intra-
Control Area Equity Measures (Hybrid Workgroup Meeting - September 14
2005)
Page 58
Hybrid Case 3c - Percentage Difference in NPV Revenue Requirement from
Revised Protocol using March 2005 Forecast with Intra-Control Area Equity
Measures (Hybrid Workgroup Meeting - September 14, 2005)
Page 58
Multi-State Process
October 20, 2005
Page v PacifiCorp
Load Growth Report
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PacifiCorp s Load Growth Report
October 20 2005
Executive Summary
Overview
The Multi-State Process 1 commenced in April 2002 and was a collaborative process
with stakeholders from each of the six States PacifiCorp serves. The focus was to
design, develop and implement a cost allocation methodology that would achieve a
more permanent consensus on each State s responsibility for the costs and benefits
of PacifiCorp s existing assets. Using a common cost allocation method provides
PacifiCorp with the opportunity to recover the cost of investments deemed prudent,
and provid es States with the ability to independently implement State energy policy
objectives.
A number of collaborative meetings and conferences occurred during 2002 and
2003 , which resulted in the development of the "Protocol" cost allocation
methodology proposal. The Protocol was filed with each of the State Commissions
in Utah, Oregon, Wyoming and Idaho in September 2003 and in Washington in
December 2003. Following discussions with all parties, the proposal was further
refined and re-submitted to each of the State Commissions as the "Revised
Protocol. "
Final ratification of the Revised Protocol was achieved in March 2005 with the State
Commissions in Idaho, Oregon, Utah and Wyoming3 issuing orders approving and
accepting the use of the Revised Protocol cost allocation methodology. As part of
the ongoing commitments of the Revised Protocol and the associated State Orders
additional analysis was required on the potential for inappropriate costs shifts to other
States due to the fastest growing State s load growth.
This PacifiCorp Load Growth Report4 is the culmination of the analysis and findings
carried out from March 2005 to October 2005 by the Company, the Load Growth
Workgroup (of interested parties from each State), and the MSP Standing
Committee. The report encompasses discussion on the issue of load growth, the
extent of any potential inappropriate cost shifts to other States and the development
of possible mechanisms to address those potential cost shifts.
, MSP Regulatory Dockets are (1) Idaho- PAC-02-3, (2) Oregon - UM-1050, (3) Utah -02-035-04, (4) Washington - UE 020319 or GRC 2003 UE 032065 and GRC
2005 UE 050684, and (5) Wyoming - 2000~EI-02.183.2 At the time of completing this Load Growth Report, neither the Protocol, nor Revised Protocol has been filed in the State of California. It is intended that the next
general rate case to be filed in that State will be based on the Revised Protocol allocation methodology; however, the timeline associated with such a filing is not
confirmed.3 The outcome of the GRC 2003 UE 032065 in Washington was the adoption of the Revised Protocol for reporting purposes only. To settle the issue of allocation
methodology in that State, the Company s GRC 2005 UE 050684 has been filed recommending the Revised Protocol. The outcome of that proceeding is anticipated in
April 2006.4 This PacifiCorp Load Growth Report is the product of PacifiCorp. During its drafting, it was circulated to the various members of the Load Growth Workgroup. The
Load Growth Worlgroup held a series of meetings and discussed the various issues related to the topic of load growth disparities among the States. The process that
was conducted was a "collaborative" process, however, while MSP participants had the opportunity to present their viewpoints, PacifiCorp is the author of this report and
this report contains the opinions of PacifiCorp.
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October 20,2005
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PacifiCorp s Load Growth Report
October 20, 2005
-If
PacifiCorp s Conclusion
The results of the analysis and studies carried out by the Company (and discussed
with the Load Growth Workgroup) show that the Revised Protocol protects the slower
growing States from potential inappropriate cost shifts due to the fastest growing
State s load growth. The Company s analysis of Fiscal Years 2007 through 2020
reflected that Utah would be allocated 100% 5 of the incremental cost due to its load
growth, As this is the case, it is not necessary to implement a Structural Protection
Mechanism rSPM") at this time.
PacifiCorp s Recommendation
As stated "in the conclusion above, and as discussed throughout this report, the
Company s current studies show that the Revised Protocol protects the slower
growing States from potential inappropriate cost shifts due to the fastest growing
State s load growth. Should future analysis suggest there maybe inappropriate cost
shifts due to load growth and an SPM is needed to protect the slower growing States
the Company recommends one of the preferred Embedded Cost Differential rECD"
SPMs described in Sections 5.1 and 5., or an alternative ECD-based approach
be reviewed and considered for further development in consultation with interested
parties, taking into account the relevant factors identified in Section 2.
In furtherance of the work on an SPM, the MSP Standing Committee issued a
directive 6 requesting that the Load Growth Workgroup continue this work, at least
through December 2005. The Company is therefore coordinating with the MSP
Standing Committee and Load Growth Workgroup participants to establish a timeline
to fin~lize the development of a preferred SPM. It is believed that with further
discussion and analysis, issues relating to SPMs and their proposed implementation
can be resolved.
Introduction
Requirements Under Revise d Protocol and MSP State Orders
The Revised Protocol requires the Company, in consultation with other participants,
to update the Company s load growth studies, track key factors relevant to cost shifts,
develop an SPM, and file a report on these issues with each of the State
Commissions who ratified the Revised Protocol , no later than October 20,2005.
Specifically, the Revised Protocol? states:-
In concert with the 2004 IRP cycle, the Company and parties will analyze and quantify
potential cost shifts related to faster-growing States (2)In addition multi-state workgroup
5 Based on a 14-Year NPV (g? 8.4277% (Fiscal Years 2007 through 2020) March 2005 Forecast. The 9-Year NPV (Fiscal Years 2007 through 2015) calcul ates to 99%.6 MSP Standing Committee directive was advised to MSP Participants on September 23. 2005 via an emaH from the Committee s Chair (Terri Carlock).7 Revised Protocol Section IV.
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October 20, 2005
Page 2 PacifiCorp
Load Growth Report
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PacifiCorp s Load Growth Report
October 20 , 2005
will track key factors including actual relative growth rates, forecast relative growth rates,
costs of new Resources compared to costs of existing Resources, and other factors
deemed relevant to this issue. No later than nine months after filing the 2004 IRP, the
Company, in consultation with the MSP Standing Committee and other parties, will file
report with the Commissions regarding this issue. Included in this report will be
description of one or more options for structural protection mechanism, detailed with
sufficient specificity to allow timely implementation in the event that the studies show
material and sustained net harm to customers in any jurisdiction.
The MSP Standing Committee is charged with developing one or more ameliorative
mechanisms that could be implemented in timely manner in the event that the studies
show material and sustained net harm to particular States from the implementation of the
IRP. The MSP Standing Committee should consider the impact of load growth in light of all
other relevant factors. Potential mechanisms to be studied include tiered allocations,
treatment of Seasonal Resources, structural separation of the Company, temporary
assignment of the costs of some new Resources to fas#-growing States, and the inclusion
of measures of recent load growth in the computation of allocation factors.
Footnote (2) from the Revised Protocol Section IV.E states as follows "This issue will be
monitored through studies that compute the costs allocated to each State for two cases: (a)
with currently projected load growth together with leaskost, leas#-risk mix of Resource
additions to meet that growth and (b) with the fastes#-growing State growing at the average
growth projected for the remaining States, again with leaskost, least-risk mix of
Resource additions
As well as the language in the Revised Protocol, the State Orders of Oregon and
Utah contain specific provisions relating to load growth issues.
The Oregon Order8 requires the Company to include the Hybrid9 as one of the
potential SPMs. The Oregon Order states:-
Section IV.E. of the Revised Protocol requires PacifiCorp, in consultation with the MSP
Standing Committee and other parties, to file report regarding load growth issues no later
than nine months following the filing of PacifiCorp s 2004 Integrated Resource Plan (IRP).
According to the Revised Protocol, this report will include description otone or more
options for structural protection against cost shifting. We direct PacifiCorp to include fully
developed Hybrid Method as one of (the) options for structural protection in this report. To
accomplish this, PacifiCorp should work with parties from Oregon and those interested from
other states. This Hybrid Method should be designed to meet the three original
Commission goals in Order No. 02-193.
The above statement from the Oregon Order makes reference that the Hybrid should
be designed to meet three goals of the Oregon Public Utility Commission.
These goals are:-
8 Oregon Order No. 05-021, dated January 12, 2005, Commission Conditions Section, Page 129 The Hybrid methodology is described in Section 5.3 and the results of the Hybrid studies are included as Appendix 12.
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October 20, 2005
Page 3 PacifiCorp
Load Growth Report
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PacifiCorp s Load Growth Report
October 20, 2005
Determine an allocation methodology that would allow PacifiCorp an
opportunity to recover its prudently incurred costs associated with its
investment in generation resources;
Jnsure that Oregon s share of PacifiCorp s costs is equitable in relation to
. '~
other states; and
/~Meet the public interest standard in Oregon.
The Utah Order 10 requires the Company to raise matters relating to load growth to
the Utah Public Service Commission before the Company takes a position in front of
the MSP Standing Committee. The Utah Order states:-
...
IUPSCj will require the Company to file with us IUPSCj regarding the materiality of
possible harm to other states from fast growing jurisdiction before taking position before
the MSP Standing Committee.
The Idaho 11 and Wyoming 12 State Orders did not contain explicit language relating to
load growth issues other than that contained in the Revised Protocol.
In February 2005, interested parties were invited to work with the Company to
address all of the above referenced requirements. An initial meeting was held on
February 22, 2005 and three workgroups were formed:-
(a)Load Growth Workgroup,
(b)Seasonal Workgroup, and
(c)Hybrid Workgroup.
Work plans for each of the workgroups were developed and monthly meetings were
established. Shortly thereafter, and in accordance with the requirements of the
Revised Protocol, the Company initiated the formation of the MSP Standing
Committee. More information on the workgroups and MSP Standing Committee is
included in Section 2. In addition, the following sub-sections provide information
on the specific requirements included in the language referenced above.
PacifiCorp s Studies to Measure Cost Shifts - The Re\1sed Protocol requires
participants to analyze and quantify potential inappropriate cost shifts due to
the fastest growing State s load growth, in concert with the Company s IRP.
The Revised Protocol also identifies the study design.
10 Utah Order dated December 14, 2004, Section VI. C, Page 3811 Idaho Order No. 29708 dated February 28, 2005
12 Wyoming Order No. 7395 dated March 2, 200513 Revised Protocol Section IV.E Footnote 2
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Load Growth Report
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PacifiCorp s Load Growth Report
October 20, 2005
The Company completa::t the required studies and presented the results at
the Load Growth Workgroup meetings held from June 2005 through October
2005. More specific information about the Company s studies is included in
Section 3 and Appendix 2. The Company also completed a number of
other studies related to potential load growth issues; a list of these studies is
also included in Appendix 2.
Track Kev Factors - The Revised Protocol 14 states:-
a multi -state workgroup will track key factors including actual relative growth
rates, forecast relative growth rates, costs of new Resources compared to costs
of existing Resources, and other factors deemed relevant to this issue.
In the Company s studies completed during 2003, 2004 and 2005 (prior to
the ratification of the Revised Protocol in March 2005), and in all the
Company s studies completed since, three primary elements have been
found to increase the potential for inappropriate cost shifts due to the fastest
growing State s load growth. These elements are:-
(a)differential load growth - one or more States growing faster than the
average of the other States,
(b)addition of new resources - being added to the system at costs
above the average of the system, and
(c)mismatch between load growth and new resource additions.
With these elements in mind, tracking factors have been identified as early
indicators of potential inappropriate cost shifts due to the fastest growing
State s load growth. The specifics of tracking factors are included in Section
Develop Structural Protection Mechanisms ("SPMs - The Revised
Protocol 10 requires the Company to include, in its Load Growth Report, one
or more SPM options that could be implemented in a timely manner should
the study results show a potential for inappropriate cost shifts due to the
fastest growing State s load growth. The options are required to be
presented in sufficient detail to enable implementation in a timely manner.
The Revised Protocol also requires that the SPMs will be developed in
consultation with the MSP Standing Committee. Specifically, it states:-
14 Revised Protocol Section IV.E Page 715 Revised Protocol Section IV.E Page 8
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PacifiCorp s Load Growth Report
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. . .
developing one or more ameliorative mechanisms that could be
implemented in timely manner in the event that the studies show material and
sustained net harm to a particular State from implementation of the IRP.
The Load Growth Workgroup put considerable effort into developing a
i-number of potential SPMs , the details of which are included in Section 5.
1.4 Identifv Process for Implementation of Structural Protection Mechanisms
~:~~ -
To meet the "timely implementation" requirement of an SPM, the
Load Growth Workgroup decided it would be conducive to develop an
::implementation process specifying when and how to implement an SPM.
Much time was spent considering the workgroup s differing views. Ideas
ranged from a trigger point that would lead to the immediate implementation
of an SPM to a trigger point that would necessitate further analysis before an
SPM is considered appropriate for implementation. Although significant
progress was made, at the conclusion of the Load Growth Workgroup
meeting held September 13, 2005, the workgroup was unable to reach
consensus on the specifications of the preferred SPM or how such an SPM
would be implemented. At this time, the SPM and its implementation
process remains a priority for the MSP Standing Committee to resolve (see
also Section 6). One of the key implementation challenges is that the
Company s load growth studies are forward-looking, however, SPMs can
only be applied to current test case periods.
On September 23, 2005, the MSP Standing Committee issued a directive
requesting that the Load Growth Workgroup continue this work, at least
through December 2005. The Company is coordinating with the MSP
Standing Committee and Load Growth Workgroup participants to establish a
timeline to finalize the development of a preferred SPM. It is believed that
with further discussion and analysis, issues relating to SPMs and their
proposed implementation can be resolved.
Relevant Factors - The Revised Protocol 17 states:-
The MSP Standing Committee should consider the impact of load growth in light
of all relevant factors.
This statement acknowledges that there may be other factors to consider in
addition to the results of the Company s load growth studies when making a
decision to implement an SPM. Below are some of the other relevant factors
discussed. This list is only a guide and is not intended to be an exhaustive
list; there may be other factors, not listed, which may also be deemed
relevant (now or in the future):-
16 MSP Standing Committee directive was advised to MSP Participants on September 23, 2005 va an email from the Committee s Chair (Terri Carlock).11 Revised Protocol Section IV.E Page 8
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PacifiCorp s Load Growth Report
October 20, 2005
benefit of operating and planning as an integrated system
structural protection provided by the hydro endowment ECO
structural protection provided by Seasonal Resources,
impact of lost hydro generation, value of reserves and value of shaping,
as referenced in Section 3.
benefit of sharing costs with other States when loads are lost
impact of paying for retiring resources and expiring contracts on a
system-wide basis,
overall energy market conditions,
planning and forecasting assumptions and expectations.
Consultation with MSP Standina Committee - Shortly after the ratification of
the Revised Protocol, the MSP Standing Committee was formed. Its charge
has been to develop potential ameliorative mechanisms to address potential
inappropriate cost shifts due to the fastest growing State s load growth. In
addition, the Company has a directive to consult with the MSP Standing
Committee regarding the development and inclusion of SPMs in the
Company s Load Growth Report. As the majority of the MSP Standing
Committee members are also members of the Load Growth Workgroup, the
efforts of both have been aligned such that the mechanisms developed in the
workgroup forum and presented here , are offered as the same mechanisms
developed by the MSP Standing Committee.
File a Load Growth Report - The Revised Protocol 18 states:-
No later than nine months after filing the 2004 IRP, the Company, in
consultation with the MSP Standing Committee and other parties, will file report
with the Commissions regarding this issue. Included in this report will be
description of one or more options for structural protection mechanism, detailed
with sufficient specificity to aI/ow timely implementation in the event that the
studies show material and sustained net harm to customers in any jurisdiction.
The Company s 2004 IRP Report was filed with the State Commissions on
January 20,2005. As such, the deadline for filing a Load Growth Report with
the State Commissions was established as October 20, 2005 (nine months
later).
18 Revised Protocol Section IV.E Page 7
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Load Growth Report
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PacifiCorp s Load Growth Report
October 20, 2005
r::_.
An outline of PacifiCorp s Load Growth Report was presented to the Load
Growth Workgroup at its meeting in August 2005, and an initial draft of the
report's content was presented in September 2005. A final draft was
presented to the Load Growth Workgroup in October 2005; the same was
':,aalso provided to the MSP Standing Committee members.
g. On October 20,2005, this PacifiCorp Load Growth Report was filed with the
~tate Commissions who ratified the Revised Protocol (Idaho, Oregon, Utah
""""
and Wyoming) and submitted, for informational purposes, to the State
"",
Commissions in Washington and California.
Process
Formation of the Load Growth Workaroup - At the February 22 2005
meeting referenced in Section 2., the Company initiated the formation of
the Load Growth Workgroup to specifically focus on issues related to load
growth and to address specific requirements contained in the Revised
Protocol. A work plan was prepared, monthly meetings were scheduled, and
an issues list was developed. The participants agreed that the development
of a Hybrid, as required by the Oregon Public Utility Commission s Order
would be performed within the Hybrid Workgroup, but the development of the
Hybrid as an SPM would be addressed by the Load Growth Workgroup
(information regarding the Hybrid is included in Section 5.3).
Load Growth Workaroup Work Plan - At the March 30, 2005 meeting of the
Load Growth Workgroup, the Company presented a proposed scope and
work plan. The work plan covered five major tasks for the workgroup,
summarized as:-
(a)
(b)
Develop key tracking factors;
File Load Growth Report by October 20, 2005;
(c)Compute the costs allocated to each State for two cases utilizing the
Company s load growth studies defined within the Revised Protocol;
(d)
(e)
Develop structural protection mechanisms; and
Consider other relevant factors.
A copy of the original scope and work plan document is included as
Appendix 3. The workgroup kept to schedule throughout the process and
has met its deliverables accordingly.
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Page 8 PacifiCorp
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PacifiCorp s Load Growth Report
October 20, 2005
Load Growth WOrkQrouD Meetinas - The Load Growth Workgroup held eight
meetings during March 2005 through October 2005, culminating in the filing
of this PacifiCorp Load Growth Report. Prior to each meeting, an agenda
and meeting materials were prepared by the Company and provided to the
participants. Meeting summaries briefly recording the progress of the
workgroup were circulated to participants after each meeting. Below is a list
of the meetings held, together with a brief description of the key topics
covered:-
March 30. 2005
Workgroup Guidelines
Scope and Work Plan
Initial Discussion on Key Tracking Factors
Initial Discussion on Resource Additions for Average Growth Study
Prioritization c:i Load Growth Issues List
Mav 4. 2005
Discussion on Key Tracking Factors
Initial Discussion on Structural Protection Mechanisms
Identification of Analysis
Review of Study Assumptions
June 1. 2005
Discussion on Key Tracking Factors
Structural Protection Mechanisms - Tiered Allocation Approaches
Initial Discussion on Evaluation Criteria
June 29. 2005
Analysis Assumptions and Results
Structural Protection Mechanisms - Tiered Allocation and ECD
Approaches
Review of Load Growth Work Plan
August 10. 2005
Analysis Assumptions and Results
Structural Protection Mechanisms - Tiered Allocation, ECD and Lump
Sum Approaches
Draft Outline of Load Growth Report
August 23.2005
Structural Protection Mechanisms - Tiered Allocation, ECD and Lump
Sum Approaches
Preliminary Ra nkings of Structural Protection Mechanisms
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PacifiCorp s Load Growth Report
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Draft Outline of Load Growth Report
September 13. 2005
Structural Protection Mechanisms ECD and Lump Sum Approaches
. Rankings of Structural Protection Mechanisms
Draft Load Growth Report
. .
Final Review of PacifiCorp s Load Growth Report
. -
,. Analysis and Results
MSP Standing Committee Directive
PacifiCorp s Load Growth Studies and Analysis
PacifiCorp s Load Growth Study Approach and Assumptions
As set out in the Revised Protocol (and as referenced in Section 2.1), two studies
are identified to analyze load growth issues:-
Study 1 - a study with currently projected load growth together with a least-
cost, least-risk mix of resource additions 19 to meet load growth and,
Study 2 - a study with the fastest growing State growing at the average
growth projected for the other States, again with a least-cost, least-risk mix of
resource additions. 20 Throughout the analysis leading up to this report, Utah
was consistently identified as the fastest growing State.
In order to perform the required analysis, the Company completed a number of
studies, a list of which is included as Appendix 2. For consistency purposes, the
study assumptions in the Company s Generation and Regulation Initiatives Decision
tool ("GRID") and Regulatory Forecast Model ("RFM") were updated to match the
assumptions in the Company s 2004 IRP Report. Lists of the study assumptions are
included as Appendices 4 and
In Study 2, where the fastest growing State is adjusted to the average of the other
States, Utah's compound annual peak load growth rate is reduced from 4.1 %
(forecast growth rate) to 1.5% (average growth rate of other States). The IRP
Preferred Portfolio, from the Company s 2004 IRP Report, is then adjusted by
removing planned resources, as needed, in order to maintain a consistent planning
margin (no lower than a 15% planning margin). The adjusted portfolio was prepared
by the Company s IRP Group and is included as Appendix 6.
19 Based in the Companys 2004 IRP Preferred Portfolio E with DSM (Original)20 Based on the Companys 2004 IRP Preferred Patfolio E with DSM (adjusted to maintain planning margin)
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In the Company s studies, two scenarios were utilized:-
(1 )the June 2004 or CG24 market and gas forecast (the "June 2004
Forecast,,, and later
(2)the March 2005 or CG27 market and gas forecast (the "March 2005
Forecast"
The Load Growth Workgroup believed it was important to use a more recent natural
gas and market price projection in the Company s studies performed, especially as
the March 2005 prices exceeded those in June 2004 by approximately 40% for
natural gas and 20% for market prices. Details of the June 2004 Forecast and the
March 2005 Forecast is included as Appendix 7.
For comparison purposes, the Company s studies were run using each of the
following allocation methodologies:-
(a)
(b)
Revised Protocol
Rolled-In
(c)
(d)
Modified Accord, and
Hybrid (information on the Hybrid is included in Section 5.3).
PacifiCorp s Load Growth Study Results
Under the Revised Protocol, the results of the Company s load growth studies show
that between 100% 22 and 106% 23 of the incremental cost of load growth would be
assigned to Utah (the fastest growing State). The Company s studies did not show
that the slower growing States suffered any material and sustained harm from Utah'
faster growth. Based on these results, the Company concludes the Revised Protocol
provides adequate protection to slower growing States from potential inappropriate
cost shifts due to the fastest growing State s load growth. The primary factors for the
Revised Protocol providing this protection are:-
dynamic allocation factors;
the hydro endowment ECD;
the treatment of Seasonal Resources.
21 The use of the June 2004 Forecast is consistent with the assumptions used in the Companys 2004 IRP22 Based on a 14-Year NPV (g18.4277% (Fiscal Years 2007 through 2020) March 2005 Forecast The 9-Year NPV (Fiscal Years 2007 through 2015) calculates to 99%.23 Based on a 14-Year NPV (g18.4277% (Fiscal Years 2007 through 2020) June 2004 Forecast The 9-Year NPV (Fiscal Years 2007 through 2015) calculates to 105%.
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More specifically:-
June 2004 Forecast Studies - Utilizing the June 2004 Forecast, the results of
Study 2 (as referenced in Section 3.1) were compared with the results of the
:&Study 1 (also referenced in Section 3.1). The Revised Protocol results
demonstrate 106% 24 of the incremental costs related to load growth would be
:-allocated to Utah, the fastest growing State.
2 ,arch 2005 Forecast Studies - Utilizing the March 2005 Forecast, the
'.results of Study 2 (as referenced in Section 3.1) were compared with the
results of Study 1 (also referenced in Section 3.1). The Revised Protocol
results demonstrate 100% 25 of the incremental costs related to load growth
. would be allocated to Utah, the fastest growing State.
Table 1 presents a summary of the results of the Company s studies by state, as
referenced in Sections 3.1 and 3.
Table 1
Percentage of Load Growth Cost Allocated by State
(Revised Protocol)
(Adjusted to Maintain Consistent IRP Planning Margins)
(Load Growth Workgroup Meeting - August 10, 2005)
9 Year NPV (2007 - 2015) (g2 8.4277%14 Year NPV (2007 - 2020)(g2 8.4277%
Costs Costs Costs Costs
June 2004 Forecast March 2005 Forecast June 2004 Forecast March 2005 Forecast
State
California
Oregon
Washington 0.4%
Utah 104.98.105.100.
Idaho 0.4%
Wyoming
In analyzing load growth issues, the Company also performed and presented a
number of additional studies; a list of these studies is included as Appendix 2.
24 Based on a 14-Year NPV ~ 8.4277% (Fiscal Years 2007 through 2020) June 2004 Forecast. The 9-Year NPV (Fiscal Years 2007 through 2015) calculates to 105%.25 Based on a 14-Year NPV ~ 8.4277% (Fiscal Years 2007 through 2020) March 2005 Forecast. The 9-Year NPV (Fiscal Years 2007 through 2015) calculates to 99%.
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Comparison to PacifiCorp s Previous Load Growth Study Results
Following the 2003 MSP Filing 26, and at the request of Oregon 27 and Utah 28 parties,
the Company completed a number of studies to analyze potential inappropriate cost
shifts due to the fastest growing State s load growth. Most of the Company s studies
assumed either a one-time increase in Utah loads or a continuing pattern of higher
Utah load growth which were matched with different types of Resource additions.
The Company performed additional studies assuming higher Oregon load growth and
corresponding Resource additions.
In the Company s previous studies , the results showed that, under the Revised
Protocol, the fastest growing State supported between 86% 29 and 127% 30 of the
incremental cost of load growth. As indicated in Section 3., the Company s current
load growth studies show between 100% 31 and 106% 32 of the incremental cost of
load growth would be allocated to the fastest growing State.
The Company s current studies are believed to be an improvement on the previous
studies for several reasons, including:-
(1 )to ensure a better match of the loads and resources, the current studies were
based on the Company s 2004 IRP with additions and deletions identified by
the Company s IRP Group,
(2)in the Company s current studies, a consistent planning margin was
maintained (no lower than 15%); previous studies were not modeled as
precisely.
(3)in the Company s current studies, both plants and contracts are
added/deleted; previous studies only added/deleted plants.
When comparing the Company s previous load growth studies to the Company
current load growth studies, the Company concludes that the results show the
Revised Protocol provides adequate protection to slower growing States from
potential inappropriate cost shifts due to the fastest growing State s load growth. The
primary factors for the Revised Protocol providing this protection are:-
dynamic allocation factors;
the hydro endowment ECO;
26 The 2003 MSP Filing was submitted to the States of Idaho, Oregon, Utah and Wyoming on September 30, 2003. Regulatory Dockets PAC-Q2-3 (Idaho), UM-1050
~Oregon), 02-035-04 (Utah) and 20000-EI-02-183 (Wyoming) refer.7 MSP Regulatory Docket UM-1050 / OPUC Staff Data Requests 59 and 6028 MSP Regulatory Docket 02-035-04/ DPU Data Request 7.3 and CCS Data Request 10.29 Based on a 14-Year NPV (Fiscal Years 2005 through 2018)
30 Based on a 14-Year NPV (Fiscal Years 2005 through 2018)
31 Based on a 14-Year NPV (Fiscal Years 2007 through 2020) March 2005 Forecast
32 Based on a 14-Year NPV (Fiscal Years 2007 through 2020) June 2004 Forecast
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the treatment of Seasonal Resources.
Additional Findings
In addition to the conclusions referenced in Sections 3.2, and 3.3, the Company
findings 'of the principal drivers of the study outcomes are:-
(a),'..the greater the rate of growth of one State compared to other States, the
;.greater the potential for inappropriate cost shifts to slower growing States,
(b);.,the higher the cost of new resource additions compared to existing
Tesources, the greater the potential for inappropriate cost shifts to slower
growing States, and
(c)the better the match between new resource additions and load patterns
through an effective IRP process, the lower the potential for inappropriate
cost shifts to slower growing States.
Other Analysis
During the Load Growth Workgroup meetings, the Company was directly approached
by Oregon Commission Staff and requested to update analysis provided in previous
data requests.33 The analysis looked at the value of reserves, the value of shaping,
and the value of lost hydro generation; elements not incorporated into the Revised
Protocol. Oregon believes that without these elements integrated into the Revised
Protocol, they are not receiving the full benefits of hydro within the hydro endowment.
However, under the Revised Protocol's hydro endowment, Oregon is not bearing the
cost for the replacement of lost hydro generation. 34 After reviewing the original and
updated analysis, the Company concludes the value of reserves together with the
value of shaping offset the value of lost hydro generation during the identified study
period. The Company further concludes that the inclusion of these three elements in
the Revised Protocol would not change the allocation of costs among the States. No
further work has been performed on these elements and no further work has been
requested.
Tracki ng Key Factors
Purpose of Tracking Key Factors
As referenced in Section 2.1, the Load Growth Workgroup was tasked with
developing and tracking key relevant factors to act as early identifiers of potential
inappropriate cost shifts due to the fastest growing State s load growth. As defined in
33 MSP Docket UM-1050 OPUC Staff Data Requests 68, 70, 74, and 7534 Lost hydro generation from Hydro-Electric Resources and Mid-Columbia Contracts as a result of relicensing, contract renegotiation and plant retirements.
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the Revised Protocol 35 and as further identified by Load Growth Workgroup
participants, key factors for load growth and potential cost shifts include:-
(1 )
(2)
(3)
(4)
(5)
(6)
Historical Relative Load Growth Rates,
Forecast Relative Load Growth Rates
Cost of New Resources Compared to Cost of Existing Resources
Market Prices,
Forecast Demand Side Management Compared to Actual Demand Side
Management ("DSM"), and
More detail on these factors is included in Section 4.
Rate Design Changes.
Description and Source of Factors
Historical Relative Load Growth Rate - provides a n historical view of the
peak and energy growth in the PacifiCorp system, how each State s growth
compares to the other States, and which State experienced the highest
growth.
The purpose of this tracking factor is to identify disproportionate growth in
one State as compared to the rest of the system as this could indicate a
potential for inappropriate cost shifts due to the fastest growing State s load
growth.
Historical peak and energy load data, along with the SG and SE factors, is
included in the Company s Semi-Annual/Annual Filing. 36 In addition, the
Company s historical peak and energy data is included in the Company
2004 IRP Report.
Forecast Relative Load Growth Rate - while historical relative load growth
rate provides an overview of historical peak and energy growth, the
forecasted relative load growth rate provides a projection of where system
growth is expected to occur, including which State is expected to experience
the highest growth in energy and peak demand.
3$ Revised Protocol Section IV.E Page 736 Companys Semi-Annual/Annual Filing, "Allocation Factor" tab37 2004 IRP Report, Technical Appendix I "Retail Load Forecasting
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The purpose ofthis tracking factor is to help identify forecasted growth in one
State, exceeding the average of the other States, ,as this could indicate a
potential for inappropriate cost shifts due to the fastest growing State s load
growth. The Company s forecasted peak and energy load data is included in
:::::the Company s 2004 IRP Report. 38
"""
Cost of New Resources Compared to Cost of Existina Resources - the need
~.for new resources can be driven by many factors including, among others,
..-expiring purchase contracts, plant retirements, and load growth, with new
~:;;.and replacement resources typically more expensive than the existing
resources.
The purpose of this tracking factor is to help identify when the differential
between the cost of new resources and the cost of existing resources grows,
as this may indicate an increase in the potential for inappropriate cost shifts
due to the fastest growing State s load growth.
The actual cost of existing resources is reported in the Company s Semi-
Annual/Annual Filing.39 In addition, the Company s forecasted cost of new
resources is included in the Company s 2004 IRP Report.
2.4 Market Prices - as referenced in Section 4.3, there are several factors
impacting the need for replacement resources. The need for replacement
resources, along with an increasing demand for energy, may increase the
Company s potential market exposure.
The purpose of this tracking factor is to help identify rising market prices
during a time of load growth as this could increase the potential for
inappropriate cost shifts due to the fastest growing State s load growth. The
Company s forecasted market prices are included in the Company s 2004
IRP Report41 and reflected in graph form in Appendix 7.
Forecast Demand Side Management Compared to Actual Demand Side
Management ("- for many years, the Company has been operating
several DSM programs in each of its six State service territories. There are
four general classes of DSM42 programs ranging from those aimed at
conservation education to programs including resources able to be
dispatched that the Company uses to pro actively manage loads. Each
program is designed to reduce energy and/or peak use.
2004 IRP Report, Technical Appendix I "Retail Load Forecasting39 Companys Semi-Annual/Annual Filing, "Annual Embedded Costs-All Other"
2004 IRP Report, Technical Appendix C "Base Assumptions Table C.27 and C.28"41 2004 IR P Report, Technical Appendix C "Base Assumptions Figure C.
2004 IRP Report, Chapter 2 Pg 30 to 32, Chapter 2 "Table 2.4 and 2., Technical Appendix C "Base Assumptions Tables C.10 to C.22" and Technical Appendix C Pg
62 to 64
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Projected DSM programs and assumptions are included in the Company
20041RP Report ; and under the Revised Protocol, the costs and benefits
are situs assigned to the State sponsoring the DSM activity. PacifiCorp
DSM activities 44 are tracked by the Company s DSM Group, although no
formal reporting is required at this time. Tracking these programs helps to
identify actions being taken by each State to reduce load growth.
At the June 2005 meetings of the Load Growth Workgroup, the Company
presented information about each State s DSM activities, including a
summary which displayed DSM targets and accomplishments. This
information shows that customers in Utah, the fastest growing State, are
currently paying a 3% surcharge for DSM programs.
Rate Desiqn Chanqes - There have been several recent rate design
changes in Utah intended to address load growth. Some of the residential
design changes include seasonal rates, inverted block rates, and time-of-use
rates. Seasonal rates became effective in April 2004. Customers are
charged a higher rate from May through September. Inverted block rates
consist of a three-block design where customers using 1,000 kWh/month (or
more) are charged 9.272 cents/kWh. Time-of-use rates are part of an
experimental program introduced in April 2004. For small- and medium-
service customers, there are seasonal rates and two optional time-of-use
rates. Large industrial customers and general service customers also have
seasonal rates and mandatory time-of-use rates.
As with the DSM programs referenced in Section 4.5, the purpose of this
tracking factor is to help identify actions taken to reduce load growth.
Structural Protection Mechanisms ("SPMs
General Discussion
The Revised protocol45 states:-
..
the Company, in consultation with the MSP Standing Committee and other parties,
will file report with the Commissions regarding this issue (Load Growth). Included in
this report will be description of one or more options for structural protection
mechanism, detailed with sufficient specificity to allow timely implementation in the
event that the studies show material and sustained net harm to customers in any
jurisdiction.
43 2004IRP Report, Chapter 2 Pg 30 to 32, Chapter 2 "Table 2.4 and 2., Technical Appendix C "Base Assumptions Tables C.10 to C.22" and Technical Appendix C Pg62 to 6444 DSM activity in Oregon is tracked by The Energy Trust of Oregon
45 Revised Protocol Section IV.
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In accordance with this requirement, the Load Growth Workgroup developed and
considered seven SPMs:-
(1 )Embedded Cost Differential rECD Alternative 1") - see Section 5.1 and
;;;Appendices8 and 11
(2)"'-Embedded Cost Differential ("ECD Alternative 2") - see Section 5.2 and
'TAppendices9, 10 and 11,
(3)
(4)
(~Hybrid - see Section 5.3 and Appendix 12
Tiered Allocations ("Tiered Alternative 1") - see Section 5.4 and
Appendices 13 and 15,
(5)Tiered Allocations ("Tiered Alternative - see Section 5.5 and
Appendices 14 and 15,
(6)
(7)
Structural Separation - see Section 5.6 , and
Seasonal Resources - see Section 5.
Each of the SPMs listed above were developed (to varying degrees), evaluated and
ranked according to the criteria and process provided in Section 5.2. The key issues
considered, when evaluating each of the proposals, included (1) the level of
protection the SPM provided from inappropriate cost shifts due to load growth, (2) the
level of complexity for understanding and communicating, (3) the ease in which the
SPM can be implemented and administered, and (4) whether the SPM would lead to
unintended consequences. Details of the ranking process and criteria are included in
Section 5., the results of the ranking process are included in Section 5.3 and a
description of each SPM is included in Section 5.
Evaluation Criteria and Ranking Process
Following discussions at the March 2005 Load Growth Workgroup meeting, a sub-
committee met in April 2005 to develop criteria for evaluating each potential SPM.
The draft evaluation criteria, developed by the sub-committee, was presented and
discussed at the May 2005 and June 2005 meetings of the Load Growth Workgroup,
with an additional meeting held in July 2005 to finalize the evaluation criteria.
Preliminary rankings of each proposed SPM were initiated by the Company and
provided to participants for discussion at the August 2005 Load Growth Workgroup
meeting.
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The final set of evaluation criteria, developed by the sub-committee and the Load
Growth Workgroup, are provided below. A more detailed description of each is
included as Appendix 16:-
Consistent with Revised Protocol
Degree of Protection from Load Growth
Equitable in Treatment Among the States
Does Not Create Unintended Consequences
Consistent with Utility System Least-Cost Planning
Consistent with Minimizing Total System Operating Costs
Aligns Assignment of Costs and Benefits of New Resources
Can be Implemented in a Timely Manner
Easy to Understand
Simple to Implement, Track and Maintain
Ranking of Structural Protection Mechanisms ("SPMs
Table 2 provides an overview of the Company s ranking of each SPM, reflecting a
high" or "low" measure to indicate how well each SPM is anticipated to perform to
the evaluation criteri a, compared to each other. A detailed description of each SPM
is included in Section 5.
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Table 2
PacifiCorp s Ranking of Structural Protection Mechanisms
Model Rank ing to Evaluation Load Growth
Criteria Report Reference
Preferred SPM Proposals:-
- ECO Alternative 1 High Section 5.
- ECO Attemative 2 High Section 5.
(Also refer to Appendices 8,9, 10, 11 and 12)
----.u ,
--"
Other SPM Proposals:-
Hybrid Low Section 5.
Tiered Alternative 1 Low Section 5.4.4
Tiered Alternative 2 Low Section 5.
(Also refer to Appendices 13, 14 and 15)
SPM Proposals Not Pursued:-
- Structural Separation Not Ranked Section 5.
- Seasonal Resources Not Ranked Section 5.
Description of Structural Protection Mechanisms("SPMs")
Preferred SPM Proposals
The following two ECD-based SPMs ranked "high" as they show the most promise for
addressing potential cost shifts due to the fastest growing State s load growth.
Although there is consensus among many of the workgroup participants that ECD-
based SPMs are superior to other SPMs under consideration , neither of these
approaches are agreed to or finalized in sufficient detail to allow timely
implementation. Overall, the ECO-based SPMs appear more promising than other
SPMs as they are designed specifically to target and remedy inappropriate cost shifts
due to the fastest growing State s load growth in the event a material and sustained
harm is determined, and their methodology is more consistent with the Revised
Protocol. The Company therefore recommends either of these two SPMs, or an
alternative ECD-based SPM, merit further review, development and consideration
under the MSP Standing Committee Directive.
46 On Se ptember 23, 2005, the MSP Standing Committee issued a directive 46 requesting that the Load Growth Workgroup continue working to complete this work, at
least through December 2005. The Company is coordinating with the MSP Standing Committee and Load Growth Workgroup participants to establish a timeline to
finalize the development of a preferred SPM. It is believed that with further discussion and analysis, issues related to SPMs and their proposed implementation can be
resolved.
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Embedded Cost Differential Method "ECD Alternative 1" - EGO Alternative
1 is based on the temporary assignment of new resources to the fastest
growing State. The costs of all resources are allocated on system load
based allocation factors. The ECD Alternative 1 provides a supplemental
allocation of the amount by which the cost of the new resource(s) exceeds
the average embedded cost of existing resources for a temporary two year
period.
The Company provided an example of the estimated annual ECD Alternative
1 adjustment, beginning in Fiscal Year 2010 (when the first new IRP
Resource is estimated to come on-line), through Fiscal Year 2017 (two years
after the last new IRP Resource is estimated to come on-line). The results
were shared with the Load Growth Workgroup in August 2005.
The Company s ranking of "high" reflects that this type of SPM is considered
easy to comprehend, mechanically simple to implement, and is consistent
with the basic concepts embodied in the Revised Protocol. However, the
drawback is that it has not been shown to result in a sufficient redistribution
of costs.
The paper that presented ECD Alternative 1 to Load Growth Workgroup
participants is included as Appendix 8. Also, ECO Alternative 1 was
qualitatively contrasted with ECD Alternative 2, the outcome of which is
included as Appendix 11.
5.4.Embedded Cost Differential ("EClLA)ternative 2"- The approach of ECD
Alternative 2 proposes a direct (and permanent) assignment of resources as
a protection against load growth. The method also determines if the fastest
growing State is covering its costs by conducting a load growth study using
two 10-year GRID runs (5-historical and 5-forecast).
The 1 O-year NPV results of the two studies are compared to calculate what
percentage increase in costs from higher load levels is allocated to the
fastest growing State. The implementation of ECD Alternative 2 is a lump
sum transfer payment approach calculated such that the fastest growing
State bears 95% of the costs of a new resource(s) that are deemed to be
required in order to meet the differential in load growth, and assuming pre-
determined triggers are met. A key element of this SPM approach is the
attaching of the ECD to specific resources, on a permanent basis.
The Load Growth Workgroup discussed the details of this proposal at its
meeting in August 2005. Based on feedback and comments received,
changes were incorporated and a revised proposal was considered.
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Iii',C ,
~-' ,
The Company s ranking of "high" reflects that ECO Alternative 2 is
considered arithmetically straight-forward and requires a relatively simple
adjustment to the Revised Protocol. However, this proposal requires multiple
GRIO runs and a re-fit of existing resources to a hypothetical load level.
"".
Additionally, this method raises the potential to re-open decisions of
. .
,:previously settled rate cases with its 5-year historical analysis, and it might
., require dollar adjustments to be included into a general rate case for plants
~projected to come on line in the future, which may not, in real time, come on
",..line at all. In response to this latter concern, discussions focused on limiting
:~.the forecast to the end of a rate case test period.
The paper that presented ECO Alternative 2 to Load Growth Workgroup
participants is included as Appendix 9. Additionally, a Lump Sum Transfer
Proposal, the mechanics of which are included into ECO Alternative 2, was
originally presented as a separate SPM proposal. The paper that presented
the Lump Sum Transfer approach to Load Growth Workgroup participants is
included as Appendix 10. Also, ECO Alternative 2 was qualitatively
contrasted with ECO Alternative 1 , the outcome of which is included as
Appendix 11.
Other SPM Proposals
The following three SPMs ranked "low , reflecting less promise for addressing
potential load growth issues. These SPMshave also attracted little or no consensus
as to their mechanics (other than Hybrid) among workgroup participants and theCompany considers them complex and challenging to implement. As such, the
Company does not consider these SPMs suitable options for implementation if and
when any future load growth issues arise. This is also based on the conclusion that
an ECO-based approach, like those described in Section 5.4 1 and Section 5.
appears to be more promising and mechanically more agreeable to workgroup
participants.
5.4.Hvbrid - This SPM approach is based on the Hybrid that has been under
development within the Hybrid Workgroup since March 2005. In offering the
details of this method as a potential SPM , it should be noted that the Hybrid
is not an agreed or acceptable cost allocation methodology among any of the
States in which the Company operates and has been solely developed for
reporting purposes only, as specifically directed by the Oregon Public Utility
Commission. The Oregon Order47 specifically states:-
. ..
We direct PacifiCorp to include fully developed Hybrid Method as one
of (the) options for structural protection in this (Load Growth) report.
accomplish this, PacifiCorp should work with parties from Oregon and those
interested from other states. This Hybrid Method should be designed to
47 Oregon Order No. 05-021, dated January 12, 2005, Commission Conditions Section, Page 12
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meet the three original Commission goals in Order No. 02-193. Once
completed, the participating Oregon parties are to present the Hybrid
Method to the Commission no later than December 1 2005.
Furthermore, while the Revised Protocol uses the Modified Accord as a
comparator for the Revised Protocol, we want to also use the Hybrid
Method as a comparator. Therefore, upon approval of the agreed-upon
Hybrid Method or January 2006, whichever comes first, PacifiCorp must
file its annual reports and general rate case filings comparing results under
the Revised Protocol with both Modified Accord and Hybrid Method results."
The Hybrid is an accounting assignment of all loads and resources to the
control area where they were physically located (with exceptions). The East
Control Area contains loads for Idaho, Utah and Wyoming, while the West
Control Area contains loads for California, Oregon and Washington. The
East and West Control Areas are balanced using a complex interchange
accounting methodology that assigns system balancing sales and purchases
on an hourly basis , using MWhs and market prices.
Conceptually, the Hybrid provides a structural-type approach to separate the
resources added to meet loads in each of the control areas, while retaining
the primary hydro resources within the West Control Area. Exceptions to the
direct control area assignments have been factored into the methodology to
better balance the loads and resources in each control area and to reflect
deliveries from certain exchanges.
Several studies were run by the Company to assess the Hybrid, including the
potential of the Hybrid as an SPM to manage inappropriate cost shifts of the
fastest growing State s load growth. Table 3 presents the results of the
Hybrid load gowth study performed under the March 2005 Forecast. A list of
all of the Company s Hybrid studies is included as Appendix 12.
'8 A detailed description of the Hybrid will be contained in the material that will be presented to the Oregon Public Utility Commissions, anticipated to be available by
December 1, 2005.
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5.4.
Table 3
Percentage of Load Growth Cost Allocated by State
(Hybrid - Case 3b1 a) (with Intra-Control Area Equity Measures)
(Load Growth Workgroup Meeting - October 11,2005)
Costs CostsMarch 2005 Forecast March 2005 Forecast
9 Year NPV (2007-2015)14 Year NPV (2007-2020)State
California
Oregon
...,
Washington
Utah 86.86.
Idaho
Wyoming
The Company ranks the Hybrid "low . The ranking reflects (1) the Hybrid
does not protect all States from inappropriate cost shifts due to the fastest
growing State s load growth, (2) has little support of workgroup participants
(3) is a significant departure from the Revised Protocol, (4) has the potential
for unintended consequences , and (5) has the potential to deviate from
system-wide, integrated planning. On this basis, the Company would not
recommend the Hybrid be considered a; a potential SPM.
Tiered Allocation "Tiered Alternative 1" - Tiered Alternative 1 allocates
generation and purchase resources, and loads into two tiers. The existingresources acquired prior to a trigger date are placed in Tier 1 and allocated
to the States based on loads at the trigger date. As the system grows, as
contracts expire and as resources retire, new resources are acquired. Thes e
new resources are placed in Tier 2 and allocated to the States causing the
incremental loads above Tier 1 loads. The effect of using this method
segregates incremental system costs into Tier 2 loads. Over time, Tier
loads are shifted to Tier 2 as Tier 1 resources expire or retire. The fastest
growing State is allocated a larger share of Tier 2 within their revenue
requirement calculations. The overall effect of moving all resources into Tier
2 is to gradually move allocations back to a single tier. The Company has
not performed any detailed analysis or specific modeling relating to Tiered
Alternative 1.
The Load Growth Workgroup discussed and developed Tiered Alternative
at its meetings from May 2005 through August 2005. The paper presenting
Tiered Alternative 1 included as Appendix 13. Also, Tiered Alternative
was qualitatively contrasted with Tiered Alternative 2, the outcome of which
is provided as Appendix 15.
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October 20, 2005
The Company ranks Tiered Alternative 1 "low . Specifically, it is not clear
that Tier 2 would, in practice, capture only inappropriate cost shifts due to the
fastest growing State s load growth and therefore it is not considered a
reasonable approach for protecting States from such cost shifts. It is also
considered complex to implement, track and maintain. On this basis, the
Company would not recommend Tiered Alternative 1 be considered as a
potential SPM.
5.4.Tiered Allocation "Tiered AlternativeZ' - This approach is based on
assigning generation and purchase resources and loads into multiple tiers (or
vintages) which segregates existing resources from new resources, with the
fastest growing State being allocated a larger share of a new resource. The
trigger dates occur once a new resource is added and as loads exceed
resource capacity in the prior tier. The Company has not performed any
detailed analysis or specific modeling relating to Tiered Alternative 2.
The Load Growth Workgroup discussed and developed the Tiered
Alternative 2 at its meetings in June 2005 through August 2005. The initial
paper presenting Tiered Alternative 2 included as Appendix 14. Also, Tiered
Alternative 2 was qualitatively contrasted with Tiered Alternative 1 , the
outcome of which is provided as Appendix 15.
As with Tiered Alternative 1 , the Company ranks Tiered Alternative 2 "low" in
terms of its promise as an SPM. Specifically, it is not clear that multiple tiers
would, in practice, only capture inappropriate cost shifts due to the fastest
growing State s load growth and therefore it is not considered a reasonable
approach for protecting States from such cost shifts. It is also considered
complex to implement, track and maintain. On this basis, the Company
would also not recommend Tiered Alternative 2 be considered as a potential
SPM.
In summary, both of the tiered alternative proposals referenced in Sections 5.4 and
5 are complex and represent a significant deviation from the Revised Protocol.
The design of a tiered allocation proposal requires a number of decisions, including
the number of tiers, timing of creating a tier, deciding which tier a resource is placed
, and deciding what happens to the tiers when loads increase or decrease and
resources are acquired, expire or retire. It should also be noted that resource
additions are not always driven by load growth, but may be caused by a need to
replace expiring or retiring resources. The tiered-based proposals have the potential
for unknown and unintended consequences, and workgroup participants have not
expressed any interest in further developing a tiered-based SPM.
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PacifiCorp s Load Growth Report
October 20, 2005
SPM ProDosals Not Pursued
The last two SPMs have not been ranked and have not been fully developed (nor
modeled) by the Load Growth Workgroup. The Company considers these SPMs to
be overly complex , a significant deviation from the Revised Protocol and would not
recommend any additional work be carried out on these SPM proposals.
5.4.Structural SeDaration - Structural separation of the Company s system was
;;.identified as an option for consideration as a SPM in the Revised Protocol.
~...
In particular, a number of possible scenarios have received initial
;:;;.consideration, such as a divisional separation (similar to a UP&L and PP&L
type separation), a control area-based separation (similar to the Hybrid),
operating company separation and a physical separation (similar to the
Company s Structural Realignment ProposaI ). As well as requiring a
structural separation approach to be considered as an SPM option , the
Revised Protocol also contained a caveat that an SPM should be able to be
implemented in a timely manner.
Recognizing that any potential structural separation would require significant
time and attention to both develop and implement, the workgroup did not
focus on developing a structural separation option as part of this effort. As
such, no structural separation proposals exist for consideration at this time.
5.4.Seasonal Resources - Alternate treatment for Seasonal Resources was
specifically identified in the Revised Protocol50 to be considered as an SPM.
Due to the work priorities of the Load Growth and Hybrid Workgroups, issues
related to Seasonal Resources played a smaller part of the overall
discussions. Ultimately, work on the alternate treatment of Seasonal
Resources was suspended for two reasons - (1) the Company s updated
studies utilizing Revised Protocol indicated that the impact of Seasonal
Resources was relatively small in the context of the overall Revised Protocol,
and (2) the participants most interested in Seasonal Resources were no
longer available to dedicate efforts to explore alternatives.
At the June 2005 Seasonal Workgroup meeting, it was agreed to suspend
further discussions on Seasonal Resources.
PacifiCorp s Structural Protection Mechanism ("SPM") Recommendation
The analysis and studies carried out by the Company, and discussed with
participants of the Load Growth Workgroup, show that the Revised Protocol currently
protects the slower growing States from potential inappropriate cost shifts due to the
49 The Companys Structural Realignment Proposal was filed with each State Commission in 2000. Regulatory Dockets are (1) Idaho- PAC-QO.6. (2) Oregon -UM-
1001, (3) Utah - QO.035-15, (4) Washington -UE-001878, and (5) Wyoming -20000-EA-QO.161. This proposal was not filed in the State of California.so Revised Protocol Section IV.A Page 3, Section IV.E Page 8 and Section XIII Page 13
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October 20,2005
fastest growing State s load growth. As this is the case, it is not necessary to
implement an SPM at this time.
However, should future analysis suggest there is a potential for inappropriate cost
shifts due to the fastest growing State s load growth, and an SPM is needed to
protect the slower growing States, the Company recommends one of the preferred
SPMs described in Sections 5.1 and 5.2 or an alternative ECD-based approach
be reviewed and considered for further development in consultation with interested
parties, taking into account the relevant factors identified in Section 2.
Process for Implementing Recommended Structural
Protection Mechanism ("SPM"
As previously noted in this report, the results of the Company s current load growth studies
do not appear to indicate there is a potential for material and sustained harm resulting from
inappropriate cost shifts due to the fastest growing State s load growth. Therefore, there is
no need to implement a structural protection mechanism at this time.
However, the Revised Protocol does require at least one SPM be developed, with a process
for implementing the SPM in a timely fashion, if analysis indicates that inappropriate cost
shifts due to the fastest growing State s load growth will occur.
Much time was spent considering the workgroup participant's views on implementation the
process. Ideas ranged from a trigger point that would lead to the immediate implementation
of an SPM to a trigger point that would necessitate further analysis before an SPM is
considered appropriate for implementation. Although significant progress was made, at the
conclusion of the Load Growth Workgroup meeting held September 13, 2005, the workgroup
participants were unable to reach consensus on the specifications of the preferred SPM or
how such an SPM would be implemented. At this time, the SPM and its implementation
process remains a priority for the MSP Standing Committee to resolve (see also Section
4).
On September 23, 2005, the MSP Standing Committee issued a directive 51 requesting that
the Load Growth Workgroup continue this work, at least through December 2005. The
Company is coordinating with the MSP Standing Committee and Load Growth Workgroup
participants to establish a timeline to finalize the development of a preferred SPM. It is
believed that with further discussion and analysis, issues relating to SPMs and their proposed
implementation can be resolved.
51 MSP Standing Committee directive was advised to MSP Participants on September 23, 2005 via an email from the Committees Chair (Terri Carlock).
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October 20, 2005
PacifiCorp s Conclusions and Recommendation
Based on the results of the Company s current load growth studies, it is the Company
conclusion that it is not necessary to implement an SPM at this time.
If future analysis suggests there is a potential for inappropriate cost shifts due to the fastest
growing State s load growth , the Company recommends that one of the preferred SPMs
described in Sections 5.1 and 5.2 or an alternative ECO-based approach be reviewed
and considered for further development in consultation with interested parties, taking into
account the relevant factors identified in Section 2.
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Appendices
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Appendix
Abbreviations and Definitions Used in this Report
2004 IRP Report"means the IRP report known as "PacifiCorp s IRP 2004" which
was filed with each of the State Commissions on January 20
2005
DSM"means the Company s Demand Side Management programs
ECD"means Embedded Cost Differential
GRID"means the Company s Generation and Regulation Initiatives
Decision tool; an hourly production cost dispatch model that
simulates dispatch of PacifiCorp s resources to serve load
obligations and utilized for forecasting (substantiating) net power
costs for regulatory proceedings and other long-term power cost
analysis and projection purposes
IRP"means the Company s Integrated Resource Plan program and
published report
IRP Preferred Portfolio means the 2004 IRP Report's IRP Preferred Portfolio E with
DSM
June 2004 Forecast"means the June 2004 or CG24 market and gas forecast
(consistent with the assumptions used in the Company s 2004
IRP)
March 2005 Forecast"means the March 2005 or CG27 market and gas forecast
MSP"means the Company s Multi-State Process collaborath.e inter-
jurisdictional allocations project
N PV"means Net Present Value
PP&L"means Pacific Power and Light
RFM"means the Company s Regulatory Forecast Model , used to
calculate state revenue requirements
SE factors means the Company s System Energy allocation factors
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October 20 2005
SG factors means the Company s System Generation allocation factors
SPM"means a Structural Protection Mechanism
SPMs means Structural Protection Mechanisms, in the plural
UP&L"means Utah Power and Light
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Appendix 2
List of PacifiCorp s Load Growth Studies
Below are the results ()f the load growth studies performed by the Company from June 2005 through
October 2005. These studies are presented in chronological order, based on the date of the Load
Growth Workgroup meeting at which they were presented. For study assumptions, refer toAppendices 4 and 5.
Load Growth Workgroup Meeting - June 29. 2005
The load growth study results shown in Table 4 were presented to the Load Growth Workgroup
meeting held on June 29, 2005. These studies were performed using both the June 2004 Forecast
and March 2005 Forecast gas and market pricing data.
Table 4
Percentage of Load Growth Cost Allocated by State
(Revised Protocol)
(Load Growth Workgroup Meeting - June 29, 2005)
9 Year NPV (2007 - 2015) ~ 8.4277%14 Year NPV (2007 - 2020)~ 8.4277%
Costs Costs Costs CostsStateJune 2004 Forecast March 2005 Forecast June 2004 Forecast March 2005 Forecast
California
Oregon 0.4%Washington
Utah 103.97.105.99.
Idaho
Wvominq
Load Growth Workgroup Meeting - June 29. 2005
The load growth study results shown in Table 5 were presented to the Load Growth Workgroup
meeting held on June 29, 2005. These studies were performed by the Company at the request of the
Utah Participants, and were only performed using the March 2005 Forecast gas and market pricing
data. The 2004 IRP Portfolio Q was not the preferred portfolio and as such, the underlying
assumptions of the Portfolio had not been fully developed to include elements like DSM. For this
reason , this is the only study run with the 2004 IRP Portfolio
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Table 5
Percentage of Load Growth Cost Allocated by State
(Revised Protocol)
(Portfolio Q)
(Load Growth Workgroup Meeting - June 29, 2005)
Costs Costs
March 2005 Forecast March 2005 Forecast
9 Year NPV (2007-2015)14 Year NPV (2007-2020)
State
California
Oregon
Washington
Utah 89.89.
Idaho
Wyoming
Load Growth WorkarouD Meetina - Auaust 10. 2005
The load growth study results shown in Table 6 were presented to the Load Growth Workgroup
meeting held on August 10, 2005. These studies are the same as presented in Table 4, except that
an adjustment was incorporated to maintain consistent IRP planning margins between Study 1 and
Study 2 (see Appendix 6). These studies were also performed using both the June 2004 Forecast
and March 2005 Forecast gas and market pricing data.
Table 6
Percentage of Load Growth Cost Allocated by State
(Revised Protocol)
(Adjusted to Maintain Consistent IRP Planning Margins)
(Load Growth Workgroup Meeting - August 10, 2005)
9 Year NPV (2007 - 2015) ~ 8.4277%14 Year NPV (2007 - 2020)~ 8.4277%
Costs Costs Costs Costs
June 2004 Forecast March 2005 Forecast June 2004 Forecast March 2005 ForecastState
California
Oregon
Washington 0.4%
Utah 104.98.105.100.
Idaho 0.4%
Wyoming
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Load Growth WorkarouD Meetina - October 11. 2005
The load growth study results shown in Table 7 were presented to the Load Growth Workgroup
meeting held on October 11 , 2005. This is Case 3b1 a Hybrid (refer to Section 5.3 and Appendix
12). These studies were performed using only the March 2005 Forecast gas and market pricing data
and incorporate the :intra-control area equity measures of (1) QFs situs assigned , (2) hydro reserve
credit situs assigned to Wyoming, and (3) a Mid-C ECO.
Table 7
".Percentage of Load Growth Cost Allocated by State
(Hybrid - Case 3b1
(with IntrcK:ontrol Area Equity Measures)
(Load Growth Workgroup Meeting - October 11 2005)
Costs Costs
March 2005 Forecast March 2005 Forecast
9 Year NPV (2007-2015)14 Year NPV(2007-2020)
State
California 0.4%
Oregon
Washington
Utah 86.86.
I Idaho
I Wyoming
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Appendix 3
Load Growth Workgroup Scope and Work Plan
Load Growth Workgroup Meeting March 30, 2005
SCOPE DUE DATE
A multi-state workgroup will track key factors including actual relative growth May 31 2005
rates, forecast relative growth rates, cost of new Resources compared to costs
of existing Resources, and other factors deemed relevant to this issue.
PacifiCorp must file a report with the Commissions regarding potential cost October 20,2005
shifts related to faster growing states. (See Section IV.E. of the Revised
Protocol)
PacifiCorp will consult with Standing Committee and other parties.Ongoing
Studies will compute the costs allocated to each State for two cases: (a) with October 20, 2005
currently projected load growth together with a least-cost, least-risk mix of
Resources additions to meet the growth and (b) with the fastest-growing State
growing at the average growth projected for the remaining States, again with a
least-cost, least-risk mix of Resource additions.
The report will include a description of one or more options for a structural October 20, 2005
protection mechanism detailed with sufficient specificity to allow timely
implementation in the event that the studies show a material and sustained net
harm to customers in any jurisdiction.This supports the Standing Committee
charge to develop one or more ameliorative mechanisms. (see below)
The report should include information on other relevant factors to support the October 20, 2005
Standing Committee charge. (see below)
STANDING COMMITTEE CHARGE DUE DATE
The MSP Standing Committee is charged with developing one or more TBD
ameliorative mechanisms that could be implemented in a timely manner in the
event that the studies show a material and sustained net harm to particular
States from the implementation of the I RP.
The MSP Standing Committee should consider the impact of load growth in TBD
light of other relevant factors.
WORK PLAN
Meetin 1 end of March
Process Issues
Discuss Guidelines for the Workgroup
Discuss Reporting from the Workgroup
Discuss Overall Scope and Work Plan
Discuss Logistics for future meetings
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- ,
Technical Issues
Discuss tracking of key factors
Discuss Resource additions for average growth study
Prioritize Issues
Define deliverables for Meeting 2 (Note: This could be analysis or written documents from
both the Company and other parties)
Key factors
Study work
Structural Protection / ameliorative mechanisms
Other relevant factors
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for future meetings
Technical Issues
Review deliverables
Review key factor tracking
Review assumptions for updated study
Review write-ups on ameliorative mechanisms
Review write-ups on Other relevant factors
Define preferred / potential solution for issues reviewed
Define deliverables for Meeting 3
Key factors
Study work
Structural Protection / ameliorative mechanisms
Other relevant factors
Meetin 3 end of Ma
Process Issues
Review Work Plan
Approve final key factor tracking
Discuss Reports (as needed)
Discuss Logistics for future meetings
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Technical Issues
Review deliverables
Finalize key factor tracking
Define study scenarios for updated study
Review write-ups on ameliorative mechanisms
Review write-ups on Other relevant factors
Define preferred / potential solution for issues reviewed
Define deliverables for Meeting 4
Study work
Structural Protection ameliorative mechanisms
Other relevant factors
Meetin 4 end of June
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for futlre meetings
Technical Issues
Review deliverables
Review write-up on tracking key factors
Present results of updated studies
Review write-ups on ameliorative mechanisms
Review write-ups on Other relevant factors
Define preferred potential solution for issues reviewed
Define deliverables for Meeting 5
Study work
Structural Protection ameliorative mechanisms
Other relevant factors
Meetin 5 end of Jul
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for future meetings
Technical Issues
Review deliverables
Present follow-on work on updated studies
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Review write-up on updated studies
Review write-ups on ameliorative mechanisms
Review write-ups on Other relevant factors
Define preferred potential solution for issues reviewed
Define deliverables for Meeting 6
Study work
Structural Protection ameliorative mechanisms
Other relevant factors
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for future meetings.
Technical Issues
Review deliverables
Review draft report
Define deliverables for Meeting 7
Comments from workgroup participants
Meetin 7 Middle of 5e
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for future meetings
Technical Issues
Review comments from workgroup participants
Meetin 8 Middle of October
Process Issues
Review Work Plan
Discuss Reports (as needed)
Discuss Logistics for future meetings
Technical Issues
Review Final Report
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Appendix 4
Key Assumptions of PacifiCorp s Load Growth Studies
(Base Case Using June 2004 Forecast and March 2005 Forecast)
2004 IRP Preferred Portfolio
Forecasted study period FY2007 to FY2020
March 2004 load forecast
June 2004 Forecast, subsequently updated to the March 2005 Forecast for market and gas
prices
Recent forecast of clean air improvements to existing thermal generation
Recent forecast of relicensing hydro facilities
CO2 tax timing and cost assumptions consistent with IRP ($8/ton in 2008 dollars)
IRP Preferred Portfolio Resource Additions (under a 15% planning margin):-
FY2010 - 525MW Utah (Brownfield) Dry Cool CCCT with duct firing
FY2012 - 575MW Utah (Brownfield) Coal
FY2013 - 586MW West Main Dry Cool CCCT with duct firing
FY2014 - 560MW Utah Wet Cool CCCT with duct firing
FY2015 - 383MW Wyoming (Brownfield) Coal
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Appendix 5
Key Assumptions of PacifiCorp s Load Growth Studies
(Base Case Using June 2004 Forecast and March 2005 Forecast)
(With Utah-Growing at the Average of the Other States)
2004 IRP Preferred "Po rtfo Ii 0
Forecasted study period- FY2007 to FY2020
March 2004 load forecast
June 2004 Forecast, subsequently updated to the March 2005 Forecast for market and gas
prices
Recent forecast of clean air improvements to existing thermal generation
Recent fo recast of relicensing hydro facilities
CO2 tax timing and cost assumptions consistent with IRP ($8/ton in 2008 dollars)
IRP Preferred Portfolio E: ,485MW of new resources removed by 2015 while loads decreased
271MW
Remove East Mona Front Office transactions 50MW in 2008, 175MW in 2009, 50MW in
2010, then 200MW afterwards
Lower the Four Corners Front Office transactions 175MW in 2008, 225MW in 2012, 400MW
in 2013, 75MW in 2014, 200MW in 2015
Lower the West Main Front Office transactions by 200MW in 2009
Remove 525MW Dry Cool CCCT in 2010 located at Utah- S. Mona
Remove 560MW Wet Cool CCCT in 2014 located at Utah- N. Salt Lake Valley
The study adjusted the Front Office transactions in 25MW increments in calculating the planning
margin.
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Appendix 6
Preferred Portfolio E with DSM and Preferred Portfolio E with DSM
Adjusted to Maintain Consistent IRP Planning Margins
(2004 IRP, Executive Summary, page 9)
Locati n 2006 007 2008 2009 2010 2011 2012
Brownfield Coal Utah-S Hunter 4 575Greenfield Coal
Dry Cool CCCT Utah-S Mona
' ,,....
525:;:"525/3:525Wet Cool CCCT Utah-N Salt Lake Valley
East Market Mona 200 200 200,200'East Market Corners 400 400 500 500 500 500OF East OF Utah-100 100 100 100 100 100 100TransferTo East 454 454 454 454 454 454 454
Comm Cool Control East
Irrigation Control East
West
Lo a ion 006 207 2008 2011 201
Dry Cool CCCT WMAIN (1500') Medford 586 586
West Market WMAIN 200 150 200 400 400 500 500 500TransferFrom West 454 -454 454 -454 -454 -454 -454 454AC Control West
Irri alion Control West
Total MW 400 650 750 1288 1813 2488 3723 4106
15.15.15.15.15.17.17.15.
Preferred Portfolio E with DSM - Ad'usted to Maintain Plannin
East
Brownfield Coal Utah-S Hunter 4 575 575 575 575Greenfield Coal
Dry Cool CCCT Utah-S MonaWet Cool CCCT Utah.N Salt Lake Valley
East Market Mona " 0
East Market Corners 400 225 500 500
OF East OF Utah-100 100 100 100 100 100 100 100 100TransferTo East 454 454 454 454 454 454 454 454 454Comm Cool Control East
Irrigation Control East
West
Dry Cool CCCT WMAIN (1500') Medford
West Market WMAIN 200 150 200 200 400 400 500Differences in Load From West 454 -454 454 -454 454 -454 -454
AC Control West
Irri ation Control West
Total MW 400 650 525 913 1238 1088 1538
15.15.15.15.17,15.17,
Differences in MW'2251 3751 575'7251 9501 1251 360 I 1,4851
Differences in East Load 191 ~3191 4771 6441 795 ~9681 1111 271 1
1/ Planning Margin on adjusted Case (Utah Load Growth) set equal Base Case by adjusting FOT in 25 MW increments
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Appendix 7
Comparison of March 2005 Forecast (or CG 27) and June 2004
Forecast (or CG24) of Market and Natural Gas Prices
:~tAverage (East & West) Fiscal Year Natural Gas Price Comparison
March 2005 Forecast (or CG27) and June 2004 Forecast (or CG24)
E 4
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
--
June 2004 (CG24) --March 2005 (CG27)
Average Fiscal Year Market Price Comparison
March 2005 Forecast (or CG27) and June 2004 Forecast (or CG24)
.r. 55
tit 50
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
I-+-Average COB, Mid Columbia, DSW (June 2004) (CG24) -;r-Average COB, Mid Columbia. DSW (March 2005) (CG27) I
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Appen dix 8
ECD Alternative 1 Paper
MSP Revised Protocol
(Load Growth Workgroup Meeting - August 10, 2005)
New Resource ECD
As part of the Load Growth Workgroup various proposals for a structural mechanism to ensure that all
states pay their full share of the cost of meeting load growth have been discussed. In this paper
(together with Attachment 1) PacifiCorp sets forth a proposed New Resource Embedded Cost
Differential calculation as a structural protection mechanism that addresses the drivers of cost shifts
associated with load growth and at the same time is relatively simple to implement.
New Resource ECD
The New Resource ECD operates very much like the Hydro, Mid-C and Existing OF ECD calculations
in the current Revised Protocol. In the ECD calculation, a new resource category would be created.
This category would contain the costs of each newly constructed owned resource for a period of two
years. As with other ECD adjustments, the amount by which the cost of the new resource exceeds
the cost of the "All Other Resources" would be allocated to states using a forward looking SG factor
calculated with projected loads from a future period. Projected loads two years beyond the test
period would be used during the first year of the ECD assignment and one year beyond the test
period during the second year. The inverse amount would then be allocated back to states using the
SG factor from the test period. There may be times when there are both first and second year
resources in the New Resource category. Because a different allocation factor is applied during the
first and second years a resource is included in the New Resource ECD, a separate calculation would
be made for each resource.
Drivers of Cost Shifts
Potential cost shifts associated with load growth occurs when two conditions (drivers) exist
simultaneously. The first condition is differential load growth rates among the states; one or more
states growing significantly faster than the other states. The second condition is that the costs of new
resources are greater than the average embedded costs of the existing resource portfolio. The New
Resource ECD incorporates both of these drivers. The forward looking allocation factors address
differential load growth and the Total Company New Resource Embedded Cost Differential addresses
the higher cost of the new resource.
Why is only the cost difference between new and existing resources rather than the total cost
of new resources allocated on the forward looking factor?
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The costs of all resources continue to be allocated on system load based allocation factors. As one
state grows faster than the other states, that state is allocated a larger portion of the cost of all
resources. The faster growing state will already be allocated an increased share, a share that reflects
differential load growth, of the average embedded cost of the portfolio. The New Resource ECO only
needs to provide a supplemental allocation of the amount by which the new resource costs exceed
average embedded costs.
Why is the New Resource only included in the ECD for the first two years?
The Company s studies on the impact of differential load growth show that the largest potential for
cost shifts occur during the first two years after a new resource come on line. This is driven by front
revenue requirement loading of owned resources. The impact of front end loading is mostly offset by
the third year as the allocation of all generation, transmission and common overhead costs to the
faster growing state has increased enough to absorb the incremental costs difference.
Summary New Resource Embedded Cost Differential adjustment
Create New Resource ECO category
Compare cost of new resource ($/MWH) to cost of Annual Embedded Cost - All Other
Newly constructed resources included in EGO for two years
Separate calculation for each new resource
First year ECO allocated using SG factor calculated with projected loads two years beyond test
year
Second ECO allocated using SG factor calculated with projected loads one years beyond test
year
Inverse amount allocated with test year SG factor
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PaclflCorp
New Resource ECD (Attachment 1)
(Load Growth Workgroup Meeting. August 10, 2005)
2010 ECD Adjustment Total California Oregon Washington Wyoming Utah IdahoNew Resource Year 1 Alternate SG-FY12 55.433,142 950,869 14,321.956 4,425,975 491,420 26,308,402 934,519New Resource Year 1 Currenl SG-FY10 (55433,142)(966,188)(14 767,204)476,756)(6,744.029)(25,485.048)(2,993.917)New Resource Year 2 Allernale SG-FY11
New Resource Year 2 Currenl SG.FY10
Total Net ECD Adustment (15,319)(445,248)/50.782)/252.608)823.354 /59,398)
2011 ECD Adjustment
New Resource Year 1 Allernate SG.FY13
New Resource Year 1 Current SG.FY11
New Resource Year 2 Allernate SG.FY12 51,156.512 877,510 13,217027 084,514 990,612 24,278,727 708,123New Resource Year 2 Currenl SG.FY11 /51 156.512)/885,451\/13,479 581)(4,118,276)/6,034,322)/23,910775)728108)Total Nat ECD Adustment /7941)(262.554)(33 762)(43,711)367952 (19.985)
2012 ECD Adjustment
New Resource Year 1 Allernale SG-FY14 26,547 065 445,256 778,350 089.069 075947 12,799,737 358 706New Resource Year 1 Currenl SG-FY12 (26 547 065)(455374)(6,858,819)(2,119610)(3,108.757)(12,599,158)(1,405,348)New Resource Year 2 Alternale SG.FY13
New Resource Year 2 Current SG.FY12
Total Net ECD Adustment /10,117)/80,470)(30,541)/32,810)200,580 /46,642)
2013 ECD Adjustment
New Resource Year 1 Allernate SG-FY15 SO.397,609 836,958 12.797.304 940 341 745.149 24.523.499 554,359New Resource Year 1 Current SG.FY13 (SO.397 609)(853,033)(12,915,899)(3,988,708)(5.888 047)(24,146068)605855)New Resource Yaar 2 Alternale SG-FY14 463 150 141947 160,924 665.991 980.606 080,530 433,153New Resource Year 2 Current SG-FY13 /8,463,150)/143,248)(2,168,936)/669,814)/988,766)054,792)(437595)Total Nat ECD Adustment /17,376)/126,606)/52.191\/151,058)403,170 /55,938)
2014 ECD Adjustment
New Resource Year 1 Alternate SG-FY16 724,459 769,723 793,556 641,898 189281 22,990930 339,071New Resource Year 1 Current SG.FY14 (46724 459)(783679)(11,930.310)(3,676,889)(5,413,855)(22.528,320)(2,391406)New Resource Year 2 Alternate SG-FY15 48.325058 802,539 12,271,028 778,298 SO8,885 23,514,995 449 313New Resource Year 2 Current SG-FY14 /48,325.058)/810,524)/12,338,996)/3.802,845)/5.599,313)/23,300,053)/2,473.326)Total Net ECD Adustment /21 941)/204.723)/59,538)/315,002)677.552 (76.348)
2015 ECD Adjustment
New Resource Year 1 Alternate SG.FY17 63,051 950 031,328 15,681 826 881 894 964,918 31.357113 134,870New Resource Year 1 Currenl SG.FY15 (63,051.950)(1,047109)(16,010.581)(4,929,721)(7,187699)(30,681.107)(3.195.733)New Resource Year 2 Alternate SG.FY16 47,715942 786,056 12,043,812 719,178 299,397 23,478.793 388,705New Resource Year 2 Current SG-FY15 /47.715.9421 /792.423)/12.116,3571 /3.730.674)(5,439,448)/23218,599)/2.418.441)Total Net ECD Adustment /22.148)/401,299)/59323)/362,833)936200 /90.598)
2016 ECD Adjustment
New Resource Year 1 Alternate SG-FY18
New Resource Year 1 Currenl SG-FY16
New Resource Year 2 Alternate SG.FY17 55,454.984 907 066,13,792,363.293,687.125,732.578,975.757 157.New Resource Year 2 Current SG.FY16 /55,454,984)/913,546,74)/13.997,196,781 /4,322,391,46)/6,158,904,96)/27,286,815,211 /2,776,129.251Total Net ECD Adustment /6481)(204.8331 /28.704)/33.172)292,161 (18,971)
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Appendix 9
ECD Alternative 2 Paper
Straw Proposal for Direct Resource Assignment (Revised)
Marc Hellman, Public Utility Commission of Oregon
(Load Growth Workgroup Meeting - August 23, 2005)
This straw proposal presents a structural protection for cost shifts. The proposal uses
concepts embodied in the Revised Protocol relating to the treatment of hydroelectric resources.
key component of this proposal is the use of comparative grid runs, each with the same ten- year
period. For any study conducted up to December 31 , 2009, the time period of cost-shift analysis is
January 1 2005 through December 31,2014. Studies conducted subsequent to December 31 2009,will continue to use a ten-year period, comprised of the most recent five-year history along with a
projected five-year term. The analysis will use the actual costs of new resources as available.
For the ten-year period, two Grid runs would be used. The first would be based on Grid and
the Revised Protocol for the relevant time period as defined above, using IRP identified resources as
needed for the projected future five-year period. The first Grid run would also include the new
resources and contracts acquired during the historic five-year period, of the ten year period. The
second modeling exercise would have two complementary adjustments. First, the highest growth
state (in terms of aMW) would have its loads revised to equal the average growth rate (in percentage
terms) of the remaining states. For the start of the ten-year period, the highest growth state would
begin with the actual loads for the initial year of the study period. The subsequent nine years would
be adjusted so that high growth state loads grow at the average percentage growth rate equal to that
of the remaining jurisdictional states. Resources, including purchases, would be adjusted
downwards, consistent with the IRPs and knowledge available at the time, over the ten-year period toreflect the revised load levels. So adjustments would be made to resources and contracts for both
the five-year historic as well as the five-year projected period of the ten-year analysis. Only new
resources and longer-term purchases added over the unadjusted study ten-year period may be
dropped from the analysis should the adjusted load levels no longer warrant the power purchase or
new resource coming on line as scheduled. New resources, as the last sentence suggests, could
have on-line dates changed so that they remain in the analysis, but coming on line later in the study
period.
The two studies would be compared to calculate what percentage of the increase in costs
from the higher load levels was being allocated to the highest growing state. If the highest growing
state is being allocated under Revised Protocol a net 90 per cent or more of the 10-year present-
valued costs of new resources needed to serve the additional loads within the study, then the
structural protection mechanism would not be implemented.
However, if the highest growth state is allocated under the Revised Protocol less than a net
90 per cent of the costs of new resources, for each of any two consecutive years of study (not an
average of the two years), then this structural protection would be implemented. The net 90 per cent
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calculation represents offsetting the ten-year present value estimate by the cumulative percentage
that the preceding five years of studies resulted in the high growth state bearing more than 110% of
cost of new resources. By two consecutive years, it is meant that if the 1 O-year study conducted in
2007, and the 10-year study conducted a year later in 2008 both result in less than a net 90 percent
of the costs of new resources being assigned under Revised Protocol to the highest cost state, then
the structural protection mechanism would be implemented.
In addition , if the highest growth state is allocated under the Revised Protocol less than a net
80 per cent of the costs of new resources for any single study, then this structural protection would be
implemented.
The "netting" process steps are as follows:
1. Check to see if any of the preceding five years of results yielded the high growth state
bearing more than 110% of costs of new resources and purchases. If no, no netting is
required. If yes, go to Step 2.2. Calculate the cumulative excess above 110% for any of the preceding five years of study
that have the high growth state bearing more than 110% of costs of new resources and
purchases.
3. Review the % cost burden borne by Utah for the current year study and last year s study.
If either year has a % level lower than 80%, use any excess cumulative % to bring the
below-80% level up to 80%.4. If any excess cumulative % remains after step 3, review cost burden % to see if either the
prior year or the current year study is below 90% and the remaining excess cumulative
percentage could bring that value up to 90%. If yes, then take that action.
The examples below might help illustrate the trigger proposal:
Example # 1
Year Action
10-Year Present 2005 2006 2007 2008
Value No Trigger
102%89%93%83%
Example # 2
Year Action
10-Year Present 2005 2006 2007
Value Triggered in 2007
102%89%87%
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Example # 3
Year Action
10-Year Present 2005 2006 2007 2008
Value Trigger in 2008
102%89%93%77%
Example # 4
Year Action
10-Year Present 2005 2006 2007 2008 No Trigger
Value Adjusted 2006 =
112%89%87%93%90%
Adjusted 2007 =
88%
Calculation-Use the "excess" 2% (112 - 110) to bring the 89% to 90%, then any remaining excess is applied to 2007.
Example # 5
Year Action
10-Year Present 2005 2006 2007 Triggered in 2007
Value Adjusted 2006 =
102%75%82%80%
Adjusted 2007 =
87%
Calculation-Use the "excess" 10% (120 -110) to bring the 75% to 80%, then any remaining excess is applied to 2007.
The 75% value for 2006 would also have been raised in that year due to the 120% value for the 2005 study.
Once the trigger thresholds are met establishing the implementation of the structural
protection mechanism, the resources that came on line during the ten-year study period would be
ranked for possible use in the structural protection mechanism. New resources that are renewable or
hydroelectric-based would be excluded from the candidates considered for disparate treatment. (See
Revised Protocol, Section IV.2) The remaining new resources would be ranked fist by identifying
the resources added within the five-year historic period, with the highest cost per aMW being first and
lowest cost per aMW last. Next transfer payments would be established similar to the treatment of
hydroelectric resources. In conceptual terms the fastest growing state bears the differential in cost
between the resource added during the study period and the average cost of the remaining
PacifiCorp thermal resources.
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The objective is to establish a set of transfer payments such that 95 per cent of the costs of
new resources needed to meet the differential in load growth are assigned to the highest growth
state. Again, the difference in costs of the new resource would be compared to all other thermal
resources, with the higher than average costs being assign to the highest growth state to the extent
necessary to achieve the 95 per cent target. If assigning all of the capacity of the highest cost
resource differential is insufficient with respect to the highest new thermal resource, then the nexthighest cost resource would be used for transfer payment purposes. These steps would be repeated
until the 95 percent target is met. Once the 95 per cent target is met, the Revised Protocol with the
structural protection transfer payments would be used for PacifiCorp general rate filings on a going
forward basis until the trigger is triggered again.
Transfer payments would not include costs of resources or purchases projected to come
line in the future five-year period because they are not yet used and useful, and as such would not be
included in rates.
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Appendix 10
Lump Sum Transfer Paper
Load Growth Lump Sum Transfer ECD Adjustment
(Load Growth Workgroup - August 10, 2005)
One approach to ensuring that a faster growing state picks up an adequate level of the cost of load
growth is to make a lump sum revenue requirement transfer from slower growing states to the faster
growing state. Such an approach would only be implemented when analysis suggests that a faster
growing state is not covering the cost of its load growth. A Lump Sum EGO Adjustment is one
approach to make such a lump sum transfer. For discussion purposes an example Lump Sum EGO
Adjustment is shown.
This example is based on the FY 2010, GG27 load growth study (the year where Utah picks up the
lowest percentage of the cost of load growth). An $11 million lump sum transfer, the amount neededto bring Utah up to 90% of the cost of load growth that year, is direct assigned to Utah. An equal
credit is allocated back to the other states using a modified SG factor (the proportional SG factors of
all states except Utah).
PacifiCorp
FY 2010 Lump Sum ECD Adjustment
Lump Sum Transfer to bring Growth State to 90% of Cost of Incremental Load Growth
FY 2010 MSP Factors Total California Oregon Washington Wyoming Utah Idaho
100.0000%7430%26.6397%0760%12.1661%45.9744%5.4010%
SG-Less UT 100.0000%2262%49.3093%14.9484%22.5191%0000%9970%
Lump Sum ECO Adjustment Factor
Assignment to Growth State Situs 11,220,400 11,220,400Adjustment to non Growth States SG-Less UT (11 ??O dOO)("1/';1 QQ"I)(r:; r:;"I? 7n.d)(1 /,;77 ?RQ)(? "?R 7?R)(1 1?1 70/,;)
Total (361,993)(5,532,704)677 269)(2,526,728) 11,220,400 (1,121 706)
FY2010 - Comparison of Utah growing at system average vs Utah growing as projected (Revised Protocol- CG27)5 Cost of Incremental Load Growth $147,006,000
690% of Incremental Cost $132.305,4007 Utah Incremental Revenue Requirement $121,085,000
8 Lumo Sum Transfer (line 6 less line 7) $11220400
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Appendix
Structural Protection Mechanisms
ECD Alternative 1 Compared to ECD Alternative 2
ECD ECD
Alternative 1 Alternative 2
Author PacifiCorp Marc Hellman, Oregon PUG Staff
Load Growth August 10, 2005 August 23, 2005
Workgroup Meeting
Proposal New Resource ECD and Process Straw Proposal for Direct Resource
for Implementing SPMs on Revised Assignment
Protocol
LG Study Period Minimum 10- Year forward looking 5 Year Historical/5 Year Forward
forecast that captures IRP planned
resource additions Start with calendar 2005, replace
forecast with actual until 5 years of
actuals are included. Studies
conducted after calendar 2009 will roll
forward annually maintaining 5 years
historical & 5 years forecast
Commencement Year of 2"" year of IRP Study period Calendar 2005 to start
LG Study Period
LG Study Load Growth Study defined by Same as Company Study except for
Revised Protocol page 7 footnote 2.study period (see above). Average
Requires comparative GRID & RFM load growth study defers or removes
runs. Average load growth study IRP newly acquired resources and IRP
defers or removes IRP planned planned resources to maintain IRP
resources to maintain IRP planning planning margin
margin
LG Study Updates Biennial (every two years) -Annuall - recognizing In the years
following IRP cycle, and upon where IRP is not published update is
request by MSP Standing limited (excludes loads and new
Comm ittee after it has reviewed the resources forecast updates)
key tracking factors.Follows
acknowledgement of the
Company s IRP
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Trigger
Resource Cost
Adjustment (ECD)
SPM Allocation
SPM Implementation
SPM Duration
ECD
Alternative 1
Qualitative Tri er-
Fast Growing State Pays 85% or
higher on a NPV basis, no material
"harm & no action required. Fast
Growing State pays less than 85%
. MSP Standing Committee to
define action
Newly constructed cost of owned
resources included in rates.
New resource costs built and in
operation in excess of the all other
resource cost. Projected loads two
years beyond the test period during
151 year of new resource addition
and projected loads one year
beyond test period during second
year. Inverse SG factor for test
period.
MSP Standing Committee decides
one of three actions.
1) Do nothing
2) Recommend PacifiCorp, in each
of its subsequent general rate case
filings, include structural protection
mechanism
3) consider changes to the Revised
Protocol
Temporary assignment of 2 years
for GRC within period
ECD
Alternative 2
Quantitative Tri er -Fast Growing
State Pays 90-110% on a NPV basis,
no material harm & no action required.
Trigger occurs:
Below 90% for two
consecutive years
. Any year below 80%
Allows netting when load growth study
is above 110%.
Newly constructed cost of owned and
purchased resources, ranked from
highest cost (first) to lowest cost (last)
per aMW. Transfer payment is
determined by starting with highest cost
company acquired resource during
historical 5 year period. Exclude
renewable or hydro-electric resources
given disparate treatment
Objective to create transfer payments
so 95% of unpaid load growth on a NPC
, basis is assigned to highest growth
state. Start with assigning highest cost
new resources (over last 5 years
historical) until transfer payment
threshold is met to ECO. Approach
similar to QF existing methodology in
ECO. Inverse SG factor without high
growth state for test period.
Implement immediately and
automatically upon trigger, SPM
transfer payment in next general rate
filing
Permanent assignment using a transfer
payment
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Appendix 12
List of PacifiCorp s Hybrid Studies and Results
Hybrid Studies
A number of Hybrid studies were modeled before Case 3b1 a was confirmed as the basis for the
presentation to the Oregon Public Utility Commission. Table 8 is a Resource Matrix providing a list of
the studies performed and presented to the Hybrid Workgroup.
Table 8
Resource Matrix for Hybrid Studies
IRP Jim BridgerHybridHybrid Workgroup Cholla Jim Bridger Unit 5 IRP 2014 CCCT IRP 2010 CCCTCaseMeeting (except APS (380 MW Units 1 - 4 (383 MW (560 MW (525 MWNumberwhere indicated)(480 MW)Nameplate)(1412 MW Nameplate)Nameplate)Nameplate)Nameplate)
2004 Forecast -
June 28, 2005
West West All units in West East East East2005 Forecast -
July 18, 2005
1 (Load 2004 Forecast -Removed from Removed fromGrowthJune 28, 2005 West West All units in West East the East Control the East ControlStudy)Area Area
Existing Resource Sensitivities
380 MW allocated to the
August 24, 2005 West West East and remainder is East East Eastallocated to the West
Equally split between
August 24, 2005 West West East and West East East East
(1)June 28, 2005 East East All units in West East East East
July 18, 2005 West East All units in West East East East
New Resource Sensitivities
August 24, 2005 West East All units in West West East East
August 24, 2005 West East All units in West East West East
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Hybrid
Case
Number
Hybrid Workgroup
Meeting (except
where indicated)
APS
(480 MW)
Cholla
(380 MW
Nameplate)
Jim Bridger
Units 1 - 4
(1412 MW Nameplate)
IRP Jim Bridger
Unit 5
(383 MW
Nameplate)
IRP 2014 CCCT
(560 MW
Nameplate)
IRP 2010 CCCT
(525 MW
Nameplate)
3b1a (Load October 11, 2005 125 MW allocated to the Removed from Removed fromGrowth(Load Growth West East East and remainder is East the West Control the East ControlStudy)Workgroup Meeting)allocated to the West Area Area
Equally split 190 MW allocated to the
September 14, 2005 West between East East and remainder is East West Eastand West allocated to the West
100 MW allocated to theTest Case September 14, 2005 West East East' and remainder is East West East(3b1 )allocated to the West
200 MW allocated to theTest Case September 14, 2005 West East East and remainder is East West East(3b2)allocated to the West
300 MW allocated to the
Test Case September 14, 2005 West East East and remainder is East West East(3b3)allocated to the West
(1)Study was run using only the 2004 Forecast
Below are the results of the Hybrid studies performed by the Company from June 2005 through
October 2005. These studies are presented in chronological order, based on the date of the HybridWorkgroup meeting at which they were presented. For study assumptions, refer to Appendices 4
and 5.
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Hybrid WorkarouD Meetina - June 28. 2005
The Hybrid study results shown in Table 9 were presented to the Hybrid Workgroup meeting held on
June 28, 2005. The studies were performed using the June 2004 Forecast gas and market pricing
data.
Table 9
Hybrid Cases 1 and 2
Percentage Difference in NPV Revenue Requirement
from Revised Protocol using June 2004 Forecast
(Hybrid Workgroup Meeting - June 28, 2005)
State Hybrid Case 1 Hybrid Case 2
Base Case
Year 14-Year Year 14-Year
NPV 2007-2015 NPV 2007-2020 NPV 2007-2015 NPV 2007-2020
California 33%79%16%80%Oregon 23%86%2.43%21%
Washington 09%04%36%58%
West Control Area 13%81 %25%18%
Idaho 17%55%60%08%
Utah 29%76%06%65%Wyoming 2.46%51%83%00%
East Control Area 67%05%34%84%
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Hybrid WorkarouD Meeting - July 18. 2005
The Hybrid study results shown in Table 10 were presented to the Hybrid Workgroup meeting held on
July 18, 2005. The studies were performed using the March 2005 Forecast gas and market pricing
data and incorporate the intra-control area equity measures of (1) QFs situs assigned, and (2) hydro
reserve credit situs assigned to Wyoming.
Table 10
Hybrid Case 1 Variations
Percentage Difference in NPV Revenue Re quirement
from Revised Protocol using March 2005 Forecast
with Intra-Control Area Equity Measures
(Hybrid Workgroup Meeting - July 18, 2005)
Includes Intra-Control Area Equity Measures
State Hybrid Case 1 Results with APS Results with APS in Results with APS in
West Cholla in West Cholla in West Cholla in
East East, QFs situs East, QFs situs
assigned assigned and hydro
reserve credit situs
to Wyoming
Year 14-Year Year 14-Year Year 14-Year Year 14-Year
NPV NPV NPV NPV NPV NPV NPV NPV
2007 -2007-2007-2007-2007-2007-2007-2007-2015 2020 2015 2020 2015 2020 2015 2020
California 62%70%87%25%61%86%61%86%Oregon 92%08%88%2.44%59%24%59%24%Washington 97%41%00%87%2.43%02%43%02%West Control Area 83%04%~ 1.83%2.44%83%44%83%2.44%
Idaho 33%37%38%68%36%59%50%72%
Utah 14%31%71%12%82%21%96%34%
Wyoming 06%78%95%94%52%57%86%96%
East Control Area 68%75%08%1.40%08%1.40%08%1.40%
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Hybrid Work~arouD Meetina - Auaust 24. 2005
The Hybrid study results shown in Tables 11 and 12 were presented to the Hybrid Workgroup
meeting teld on August 24, 2005. The studies were performed using the March 2005 Forecast gas
and market pricing data and incorporate the intra-control area equity measures of (1) QFs situs
assigned, (2) hydro reserve credit situs assigned to Wyoming, and (3) Mid-
Table 11
Hybrid Cases 1a and 1b
Percentage Difference in NPV Revenue Requirement
from Revised Protocol using March 2005 Forecast
with Intra-Control Area Equity Measures
(Hybrid Workgroup Meeting - August 24, 2005)
Includes Intra-Control Area Equity Measures
State Hybrid Case 1 Hybrid Case 1
Year 14-Year Year 14-Year
NPV 2007-2015 NPV 2007-2020 NPV 2007-2015 NPV 2007-2020California25%07%54%23%Oregon 90%62%25%86%
Washington 19%82%88%33%West Control Area 92%63%27%86%
Idaho 74%62%64%34%
Utah 20%95%58%20%Wyoming 57%57%80%61%
East Control Area 14%93%71%36%
Table 12
Hybrid Cases 3, 3a, and 3b
Percentage Difference in NPV Revenue Requirement
from Revised Protocol using March 2005 Forecast
with Intra-Control Area Equity Measures
(Hybrid Workgroup Meeting - August 24, 2005)
Includes Intra-Control Area Equity Measures
State Hybrid Case 3 Hybrid Case 3a Hybrid Case 3b
Year 14-Year Year 14-Year Year 14.Year
NPV 2007-NPV 2007-NPV 2007-NPV 2007-NPV 2007-NPV 2007-
2015 2020 2015 2020 2015 2020
California 54%95%35%52%09%14%Oreaon 84%2.45%1 .58%89%22%35%Washington 87%55%57%89%19%35%
West Control Area 83%44%56%87%21 %34%
Idaho 50%72%39%52%17%16%
Utah 96%34%79%96%58%69%Wyoming 86%96%75%79%51%37%East Control Area 08%1.40%92%07%71%77%
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Hybrid Workaroup Meetina - September 14~ 2005
The Hybrid study results shown in Tables 13 and 14 were presented to the Hybrid Workgroup
meeting held on August 24 2005. The studies were performed using the March 2005 Forecast gas
and market pricing data and incorporate the intra-control area equity measures of (1) QFs situs
assigned, (2) hydro reserve credit situs assigned to Wyoming, and (3) Mid-C.
Table 13
Case 3b Variations
: Percentage Difference in NPV Revenue Requirement
from Revised Protocol using March 2005 Forecast
with Intra-Control Area Equity Measures
(Hybrid Workgroup Meeting - September 14 2005)
Includes Intra-Control Area Equity Measures
State Hybrid Case 3b1 Hybrid Case 3b1 a Hybrid Case 3b2 Hybrid Case 3b3
Year 14-Year Year 14-Year Year 14-Year Year 14-Year
NPV NPV NPV NPV NPV NPV NPV NPV
2007 -2007-2007-2007-2007-2007-2007-2007-
2015 2020 2015 2020 2015 2020 2015 2020
California 39%0.43%15%21 %57%47%54%38%
Oregon 29%39%03%09%98%82%26%04%
Washington 20%35%14%03%16%93%54%22%
West Control Area 28%38%05%08%99%82%28%04%
Idaho 0.48%0.48%69%68%33%27%20%06%
Utah 09%20%08%04%60%0.44%30%08%
Wyoming 77%65%54%0.43%18%23%14%12%
East Control Area 16%22%02%05%59%0.47%35%17%
Table 14
Case 3c
Percentage Difference in NPV Revenue Requirement
from Revised Protocol using March 2005 Forecast
with Intra-Control Area Equity Measures
(Hybrid Workgroup Meeting - September 14,2005)
Includes Intra-Control Area Equity Measures
State Hybrid Case 3c
Year 14-Year
NPV 2007-2015 NPV 2007-2020
California 07%14%
Oregon 33%38%
Washington 0.49%51%
West Control Area 35%39%
Idaho 77%84%
Utah 31%28%
Wyoming 0.49%29%
East Control Area 21%23%
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Appendix 13
Tiered Alternative 1 Paper
Straw Proposal for Tiered Allocations
(Second Revision)
Marc Hellman, Public Utility Commission of Oregon
Load Growth Workgroup Meeting - June 29, 2005
This straw proposal presents a structural protection from cost shifts. The proposal is based
upon a two tiers of resources framework with corresponding load demarcation. All new resources
would begin to be allocated to the second tier when it is determined52 that the least-cost plans identify
resource additions, or group of resource additions, to come on-line within 36 months, to meet
disparate load growth, will cause a cost shift among the states for which offsetting considerations are
not sufficient to mitigate the cost shift. Allocations for changes in Tier 1 resources are made on a
fixed set of allocation factors established at the trigger date. 53 Reductions in Tier 1 loads are
handled slightly differently. (See Scenario 1) Common costs are allocated based on total loads.
A. Base Tier1. Existing resources and contracts as of a trigger date and includes:a) Refurbishment of TIer 1 resourcesb) Relicensing of Tier 1 resourcesc) Contract renewal of Tier 1 resources for which renewal rights are
specified by contract which is being renewed. (Holder of contract has
renewal rights different than what would be available to an independent
third party.d) Net of existing wholesale sales commitments executed prior to trigger
date
52 This paper does not have a definitive suggestion as to whom or how this determination is made. One option would be that
any state could make the determination independently. Presumably the state would try to convince the other states to agree
with this finding. The Revised Protocol identifies the consequences should Oregon depart from the Revised Protocol and
PacifiCorp s obligations assuming Oregon does not depart from the Revised Protocol. An alternative for how the cost shift
determination could be made is through the Standing Committee. However, it is clear that no state is delegating to the
standing Committee the state s obligation to ensure fair and reasonable rates. This "determination" matter need not be
resolved at this time. The Revised Protocol directs the development of a structural protection mechanism but does notprescribe the considerations for when it would be adopted. 53 If a state has load loss causing the state loads to fall below the Tier 1 trigger date levels, any benefits/costs of the remaining
Tier 1 resources would be allocated to all the states proportionally to their respective Tier 1 trigger date levels with the
exception of using the state s reduced load levels. The trigger date is the date by which a s1ate finds cost shifts would occur
and hence is never retroactive, and can start at the date of the order or some future date as established through that
commission s order.
54 The structural protection is prospective in nature. The proposal is not based on the concept that cost shifts have occurred.
All four states adopting the Revised Protocol have essentially concluded that at the time of adoption, and studies analyzing its
reasonableness, the allocations based upon the Revised Protocol are reasonable. The trigger date can be based on resources
currently under construction and not on line as of early 2005, when the Revised Protocol was adopted.
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(1) Base Tier net position (Tier 1 resources net of firm long-term
wholesale sales) can increase or decrease
2. No replacement of Tier 1 except as provided above3. Resource/costs allocated using Revised Protocol Methodology
4. Base factors are those calculated as of the trigger date.a) Establish state load levels as of trigger date and allocation at a level of
loads that equals available resources
(1) Calculate pro rata reductions in loads to establish Tier 1 loads
and resources.
(2) For changes in Tier 1 Resources, first step is to use pro rata
changes using trigger date load ratio/factors.
(3) If state loads fall below original Tier 1 allocations, any remaining
Tier 1 resources are allocated pro rata across states using
adjusted state trigger-date factors. In this case the benefits of
the excess Tier 1 resources (cost versus market) are what are
allocated. Such state can grow back into its original Tier
allocation, with corresponding reversal of increases in Tier
allocations for other states.5. Calculate remaining resource needs for each state
6. Power cost runs are based on Tier 1 loads and resources
7. To the extent reserves are needed, purchase at market prices
B. Second Tier (only two tiers are proposed)1. All new resources, purchase contracts and wholesale sales on and after the
trigger date2. Tier 2 cost and allocations is given by the following: Tier 2 allocations = Total
Company Grid run - Grid run on Tier
a) The costs identified as Tier 2 costs are allocated using the Tier 2 load
based factors.3. Calculate remaining resource needs for each state. (Remaining resource needs
of each state equals total state loads minus allocated Tier 1 resources.
4. Power cost runs are based on net remaining loads and Tier 2 resources
5. To the extent reserves are needed, purchase at market
C. Changes in loads
1. Loads assigned to Tier 2 for any state cannot decrease except when Tier 2
resources decrease.a) Reductions in load are assigned unadjusted shares of Tier 2 and any
offsetting sales for resale revenues2. Reductions in Tier 1 loads are handled consistent with Revised Protocol.
Reductions caused by factors other than direct access result in a reduction in
allocation of Tier 1 resources. Tier 1 resources are reallocated to other states.
However, Tier 1 resource allocations can be restored if loads return to pre-trigger
date levels.
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3. Calculate remaining resource needs for each state
D. Other
a) Short-term and new long-term sales for resale are assumed to be
provided by Tier 2 resources up to the energy generating capability of
Tier 2 resources. Exception is sale of power matching a Tier 1 load
reduction.
Appendix
Option Selections
The following lists the options selected from the PacifiCorp paper provided in the Appendix.
) Tier 1 Design:Option 1
) Growth Costs:Option 1
) Multiple Tiers:Option 1
2) Selection of Base Year:Option 3
) Wholesale Sales:Option 1
) Long Term Wholesale Purchases:Option 1
) Treatment of Load Decrements:Not applicable
) Reductions in Load:Option 1
) One state grows then loses load Option 1
) Gain or loss of Service Territory Option 1
) Sale of Generation Option 1
) Direct Access Treat consistent with Revised Protocol
) Replacement power Option 1
) Generation Changes Option 1
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) Lost Hydro Generation Same as 5.
) Planning Reserves New Proposal closest to Option 2
Base Case
Tier 1 Resources equals 1000 Tier 1 Allocations
Tier 1 Loads as of Trigger Date
Utah
Wyoming
Idaho
Washington
Oregon
425
150
100
250
0.425
150
100
075
250
Tier 2 Resources equals 100 Tier 2 Allocations
Tier 2 loads
Utah
Oregon
The following examples are designed to provide how factors would be derhed for both Tier 1 and Tier
2 costs. Tier 1 costs are identified by means of the resources existing prior to the trigger date. Tier 2
costs are total company costs minus Tier 1 costs. General allocators are based on total loads.
Scenario 1 = Idaho Tie r 1 loads decrease by 25 mW
Tier 1 Resources equals 1000 Tier 1 Allocations
Tier 1 Loads as of Trigger Date with Adjustment
Utah
Wyoming
Idaho
Washington
Oregon
425
150
75 (100 - 25)
250
0.425
150
100
075
250
Excess 25 MW gets valued at market and margins are distributed pro rata to the adjusted Tier allocations.
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Adjusted Tier 1 allocations for distribution of margins
Utah
Wyoming
Idaho
Washington
Oregon
Adjustment
.425*00010.975
150*00010.975
75*000/0.975
75*000/0.975
250*000/0.975
Factor
0.436
154
077
077
256
Adjusted Tier 1 allocations for 975 mw of Tier 1 Resources
Utah
Wyoming
Idaho
Washington
Oregon
Load
425
150
Factor
0.436
154
077
077
256
Tier 2 Resources equals 100 Tier 2 Allocations
Tier 2 loads
Utah
Oregon
Scenario 2 = Tier 1 Resources reduced by 100 mW
Tier 1 Resources equals 1000 Tier 1 Allocations
Tier 1 Loads as of Trigger Date
Utah
Wyoming
Idaho
Washington
Oregon
425
150
100
250
0.425
150
100
075
250
Tier 1 loads shifted into Tier 2
Adjustment Load Shifted
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Utah
Wyoming
Idaho
Washington
Oregon
425*100/1000
150*100/1000
100*100/1000
75*100/1000
250*100/1000
42.
15.
10.
25.
Tier 2 Resources equals 200 (100 + 100)Tier 2 Allocations
Tier 2 loads
Utah
Oregon
Idaho
Washington
Wyoming
75+42.5 = 117.
25+25 =50.
0+10 = 10.
0+7.5 = 7.
0+15 =
5875
0375
075
Scenario 3 = Uta h Tier 2 loads decrease bv 25 mW
Tier 1 Resources equals 1000 Tier 1 Allocations
Tier 1 Loads as of Trigger Date
Utah
Wyoming
Idaho
Washington
Oregon
425
150
100
250
425
150
100
075
250
Tier 2 Resources equals 100 Tier 2 Allocations
Tier 2 loads
Utah
Oregon
50 (75 - 25)75*
* 25 mW of Tier 2 resources are sold on market for a term of one year with 100% sales for resale
allocated to Utah.
Scenario 4 = Tier 2 Resources Increase by 100 mW with loads increasing 50
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Tier 1 Resources equals 1000 Tier 1 Allocations
Tier 1 Loads as of Trigger Date
Utah
Wyoming
Idaho
Washington
Oregon
425
150
100
250
425
150
100
075
250
Tier 2 Resources equals 200 Tier 2 Allocations
Tier 2 loads
Utah
Oregon
120 (75 + 45)
30 (25 + 5)
80 (120/150)
20 (30/150)
* The excess 50 aMW is marketed in the wholesale market and the revenues from such a sale are
allocated to Utah and Oregon on an 80/20 basis. The full costs of the excess 50 aMW are allocated
to the Tier 2 loads using the 80/20 factors in this illustrative example.
Tiered Allocation
Issues and Options for Resolution
(Load Growth Workgroup Meeting - June 29, 2005)
PacifiCorp Discussion Paper
April 20, 2004
Initial studies of tiered allocation identified a large number of issues that must be resolved before a
tiered allocation method could be put in place. Each issue appears solvable and in most cases more
than one solution is possible. This paper summarizes the options identified so far.
1) Overall Design Issues
) Tier 1 Design
Fundamental to the design of tiered allocations is the identification of loads and resources to be
included in Tier 1 over time. The initial design of a tiered allocation method started Tier 1 loads andresources at FY 2002 levels. All growth in resources and loads were added to Tier 2. Over time, anumber of Tier 1 resources expire or retire. It is desirable to keep Tier 1 loads and resources
relatively in balance because the load/resource balance will affect the assignment of system
balancing sales and purchases to Tier 1. The initial concept was to reduce Tier 1 loads to keep themrelatively in balance with resources as the later expired or retired over time. This would represent a
gradual move toward Rolled-In allocation as Tier 1 loads and resources decline.
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Another possible design of a tiered allocation method would replenish Tier 1 resources as they
expire. This would keep Tier 1 loads and resources near their initial values. It would also increase
the mix of Tier 2 costs in Tier 1. This tiered allocation method requires calculation of Tier 1 and Tier
2 before adjustments, determination of the size of the Tier 1 adjustment, then adjustment of both
loads and resources for Tier 1 and Tier 2. Fundamentally, the design of the tiered allocation method
will reflect whether parties believe that the tiers should diminish over time or persist.
Option 1:
Option 2:
Reduce Tier 1 loads as Tier 1 resources expire. Over time, Tier 1 goes away.
Replenish expiring Tier 1 resources, maintaining the size of Tier 1 over time. For
issues related to replenishment of resources, see the "Replacement Power" section
on page 5 of this paper.
) Growth Costs
Tiered allocation methods are intended to cause fast growing states would pay for their own load
growth. Costs associated with growth can be difficult to quantify and assign to Tier 2 within a single
company system. Identifying the addition of new generation resources is easy but each new
resource may contribute to factors other than growth. In addition, other system costs needed to
support needed to support new resources are more difficult to quantify. Examples include
transmission and overheads. A central design question for tiered allocation is whether TIer 2 has
adequately captured all costs of load growth.
Option 1:
Option 2:
Option 3:
Apply tiered allocation method only to direct new resource costs.
Identify additional categories of costs related to growth.
Determine the growth-related portion of new resources, existing resources and
overheads and assign only growth-related costs to Tier 2.
) Multiple Tiers
The design of a tiered allocation method could come under considerable pressure if load growth
patterns were to change in the future. Utah loads are presently growing faster loads in other states.
Present tiered allocation designs place relatively more Utah load in Tier 2 than other state loads.
Suppose the growth patterns of Utah and Oregon were to reverse in future years and the Company
began acquiring resources in the West. The principles of tiered allocation would suggest that Utah
should not be responsible for the costs of those Western resources just because they happened to
have grown in prior years. A third tier may be needed to refl ect this new era. Indeed , it would be
possible to argue that every resource is the product of a unique pattern of growth.
Option 1:
Option 2:
Option 3:
Agree in advance that no additional tiers will be created.
Create additional tiers under specified circumstances.
Allocate resources added in each year based on growth formulas specific to that year
(Le. a new tier each year.)
2) Selection of Base Year
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The base year divides Tier 1 from Tier 2. Selection of the base year is a fundamental design step for
tiered allocation. Since growth and resource acquisition are more-or-Iess continuous processes,parties may differ in their choice of one base year over another. For initial studies of tiered allocationFY 2002 was chosen because energy loads and resources were roughly in balance in that year. This
base year also places in Tier 2 the newer resources that Oregon parties believed were associated
with the type of growth to be captured by Tier 2.
Option 1:Move base year to FY 2005. Moving the base year to 2005 would have the effect of
including Gadsby ers and West Valley in Tier 1. The change would not eliminate
the problem of decreasing loads discussed in the Section 4.a. of this paper.
Leave base year in FY 2002
Pick a different year.
Option 2:
Option 3:
3) Loads To Be Included
) Wholesale Sales
When wholesale sales contracts expire, existing resources can serve more retail load. The initialtiered allocation studies were based on retail loads. Studies increased the size of Tier 1 loads whenexisting wholesale sales contracts expired, consistent with the treatment of expiring long-term
purchases. Increasing Tier 1 loads in this way contributed to the problem of negative Tier 2 loads in
the initial studies. Alternatively, expiring wholesale sales contracts are one way that the Company
plans to serve new retail loads. New resource additions in the Integrated Resource Plan assume that
certain wholesale sales contracts will expire. Focusing on these considerations, one could decide notto increase Tier 1 loads as wholesale sales contracts expire.
Option 1:
Option 2:
Option 3:
Increase adjusted Tier 1 loads as long-term wholesale sales contracts expire
Do not increase adjusted Tier 1 loads as long-term wholesale sales contracts expire.
Use loads that include long-term wholesale sales for Tier 1 modeling and allocation
factors.
) Long-Term Wholesale Purchases
The initial tiered allocation studies reduced the size of Tier 1 as long-term purchase contracts expired.The treatment maintains a reasonable match between base period loads and resources. See also
Section 1.a. of this paper on "Tier 1 Design.
Option 1:
Option 2:
Reduce Tier 1 loads as long-term purchase contracts expire.
Do not reduce Tier 1 loads as long-term purchase contracts expire. Replace expiring
contracts with an average of Tier 2 resources.
Similar to Option 2 but replace expiring contracts with specific replacement
resources.
Option 3:
) Treatment of Load Decrements
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The initial tiered allocation studies used decremented loads to allocate West Hydro, Mid-C contracts
and QFs. The studies used no decrements assigned to Tier 2 because new QF contracts were not
assumed. The combination of load decrements and tiered allocation is much more computationally
complex than either method alone. Load decrements may be redundant with tiered allocation since
both are aimed, at least to some degree, at removing load growth impacts. In addition, Utah parties
have raised concerns regarding the load decrement approach.
Option 1:
Option 2:
Apply the load decrements approach with tiered allocation.
Use other methods of calculating a hydro endowment with tiered allocation.
4) Changes in Load Over Time
) Reductions in Load
State loads can fall as well as rise. The initial design br tiered allocations makes no special provision
for that fact. Wyoming loads, in particular, fall below their FY 2002 levels during the forecast. When
a state s load falls below the Tier 1 amount, its calculated Tier 2 loads would be negative under the
initial design. In effect, the state buys power at Tier 1 costs and sells it at higher Tier 2 costs, creating
benefits for that state. Negative loads reverse the signs of many computations and this can make
interpretation of results difficult. If a tiered allocation method reduced a state s Tier 1 allocation if
loads fall below the base level, parties would have to agree on changes to the allocation of Tier
resources and on whether the state s Tier 1 allocation could increase again once loads started to
grow.
Option 1:
Option 2:
Option 3:
Tier 1 load is the lower of the adjusted base period Tier 1 load or the actual load.
When actual load is less than adjusted Tier 1 load there would be no Tier 2
allocations. Reductions in Tier 1 load are permanent.
Similar to Option 1 except that reductions in Tier 1 load are temporary so that a state
could grow again and remain in Tier 1.
No adjustment for negative loads in a tier.
) One state grows then loses load
A state that is growing and loses a material portion of its load, such as could occur in areas that
currently serve industrial loads, may create unintended revenue requirement impacts to other states.
The design of tiers should consider whether the load being lost is from Tier 1 or Tier 2. The allocation
effect of losing loads will be more pronounced in Tier 2 than under Rolled-In because of the smaller
base of Tier 2 loads. The loss of load in Tier 2 may magnify any imbalance between Tier 2 retail
loads and resources. A key concern in developing tiered allocations is the risk sharing issue.
Option 1:
Option 2:
Option 3:
Option 4:
No adjustments for large load losses
Adjustment to Tier 1 or Tier 2 depending on when and where load was originally
assigned
Reset Tier 1 and Tier 2 prices. This option would require specification of when and
how the tiers are reset.
Add additional tiers
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,"*'
) Gain or Loss of Service Area
The design of tiered allocations should consider the impact of gaining or losing service territory, either
within an existing state or in a new state. Generally, MSP parties have favored treating allocation
issues associated with acquisition of service territory as special cases. This discussion focuses on
loss of service territory.
, ..
or,Loss of service territory could potentially impact both Tier 1 and Tier 2 loads. A power sales contract
may be associated with the loss of service area. This power sales contract would need to be split into
Tier 1 and Tier 2 resources.
Option 1:Adjust Tier 1 and Tier 2 loads to reflect the sale, net of obligations under any power
sales contract.
Treat lost load and power supply obligations in different ways.
Do not adjust Tier 1 loads in response to loss of service territory.
Option 2:
Option 3:
) Sales of Generation
The design of tiered allocations should consider the impact of sold generation. The sold generation
resource would be removed from the tier originally assigned and the loads in that tier adjusted. How
would the gain on the sale be allocated to the states? If a purchased contract is secured as part of
the sold generation, to what tier should this purchase contract be applied?
Option 1:Remove sold generation from original tier assigned, apply purchase contract & gain
on sale to the same tier
Remove sold generation from original tier assigned, apply purchase contract & gain
on sale to an alternative tier
Remove sold generation from original tier assigned, apply purchase contract & gain
on sale to both Tier 1 and Tier 2
Option 2:
Option 3:
) Direct Access
A tiered allocation method should account for load that permanently elects direct access. (Load that
elects direct access service with a right to return to cost-based service would continue to be reflected
in a jurisdiction s loads and would not be removed from any tier.) One may adopt the view that most
permanent direct access load would have been served in the base period and would, therefore, be
part of Tier 1. In this view, Tier 1 loads would be reduced by the amount of permanent direct access
load. This would have the effect of altering the Tier 1 allocations of other states. Additionally, if the
state in which the departing direct access customer was located had a positive Tier 2 allocation at the
time of departure, a Tier 2 load adjustment may also be appropriate. Generally, MSP participants
have adopted the principle that implementation of direct access should not affect other states.
Transition adjustments associated with the direct access load would reflect the change in system cost
associated with the loss of this load.
Option 1:Reduce Tier 1 load by the amount of load that permanently elects direct access
service.
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Option 2:
Option 3:
Do not reduce Tier 1 load in response to direct access.
Similar to Option 1 but split load reduction between Tier 1 and Tier 2.
~ Re source Issues
) Replacement Power
In some cases an expiring or retiring resource may be explicitly replaced by another resource. For
instance, contracts may be replaced according to specific renewal provisions or a generating
resource may be replaced by another built on the same site. Parties have discussed solutions to the
Tier 1 design issue discussed in the first section of this paper that give special consideration to costs
of replacement resources. When an expiring Tier 1 resource is explicitly replaced by another, the
costs of the replacement resource could be assigned to Tier 1. This would slow the decline in the
size of Tier 1 compared to the case where no resources are added.
Special treatment of replacement resources would require parties to agree on design choices. For
instance, do such replacements include generating plant shut-down, expiring contracts, or both? Do
replacements include contracts entered into when the renewal provisions of the expiring ,contract
were vague and the new contract differs from the old? The Integrated Resource Plan does not
provide guidance since it does not distinguish between new resources intended to replace expiring
resources and resources to meet new growth. Initial studies indicate that the definition and treatment
of replacement power has an important effect on the assignment of costs to the tiers.
Option 1:
Option 2:
Option 3:
Reduce Tier 1 loads as Tier 1 resources expire. Over time, Tier 1 goes away.
Replenish expiring Tier 1 resources with specific identiied replacements, where they
can be identified.
Replenish expiring Tier 1 resources with Tier 2 resources at the average cost of Tier
2 resources.
) Generation Changes: Overhauls, Re-powering and Capacity Increases
The initial study treated the re-power of Gadsby plant as a Tier 2 resource and not as a replacement
of a Tier 1 resource. No special treatment was given to overhauls which increased generating plant
capacity. Modeling becomes substantially more complex if the fixed costs of a resource are split
between the tiers.
Option 1:
Option 2:
Option 3:
Option 4:
Treat overhauls and re-powering as replacements of or changes to Tier 1 resources.
Treat generation changes as Tier 2 resources. Split resources where needed.
Include the fixed and variable costs associated with overhauls and re-powering in
Tier 2.
Adjust Tier 1 loads to reflect generation changes.
Do not adjust Tier 1 load.
) Lost Hydro Generation
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The initial study treated the lost hydro generation as a reduction to a Tier 1 resource. This issue is
similar to the Generation Changes issue discussed in the preceding section of this paper.
'..,.
Planning Reserves
The initial study did not attempt to segregate planning reserves between the tiers. The resources in
Tier 2 are built with a reflection of planning reserves, so the output of a base load plant may not be
fully dispatched due to fuel and market prices. This is a similar issue where SeCT plants are being
added to address peak loads , but they dispatch at low capacity factors.
An alternative view does not recognize that planning reserves are included in or adjusted for in Tier 2
resources.
Option 1:
Option 2:
No adjustment for planning reserves in Tier 2
Adjust Tier 2 to recognize planning reserves; include a corresponding adjustment
Tier 1.
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Appendix 14
Tiered Alternative 2 Paper
ILLUSTRATIONS OF A MODIFIED TIERINGNINT AGING
ALLOCATIONS MECHANISM FOR MITIGATING THE BURDEN
OF GROWTH COSTS ON NON-GROWING JURISDICTIONS:
A STRAWMAN FRAMEWORK
by George Compton
(Load Growth Workgroup - June 29, 2005)
Exhibit A. The problem: Growth costs are incurred to meet annual and seasonal peak loads , yet
most of PacifiCorp s generation fixed costs are allocated on the basis of all twelve
monthly peaks. A future departure from the 12CP approach mayor may not be
called for on cost-causation grounds. A mechanism is required for synchronizing
growth costs and the cost allocations methodology that is now in effect.
Discussion: When growth loads are being distinguished from prior loads, the
allocations problem seems to be more tractable when apportionments of capacity
(rather than costs) are being kept track of. The simplest combination of system
capacity sizing and capacity allocations would be to use the single annual peak.
But the Revised Protocol uses a combination of a 12CP allocator and seasonal
allocations which employ a monthly energy component. Obviously the average of the
12 coincident peaks will lie below the annual coincident peak, which more than
anything else dictates the requisite system capacity level. To place the capacity
allocation on the same level of the overall capacity requirement, it is necessary to
inflate the average 12CP figure commensurately so as to yield "composite loads" that
are the working equivalent of annual peak loads.
Suggested resolution: The last column of the exhibit inflates each jurisdiction s 12CP
monthly average figure by a uniform percentage amount so that the sum of the new
figures equates to the annual peak (which appears in month 7 in this example).
Those adjusted averages are what will subsequently be used to allocate the capacity
costS.
55 Example: If a system s capacity was 1000MWs and Jurisdiction A's annual coincident peak load (including
reserve requirement) was 400MWs, then in a simple 1 CP world that jurisdiction would be allocated 40% of the demand, or
capacity, costs.
56 One might object to the fact that HiGro s allocation of 427 is beneath its load (450) at the time of the annual
system peak (in July) while the other two jurisdictions' allocation figures (206 and 90) exceeds their annual coincident peak
loads. The apparent break received by HiGro under the 12CP approach is justified insofar as the winter peak (in months 1 and
12) is also cost sensitive (as manifest by its being almost as great as the summer peak). HiGro s allocation figure exceeds its
winter figure while the allocation amounts of the other two jurisdictions are below their winter peak figures.
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II.Exhibit A. The problem: Should the loads used to establish the Tier 1 allocations be those of
the trigger year (from wh en subsequent growth is recognized in future-tier
allocations) or some average of that and prior years' loads?
Discussion: Rather than deciding this issue arbitrarily, it is useful to compare the
trigger- and pre-trigger-years' loads with the amount of capacity residing in the first
tier. Different answers to the problem suggest themselves depending on that
comparison.
Suggested resolution: Where the base tier s capacity is less than the trigger year
peak load, it is reasonable to use an average of past loads going back in time as far
as to yield an average that will approximate the tier 1 capacity. Where the tier
capacity exceeds the trigger year peak load, it is reasonable to base the initial
allocation on the trigger year s loads themselves (assuming that such represent the
highest recent load level). Exhibit 2 illustrates those two types of resolutions and
their respective contexts.
j;:
III.Exhibit A. Block 1: This is merely a duplication of Base Case B from the previous exhibit.B. Block 2:1. Problem: How should the Tier 1 resources be allocated in the years between
the trigger year and the introduction of large new production resource(s) that
constitutes the Tier 2 Note: It may not appear important to allocate Tier
resources when the concern is the post-Tier 1 growth. But it is difficult to
know how much of a jurisdiction s load is being served from Tier 2 (and
subsequent tiers ) resources unless it is know how much is being served out
of Tier 1. (This also helps to explain the practice of placing the allocations -
at least preliminarily - in terms of capacity magnitudes rather than costs.
Suggestion as illustrated in this block: Until which time a new tier is
introduced, it would seem appropriate to allocate the Tier 1 resources in the
same manner as was used in the trigger year. This approach seems suitable
whether the loads are beneath or in excess of the Tier 1 capacity.
Block 3:1. Problem: How should the Tier 1 resources be allocated in the year in which
the second tier is introduced?
Discussion and Resolution: It would seem intrinsic to the notion of a trigger
year that a jurisdiction s Tier 1 allocation for purposes of establishing its Tier
2 (or growth) allocation should not be lower than what it would be if based on
the trigger year s loads (or the average of the "basis" years' loads). Where
the Tier 1 capacity exceeded the aggregate load, the "surplus" might be
57 One would think that a mere increase in front-office acquisitions would not warrant creating a new cost allocations
tier. Instead, it would seem to require the addition of a new generation plant or comparable. long-termed production resource.
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Exhibit A. Block 1. This block merely applies to the second Tier 2 year the methodology
employed in the first (as illustrated in Block 4 of Exhibit 3).
Block 2.1. Problem: How should the Tier 1 resources be re-allocated to reflect the
retirement of some of them? Of particular interest is the case where one of
those retired resources had benefits that were differentially dedicated among
the jurisdictions.
Discussion: One basis for system capacity expansion is the need to replace
production resources as they are retired or otherwise discontinued. "Growth"
can be defined as the difference between current demand and some prior
capacity allocation. Accordingly, increased demand and a reduced allocation
of earlier tier resources are algebraically equivalent. This invokes a
requirement to differentially re-allocate Tier 1 resources insofar as a retired
resource provided benefits differentially to jurisdictions.
Resolution: Block 2 illustrates the re-allocation of Tier 1 resources where a
portion of the retired resources had dedicated beneficiaries and another
portion s benefits were shared among all the jurisdictions.
IV.
allocated to all the jurisdictions in proportion to their growths between the
trigger year and the first Tier 2 year. The block illustrates that approach.
Block 4:1. Problem: How to allocate a new tier s resources, given a recognition of the
fact that growth may not account initially for the entire magnitude of those
",.resources?
d. Discussion: Resources large enough to constitute the beginnings of a new
Aier possess the distinguishing characteristic of "lumpiness " Le., their
magnitude may not mesh exactly with the growth that has occurred since the
; prior tier s trigger period. Two methods of dealing with this matter suggest
themselves. One is to assign the entire new resource to the growth
jurisdictions and credit them with the off-system sales that are enabled by the
lumpiness surplus. The downside of this approach is that it adds to the direct
growth burdens the onus of a somewhat arbitrary portfolio expansion plan
and the risk, in a normalized, future test-year context, that the Company
modelers can adequately project the added non-jurisdictional sales enabled
by temporarily surplus production capacity. The other,method is to allocate
the surplus capacity to all the jurisdictions in proportion to their total loads
so as to reflect their shares of benefits to whatever added sur~lus sales
margins are ultimately captured in the net power cost results.
Resolution: Block 4 illustrates the second approach that was just discussed.
58 Recall that this proposed multi-tier methodology only differentially allocates the demand portion of the new
production costs, and not the added energy costs. The latter would presumably be allocated according to the standard
Revised Protocol techniques.
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Block 3. This block allocates the entire amount of the Tier 2 resource to the jurisdictions
in proportion to their load growth beyond their Tier 1 allocations.
Block 4.1. Problem: How should the tiers' resources be re-allocated in the presence of a
substantial reduction in the loads of some of the jurisdictions?
Discussion and Resolution: As a rule of thumb it would seem that a reduction in
demand would be reflected in a reduction in the allocation of the most recent
tier s capacity. Beyond that, if a jurisdiction s demand falls below its Tier
allocation, then that allocation should be reduced to the new demand level, with
the newly created excess within that tier re-allocated to the other jurisdictions.
Block 4 shows the consequences of two jurisdictions having a lower demand
than in the previous year. The reduction experienced by the jurisdiction that had
not grown earlier (Le., "NoGro ) caused it to lose a portion of its Tier 1 allocation.
That portion was redistributed to the other two jurisdictions. The other declining
jurisdiction s load loss was reflected in the reduction of its Tier 2 allocation. The
faster growing jurisdiction (Le., "HiGro ) picked up the entire surplus that would
have otherwise been created in the Tier 2 resources.
A discussion of why a load-losing jurisdiction should be able to receive a smaller
allocation of growth-tier resources, even if the load loss produces a production resource
surplus:1. The primary ongoing MSP growth concern is to require a growing jurisdiction to
itself bear the costs of growth, not to insulate the jurisdictions from the risks of
other jurisdictions' declining demands. It is one thing to bear growth costs when
at the same time , sales are increasing (thereby bearing most of the incremental
costs). It is another to have increased costs in the presence of diminished sales.
The issue may be moot. As long as the overall system is growing, when the
system is running short the capacity freed up by one jurisdiction s occasional
load reduction will be utilized by the rest of the growing system - thereby
reducing the need for market pu rchases and allowing savings from the
postponement of new plant additions. In other words, one jurisdiction s load
reduction may not be accompanied by additional market sales (but rather by
reduced purchases), and even if there temporarily is spare capacity the reduction
of one jurisdiction s load will enable the growing jurisdictions to benefit from
greater utilization of existing capacity rather than having to bear the cost of new
capacity.
Estimating the incremental off-system market sales made possible by a reduction
in a jurisdiction s load involves multiple GRID runs and is heavily assumption
driven, with price estimates based upon hourly regional supply and demand
projections. The benefits of not allowing allocations to ratchet down and
attributing the enabled market sales to the load-losing jurisdictions do not appear
to justify the added regulatory complexity and uncertainty involved in making
what-if' projections of such market sales absent versus given the released
production capacity.
59 An exception to this rule would apply under Direct Access, where the jurisdiction that loses a designated load would
still receive its allocation - and have the benefit of the added off -system sales enabled therefrom.
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Block 5. This illustrates the allocations of Tier 3 resources being performed in the same
manner as the Tier 2 resources were allocated in Block 4 of Exhibit 3.
A discussion of why there should be more than one growth tier:1. Primary justification: The cost consequences of growth are partly a function of
the timing of a jurisdiction s growth. Not taking such into consideration can cause
a jurisdiction to pay costs that are well in excess of what it caused.
Illustration of the problem of having just one growth tier: Say that one jurisdiction
experiences considerable growth in year 1 , causing a new plant of
commensurate capability to be built and entered as the sole item in Tier 2.
Assume no more growth occurs until year 15, when a different jurisdiction
experiences the same amount of growth, which causes the addition of a new
plant into Tier 2 of the same size as the first. With only one growth tier, and
which is simply allocated in proportion to post- trigger-year growth, both
jurisdictions would pay the same amount in year 16 even though most of the
growth costs in that year (given the fifteen years of depreciation of the first
growth plant) are due to the second plant, which was caused to be built by the
second jurisdiction. If a second growth tier were added, then the cost of the
second new plant would be borne solely by the later-growing jurisdiction - whose
growth caused it to be built.
Complexity? Obviously having several tiers or vintages makes for greater
complexity than having just two. But the algorithm for allocating within and
between the tiers can be relatively straightforward, as has been illustrated in this
paper. As far as a multiplicity of GRID runs being required, I think not. In fact, I
don t see the need for any additional runs being run beyond what would
otherwise be needed to estimate the effects of a large load loss owing to direct
access in Oregon (i.e., with that State capturing the benefits of the additional off-
system sales or reduced purchase costs made possible thereby).
A related issue: When all the new plants are placed into a single costing tier
there is a diluted potential for the somewhat arbitrary timing of the installation of
an expensive coal baseload plant versus a CCCT of SCCT to have an
unwarranted impact on a jurisdiction whose growth spurt just happened to
coincide with the installation of such a plant. But with each new plant constitutinga new tier, such a consequence would be inevitable if the full fixed costs of such
plants are what are allocated. To avoid that problem, it is proposed that only thedemand portion of new plants be allocated according to vintage. (That portion is
approximately half of the fixed costs of a coal plant.) The balance of those costs,
i.e., the energy portion, would be allocated as part of the net power costs, which
would be spread across all sales in the current manner.
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Exhibit 1
Simplified Scenario Analysis of Strawman Skeleton
Proposal for Modified Tier Allocations
by George R. Compton, UDPU
(Load Growth Workgroup - June 29, 2005)
A PRELIMINARY CONSIDERATION
COMMENT:Both Marcs and my tiering proposals place loads. resources, and allocations on the same numeric terms - ostensibly annual coincident
peak megawatts. However, the current allocations practice is to use the twelve monthly coincident peaks rather than the annual peak.
One method - illustrated below - for placing the twelve monthly peaks on the same terms as the total load that matches with total
resources (and making the simplifying assumption that resources are acquired primarily to meet the annual peak) is to ratio up the average
monthly peaks by a uniform amount sufficient to bring the final total load figure up to the same level as the annual coincident peak. The
pros and cons of this approach are discussed briefly in the text accompanying these worksheets.
YEAR 0 LOADS ANAL Y~I~
MONTH AND LOADS
SUM MONTHS'ADJUSTEDJURISDICTIONAVERAGEAVERAGE
HiGro 389 385 375 355 369 405 425 415 375 335 355 389 457 381 40ULoGro214211207180175180194195190185200214234!195 206.Nnr..rn R'i !J()102.90.SUM 694 686 667 620 629 665 698 690 647 605 645 7941 662 698.
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Exhibit 2
Simplified Scenario Analysis of Strawman Skeleton
Proposal for Modified Tier Allocations
(Refined Initial Proposal)
by Geor~e R. Compton, UDPU
(Load Growth Workgroup - June 29. 2005)
Initial Tier 1 Allocation
COMMENT:Whether the initial Tier 1 allocation is based upon the trigger-year loads or some average of prior year
loads will depend on whether the trigger year loads are less than or greater than the Tier 1 cacacity.
URIS DICTION
PEAK" LOAD HISTORY
BASIS YEAR
AVERAGE
300 350 375 401.325
190 195 200 206.195
HiGro
LoGro
NoGro
198
184
SUM 472
NOTE: In every instance. the loads and resources are exclusive of QFs, which are situs. Also, the loads include the
suggested 15% planning margin.
ssume the "tri er" occurs at the end of ear O.
JURISDICTION
HiGro
LoGro
NoGro
BASE CASE A: Tier 1 Capacity Less Than Five Basis Years' Average Total Load
TIER 1 CAPACITY 600
YEAR AVG. CAPACITY
AVERAGE SHARE ALLOCATION325 53% 320195 32% 19290 15% SUM 610 100% 600
ProDosal: Use the basis vears' averaae to establish the allocations.
BASE CASE B: Tier 1 Capacity Greater Than Trigger Year s and Basis Years' Average Load
TIER 1 CAPACITY 750
YEAR YEAR 0
SHARE
CAPACITY
ALLOCATIONiJURISDICTION
HiGro
LoGro
NoGro
401.58% 431.
206.30% 221.
90.13% 96.
SUM 698.100% 750.
Use the triaaer vear s loads to establish the allocations.Proposal:
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Exhibit 3
Simplified Scenario Analysis of Strawman Skeleton
Proposal for Modified Tier Allocations
(Refined Initial Proposal)
by George R. Compton, UDPU
(Load Growth Workgroup - June 29, 2005)
The Evolving Tier 1 Allocation and Initial Tier 2 Allocation
INITIAL (i.e., year 0, or trigger-year) TIER 1 ALLOCATION
BASE CASE B: Tier 1 Capacity Greater Than Trigger Year s Total
TIER 1 CAPACITY 750
Trigger year (0)Load CapacityJURISDICTIONpeak" loads Share Allocation
HiGro 401.58%432
LoGro 206.30%221NoGroffl
SUM 698.100%750
POST TRIGGER-YEAR LOADS AND TIER 1 ALLOCATIONS
Proposal:Prior to the initial Tier 2 year, allocate Tier 1 capacity in proportion to each year s "peak" loads.
YEAR
JURISDICTION Peak"Load Capacity Peak"Load Capacity Peak"Load CapacityLoadsShareAllocationLoadsShareAllocationLoadsShareAllocationHiGro42559%440 450 60%447 475 61%454LoGro21029%217 215 28%214 220 28%210NoGro12%12%11%SUM 725 100%750 755 100%750 785 100%750NOTE: Shortfall in years when aggregate peak load exceeds capacity is assumed to be met with balancing purchases included in Net Power Costs.
NOTE: The indicated 3rd vear mav be a "future" test vear.
ADJUSTED TIER 1 ALLOCATION OWING TO A NEW (i., Tier 2) RESOURCE THAT ARRIVES IN YEAR 4
Proposal (given Base Case B): Each jurisdiction receives an allocation of Tier 1 resources that is at
least equal to its trigger-year (i.e., year 0) load. The surplus Tier 1 capacity relative to the trigger-year loadis allocated in proportion to growth between the trigger-year and the new resource (i.e., Tier 2) year.
TIER 1 CAPACITY: 750
NOTE: The total prior Tier 1 surplus capacity was 750 - 698 = 52
Year 0 Year 4 Growth sinceJURISDICTION "peak" loads "peak" loads trigger year
SUM
401.
206.
900
698.
510.
225.
900
825.
108.
18.
127.
Allocation of New Tier Adjusted
Tier 1 trigger-1 capacity Tier 1
year surplus allocation Share
44.446.59%
213.29%
900 12%
52.750.100%
HiGro
LoGro
NoGro
TIER 2 ALLOCATION FOR ITS INITIAL YEAR (i.e., year 4)Proposal: After having "filled" the Tier 1 capability, first allocate the Tier 2 capacity in proportion to the year 4 "peak" loads that arebeyond the Adjusted Tier 1 allocation, and then allocate the "unused" Tier 2 quantity in proportion to the year 4 "peak" loads per S8.
TIER 2 CAPACITY:130
TIER 1 plus 2 CAPACITY:880
New Tier Tenninal, or Growth over Preliminary Year 4 Residual Total Tier Total TOTALJURISDICTION1 capacity Year 4, Tier 1 Tier 2 load Tier 2 2 capacity Tier 2 TIER 1 PLUS 2allocationpeak" loads allocation allocation shares allocation allocation Shares ALLOCATIONHiGro446.510.63.63.61.34.97.75%544.LoGro 213.225.11.11.27.15.26.20%240.NoGro 90.90.10.96.SUM 750,825.75.75,100.55.130.100%880.
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Exhibit 4
Simplified Scenario Analysis of Strawman Skeleton
Proposal for Modified Tier Allocations
(Refined Initial Proposal)
by George R. Compton, UDPU
(Load Growth Workgroup - June 29, 2005)
Teir 3 Allocations and Later-Year Tiers 1 & 2 Re-allocations
TIER 2 ALLOCATION FOR ITS SECOND YEAR (i.e., year 5)
Proposal: Allocate the Tier 2 capacity, In preportlon to the Terminal Figure s growth beyond the Tier 1 allocation.
TIER 2 CAPACITY:
""",
130
TIER 1 plus 2 CAPACITY:,....880
Tier 1 Year 5 Growth over Preliminary Year 5 Residual Total Tier Total TOTAL
JURISDICTION capacity peak" loads Tier 1 Tier 2 load Tier 2 2 capacity Tier 2 TIER 1 PLUS 2
allocation allocation allocation shares allocation allocation Shares ALLOCATION
HiGro 446.530.83.83.62.15.99.76.4%545.
LoGro 213.235.21.21.27.28.21.241.
NoGro 90.90.10.92.
SUM 750.855.105.105.100.25.130.100.880.
YEAR 6 TIER 1 RE.ALLOCATION DUE TO RESOURCE DECREMENTS
Prior Tier 1 Capacity
New Tier 1 Capacity
Dedicated Decrement:
hared Decrement
JURISDICTION
750
730
Previous, Le,
year 4, capacity
allocation
from LoGro
Dedicted Preliminary Shared New Tier 1
Capacity Capacity Capacity Capacity
Decrement Allocation Decrement Allocation
446.-8.437.
208.-4.204.
HiGro
LoGro
NoGro
446.
213.
SUM
TIER 2 ALLOCATION FOR ITS THIRD YEAR (I.. year 6)
Proposal: Allocate the Tier 2 capacity in proportion to the Terminal Figure s growth beyond the Tier 1 allocation.
TIER 1 CAPACITY:
TIER 2 CAPACITY:
TIER 1 plus 2 CAPACITY:
730
130
860
New Tier 1 Year 6 Growth over Total Total Tier Total TOTAL
JURISDICTION capacity peak" loads Tier 1 growth 2 capacity Tier 2 TIER 1 PLUS 2
allocation allocation shares allocation Shares ALLOCATION
HiGro 437.550.112.70.91.70.528.
LoGro 204.250.45.28.4%36.28.241.
NoGro
YEAR 7 TIER 1 and 2 RE.ALLOCATION DUE TO CHANGING LOADS
Proposal: Make the Tier 1 allocation consistent with the reduced load of NoGro, which was previously receiving
a minimal Tier 2 allocation. LoGro s recent negative growth is reflected in a reduced Tier 2 allocation.
TIER 1 CAPACITY: 730
TIER 2 CAPACITY: 130TIER 1 plus 2 CAPACITY: 860
New (Le.Prior Tier 1 New Tier 1 Growth from Total New TOTAL
JURISDICTION yr. 7) "Peak"Capacity Capacity New Tier 1 growth Tier 2 TIER 1 PLUS 2
Loads Allocation Allocation Allocation shares Allocation ALLOCATION
HiGro 570 437.439.130.84.109.548.
NegGro (LoGro)230 204.205.24.4 15.20.226.
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Appendix 15
Structural Protection Mechanisms
Tiered Alternative 1 Compared to Tiered Alternative 2
Author
Load Growth Workgroup
Meeting
Proposal
Tiered Alternative 1
Marc Hellman, Oregon puc Staff.
June 29, 2005
June 2005 Straw Proposal for
Tiered Allocation (Second
Revision)
Method
Method Overview
Tiering
The proposal is based on two
Tiers of resources and the
segregation of corresponding
loads at the "trigger date . All
new resources and loads
increases will be added to the
second Tier after the trigger date.
The jurisdictional allocations of
resources within the Tier are
based on the associated
jurisdictional loads assigned to
the Tier. The Tiers increase or
decrease for changes to
resources, and some changes to
loads.
Creation of Tier Determination is made that new
Tiered Alternative 2
George Compton DPU
June 1 , 2005 and June 29, 2005
Elements of a Modified Tiering
Vintaging Allocati on Mechanism
for Mitigating the Burden of
Growth Costs on Non-Growing
Jurisdictions: A Strawman
Framework. Illustrations of a
Modified Tiering Vintaging
Allocation Mechanism for
Mitigating the Burden of Growth
Costs on Non-Growing
Jurisdictions: A Strawman
Framework
Vintaging
The proposal is based on
vintaging resources into multiple
Tiers and the segregation of
corresponding loads at the
trigger dates
" .
The proposal
would track the peak loads
against the resource capacity
(see Stock of Resources) in
creating the jurisdictional
allocation factors. Resources
within Tiers are allocated on
associated loads or resource
capacity for that Tier. Any unused
resource capacity is segregated
and system allocated, after the
first Tier is filled. This reflects
unused resource capacity being
sold to the market Costs are
segregated into Tier 1 for existing
owned resources and contracts at
trigger date , additional Tiers for
each new resources added, and
production costs reflecting short
term market purchases. Costs of
short term purchases are system
allocated.
All new resources (see Stock of
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Tiered Alternative 1 Tiered Alternative 2
(Trigger Date)resources coming on-line within Resource) will be allocated to a
36 months to meet disparate load new Tier once a new resource is
growth will cause a cost shift added and loads exceed capacity
among the states without in the prior Tier (also suggested
offsetting considerations. The using calendar 2004 date or fiscal
trigger date establishes resources year 2005 as starting point). The
to be included in Tier 1.trigger dates establishes which
Tier resources are assigned.
Number of Tiers Two Unlimited
Tier 1 The base Tier includes resources The base Tier includes resources
and contracts at the trigger date and contracts at the trigger date
and includes the refurbishment
relicensing, and contract renewal
of these base resources net of
existing wholesale sales
commitment.
Jurisdictional Allocation Created on jurisdictional loads For Base Tier, the proposal uses
Factors associated with each Tier, 1 and the loads to create the allocation
2. Tier 2 loads calculated as factor until the loads exceeds the
system loa ds less Tier 1. See capacity, then the loads are
Reduction in Loads" and "Retired scaled down to the resource
or Expired Resources" below.capacity for allocation purposes.
Follows Revised Protocol for For Initial Tier use 5 year
allocation purposes.average of loads when loads
are lower than capacity,
other wise use capacity
when capacity is lower than
loads
For other Tiers, the growth in
peak loads between this Tier and
the prior Tier is calculated to
create an allocation factor.
When capacity of the new
resource exceeds loads
delta, allocate used portion
of resource capacity to serve
loads on the load delta
factors. The unused
capacity of the new resource
is allocated on the system
loads so all jurisdictions
share in the cost (reflects
excess capacity is sold at
the market).
When the resource capacity
is less than the load deltas,
allocate the capacity on the
load delta
Seasonal allocation mLSt be a
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Increase in Loads
Reduction in Loads
Resources Acquired
Retired or Expired Resources
(Generation! Long Term
Contract Purchases! Lost
Hydro Generation)
Power Co~ Model Runs
Resource Definition
Other Elements of Proposal
Tiered Alternative 1
Assigned to Tier 2
Reduction in Tier 1 loads are
handled consistent with Revised
Protocol. Load reduction , other
than Direct Access, result in
reduction in allocation of Tier
resources for that state. Other
states reallocated larger share of
existing resources. Tier
resource allocation can be
restored if loads return to trigger
levels. Loads assigned to Tier
for any state can not decrease
except when Tier 2 resources
decrease. The state losing loads
receives the same allocation of
resource cost but is assigned a
short term market sales in
proportion to the lost load.
Assigned to Tier 2
Tier 1 resource reductions are
pro-rata reduction to state
jurisdictional loads. A
corresponding increase occurs in
Tier 2 loads and short term
resources. Reduction in long-
term wholesale sales would have
opposite effect of increasing Tier
1 state loads. Reduction in Tier 2
resources removed from Tier 2
no change to allocation factors.
Requires two GRID runs - one for
Tier 1 study, another for System
Study (Tier 2 calculated as
System less Tier 1). Alternative
Tier 2 GRID run then adjust so
Tier 1 plus Tier 2 equal System.
Owned Generation and Long
Term Contracts
Resources built in excess of loads
Tiered Alternative 2
consideration in this proposal.
Assigned to current Tier until new
resource addition, then excess
over resource capacity in current
Tier is assigned to new Tier
If one or more jurisdictions has
experienced a load reduction for
the Tier 1 loads, reallocate the
Tier 1 existing resources using
the lower Tier 1 loads. Same
effect as Tiered - Alternative 1.
Other load reductions assigned to
last Tier and then work backwards
if needed.
Assign to New Tier
The load for each jurisdiction
related to the Tier where the
retired resource resides, would be
reduced by each jurisdiction
allocated share of the capacity of
the retired resource. If other than
last Tier, a corresponding
increase in the last Tiers loads
occurs.
Not specified - required GRID
System Study at minimum
The proposal suggested "Stock of
Resources" are company owned
and contracts with a life of at least
1 O-years. Production resources
(includes shorter term market
purchases), excludes "Stock of
Resources , allocated as system
resources
The paper proposes a basis of
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" ,
Tiered Alternative 1
allocated on Tier 2 allocation
factors. Gain or loss on Service
Territory - Adjust Tier 1 and Tier 2
loads to reflect the sale, net of
obligations, under any power
sales contract. Sale of
Generation - Remove sold
generation from original Tier
assigned, apply purchase contract
and gain on sale to same Tier.
Direct Access - Treat consistent
with Revised Protocol. Short term
and new long term sales for
resale are assumed provided by
Tier 2 resources up to generating
capability of Tier 2 resources.
Power sales matching Tier 1 load
reduction is an exception. The
paper proposes common costs
are allocated on system loads.
This proposal is administratively
complex. Unknown and potential
for unintended consequences.
Assumptions require modeling
judgments. For each Tier
proposal requires more definition
on calculation of remaining
resource needs for each state.
Unclear how to incorporate
reserves required to be
purchased at market Unclear
methodology to measure short
term market sales in proportion to
lost load under Tier 2.
Issues
Tiered Alternative 2
allocation and classification
different than that used in the
Revised Protocol that is
unresolved and lacks
quantification.
Proposal System Capacity 4
Coincidental Peak (CP)
versus 12 CP in Revised
Protocol
Proposal SG factor 50%
Demand! 50% energy
weighting versus 75%
Demand ! 25% Energy in
Revised Protocol
This proposal is administratively
complex in the requirement to
track the loads against the system
capacity and represents a
deviation from Revised Protocol
that uses loads to create the
allocation factors. Unknown and
potential for unintended
consequences. Assumptions
require modeling judgments.
Unclear how long-term wholesale
sales capacity is accounted for in
adjusting the resource capacity.
Unclear how the proposal
addresses segregating the cost!
revenue requirement to vi ntage
the resources. Unclear in
proposal what occurs when the
loads and capacity do not match
for the existing Tier and a new
resource is added. Proposal
should consider the implication of
reserves in building of resource
capacity in relation to the
proposal.
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Appendix 16
Structural Protection Mechanisms
Ranking Criteria
To assess the viability of the SPMs being developed by the Load Growth Workgroup, a ranking
evaluation criteria was developed by a sub-group that met on July 14, 2005. That SPM Ranking Criteria
is summarized in Section 5., and provided in more detail below:-
Consistent with Revised Protocol
Makes small incremental modifications to the Revised Protocol
Promotes the stability or integrity of the Revised Protocol
Employs principles of the Revised Protocol
Degree of Protection from Load Growth
. Overall , to what degree does the mechanism provide protection from cost shifts (revenue
requirement impacts) associated with differential load growth
Includes consideration of other load growth impacts, including the increased assignment
of common and other costs to States with higher load growth
Is Equitable in Treatment among the States
Does not unduly burden single State or group of States
Does not develop systemic bias to single State or group of States
Does Not Create Unintended Consequences
Does not modify items that can negatively impact other allocations/assignments
Does not create unwanted incentives
Consistent with Utility System Least-Cost Planning
Mechanism does not conflict with IRP , system-wide planning to minimize total system
costs
Mechanism provides the utility with the incentive to identify system, least-cost resource
alternatives including DSM options
Consistent with Minimizing Total System Operating Costs
Mechanism promotes day-to-day operation of the system that achieves lowest total
system-wide operating costs
Alternatively, mechanism does not provide perverse incentives to deviate from system
least-cost operations
Aligns Assignment of Costs and Benefits of New Resources
Closely aligns revenue requirement impact of new resources with the benefits of and
need for new resources
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Can be Implemented)n a Timely Manner
Timeframe for implementation of the mechanism is consistent with requirements of
Revised Protocol
Mechanism can be quickly implemented to offset demonstrated impacts from cost shifts
Easy to Understand
Mechanism is easy to explain and for easy non-regulatory people to understand
Simple to Implement, Track and Maintain
Mechanism does not add additional modeling/processing during regulatory cycles as
compared to Revised Protocol. Applies to implementation of the mechanism as well as
on-going filing, reporting and analysis/auditing of results
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