HomeMy WebLinkAbout20100915Kelly Direct.pdfRECEI
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
In the Matter of the Application of )
PacifiCorp dba Rocky Mountain )
Power for Approval of Amendments to )
Revised Protocol Allocation )Methodology )
CASE NO. PAC-E-I0-09
Direct Testimony of Andrea L. Kelly
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-I0-09
September 2010
1 Q.Please state your name, business address and present position with
2 PacifiCorp (the Company).
3 A.My name is Andrea L. Kelly, and my business address is 825 NE Mu1tnomah
4 Street, Suite 2000, Portland, OR 97232. lam curently employed as a Vice
5 President in Regulation.
6 Qualifications
7 Q.Please summarize your education and business experience.
8 A.I hold a Bachelor's degree in Economics from the University of Vermont and an
9 MBA in Environmental and Natual Resource Management from the University
10 of Washington. After graduate school, I joined the Staff of the Washington
11 Utilties and Transportation Commission. In 1995, I became employed by
12 PacifiCorp as a Senior Pricing Analyst in the Regulation Departent and
13 advanced through positions of increasing responsibility. From 1999 through
14 2005, I led major strategic projects at PacifiCorp including the Multi-State
15 Process (MSP) and the regulatory approvals for the MidAmerican-PacifiCorp
16 transaction. In March 2006, I was appointed as a Vice President in Regulation.
17 Q.Have you appeared as a witness in previous regulatory proceedings?
18 A.Yes, I have appeared as a witness on behalf of PacifiCorp in the states of
19 California, Idaho, Oregon, Utah, Washington, and Wyoming.
20 Purpose and Overview of Testimony
21 Q.What is the purpose of your testimony?
22 A.My direct testimony describes the process and approaches leading up to this fiing
23 of the proposed 2010 Protocol allocation methodology. Specifically, my direct
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testimony provides:
. a brief history of the MSP leading up to the adoption of the Revised Protocol;
. a brief history of the work of the Standing Committee workgroup since
November 2008 that has culminated in this fiing proposing limited
amendments to the Revised Protocol;
. an overview of the proposed amendments to the Revised Protocol and the
concerns that the amendments are designed to address;
. a discussion of the Company's view of the commission proceedings necessary
to process this application; and
. a discussion of the Company's view of processes necessary to ensure
successful implementation of the 2010 Protocol through calendar year 2016
and beyond.
I also introduce the other two Company witnesses in this proceeding.
Are you also sponsoring aD exhibit to your testimony?
Yes. Exhibit NO.1 presents the 2010 Protocol with all of its Appendices.
Although I sponsor Appendix A, Company witness Mr. Steven R. McDougal
17 sponsors the remaining Appendices.
18 Brief History of the Revised Protocol
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Please provide a brief history of the events that gave rise to the Revised
Protocol.
In December 2000, the Company proposed to reorganize itself into six state
distrbution companies, a generation company and a service company. This
Strctual Realignment Proposal (SRP) filing was in response to a number of
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external developments, including: (1) the lack of agreement among regulatory
jurisdictions regarding the Company's inter-jursdictional cost allocation process;
(2) direct access initiatives in Oregon and elsewhere; (3) the need to provide
independent control of transmission assets consistent with Federal Energy
Regulatory Commission (FERC) expectations; (4) fudamental changes that
occured in wholesale power markets; and (5) increasingly divergent policy goals
of various state commissions.
What was the outcome of the SRP filings?
The SRP fiings proved to be controversial - in large measure because of a
concern that the proposed restrcturng would result in a transfer of jurisdiction
from state commissions to the FERC and the Securities and Exchange
Commission. Ultimately, a number of parties and some state commissioners
encouraged the Company to seek other means of resolving the Company's
concerns that did not require a legal restrcturng of the Company. The Company
was strongly encouraged to initiate an informal process aimed at achieving
consensus among interested parties regarding a number of important issues facing
the Company. To that end, in March 2002, the Company made an additional set
of state filings asking the state commissions to initiate investigations and endorse
a collaborative process to address inter-jurisdictional issues facing PacifiCorp.
These fiings were broadly supported by the state commissions and gave rise to
what became known as the MSP. Pending the MSP, the Company agreed to put
the SRP fiings on hold.
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What occurred in the MSP?
An initial organizing meeting was held in April 2002 in Boise, Idaho. At that first
meeting, a schedule of futue meetings and objectives for the process were
established. A number of additional MSP meetings were held through July 2003,
after which the Company made an additional filing with the states seeking
ratification of a proposed solution, the Protocol. Additional discussions related to
the Protocol continued through September 2004, which resulted in the Company
supplementing its filings with the Revised Protocol. Through commission
proceedings, the four state commissions of Utah, Oregon, Wyoming and Idaho
issued orders adopting the Revised Protocol in late 2004 and early 2005. Utah's
and Idaho's adoption of the Revised Protocol was accompanied by rate mitigation
mechanisms tied to the difference between the revenue requirement calculated
under the Revised Protocol allocation methodology and the revenue requirement
calculated under the Rolled-In allocation methodology.
Who participated in the MSP collaborative meetings?
All of the major meetings were attended in person by in excess of 50 individuals
representing some 18 entities from the states of Utah, Oregon, Wyoming,
Washington and Idaho. These included representatives of state commission
policy staffs, advocacy staffs, industral customers and consumer groups. A
number of other people participated by telephone.
How would you characterize the overall objectives of the Revised Protocol?
The objectives of the Revised Protocol include:
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· allocating PacifiCorp's costs among its jursdictional states in an equitable
manner;
· ensuring PacifiCorp plans and operates its generation and transmission system
on a six-state integrated basis in a maner that achieves a least cost-least risk
resource portfolio for its customers;
. allowing each state to independently establish its ratemaking policies. Each
state is encouraged to consider the impact its decisions have on other states
served by PacifiCorp; and
· providing PacifiCorp a reasonable opportnity to recover 100 percent of its
prudently incured costs.
Does the Revised Protocol contain provisions for continued dialogue among
the states?
Yes. Section XIII.B of the Revised Protocol established the Standing Committee.
While not abridging the integrity of commission decision-making processes
within each respective state, the Standing Committee:
. monitors and discusses inter-jurisdictional allocation issues facing PacifiCorp
and its customers;
· helps to organize and direct work group analysis of inter-jurisdictional
allocation issues;
. ensures work group analysis is supported by sound technical analysis;
· shares views on possible amendments to the Revised Protocol, as they may
arise;
· seeks consensual resolution of issues arising under the Revised Protocol;
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1 . ensures wide dissemination of information regarding Standing Committee
2 meeting locations and dates and information relating to its activities;
3 . ensures and encourages open participation in Standing Committee meetings
4 by all interested persons; and,
5 . appoints the Standing Neutral to facilitate discussions among the states, to
6 monitor issues and to assist the Standing Committee.
7 Recent Activities of the Standing Committee
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Please provide an overview of the recent activities of the Standing Committee
that led up to this fiing.
At the November 2008 Commissioners' Forum, an issue was raised by Utah
related to the performance of the Revised Protocol as compared against the
forecast results at the time the Revised Protocol had been adopted. At that
meeting, MSP participants reviewed a chart comparing the MSP 2005 forecast
with the original MSP 2004 forecast. The char also provided comparisons to the
Rolled-In allocation methodology both with and without the Utah rate mitigation
measures. The chart raised concerns that Utah's expectations when adopting the
Revised Protoco1- near-term costs but long-term savings for Utah customers as
compared to Rolled-In - were not projected to be fulfilled. In response to this
concern, at the Standing Committee Annual Meeting held in November 2008, the
Company agreed to undertke a new forecast of results under the Revised
Protocol using updated information from the upcoming 2008 Integrated Resource
Plan which was to be filed in March 2009. The results were to be completed in
suffcient time to be presented at the next annual Commissioners' Foru. As
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discussed in detail in the direct testimony of Mr. McDougal, the preliminary
results of these studies were provided to parties on August 17, 2009.
On August 27,2009, the Standing Neutral sent a request to parties for any
new issues to be considered by the Standing Committee in preparation for the
annual meeting scheduled for December 9,2009. On September 9,2009, several
Utah parties issued a notification to MSP participants of the following issue:
"Given review of the Company's August 17,2009, MSP Preliminar
Study Results (2009 MSP Study) and the Public Service Commission of
Utah's (PSCU) December 14,2004, Report and Order in Docket No. 02-
035-04, (MSP Order) the issue we raise is whether continued use of the
revised protocol and rolled-in methods with rate mitigation measures is
just and reasonable for PacifiCorp's Utah jursdiction."
What action did the Standing Committee take in response to this issue?
The Utah issue was first discussed by the Standing Committee at a meeting held
on September 10, 2009. At the conclusion of the meeting, Utah parties were
asked by the Standing Committee to develop a potential solution.
What was the Utah parties' potential solution?
At the September 24, 2009 Standing Committee meeting, Utah parties proposed a
strawman solution that would eliminate seasonal and regional resource categories,
limit the state resource category to demand-side management programs and state
portfolio standard resource costs, and apply allocation factors for system
resources to the resources formerly addressed in the seasonal, regional and state
resource categories. In a nutshell, the strawran solution described a move to a
Rolled-In allocation methodology.
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What potential solutions were considered subsequently?
Over the next several months of Standing Committee meetings, participants
considered the Utah parties' strawman solution, together with additional solution
proposals offered for consideration by other MSP participants that focused on the
elements of the Revised Protocol that could be analyzed as alternative
considerations to address the Utah issue. At the direction of the Standing
Committee, the Company provided quantitative analysis of the varous propos1s to
aid the Standing Committee's deliberations and considerations.
When was the first opportunity to inform and update the Commissioners of
the work of the Standing Committee to address the issue?
The Standing Committee convened a Commissioners' Forum in Portland, Oregon
on Apri16, 2010. At that meeting, the Standing Committee updated
Commissioners generally on the activities of the Committee since the previous
Commissioners' Forum in November 2008. The Commissioners were also
presented with the Utah issue, together with a summarization of the analyses
performed and potential solutions considered. A concern raised was that the Utah
issue, if insufficiently addressed, could cause states to depart from a consistent
method of cost allocation and impair integrated system planning. After some
consideration of the issues and materials presented, the Commissioners directed
the Standing Committee to continue progress on analyzing potential solutions to
resolve the Utah issue and requested a follow-up meeting for the summer of201O.
In general, it was recognized that any solution would need to strke a balance
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between making progress toward fully Rolled-In allocations while maintaining a
hydro endowment for Oregon and Wyoming.
What was the progress of potential solutions prior to the next
Commissioners' Forum?
The Standing Committee and participants met for an additional six meetings to
continue the quantitative analyses of potential solutions to the Utah issue. As well
as analyzing potential solutions, the Standing Committee and participants
analyzed the potential impacts of not being able to achieve a resolution acceptable
to all states. These studies, known as the control area strctural separation and
go-it-a10ne studies, were informative of the benefits of PacifiCorp continuing to
operate as a single system. Progress since April 2010 was presented at the
Commissioners' Foru held on June 13,2010.
What direction was received from Commissioners at the forum held on June
13,2010?
At the Commissioners' Forum held on June 13,2010, the Standing Committee
updated Commissioners on the progress made since the previous meeting. The
Commissioners expressed praise for the progress made and requested that the
Standing Committee continue its efforts toward an acceptable resolution. An
additional check-in meeting was targeted for July 2010.
After the check-in, the Standing Committee developed a summary of what
the members heard as guidance from the Commissioners. The summary included
the following key points:
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1. All states prefer a consistent and fair cost allocation methodology that assures
the Company a reasonable opportity to recover its costs and support fuher
system investment.
2. Utah prefers the Rolled-In allocation methodology, or results stated as a
deviation from the Rolled-In allocation methodology as a viable solution
alternative.
3. Oregon and Wyoming Standing Committee members have considered pre-
2005 resource scenariosl as possible solution alternatives.
4. Both Wyoming and Oregon stressed that maintaining a hydro endowment is a
critical component on any allocation methodology.
5. Utah stressed its benchmark methodology is Rolled-In and an allocation
methodology should reflect Rolled-In +/- adjustments which are fixed for
some futue time period so as to avoid a repeat of not achieving expected
forecasted results.
6. The Commissioners have agreed that the Standing Committee should work
with the Company to develop an updated analysis based on Wyoming - 1
results which could be used to establish a fixed amount per year per state as a
deviation from the Rolled-In allocation methodology and is net of the situs
assignment of the Klamath surcharge.. The results wil be presented for all
years of the study and be accompanied by a disk with working spreadsheets.
Assessing whether the Wyoming - 1 achieves essentially a Rolled-In result
could be viewed from the perspective of treating the Klamath Settlement as
Rolled-In.
What actions did the Standing Committee take based on this guidance?
Through additional conference calls and supporting analysis, the Standing
Committee reached an agreement in principle that was presented on July 26,2010
at a fina1 Commissioners' Forum check-in conference call. The statement
provided by the Standing Committee at that meeting stated:
"Standing Committee participants of the MSP process have tentatively
reached an agreement in principle changing the Revised Protocol cost allocation
methodology. The initial premise for this new agreement is a Rolled-In cost
allocation methodology. The changed methodology continues to identify State
i "Pre-2005 resource scenaros" refers to the set of resources included in the "Aii-Other" category of the
Embedded Cost Differential calculation. This is discussed in more detail in the direct testimony of Mr.
McDougaL.
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Resources based on cost responsibility and Regional Resources for the Hydro
Endowment calculation. Besides using Rolled-In as the starting point, a
significant change relates to the Hydro Endowment quantified under the
Embedded Cost Differential (ECD). The ECD wil be reduced and limited using.
a comparison based on Pre-2005 Resources. It is proposed that for 2011 though
2016, the ECD calculation wil be projected and a fixed dollar amount per year
deviation from Rolled-In analysis would be applied. The deviation is composed
of two parts; (1) a situs adjustment charge for the Klamath Surcharge to Oregon
and California, with a corresponding credit to the other states, and (2) an
adjustment to reflect the Hydro Endowment ECD.
State specific concerns continue to be evaluated and discussed. For
instance: In Utah this cost allocation methodology produces results close to
Rolled-In so a side agreement between the Company and Utah parties wil allow
Utah to utilze Rolled-In cost allocation methodology for its ratemaking puroses.
Forecast accuracy also continues to be evaluated by the other states, Oregon in
particular, and may result in state specific measures to address the forecast risk
related to fluctuations, up or down. Wyoming parties have an interest in
addressing a concern about the Revised Protocol definition of State Resources."
What was the outcome ofthe Commissioners' Forum held on July 26, 2010?
At the Commissioners' Forum held on July 26,2010, the Standing Committee
updated Commissioners that the group had reached an agreement in principle.
Commissioners were informed that the Company hoped to fie an application in
each state by mid-September 2010 initiating limited amendments to the Revised
Protocol that would implement the terms of the agreement in principle.
25 Overview of Proposed Amendments
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In summary, what key concerns do the proposed amendments endeavor to
address?
As noted above, there were several overarching concerns expressed in the
meetings:
. The need to move more toward a Rolled-In allocation methodology to reflect
system operations while retaining the hydro endowment in some form.
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. Volatility of results and unintended consequences of the ECD.
. Unpredictabilty of reliance on forecasts.
. Any solution must be fair to all states, and the Company must be afforded the
opportnity to recover its prudently incured costs.
Are the amendments proposed by the Company and supported by the
Standing Committee consistent with this agreement in principle?
Yes. The details are discussed in the direct testimony of Mr. McDougaL.
Do the amendments exclusively address the Utah issue?
No. The amendments also reflect an additional category of state resources called
"state-specific initiatives". This addition includes emerging state-specific efforts
to encourage investment in specific types of resources.
Does this only include renewable resources?
No. The category does not limit the tye of resource for which a state may seek
14 to encourage investment.
15 Process for Commission Review of Application
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What process does the Company propose for the Commission review of this
Application?
The Company is hopeful that the Commission wil be able to complete its review
of this Application within a six-month timeframe. As discussed in the Company's
direct testimony, significant analysis has been undertaken and reviewed by many
parties since November 2008 as the Standing Committee considered its options.
However, not all interested parties were able to participate in the Standing
Committee efforts. As such, the Company proposes the following ilustrative
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1 schedule of milestones that would allow for discovery, rounds of testimony and
2 hearings that would allow sufficient time for a comprehensive record to be
3 developed upon which the Commission may base its decision:
Event Date
PacifiCorp Application, Testimony and Exhibits September 15,2010
Intervenor Testimony due Early-December 2010
PacifiCorp Rebuttal Testimony due Early-Januar 2011
Public Hearing Late-Januar 2011
Briefs due Mid-February 2011
Target Date for Commission Decision March31,2011
4 Q.Does the Company intend to continue dialogue with interested parties in each
5 state during the proceedings?
6 A.Yes. As noted in the Standing Committee's statement, the Company intends to
7 seek an agreement with Utah parties related to the use of the Rolled-In allocation
8 methodology and to work with Oregon parties to address forecast risk. The
9 Company wil also work to address any additional concerns that arise durg the
10 proceedings. It wil be imperative that any state-specific agreements do not
11 undermine the intent of the 2010 Protocol to allow PacifiCorp the reasonable
12 opportity to recover 100 percent of its prudently incured costs.
13 Processes subsequent to amendment adoption
14 Q.Assuming that the four state Commissions acknowledge the amendments and
15 adopt the 2010 Protocol, what ongoing processes does the Company envision
16 related to the 2010 Protocol?
17 A.As reflected in the 2010 Protocol, the Company is not proposing any changes to
18 the ongoing Standing Committee fuction at this time. Although the elements of
19 the 2010 Protocol are designed to minimize controversy and provide predictability
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1 through calendar year 2016, there are always emerging issues on which it is
2 valuable for states to continue to engage in discussions.
3 Q.What does the Company envision as a process to address allocation issues
4 post-2016?
5 A.The process would likely be similar to the one just followed. For example, the
6 post-20 16 issues would likely first be reviewed at the 2015 Standing COInittee
7 annual meeting. From that review, the Standing Committee would agree on
8 appropriate next steps as far as issue identifcation and analysis. Standing
9 Committee efforts would need to be designed to culminate in time for formal
10 commission proceedings to occur with decisions well in advance of January 1,
11 2017. It is also possible that the states would agree to extend the terms of the
12 2010 Protocol to apply beyond calendar year 2016.
13 Introduction of Witnesses
14 Q.Please introduce the Company's other witnesses and provide a brief
15 description of their testimony.
16 A.They are:
17 · Mr. Steven R. McDougal addresses the calculation and implementation of
18 the 2010 Protocol allocation methodology and presents the revenue
19 requirement analyses undertaken at the request of the Standing
20 Committee, and
21 . Mr. Gregory N. Duvall presents the net power cost (NPC) studies used to
22 support the 2010 Protocol revenue requirement analysis and to inform of
23 the Standing Committee's consideration of options.
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1 Q.
2 A.
Does this conclude your direct testimony?
Yes.
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Case No. PAC-E-1O-09
Exhibit NO.1
Witness: Andrea L. Kelly
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Andrea L. Kelly
2010 Protocol, including Appendices A to F
September 2010
Rocky Mountain Power
Exhibit NO.1 Page 1 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1 2010 Protocol
2 I.Introduction
3 This 2010 PacifiCorp Inter-Jursdictional Cost Allocation Protocol (2010
4 Protocol) is the result of continuing discussions that have occurred among
5 representatives ofPacifiCorp, Commission staff members and other interested
6 paries from Utah, Oregon, Wyoming, and Idaho regarding issues arising from the
7 previously adopted Revised Protocol, and the Company's status as a multi-
8 jurisdictional utility.
9 PacifiCorp commits that it wil continue to plan and operate its generation
10 and transmission system on a six-State integrated basis in a manner that achieves a
11 least cost/least risk Resource portfolio for its customers.
12 The 2010 Protocol describes regulatory policies, which, if utilized by all
13 States for rate proceedings filed prior to January 1,2017, should afford PacifiCorp a
14 reasonable opportnity to recover all of its prudently incured expenses and
15 investments and ear its authorized rate of retu. The assignment of a particular
16 expense or investment, or allocation of a share of an expense or investment, to a
17 State pursuant to the 2010 Protocol is not intended to, and should not, prejudge the
18 prudence of those costs. Nothing in the 2010 Protocol shall abridge any State's right
19 and/or obligation to establish fair, just and reasonable rates based upon the law of
20 that State and the record established in rate proceedings conducted by that State.
21 Parties who have supported the ratification of the 2010 Protocol do so in the belief
22 that it wil continue to achieve a solution to multi state issues that is in the public
23 interest. However, a part's support of the 2010 Protocol is not intended in any
24 manner to negate the necessary flexibility of the regulatory process to deal with
2010 Protocol 1
Rocky Mountain Power
Exhibit No. 1 Page 2 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1 changed or unforeseen circumstances, and a part's support of the 2010 Protocol wil
2 not bind or be used against that part in the event that unforeseen or changed
3 circumstances cause that part to conclude, in good faith, that the 2010 Protocol no
4 longer produces results that are just, reasonable and in the public interest. Support of
5 the 2010 Protocol shall not be deemed to constitute an acknowledgement by any
6 par of the validity or invalidity of any paricular method, theory or principle of
7 regulation, cost recovery, cost of service or rate design and no part shall be deemed
8 to have agreed that any particular method, theory or principle of regulation, cost
9 recovery, cost of service or rate design employed in the 2010 Protocol is appropriate
10 for resolving any other issues.
11 The 2010 Protocol describes how the costs and wholesale revenues
12 associated with PacifiCorp's generation, transmission and distribution system wil be
13 assigned or allocated among its six-State jursdictions for puroses of establishing its
14 retail rates.
15 Definitions of terms that are capitalized in the 201 0 Protocol are set forth in
16 Appendix A.
17 A table identifying the allocation factor to be applied to each component of
18 PacifiCorp's revenue requirement calculation is included as Appendix B.
19 The algebraic derivation of each allocation factor is contained in Appendix C.
20 A description and numeric example of how Special Contracts and related
21 discounts wil be reflected in rates is set fort in Appendix D.
22 The fixed and 1eve1ized Embedded Cost Differential (ECD) amounts, that
23 wil be included in filings made through December 31, 2016, are set forth in
24 Appendix E.
2010 Protocol 2
Rocky Mountain Power
Exhibit NO.1 Page 3 of 57
Case No. PAC-E-1Q-09
Witness: Andrea L. Kelly
1 Each State's allocated share of each Mid-Columbia Contract and the method
2 for calculating the shares is set forth in Appendix F.
3 II.Proposed Effective Date
4 The 2010 Protocol wil and apply to all PacifiCorp rate proceedings fied
5 prior to January 1, 2017.
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7 III. Classifcation of Resource Costs
8 All Resource Fixed Costs, Wholesale Contracts and Short-term Purchases
9 and Sales wil be classified as 75 percent Demand-Related and 25 percent Energy-
10 Related. All costs associated with Non-Firm Purchases and Sales wil be classified
11 as 100 percent Energy-Related.
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13 iv.Allocation of Resource Costs and Wholesale Revenues
14 Resources wil be assigned to one of three categories for inter-jursdictional
15 cost allocation puroses:
16 A. Regional Resources,
17 B. State Resources, or
18 C. System Resources.
19 There are two tyes of Regional Resource and four tyes of State Resources.
20 The remainder are System Resources which constitute the substantial majority of
21 PacifiCorp's Resources. Costs associated with each category and tye of Resource
22 wil be allocated on the following basis:
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A.Regional Resources
Costs associated with Regional Resources wil be assigned and
allocated as follows:
1.Hydro-Endowment.
2010 Protocol 3
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2010 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 4 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
a.Owned Hydro Embedded Cost Differential
Adjustment. The Owned Hydro Embedded Cost
Differential Adjustment is calculated as follows:
. The Forecasted Embedded Costs - Hydro-Electric
Resources, less the Forecasted Embedded Costs-
Pre-2005 Resources, multiplied by the normalized
MWh's of output from the Hydro-Electric
Resources.
. The calculation is made using forecasted
information contained in the Company's Baseline
Study (fina1ized in March 2010) for calendar years
2011 through 2016.
. The forecasted differential is allocated on the DGP
factor and the inverse amount is allocated on the
SG factor to compute State specific amounts for
calendar years 2011 though 2016.
. The net present value of the forecasted differential
by State is set at a fixed dollar level that wil be
used for all PacifiCorp rate proceedings filed prior
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to January 1,2017.
Mid-Columbia Contract Embedded Cost Differential
Adjustment. The Mid-Columbia Contract Embedded
Cost Differential Adjustment is calculated as follows:
. The Forecasted Mid-Columbia Contracts Costs,
less the Forecasted Embedded Costs - Pre-2005
Resources, multiplied by the normalized MW's of
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2010 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 5 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
output from the Mid-Columbia Contracts (Mid-C
1ess All Other).
. The calculation is made using forecasted
information contained in the Company's Baseline
Study (fina1ized in March 2010) for calendar years
2011 through 2016.
. The forecasted allocation of Mid-Columbia
Contracts to each State is established pursuant to
Appendix F. The forecasted Mid-Columbia
differential is allocated on the MC factor and the
inverse amount is allocated on the SG factor to
compute State specific amounts for calendar years
2011 through 2016.
. The net present value of the forecasted differential
by State is set at a fixed dollar level that wil be
used for all PacifiCorp rate proceedings fied prior
to January 1,2017.
The results of the Owned Hydro Embedded Cost Differential
calculation and the Mid-Columbia Contract Embedded Cost
Differential calculation are added together and a 1eve1ized
annual value for the calendar years 2011 through 2016 time
period is calculated. The 1eve1ized Hydro Endowment is fixed
for puroses of ratemaking for that time period.
Klamath Hydroelectric Settlement Agreement (KHSA). As
part of futue ratemaking proceedings, the Company wil
include the full impact of the KHSA as a system cost in
unadjusted results.
5
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
B.
21
22
23
24
25
2010 Protocol
Rocky Mountain Power
Exhibit NO.1 Page 6 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
a. Klamath Dam Removal Surcharge Adjustment. The
Klamath Dam Removal Surcharge is re-allocated to
Oregon (92 percent) and California (8 percent) as follows:
. Each State's initial allocated share of the Klamath
Dam Removal Surcharge is reversed and assigned to
Oregon and California on a situs basis. The
calculation is made using forecasted information
contained in the Company's Baseline Study (finalized
in March 2010) for calendar years 2011 through 2016.
. The net present value of the forecasted adjustment by
State is set at a fixed dollar level that wil be used for
all PacifiCorp rate proceedings fied prior to January 1,
2017. The 1eve1ized annual value for the calendar
years 2011 through 2016 time period wil be used for
puroses of ratemaking for that time period.
State Resources
Costs associated with the four tyes of State Resources wil be
assigned as follows:
1.Demand':Side Management Programs: Costs associated with
Demand-Side Management Programs wil be assigned on a
situs basis to the State in which the investment is made.
Benefits from these programs, in the form of reduced
consumption and contrbution to peak, wil be reflected
through time in the Load-Based Dynamic Allocation Factors.
6
Rocky Mountain Power
Exhibit No. 1 Page 7 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1 2.Portfolio Standards: Costs associated with Resources acquired
2 pursuant to a State Portfolio Standard, which exceed the costs
3 PacifiCorp would have otherwise incurred, wil be assigned on
4 a situs basis tothe State adopting the standard.
5 3.New Qualifying Facilities (QF) Contracts: Costs associated
6 with any New QF Contract, which exceed the costs PacifiCorp
7 would have otherwise incured acquiring Comparable
8 Resources, wil be assigned on a situs basis to the State
9 approving such contract.
10 4.State-Specific Initiatives: Costs associated with Resources
11 acquired pursuant to a State-specific initiative wil be assigned
12 on a situs basis to the State adopting the initiative. This
13 includes the costs of incentive programs, net-metering tariffs,
14 feed-in tariffs, capacity standard programs, electrc vehicle
15 programs and the acquisition of renewable energy certificates.
16 c.System Resources
17 All Resources that are not Regional Resources or State Resources are
18 System Resources. Generally, all Fixed Costs associated with System
19 Resources and all costs incurred under Wholesale Contracts wil be
20 allocated based upon the SG Factor. Generally, all Variable Costs
21 associated with System Resources wil be allocated based upon the
22 SE Factor. Revenues received by the Company pursuant to Wholesale
23 Contracts wil be allocated based upon the SG Factor. A complete
2010 Protocol 7
Rocky Mountain Power
Exhibit NO.1 Page 8 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2
3
4
5
6
7
8
9
10
11
12 V.
description of the allocation factors to be utilized is set fort in
D.
Appendix B.
Load Growth
At the direction of the MSP Standing Committee, the Company and
parties wil continue to analyze and quantify potential cost shifts
related to faster-growing States.1 In addition, the MSP Standing
Committee wil 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
any potentia110ad growth-related issues.
Refunctionalization and Allocation of Transmission Costs and Revenues
13 If the Company is required to refunctiona1ize assets that are curently
14 fuctionalized as "transmission" to "distribution", the cost responsibility for any
15 such refuctiona1ized assets wil be assigned to the State where they are located. Any
16 refunctiona1ization wil be implemented under the guidance of the MSP Standing
17 Committee.
18 Costs associated with transmission assets, and firm wheeling expenses and
19 revenues, wil be classified as 75 percent Demand-Related, 25 percent Energy-
20 Related and allocated among the States based upon the SG (System Generation)
21 factor. Non-firm wheeling expenses and revenues wil be allocated among the States
22 based upon the SE Factor.
23
1 This issue wil be monitored through studies that compute the costs
allocated to each State for two cases: (a) with curently projected load growth
together with a least-cost, least-risk mix of Resource additions to meet that 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.
2010 Protocol 8
Rocky Mountain Power
Exhibit No. 1 Page 9 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1 VI.Assignment of Distribution Costs
2 All distribution-related expenses and investment that can be directly assigned
3 wil be directly assigned to the state where they are located. Those costs that cannot
4 be directly assigned wil be allocated among States consistent with the factors set
5 forth in Appendix B.
6
7 VII. Allocation of Administrative and General Costs
8 Administrative and general costs, costs of General Plant and costs of
9 Intangible Plant wil be allocated among States consistent with the factors set forth in
10 Appendix B.
11
12 VIII. Allocation of Special Contracts
13 Revenues associated with Special Contracts wil be included in State
14 revenues and loads of Special Contract customers wil be included in all Load-Based
15 Dynamic Allocation Factors. Special Contracts mayor may not include Customer
16 Ancilary Service Contract attibutes. In recognition that Special Contracts may take
17 different forms, Appendix D provides a wrtten description and numeric example of
18 the regulatory treatment of Special Contracts and associated discounts.
19
20 IX.Allocation of Gain or Loss from Sale of Resources or Transmission
21 Assets
22 Any loss or gain from the sale of a Resource (other than a Freed-Up
23 Resource) or a transmission asset wil be allocated among States based upon the
24 allocation factor used to allocate the Fixed Costs of the Resource or the transmission
25 asset at the time of its sale. Each Commission will determine the appropriate
26 allocation of loss or gain allocated to that State as between State customers and
27 PacifiCorp shareholders.
2010 Protocol 9
Rocky Mountain Power
Exhibit NO.1 Page 10 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2 X.Implementation of Direct Access Programs
3 A.Allocation of Costs and Benefits of Freed-Up Resources
4 1.Loads lost to Direct Access - Where the Company is required to
5 continue to plan for the load of Direct Access Customers, such
6 load wil be included in Load-Based Dynamic Allocation Factors
7 for all Resources.
8 2.Loads of customers permanently choosing Direct Access or
9 permanently opting out of New Resources - Where the Company
10 is no longer required to plan for the load of customers who
11 permanently choose direct access or permanently opt out of New
12 Resources, such loads wil be included in Load-Based Dynamic
13 Allocation Factors for all Existing Resources but wil not be
14 included in Load-Based Dynamic Allocation Factors for New
15 Resources acquired after the election to permanently choose
16 Direct Access or opt out of New Resources. An effective date for
17 this process wil be established at such time as customers
18 permanently choose Direct Access or opt out, and this process wil
19 be implemented under the guidance of the MSP Standing
20 Committee.
21 3.In each State with Direct Access Customers, an additional step
22 wil take place for ratemaking puroses to establish a value or cost
23 (which could include a transfer of Freed-Up Resources between
24 customer classes within a State) resulting from the departe of
25 the departing load; other States do not implement the second step.
26 B.Freed-Up Resource Sale Approval
2010 Protocol 10
Rocky Mountain Power
Exhibit No. 1 Page 11 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2
3
4
Any proposed sale of a Freed-Up Resource for purposes of
calculating transition charges or credits wil be subject to applicable
regulatory review and approval based upon a "no-harm" standard.
States implementing Direct Access Programs that involve the sale of
5
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10
11
12
13
14
15
16
17
18
19 XI.
Freed-Up Resources wil endeavor to propose a method for allocating
the gain or loss on a sale to Direct Access Customers in a manner that
satisfies the "no-harm" standard in respect to customers in the other
States. The parties agree that they wil not advocate a sale of Freed-
Up Resources to be consummated if the proposed allocation of the
gain or loss from the sale would cause the Company to distribute
more than the total gain on a sale or recover less than the full amount
of the tota110ss on a sale.
c.Allocation of Revenues and Costs from Direct Access Purchases
and Sales
Revenues and costs from Direct Access Purchases and Sales wil be
assigned situs to the State where the Direct Access Customers are
located and wil not be included in Net Power Costs.
Loss or Increase in Load
20 Any loss or increase in retai110ad occurng as a result of condemnation or
21 municipalization, sale or acquisition of new service terrtory which involves less than
22 five percent of system load, realignment of service terrtories, changes in economic
23 conditions or gain or loss of large customers wil be reflected in changes in Load-
24 Based Dynamic Allocation Factors. The allocation of costs and benefits arising from
25 merger, sale and acquisition transactions proposed by the Company involving more
26 than five percent of system load wil be dealt with on a case-by-case basis in the
27 course of Commission approval proceedings.
2010 Protocol 11
Rocky Mountain Power
Exhibit NO.1 Page 12 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2 XII. Commission Regulation of Resources
3 PacifiCorp shall plan and acquire new Resources on a system-wide least cost,
4 least risk basis. Prudently incured investments in Resources wil be reflected in
5 rates consistent with the laws and regulations in each State.
6
7 XIII. Sustainabilty of 2010 Protocol
8 A.Issues of Interpretation
9 If questions of interpretation of the 2010 Protocol arise durng rate
10 proceedings and/or audits of results ofPacifiCorp's operations, parties wil attempt
11 to resolve them with reference to the intent of the parties who have supported the
12 ratification of the 2010 Protocol.
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
B.MSP Standing Committee
1.The existing MSP Standing Committee wil continue to be
organized consisting of one member or delegate of each
Commission. The chair of the MSP Standing Committee wil
be elected each year by the members of the Committee.
The MSP Standing Committee wil appoint a Stading2.
Neutral, at the Company's expense, to faciltate discussions
among States, monitor issues and assist the MSP Standing
Committee.
3.At least once during each calendar year, the Standing Neutral
wil convene a meeting of the MSP Standing Committee and
interested parties from all States for the purpose of discussing
and monitoring emerging inter-jurisdictional issues facing the
Company and its customers. The meetings wil be open to all
interested parties.
2010 Protocol 12
Rocky Mountain Power
Exhibit NO.1 Page 13 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
4.The MSP Standing Committee wil consider possible
amendments to the 2010 Protocol that would be equitable to
PacifiCorp customers in all States and to the Company. The
MSP Standing Committee wil have discretion to determine
how best to encourage consensual resolution of issues arising
under the 2010 Protocol. Its actions may include, but wil not
be limited to: a) appointing a committee of interested parties
to study an issue and make recommendations, or b) retaining
(at the Company's expense) one or more disinterested parties
to make advisory findings on issues of fact arising under the
2010 Protocol.
The work of the MSP Standing Committee wil be supported
by sound technical analysis. A part supporting ratification of
the 2010 Protocol wil work in good faith to address issues
being considered by the MSP Standing Committee.
2010 Protocol Amendments
5.
c.
17 Proposed amendments to the 2010 Protocol wil be submitted by
18 PacifiCorp to each Commission for ratification. The 2010 Protocol
19 wil only be deemed to have been amended if each of the
20 Commissions who have previously ratified the 2010 Protocol ratifies
21 the amendment. PacifiCorp wil not seek Commission ratification of
22 any amendment to the 2010 Protocol unless and until it has provided
23 interested paries with at least six months advance notice of its intent
24 to do so and endeavored to obtain consensus regarding its proposed
25 amendment. A part's initial support or acceptance of the 2010
26 Protocol wil not bind or be used against that part in the event that
27 unforeseen or changed circumstances cause that par to conclude that
2010 Protocol 13
Rocky Mountain Power
Exhibit NO.1 Page 14 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
1
2
3
the 2010 Protocol no longer produces just and reasonable results.
Prior to departing from the terms of the 2010 Protocol, consistent with
their legal obligations, Commissions and parties wil endeavor to
5
6
7
cause their concerns to be presented at meetings of the MSP Standing
Committee and interested parties from all States in an attempt to
4
achieve consensus on a proposed resolution of those concerns.
D.Interdependency among Commission Approvals
8 The 2010 Protocol has been developed by the parties as an integrated,
9 inter-dependent, organic whole. Therefore, fina1 ratification of the
10 2010 Protocol by any of the Commissions of Oregon, Utah, Wyoming
11 and Idaho, is expressly conditioned upon similar ratification of the
12 2010 Protocol by the other mentioned Commissions, without any
13 deletion or alteration of a material term, or the addition of other
14 material terms or conditions. Upon any rejection of the 2010
15 Protocol, or any material deletion, alteration, or addition to its terms,
16 by anyone or more of the four Commissions, the Commissions who
17 have previously conditionally adopted the 2010 Protocol shall initiate
18 proceedings to determine whether they should reaffrm their prior
19 ratification of the 2010 Protocol, notwithstanding the action of the
20 other Commission or Commissions. The 2010 Protocol shall only be
21 in effect for a State upon final ratification by its Commission. The
22 Company wil continue to bear the risk of inconsistent allocation
23 methods among the States.
2010 Protocol 14
Rocky Mountain Power
Exhibit NO.1 Page 15 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIX A
Rocky Mountain Power
Exhibit No. 1 Page 16 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
2010 Protocol - Appendix A
Defined Terms
For puroses of this 2010 Protocol, the following terms wil have the following
meanings:
"2010 Protocol" means this 2010 PacifiCorp Inter-Jursdictional Cost Allocation
Protocol.
"Baseline Study" means the calculation of the Company's projected revenue
requirement for calendar years 2010 through 2019 and the corresponding inter-jursdictional
allocation. The Baseline Study was prepared in March 2010 and was designed to facilitate
States' assessment ofthe ongoing reasonableness of the Revised Protocol.
"Coincident Peak" means the hour each month that the combined demand of all
PacifiCorp retail customers is greatest. In States using an historic test period, Coincident Peak is
based upon actual, metered load data. In States using futue test periods, Coincident Peak is
based upon forecasted loads.
"Company" means PacifiCorp.
"Commission" means a utility regulatory commission in a State.
"Comparable Resource" means Resources with similar capacity factors, start-up costs,
and other output and operating characteristics.
"Customer Ancilary Service Contracts" means contracts between the Company and a
retail customer pursuant to which the Company pays the customer for the right to curtail service
so as to lower the costs of operating the Company's system.
"Demand-Related Costs" means capital and other Fixed Costs incured by the Company
in order to be prepared to meet the maximum demand imposed upon its system.
"Demand-Side Management Programs" means programs intended to reduce electricity
use through activities or programs that promote electrc energy efficiency or conservation, more
efficient management of electrc energy loads, or reductions in peak demand.
2010 Protocol- Appendix A 1
Rocky Mountain Power
Exhibit No. 1 Page 17 of 57
Case No. PAC-E-10.09
Witness: Andrea L. Kelly
"nirect Access Customers" means retail electrcity consumers located in PacifiCorp's
service terrtory that either: a) purchase electrcity directly from a supplier other than PacifiCorp
pursuant to a Direct Access Program or b) elect to have all or a porton of the electrcity they
purchase from PacifiCorp priced based upon market prices rather than the Company's traditional
cost-of-service rate. If a State implements a Direct Access Program pursuant to which Freed-Up
Resources are trnsferred between customer classes, such transfers shall be considered Direct
Access Purchases and Sales.
"Direct Access Program" means a law or regulation that permits retail consumers
located in PacifiCorp's service terrtory to purchase electrcity directly from a supplier other than
PacifiCorp.
"Direct Access Purchases and Sales" means Wholesale Contracts and Short-Term
Purchases and Sales entered into by PacifiCorp either to supply customers who have become
Direct Access Customers or to dispose of Freed-Up Resources.
"Energy-Related Costs" means costs, such as fuel costs that var with the amount of
energy delivéred by the Company to its customers durig any hour plus any porton of Fixed
Costs that have been deemed to have been incured by the Company in order to meet its energy
requirements.
"Existing Resources" means Resources whose costs were committed to prior to Direct
Access Customers making an election to permanently forego being served by the Company at a
cost-of-service rate.
"FERC" means the Federal Energy Regulatory Commission.
"Fixed Costs" means costs incured by the Company that do not var with the amount of
energy delivered by the Company to its customers durng any hour.
"Forecasted Embedded Costs - Hydro-Electric Resources" means PacifiCorp's total
forecasted production costs contained in the Company's Baseline Study, for calendar years 2011
through 2016, expressed in dollars per MW, associated with Hydro-Electrc Resources as
recorded in the FERC Accounts listed in Appendix E to the 2010 Protocol.
2010 Protocol - Appendix A 2 Revised - March 2, 2011
Rocky Mountain Power
Exhibit No. 1 Page 18 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
"Forecasted Embedded Costs - Pre-2005 Resources" means PacifiCorp's total
forecasted production costs ofPre-2005 Resources contained in the Company's Baseline Study,
for calendar years 2011 through 2016, expressed in dollars per MW, other than costs associated
with Hydro-Electrc Resources, and Mid-Columbia Contracts, as recorded in the FERC Accounts
listed in Appendix E to the 2010 Protocol.
"Forecasted Mid-Columbia Contract Costs" means the total forecasted net costs
incured by PacifiCorp contained in the Company's Baseline Study, for calendar years 2011
though 2016, expressed in dollars per MW, under the Mid-Columbia Contracts.
"Freed-Up Resources" means Resources made available to the Company as a result of
its customers becoming Direct Access Customers.
"General Plant" means capital investment included in FERC accounts 389 through 399.
"Grant County"means Public Utility District NO.2 of Grant County, Washington
"Hydro-Electric Resources" means Company-owned hydro-electrc plants located in
Oregon, Washington or California.
"Intangible Plant" means capital investment included in FERC accounts 301 though
303.
"Klamath Dam Removal Surcharge" means the tariffs collected from customers in
California and Oregon for the purose of providing fuding to remove specific Klamath River
dams, as detailed in the Klamath Hydroelectrc Settlement Agreement.
"Klamath Hydroelectric Settlement Agreement" means the Klamath Hydroelectrc
Settlement Agreement executed on Februar 18,2010 for the purose of resolving specific
FERC relicensing proceedings by establishing a process for potential facilties removal and
operation of hydroelectric projects until that time.
"Load-Based Dynamic Alocation Factor" means an allocation factor that is calculated
using States' monthly energy usage and/or States' contrbution to monthly system Coincident
Peak.
2010 Protocol - Appendix A 3 Revised - March 2, 2011
Rocky Mountain Power
Exhibit No. 1 Page 19 of 57
Case No. PAe-E-10-09
Witness: Andrea L. Kelly
"Mid-Columbia Contracts" means the Power Sales Contract with Grant County dated
May 22, 1956; the Power Sales Contract with Grant County dated June 22, 1959;the Priest
Rapids Project Product Sales Contract with Grant County dated December 31, 2001; the
Additional Products Sales Agreement with Grant County dated December 31, 2001; the Priest
Rapids Project Reasonable Portion Power Sales Contract with Grant County dated December 31,
2001; the Power Sales Contract with Douglas County PUD dated September 18, 1963; the Power
Sales Contract with Chelan County PUD dated November 14, 1957 and all successor contracts
thereto.
"Net Power Costs" means PacifiCorp's fuel and wheeling expenses and costs and
revenues associated with Wholesale Contracts, Seasonal Contracts, Short-Term Puchases and
Sales and Non-Fir Purchases and Sales.
"New QF Contracts" means Qualifying Facilty Contracts that are entered into
subsequent to September 15, 2010.
"New Resources" means Resources that are not Existing Resources as established
pursuant to Paragraph XA2 of the 2010 Protocol.
"Non-Firm Purchases and Sales" means transactions at wholesale that are not
Wholesale Contracts, Seasonal Contracts, Short-Term Puchases and Sales or Direct Access
Purchases and Sales.
"Portfolio Standard" means a State law or regulation that requires PacifiCorp to
acquire: (a) a particular tye of Resource, (b) a particular quantity of Resources, (c) Resources
in a prescribed manner or (d) Resources located in a particular geographic area.
"Pre-2005 Resources" means Resources (other than Mid-Columbia Contracts and
Hydro-Electrc Resources) that were part of the Company's integrated system prior to Januar 1,
2005.
"Qualifying Facilty Contracts" means contracts to purchase the output of small power
production or cogeneration facilties developed under the Public Utility Regulatory Policies Act
of 1978 (PURPA) and related State laws and regulations.
2010 Protocol - Appendix A 4 Revised - March 2, 2011
Rocky Mountain Power
Exhibit No. 1 Page 20 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
"Resources" means Company-owned and leased generating plants and mines, Wholesale
Contracts, Seasonal Contracts, Short-Term Purchases and Sales and Non-firm Purchases and
Sales.
"Short-Term Purchases and Sales" means physical or financial contracts pursuant to
which PacifiCorp purchases, sells or exchanges firm power at wholesale and Customer Ancilary
Service Contracts that are less than one year in duration.
"Special Contract" means a contract entered between PacifiCorp's and one of its retail
customers with prices, term and conditions different from otherwise-applicable tariff rates.
Special Contracts may provide for a discount to reflect Customer Ancilary Services Contract
attbutes.
"Special Contract Ancilary Service Discounts" means discounts from otherwise
applicable rates provided for in Special Contracts.
"Standing Neutral" means an independent part, with experience in electrc utilty
ratemaking, retained by the MSP Standing Committee to facilitate discussions among States,
monitor issues and assist the MSP Standing Committee as required.
"State Resources" means Resources whose costs are assigned to a single State to
accommodate State-specific policy preferences.
"System Resources" means Resources that are not Regional Resources, State Resources
or Direct Access Purchases and Sales and whose associated costs and revenues are allocated
among all States on a dynamic basis.
"State" means Utah, Oregon, Wyoming, Idaho, Washington or California.
"Variable Costs" means costs incured by the Company that vary with the amount of
energy delivered by the Company to its customers during any hour.
"Wholesale Contracts" means physical or financial contracts pursuant to which
PacifiCorp purchases, sells or exchanges firm power at wholesale and Customer Ancilary
Service Contracts.
2010 Protocol- Appendix A 5
Rocky Mountain Power
Exhibit NO.1 Page 21 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIXB
2010 Protocol- Appendix B
Allocation Factor Applied to each Component of Revenue Requirement
Rocky Mountain Power
Exhibit No. 1 Page 22 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
FERC
ACCT
Sales to Ultimate Customers
DESCRIPTION
ALLOCATION
FACTOR
440 Residential Sales
Direct assigned - Jurisdiction S
442 Commeteial & Industrial Sales
Direct assigned - Jurisdiction S
444 Public Street & Highway Lighting
Direct assigned - Jurisdicton S
445 Other Sales to Public Authority
Direct assigned - Jurisdiction S
448 Interdepartmental
Direct assigned - Jurisdiction S
447 Sales for Resale
Direct assigned - Jurisdiction
Non-Firm
Firm
S
SE
SG
449 Provision for Rate Refund
Direct assigned - Jurisdicton S
SG
Other Electric Operating Revenues
450 Forfeijed Discounts & Interest
Direct assigned - Jurisdiction S
451 Mise Elecric Revenue
Direct assigned - Jurisdiction
Other - Common
S
SO
454 Rent of Electric Property
Direc assigned - Jurisdicton
Common
Other - Common
S
SG
SO
456 Other Elecric Revenue
Direc! assigned - Jurisdiction
Wheeling Non-firm, Other
Common
Wheeling - Firm, Other
Customer Related
S
SE
SO
SG
CN
Miscellaneous Revenues
41160 Gain on Sale of Utilty Plant- CR
Direct assigned - Jurisdiction
Production, Transmission
General Ofce
S
SG
SO
2010 Protocol- Appendix B
Allocation
FERC
ACCT
41170
4118
41181
421
Miscellaneous Expenses
4311
Steam Power Generation
500, 502, 504-514
501
503
Nuclear Power Generation
517 - 532
Hydraulic Power Generation
535 - 545
Other Power Generation
546, 548-554
547
Other Power Supply
555
2010 Protocol- Appendix B
Rocky Mountain Power
Exhibit NO.1 Page 23 of 57
Case No. PAC-E.10-09
Witness: Andrea L. KellyFactor Applied to each Component of Revenue Requirement
DESCRIPTION
ALLOCATION
FACTOR
Loss on Sale of Utility Plant
Direct assigned - Jurisdiction
Production, Transmission
General Ofce
S
SG
SO
Gain from Emission Allowances
S02 Emission Allowance sales SE
Gain from Disposition of NOX Credits
NOX Emission Allowance sales SE
(Gain) I Loss on Sale of Utilty Plant
Direct assigned - Jurisdiction
Production, Transmission
General Offce
S
SG
SO
Interest on Customer Deposits
Utah Customer Service Deposits
Direct assigned - Jurisdiction
CN
S
Operation Supervision & Engineering
Steam Plants SG
Fuel Related
Steam Plants SE
Steam From Other Sources
Steam Royalties SE
Nuclear Power O&M
Nuclear Plants SG
HydroO&M
Pacific Hydro
East Hydro
SG
SG
Operation Super & Engineering
Other Production Plant SG
Fuel
Other Fuel Expense SE
Purchased Power
Direct assigned - Jurisdiction
Firm
Non-firm
100 MW Hydro Extension
S
SG
SE
SG
2
Rocky Mountain Power
Exhibit No. 1 Page 24 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
556 System Control & Load Dispatch
Other Expenses SG
557 Other Expenses
Direct assigned - Jurisdiction
Other Expenses
S
SG
2010 Protocl Adjustments
Hydro Endowment
Klamath Dam Removal Surcharge
Klamath Dam Removal Surcharge Re-allocation
S
S
S
TRANSMISSION EXPENSE
560-564, 566-573 Transmission O&M
Transmission Plant SG
565 Transmission of Electricity by Others
Firm Wheeling
Non-Firm Wheeling
SG
SE
DISTRIBUTION EXPENSE
580 - 598 Distribution O&M
Direct assigned - Jurisdiction
Other Distribution
S
SNPD
CUSTOMER ACCOUNTS EXPENSE
901 - 905 Customer Accounts O&M
Direct assigned - Juridiction
Total System Customer Related
S
CN
CUSTOMER SERVICE EXPENSE
907 - 910 Customer Service O&M
Direct assigned - Jurisdicton
Total System Customer Related
S
CN
SALES EXPENSE
911 -916 Sales Expense O&M
Direct assigned - Jurisdicton
Total System Customer Related
S
CN
ADMINISTRATIVE & GEN EXPENSE
920-935 Administrtive & General Expense
Direct assigned - Jurisdiction
Customer Related
General
FERC Regulatory Expense
S
CN
SO
SG
DEPRECIATION EXPENSE
403SP Steam Depreciation
Steam Plants SG
403NP Nuclear Depreciation
Nuclear Plant SG
2010 Protocol- Appendix B 3
Rocky Mountain Power
Exhibit No. 1 Page 25 of 57
Case NO.PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
403HP Hydro Depreciation
Pacific Hydro
East Hydro
SG
SG
4030P Oter Production Depreciation
Other Production Plant SG
403TP Transmission Depreciation
Transmission Plant SG
403 Distrbution Depreciation Direct assigned - Jurisdiction
Land & Land Rights
Structures
Station Equipment
Storage Battery Equipment
Poles & Towers
OH Conductrs
UGConduit
UG Conductor
Line Trans
Services
Meters
Inst Cust Prem
Leased Propert
Street Lighting
S
S
S
S
s
S
S
S
S
S
S
S
S
S
403GP General Depreciation
Distribution
Steam Plants
Mining
Pacific Hydro
East Hydro
Transmission
Customer Related
General SO
S
SG
SE
SG
SG
SG
CN
SO
403MP Mining Depreciation
Remaining Mining Plant SE
AMORTIZATION EXPENSE
404GP Amort of L T Plant. Capital Lease Gen
Direct assigned - Jurisdicton
General
Customer Related
S
SO
CN
404SP Amort of L T Plant - Cap Lease Steam
Steam Production Plant SG
4041P Amort of L T Plant - Intangible Plant
Distribution
Production, Transmission
General
Mining Plant
Customer Related
S
SG
SO
SE
CN
2010 Protocol - Appendix B 4
Rocky Mountain Power
Exhibit NO.1 Page 26 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
404MP Amort of L T Plant - Mining Plant
Mining Plant SE
404HP Amortization of Other Electric Plant
Pacific Hydro
East Hydro
SG
SG
405 Amortization of Other Electric Plant
Direct assigned - Jurisdiction S
406 Amortization of Plant Acquisition Adj
Direct assigned - Jurisdiction
Production Plant
S
SG
407 Amort of Prop Losses, Unrec Plant, etc
Direct assigned - Jurisdicton
Production, Transmission
Trojan
S
SG
TROJP
Taxes Other Than Income
408 Taxes Other Than Income
Direct assigned - Jurisdiction
Propert
System Taxes
Mise Energy
Misc Production
S
GPS
SO
SE
SG
DEFERRED ITe
41140 Deferred Investment Tax Credit - Fed
ITC DGU
41141 Deferred Investment Tax Credit - Idaho
ITC DGU
Interest Expense
427 Interest on Long-Term Debt
Direct assigned - Jurisdicton
Interest Expense
S
SNP
428 Amortization of Debt Disc & Exp
Interest Expense SNP
429 Amortization of Premium on Debt
Interest Expense SNP
431 Other Interest Expense
Interes! Expense SNP
432 AFUDC . Borrowed
AFUDC SNP
2010 Protocol - Appendix B 5
Rocky Mountain Power
Exhibit No. 1 Page 27 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
Interest & Dividends
DESCRIPTION
ALLOCATION
FACTOR
419 Interest & Dividends
Interest & Dividends SNP
DEFERRED INCOME TAXES
41010 Deferrd Income Tax - Federal-DR
Direct assigned - Jurisdicton
Electnc Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
General
Propert Tax related
Miscellaneous
Trojan
Distnbution
Mining Plant
Bad Debt
Tax Deprecia!ion
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNF'D
SE
BADDEBT
TAXDEPR
41011 Deferred Income Tax - State-DR
Direct assigned - Junsdiction
Electnc Plant in Service
Pacific Hydro
Producton, Transmission
Customer Related
General
Propert Tax related
Miscllaneous
Trojan
Distnbution
Mining Plant
Bad Debt
Tax Depreciation
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNPD
SE
BADDEBT
TAXDEPR
41110 Deferred Income Tax - Federal-CR
Direct assigned - Jurisdiction
Electric Plan! in Servce
Pacific Hydro
Production, Transmission
Customer Related
General
Propert Tax related
Miscellaneous
Trojan
Distnbution
Mining Plant
Contnbutions in aid of construction
Production, Other
Book Depreciation
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNPD
SE
CIAC
SGCT
SCHMDEXP
2010 Protocol- Appendix B 6
Rocky Mountain Power
Exhibit NO.1 Page 28 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
41111 Deferred Income Tax - Slate-CR
Direct assigned - Jurisdicton
Electric Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
General
Propert Tax related
Miscellaneous
Trojan
Distribution
Mining Plant
Contributions in aid of constrction
Production, Other
Book Depreciation
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNPD
SE
CIAC
SGCT
SCHMDEXP
SCHEDULE. M ADDITIONS
SCHMAF Additions - Flow Through
Direct assigned - Jurisdiction S
SCHMAP Additions - Permanent
Direct assigned - Jurisdiction
Mining related
General
Production J Transmission
S
SE
SO
SG
SCHMAT Additions - Temporary
Direct assigned - Jurisdiction
Contributions in aid of construction
Miscllaneous
Trojan
Pacific Hydro
Mining Plant
Producton, Transmission
Propert Tax
General
Depreciation
Distribution
Production, Other
S
CIAC
SNP
TROJD
SG
SE
SG
GPS
SO
SCHMDEXP
SNPD
SGCT
SCHEDULE - M DEDUCTIONS
SCHMDF Deductons - Flow Through
Direct assigned - Jurisdiction
Production, Transmission
Pacific Hydro
S
SG
SG
SCHMDP Deductions - Permanent
Direct assigned - Jurisdiction
Mining Related
Miscellaneous
General
S
SE
SNP
SO
2010 Protocol- Appendix B 7
Rocky Mountain Power
Exhibit NO.1 Page 29 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
Allocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
SCHMDT
DESCRIPTION
ALLOCATION
FACTOR
Deductons - Temporary
Direct assigned - Jurisdicton
Bad Debt
Miscellaneous
Pacific Hydro
Mining related
Proucton, Transmission
Properl Tax
General
Depreciation
Distrbution
Customer Related
S
BADDEBT
SNP
SG
SE
SG
GPS
SO
TAXDEPR
SNPD
CN
State Income Taxes
40911 State Income Taxes
(Internal calculation using blended statutory state and local income ta rate)
S
40910 FIT True-up S
40910 Wyoming Wind Tax Credit SG
Steam Production Plant
310-316
Steam Plants SG
Nuclear Production Plant
320-325
Nuclear Plant SG
Hydraulic Plant
330-336
Pacific Hydro
East Hydro
SG
SG
Other Production Plant
340-346
Other Producton Plant SG
TRANSMISSION PLANT
350-359
Transmisson Plant SG
DISTRIBUTION PLANT
360-373
Direct assigned - Jurisdicton S
2010 Protocol- Appendix B 8 Revised - March 2, 2011
Rocky Mountain Power
Exhibit NO.1 Page 30 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
Allocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
GENERAL PLANT
389 - 398
DESCRIPTION
ALLOCATION
FACTOR
Distrbution
Pacific Hydro
East Hydro
Proucton I Transmission
Customer Related
General
Mining
S
SG
SG
SG
CN
SO
SE
399 Coal Mine
Remaining Mining Plant SE
399L WIDCO Capital Lease
WIDCO Capital Lease SE
1011390 General Capital Leases
Direct assigned - Jurisdicton
General
Proucton I Transmission
S
SO
SG
INTANGIBLE PLANT
301 Organization
Direct assigned - Jurisdicton S
302 Franchise & Consent
Direct assigned - Jurisdicton
Producton, Transmission
S
SG
303 Miscellaneous Intangible Plant
Distrbution
Pacific Hydro
East Hydro
Production I Transmission
Customer Related
Generl
Mining
S
SG
SG
SG
CN
SO
SE
303 Less Non-Utility Plant
Direct assigned - Jurisdicton S
Rate Base Additions
105 Plant Held For Future Use
Direct assigned - Jurisdicton
Producton, Transmission
Mining Plant
S
SG
SE
114 Electric Plant Acquisition Adjustments
Direct assigned - Jurisdicton
Proucton Plant
S
SG
115 Accm Provision for Asset Acquisition Adjustments
Direct assigned - Jurisdiction
Producton Plant
S
SG
2010 Protocol-Appendix B 9 Revised - March 2, 2011
Rocky Mountain Power
Exhibit NO.1 Page 31 of 57
Case No. PAG-E-10-09
Witness: Andrea L. Kelly
Allocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
ALLOCATION
FACTORDESCRIPTION
120 Nuclear Fuel
Nuclear Fuel SE
124 Weatherition
Direct assigned - Jurisdiction
General
S
SO
182W Weatherization
Direct assigned - Jurisdiction S
186W Weatherization
Direc assigned - Jurisdiction S
151 Fuel Stoc
Steam Production Plant SE
152 Fuel Stock - Undistrbuted
Steam Production Plant SE
25316 DG& T Worng Capital Deposit
Mining Plant SE
25317 DG&T Working Capital Deposit
Mining Plant SE
25319 Provo Working Capital Deposit
Mining Plant SE
154 Materials and Supplies
Direct assigned - Jurisdicton
Producton, Transmission
Mining
General
Producton - Common
Hydro
Distribution
Production, Other
S
SG
SE
SO
SG
SG
SNPD
SG
163 Stores Expense Undistrbuted
General SO
25318 Provo Working Capital Depoit
Provo Working Capital Deposit SG
165 Prepayments
Direct assigned - Jurisdicton
Properl Tax
Proucton, Transmission
Mining
General
S
GPS
SG
SE
SO
2010 Protocol - Appendix B 10 Revised - March 2, 2011
Rocky Mountain Power
Exhibit No. 1 Page 32 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
Allocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
182M Misc Regulatory Assets
Direct assigned - Jurisdicton
Production, Transmission
Mining
General
Producton, Oter
S
SG
SE
SO
SGCT
186M Misc Deferred Debits
Direct assigned - Jurisdicton
Production, Transmission
General
Mining
Producton - Common
S
SG
SO
SE
SG
Working Capital
CWC Cash Workng Capital
Direct assigned - Jurisdicton S
OWC Other Working Capital
131 Cash SNP
135 Working Funds SG
143 Other Accunts Receivable SO
232 Accunts Payable SO
232 Accounts Payable SE
253 Deferred Hedge SE
25330 Other Deferd Credits - Misc SE
230 Other Deferrd Credit - Misc SE
Miscellaneous Rate Base
18221 Unrec Plant & Reg Study Costs
Direct assigned - Jurisdicton S
18222 Nuclear Plant - Trojan
Trojan Plant
Trojan Plant
TROJP
TROJD
141 Notes Receivable
Employee Loans - Hunter Plant SG
Rate Base Deductions
235 Customer Service Deposits
Direct assigned - Jurisdicton S
2281 Prov for Properl Insurance SO
2282 Prov for Injuries & Damages SO
2010 Protocol- Appendix B 11 Revised - March 2, 2011
Rocky Mountain Power
Exhibit NO.1 Page 33 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
Allocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
ALLOCATION
FACTOR
SO
DESCRIPTION
2283 Prov for Pensions and Benefits
22841 Accum Misc Oper Prov-Black Lung
Mining SE
22842 Accum Misc Oper Prov-Trojan
Trojan Plant TROJD
254105 FAS 143 ARO Regulatory Liability
Trojan Plant TROJP
230 Asset Retirement Obligation
Trojan Plant TROJP
252 Customer Advances for Construction
Direct assigned - Jurisdiction
Producton, Transmission
Customer Related
S
SG
CN
25399 Other Deferred Credits
Direct assigned - Jurisdiction
Producton, Transmission
Mining
S
SG
SE
254 Regulatory Liabilties
Regulatory Liabilties
Insurance Provision
SE
SO
190 Accmulated Deferred Income Taxes
Direct assigned - Jurisdiction
Bad Debt
Pacific Hydro
Production, Transmission
Customer Related
General
Miscellaneous
Trojan
Distribution
Mining Plant
S
BADDEBT
SG
SG
CN
SO
SNP
TROJD
SNPD
SE
281 Accumulated Deferred Income Taxes
Producton, Transmission SG
282 Accumulated Deferred Incoe Taxes
Direct assigned - Jurisdicton
Depreciation
Hydro Pacific
Producton, Transmission
Customer Related
General
Miscellaneous
Trojan
Depreciation
Depreciation
S
DITBAL
SG
SG
CN
SO
SNP
TROJP
TAXDEPR
SCHMDEXP
2010 Protocol - Appendix B 12 Revised - March 2, 2011
Rocky Mountain Power
Exhibit No. 1 Page 34 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
283 Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction
Depreciation
Hydro Pacific
Production, Transmission
Customer Related
General
Miscellaneous
Trojan
Production, Other
Property Tax
Mining Plant
S
DITBAL
SG
SG
CN
SO
SNP
TROJD
SGCT
GPS
SE
255 Accumulated Investment Tax Credil
Direct assigned - Jurisdiction
Investment Tax Credits
Investment Tax Credits
Investment Tax Credits
Investmen! Tax Credits
Investment Tax Credits
Investment Tax Credits
Investmen! Tax Credits
S
ITC84
ITC85
ITC86
ITC88
ITC89
ITC90
DGU
PRODUCTION PLANT ACCUM DEPRECIATION
108SP Steam Prod Plant Accumulated Depr
Steam Plants SG
108NP Nuclear Prod Plant Accumulated Depr
Nuclear Plant SG
108HP Hydraulic Prod Plant Accum Depr
Pacific Hydro
East Hydro
SG
SG
1080P Other Production Plant - Accum Depr
Other Producton Plant SG
TRANS PLANT ACCUM DEPR
108TP Transmission Plant Accumulated Depr
Transmission Plant SG
DISTRIBUTION PLANT ACCUM DEPR
108360 - 108373 Distribution Plant Accumulated Depr
Direct assigned - Jurisdicion s
108DOO Unclassifed Dist Plant - Acc 300
Direct assigned - Jurisdiction s
108DS Unclassifed Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction S
108DP Unclassifed Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction S
2010 Protocol - Appendix B 13
Allocation
Rocky Mountain Power
Exhibit No. 1 Page 35 of 57
Case No. PAC-E-10-09
Witness: Andrea L. KellyFactor Applied to each Component of Revenue Requirement
FERC
ACCT
GENERAL PLANT ACCUM OEPR
108GP General Plant Accumula!ed Depr
Distribution
Pacific Hydro
East Hydro
Production I Transmission
DESCRIPTION
ALLOCATION
FACTOR
Customer Related
General SO
Mining Plant
Customer Related
S
SG
SG
SG
CN
SO
SE
CN
108MP Mining Plant Accumulated Depr.
Mining Plant SE
108MP Less Centralia Situs Depreciation
Direct assigned - Jurisdiction S
1081390 Accum Depr - Capital Lease
General SO
1081399 Accum Depr - Capital Lease
Direct assigned - Jurisdicton S
ACCUM PROVISION FOR AMORTIZATION
111 SP Accum Prov for Amort-Steam
Steam Plants SG
111GP Accum Prov for Amort-General
Distrbution
Pacific Hydro
East Hydro
Producton I Transmission
Customer Related
General SO
S
SG
SG
SG
CN
SO
111HP Accum Prov for Amort-Hydro
Pacific Hydro
East Hydro
SG
SG
1111P Accum Prov for Amort-Intangible Plant
Distribution
Pacific Hydro
Producton, Transmission
General
Mining
Customer Related
S
SG
SG
SO
SE
CN
1111P Less Non-Utiit Plant
Direct assigned - Jurisdiction S
111399 Accum Prov for Amort-Mining
Mining Plant SE
2010 Protocol ~ Appendix B 14
Rocky Mountain Power
Exhibit NO.1 Page 36 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIXC
Rocky Mountain Power
Exhibit NO.1 Page 37 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
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Rocky Mountain Power
Exhibit No. 1 Page 48 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
C"..
u~:.
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Rocky Mountain Power
Exhibit No. 1 Page 49 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIXD
Rocky Mountain Power
Exhibit No. 1 Page 50 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
2010 Protocol - Appendix D
Special Contracts
Special Contracts without Ancilary Service Contract Attributes
For allocation puroses Special Contracts without identifiable Ancilary Service Contract attbutes are
viewed as one transaction.
Loads of Special Contract customers wil be included in all Load-Based Dynamic Allocation Factors.
When interrptions of a Special Contract customer's service occur, the reduction in load wil be reflected in
the host jursdiction's Load-Based Dynamic Allocation Factors.
Actual revenues received from Special Contract customer wil be assigned to the State where the Special
Contract customer is located.
See example in Table 1
Special Contracts with Ancilary Service Contract Attributes
For allocation puroses Special Contracts with Ancilary Service Contrct attbutes are viewed as two
transactions. PacifiCorp sells the customer electricity at the retail service rate and then buys the electrcity
back durng the interrption period at the Ancilary Service Contract rate.
Loads of Special Contract customers wil be included in all Load-Based Dynamic Allocation Factors.
When interrptions ofa Special Contract customer's service occur, the host jursdiction's Load-Based
Dynamic Allocation Factors and the retail service revenue are calculated as though the interrption did not
occur.
Revenues received from Special Contract customer, before any discounts for Customer Ancilar Service
attbutes of the Special Contract, wil be assigned to the State where the Special Contract customer is
located.
Discounts from tariff prices provided for in Special Contracts that recognize the Customer Ancilar
Service Contract attbutes of the Contrct, and payments to retail customers for Customer Ancilar
Services wil be allocated among States on the same basis as System Resources.
See example in Table 2
Buy-through of Economic Curtailment
When a buy-through option is provided with economic curailment, the load, costs and revenue associated
with a customer buying though economic curilment will be excluded from the calculation of State
revenue requirements. The cost associated with the buy-though wil be removed from the calculation of
net power costs, the Special Contract customer load associated with the buy-through wil be not be included
in the calculation of Load-Based Dynamic Allocation Factors, and the revenue associated with the buy-
through wil not be included in State revenues.
1
Rocky Mountain Power
Exhibit NO.1 Page 51 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
2010 Protocol - Appendix 0 - Table 1
Interruptible Contract Without Ancilary Service Contract Attributes
Effect on Revenue Requirement
Factor Total system Jurisdiction 1 Jurisdiction 2 Jurisdiction 31 b2
2 Junsdictional Loads - No IntElrruptible Serviæ
3 Junsdictional Sum of 12 monthly CP demand (MW)72,000 24,000 36,000 12,000
4 Junsdictional Annual Energy (MWh)42,000,000 14,000,000 21,000.000 7,000,000
5
6 Junsdictional Loads - With Interruptible Service - Reflecting Actual Interruptions
7 Junsdictional Sum of 12 monthly CP demand (MW)71,700 24,000 35,700 12,000
8 Junsdictional Annual Energy (MWh)41,962,500 14,000,000 20,962,500 7,000,000
9
10 Special Contract Customer Revenue and Load - Non Interruptible Service
11 Special Contract Customer Revenue $20,000,000 $20,000,000
12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)900 900
13 Special Contract Annual Energy (MWh) (Included in line 3)500,000 500,000
14
15 SpElcial Contract Customer Revenue and Load - Wilh Interruptible Servce (75 MW X 500 Hours of Interruption)
16 Special Contract Customer RevenuEl $16,000,000 $16,000,000
17 Discount for Ancillary Servces
18 Net Cost to Special Contract Customer $16,000,000 $16,000,000
19 Special Conlract Sum of 12 CP- Reflecting Actal Inlerruptions (MW) (Included in line 7)600 600
20 Special Contract Annual Energy- Reflecting Actual Interrptions (MWh) (Included in line 8)462,500 462,500
21
22 System Cost Savings from Interruption $4,000,000
23
24 Allocation Factors
25 No InterruptiblEl Serviæ
26 SE factor (Calculated from line 4)SEl 100.00%33.33%50.00%16.67%
27 SC factor (Calculated from line 3)SCL 100.00%33.33%50.00%16.67%
28 SG factor (line 27*75% + line 26'25%)SGl 100.00%33.33%50.00%16.67%
29
30 Wilh Interrptible Service (Reflectng Actual Physical Interrptions)
31 SE factor (Calculaled from line 8)SE2 100.00%33.36%49.96%16.68%
32 SC factor (Calculated from line 7)SC2 100.00%33.47%49.79%16.74%
33 SG factor (line 32'75% + line 31*25%)SG2 100.00%33.45%49.83%16.72%
34
35
36 No Interruptible Service
37
38 Cost of Service
39 Energy Cost SEl $500,000.000 $166,666,667 $250,000,000 $83,333,333
40 Demand Related Costs SGl $1,000,000,000 $333,333,333 $500.000,000 $166,666,667
41 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000
42
43 Revenues
44 SpElcial Contract RevElnuEl Situs $20,000,000 $20,000,000
45 Revenues from all other customel"Situs $1,480,000,000 $500,000,000 $730,000,000 $250,000,000
46
47
48 With Interruptible Service
49
50 Cost of Service
51 EnElrgy Cost SE2 $498,000,000 $166,148,347 $248,777,480 $83,074,173
52 Demand Related Costs SG2 $998,000,000 $334,058,577 $496,912,134 $167,029,289
53 Sum of Cost $1,496,000,000 $500,206,924 $745,689,614 $250,103,462
54
55 RElvenues
56 Special Contract Revenue Situs $16,000,000 $16,000,000
57 Revenues from all other customers Situs $1,480,000,000 $500,206,924 $729,689,614 $250,103,462
2010 Protocol - Appendix D 2
Rocky Mountain Power
Exhibit No. 1 Page 52 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
2010 Protocol. Appendix D . Table 2
Interruptible Contract With Ancilary Service Contract Attributes
Effect on Revenue Requirement
Factor Total system Jurisdiction 1 Jurisdiction 2 Jurisdiction 3
1 Loads
2 Jurisdictional Loads - No Interruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW)72,000 24,000 36,000 12,000
4 Jurisdictional Annual Energy (MWh)42,000,000 14,000,000 21,000,000 7,000,000
5
6 Jurisdictional Loads - With Interruptible Servce - Reflecting Actual Interruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW)71,700 24.000 35,700 12,000
8 Jurisdictional Annual Energy (MWh)41,962,500 14,000,000 20,962,500 7,000,000
9
10 Special Contract Customer Revenue and Load - Non Interrptible Service
11 Special Contract Customer Revenue $20,000,000 $20,000,000
12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)900 900
13 Special Contract Annual Energy (MWh) (Included in line 3)500,000 500,000
14
15 Special Contract Customer Revenue and Load. With Interrptible Service (75 MW X 500 Hours of Interruption)
16 Tariff Equivalent Revenue $20,000,000 $20,000,000
17 Ancilary Service Discount for 75 MW X 500 Hours of Economic Curtilment $(4,000,000)18 Net Cost to Special Contract Customer $16,000,000 $16,000,000
19 Special Contract Sum of 12 CP- Reflecting Actuallnterrplions (MW) (Included in line 7)600 600
20 Special Contract Annual Energy- Reflecting Actuallnlerruptions (MWh) (Included in line 8)462,500 462,500
21
22 System Cost Savings from Interrption $4,000,000
23
24 Allocation Factors
25 No Interrptible Service
26 SE factor (Calculated from line 4)SE1 100.00%33.33%50.00%16.67%
27 SC factor (Calculated from line 3)SC1 100.00%33.33%50.00%16.67%
28 SG factor (line 27*75% + line 26'25%)SG1 100.00%33.33%50.00%16.67%
29
30 With Interrptible Service (Refectng Actual Physical Interruptions)
31 SE factor (Calculated from line 8)SE2 100.00%33.36%49.96%16.68%
32 SC factor (Calculated from line 7)SC2 100.00%33.47%49.79%16.74%
33 SG factor (line 32'75% + line 31'25%)SG2 100.00%33.45%49.83%16.72%
34
35
36 No Interruptible Service
37
38 Cost of Service
39 Energy Cost SE1 $500,000,000 $166,666,667 $250,000,000 $83,333,333
40 Demand Related Costs SG1 $1,000,000,000 $333,333,333 $500,000,000 $166,666,667
41 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000
4243~
44 Special Contract Revenue Situs $20,000,000 $20,000,000
45 Revenues from all other customers Situs $1,480,000,000 $SOO,OOO,OOO $730,000,000 $2SO,000,000
46
47
48 With Interruptible Service & Ancilary Service Contract
49
50 Cost of Service
51 Energy Cost SE1 $498,000,000 $166,000,000 $249,000,000 $83,000,000
52 Demand Related Costs SG1 $998,000,000 $332,666,667 $499,000,000 $166,333,333
53 Ancilary Service Contract. Economic Curtilment (Demand)SG1 $2,000,000 $666,667 $1,000,000 $333,333
54 Ancilary Service Contract - Economic Curtilment (Energy)SE1 $2,000,000 $666,667 $1,000,000 $333,333
55 Sum of Cost $1,500,000,000 $500,000,000 $750,000,000 $250,000,000
56
57 Revenues
58 Special Contract Revenue Situs $20,000,000 $20,000,000
59 Revenues from all other customers Situs $1,480,000,000 $SOO,OOO,OOO $730,000,000 $2SO,000,000
2010 Protocol - Appendix 0 3
Rocky Mountain Power
Exhibit No. 1 Page 53 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIXE
2011
Klamath Surcharge Situs
ECO Hydro
Total
2012
Klamath Surcharge Situs
ECD Hydro
Total
2013
Klamath Surcharge Situs
ECD Hydro
Total
2014
Klamath Surcharge Situs
ECD Hydro
Total
2015
Klamath Surcharge Situs
ECD Hydro
Total
2016
Klamath Surcharge Situs
ECD Hydro
Total
6 Year NPV
2011-2016 ~ 7.36%
. Klamath Surcharge Situs
ECD Hydro
Total
2010 Protocol- Appendix E
2010 Protocol- Appendix E
6 Year Levelized ECD Hydro Endowment Fixed Dollar Proposal
Revenue Requirement ($000)
Rocky Mountain Power
Exhibit No. 1 Page 54 of 57
Case No. PAC.E-10-09
Witness: Andrea L. Kelly
California
1
FERC
(70)
60
California Idaho
(976)
836
FERC
(70)
60
Wyoming
(2,955)
484
Total
(1 )
(O)!)F.'
(1 )
Idaho Wyoming FERC
(976) (2,955) (70)836 484 60
¡~~wl',III""'l~If"'..~1i.
California Oregon Washington1 ,062 11,496 (1,286)
. / (23l,..J§l (745)
..(2,a3,X"2/;
Utah
(7,272)
6,240
(i1~~~l:"
Total California
1
Utah
(7,272)
6,240
Wyoming
(2,955)
484
FERC
(70)
60
California
1
Oregon
1
Idaho
(976)
836
California
1
California Oregon Wyoming
(13,932)
2,281
FERC
(330)
281
Rocky Mountain Power
Exhibit NO.1 Page 55 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
APPENDIXF
Rocky Mountain Power
Exhibit No. 1 Page 56 of 57
Case No. PAC-E-10-09
Witness: Andrea L. Kelly
2010 Protocol - Appendix F
Methodology for Determining Mid-C (MC) Factor
Energy for each Mid-C contract is allocated as follows to determine the MC factor.
. Priest Rapids energy is assigned 100% to Oregon.
. Rocky Reach energy is allocated on the SG factor.
. Wanapum energy is assigned to Oregon and Washington based upon each state's
respective share of the SG factor.
o Wanapum energy assigned to Oregon = Oregon SG / (total Oregon and
Washington SG).
o Wanapum energy assigned to Washington = Washington SG / (total Oregon and
Washington SG).
. Wells energy is allocated on the SG factor.
. The Grant replacement contracts begin at the time the Priest Rapids contract terminates.
The energy from these contracts is assigned to Oregon through October 31, 2009.
. Effective November 1, 2009, the date the Wanapum contract expires, the Grant
replacement contract energy is divided into two pieces based on PacifiCorp's share of the
nameplate of Priest Rapids and Wanapum as shown in the following calculation:
Nameplate PacifiCorp's
PacifiCorp's
Share of
PacifCorp's
Share of
CapacityMW Share- %Nameplate - MW Nameplate - %
Priest Rapids 789 13.9%110 41.5%
Wanapum 831 18.7%155 58.65%
1,620 265 100.00%
· The Priest Rapids portion of the Grant County replacement contracts is 41.35%. The energy
associated with the Grant County replacement contracts for Priest Rapids is assigned 100% to
Oregon.
· The Wanapum portion of the Grant County replacement contracts is 58.65%. The energy
associated with the Grant County replacement contracts for Wanapum is assigned to Washington
based on the ratio of the Washington SG factor to the sum of the Oregon and Washington SG
factors. The remaining energy from the Wanapum portion is assigned to Oregon.
After all of the energy from the Mid-Columbia Contracts has been assigned or allocated to each State,
then the MC factor is created by dividing each State's energy by the total energy associated with the Mid-
Columbia Contracts. The MC factor is used to allocate the Mid-Columbia Contract embedded cost
differential to each State.
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