20210706PAC to Bayer ID Attach 28 PAC-E-19-20 Steward Exhibit No 1.pdf

Case No. PAC-E-19-20
Exhibit No. 1
Witness: Joelle R. Steward

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Joelle R. Steward

December 2019

2020 PacifiCorp Inter-Jurisdictional Allocation Protocol

Contents
1. Introduction ........................................................................................................................................................... 1
2. Timeframes and Effective Periods ........................................................................................................................ 5
2.1. Effective Period of the 2020 Protocol .......................................................................................................... 5
2.2. Post-Interim Period ...................................................................................................................................... 5 2.2.1. Commission Approvals for Post-Interim Period Method Obtained Prior to December 31, 2023 ............ 5
2.2.2. Commission Approval Not Granted ......................................................................................................... 5
2.2.3. Post-Interim Period Method Agreement Not Reached ............................................................................. 6
2.2.4. Early Commission Approvals of Post-Interim Period Method ................................................................ 6
2.2.5. Regulatory Filings to Implement Post-Interim Period Method ................................................................ 6
3. Interim Period Allocation Method ........................................................................................................................ 6
3.1. Continuing Terms of the 2017 Protocol for the Five States Interim Period Allocation Methodology ......... 7
3.1.1. Classification of Interim Period Resources .............................................................................................. 7
3.1.2. Allocation of Interim Period Resource Costs and Wholesale Revenues .................................................. 7
3.1.3. Re-functionalization and Allocation of Transmission Costs and Revenues ............................................. 9
3.1.4. Allocation of Distribution Costs ............................................................................................................ 10
3.1.5. Allocation of Administrative and General Costs ................................................................................... 10
3.1.6. Allocation of Special Contracts ............................................................................................................. 10
3.1.7 Miscellaneous Costs and Taxes .............................................................................................................. 10
3.1.8. State Programs Regarding Access to Alternative Electricity Suppliers ................................................. 11
3.1.9. Loss or Increase in Load ........................................................................................................................ 13
3.1.10. Commission Regulation of Interim Period Resources ....................................................................... 13
3.2. Modifications to the 2017 Protocol During the Interim Period .................................................................. 13 3.2.1. Net Power Costs Filings ........................................................................................................................ 13
3.3.2. Embedded Cost Differential (“ECD”) and Equalization Adjustment .................................................... 14
3.3.3. Costs and Benefits of Qualifying Facilities ........................................................................................... 15
3.3.4. Allocation of Gain or Loss from Sale of Assets ..................................................................................... 15
3.3.5. Interpretation and Governance ............................................................................................................... 15
4. Implemented Issues ............................................................................................................................................. 15
4.1. States' Decisions to Exit Coal-Fueled Interim Period Resources ............................................................... 16 4.1.1. Allocation of Costs at Closure ............................................................................................................... 16
4.1.2 Exit Orders ............................................................................................................................................. 17
4.1.3 Oregon Exit Dates .................................................................................................................................. 19
4.1.4. Washington Exit Orders ......................................................................................................................... 22
4.1.5. Establishment of Exit Dates for Hayden Units 1 and 2.......................................................................... 23
4.2. Reassignment of Coal-Fueled Interim Period Resources ........................................................................... 23 4.2.1 Company Proposals for Reassignment .................................................................................................. 23
4.2.2 Process and Timing ................................................................................................................................ 24
4.2.3 Effects of Commission Decisions Regarding Assignment ..................................................................... 25
4.3. Decommissioning Costs ............................................................................................................................. 26
4.3.1. Process for Determining Decommissioning Cost Allocation ................................................................. 26
4.3.2. Accounting for Decommissioning Costs Reserve Balances when All States Do Not Exit a Unit ......... 28
4.3.3. Accounting for Interim and Final Retirements ...................................................................................... 29
4.3.4. Individual State Review Process ............................................................................................................ 29
4.4. Qualifying Facilities ................................................................................................................................... 29 4.4.1. Existing QF PPAs .................................................................................................................................. 30
4.4.2. New QF PPAs ........................................................................................................................................ 30
5. Resolved Issues - Post-Interim Period Implementation ...................................................................................... 32
5.1. Generation Costs ........................................................................................................................................ 32 5.1.1. Interim Period Resources Fixed Allocation ........................................................................................... 32
5.1.2. New Resources Fixed Assignment ......................................................................................................... 34
5.2. Transmission Costs .................................................................................................................................... 34 5.3. Distribution Costs ...................................................................................................................................... 35 5.4. System Overhead Costs .............................................................................................................................. 35
5.5. Administrative and General Costs .............................................................................................................. 35 5.6. Other Allocation Issues .............................................................................................................................. 35
5.7. Demand-Side Management Programs ........................................................................................................ 37 5.8. State-Specific Initiatives ............................................................................................................................ 37 6. Framework Issues ............................................................................................................................................... 38
6.1. Resource Planning and New Resource Assignment ................................................................................... 38 6.2. Net Power Costs / Nodal Pricing Model (“NPM”) .................................................................................... 39 6.3. Special Contracts ........................................................................................................................................ 40
6.4. Limited Realignment .................................................................................................................................. 40 6.5. Post-Interim Period Capital Additions – Coal-Fueled Interim Period Resources ...................................... 40
6.5.1. PacifiCorp Straw Proposal - Post-Interim Period Capital Investment Allocation Exceptions ............... 41
6.5.2. PacifiCorp Straw Proposal - Incremental Capital Investments Made Between 2024 and the Exit Date
Where Exit Date is On or Before December 31, 2027 ......................................................................................... 41
6.5.3. PacifiCorp Straw Proposal - Incremental Capital Investments Made in 2024 and 2025 Where Exit Date
is After 2027 ........................................................................................................................................................ 42
6.5.4. PacifiCorp Straw Proposal - Incremental Capital Investments Made Between 2026 and the Exit Date
Where the Exit Date is After 2027 ....................................................................................................................... 43
7. Allocation of Gain or Loss from Sale of Assets .................................................................................................. 43
8. Interpretation and Governance ............................................................................................................................ 43
8.1. Issues of Interpretation ............................................................................................................................... 43
8.2. Workgroups ................................................................................................................................................ 44 8.2.1. Framework Issues Workgroup ............................................................................................................... 44
8.2.2. Multi-State Process Workgroup ............................................................................................................. 44
8.3. Commissioner Forum ................................................................................................................................. 44
8.4. Proposals to Change the 2020 Protocol during the Interim Period ............................................................ 44 8.5. Replacement of the 2020 Protocol ............................................................................................................. 45
8.6. Interdependency Among Commission Approvals ...................................................................................... 45 9. Compliance with Resource Laws ........................................................................................................................ 46
10. Signatures of Parties to the 2020 Protocol .......................................................................................................... 46

1. Introduction 1
This 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol Agreement (the “2020 2
Protocol” or this “Agreement”) reflects the agreement among PacifiCorp (or the “Company”), 3
certain Commission1 staff members, State regulatory agencies, customers, consumer advocates, 4
conservation organizations, and other interested parties from California, Idaho, Oregon, Utah, 5
Washington, and Wyoming (collectively referred to as the “States” or individually as a “State”) 6
who have executed this Agreement (collectively referred to as the “Parties” or individually as a 7
“Party”) on an interim allocation and assignment method and a process for determining a long-8
term replacement of existing inter-jurisdictional allocation and assignment methodologies.2 The 9
2020 Protocol is intended to: (1) supersede the 2017 PacifiCorp Inter-Jurisdictional Allocation 10
Protocol (the "2017 Protocol") for California, Idaho, Oregon, Utah, and Wyoming; and (2) modify 11
the West Control Area Inter-jurisdictional Allocation Methodology ("WCA") for Washington. 12
However, as part of the 2020 Protocol, the 2017 Protocol and the WCA allocation methodologies 13
will continue to be used, with modifications explained herein, during an Interim Period, as defined 14
below. Subject to the provisions set forth below, and with the acknowledgment that only the 15
appropriate state body charged with issuing orders to establish rates can approve its use, the Parties 16
agree that the 2020 Protocol can be used to set just and reasonable rates and agree to support its 17
use in rate filings in California, Idaho, Oregon, Utah, Washington, and Wyoming during the Interim 18
Period. The 2020 Protocol includes: 19
• The allocation and assignment policies, procedures, and methods to be used during 20
the Interim Period (i.e., January 1, 2020 through December 31, 2023, as specified 21
1 Capitalized terms in the 2020 Protocol are defined herein, in Appendix A, or in Appendix C. 2 For purposes of this Agreement, use of the terms assign, assignment, and assigned generally refer to the generation, capacity, benefits, and risks associated with certain assets and use of the terms allocate, allocated, allocation
generally refer to the treatment of costs associated with certain assets.
in Section 2). The 2020 Protocol describes the way all components of PacifiCorp’s 22
regulated service, including costs, revenues, and benefits associated with 23
generation, transmission, distribution, and wholesale transactions, should be 24
allocated and assigned among the six States during the Interim Period. During the 25
Interim Period, these inter-jurisdictional allocation policies, procedures, or 26
methods, if applied by each State as stated herein for rate proceedings filed during 27
the Interim Period, can provide PacifiCorp a reasonable opportunity to recover its 28
prudently incurred cost of service. 29
• An agreement on certain issues that are intended to be implemented during the 30
Interim Period and, assuming final resolution of all outstanding issues, incorporated 31
into a Post-Interim Period Method agreement ("Implemented Issues"). 32
• A conditional agreement on certain issues intended to be implemented following 33
the Interim Period, subject to final resolution of all outstanding issues ("Resolved 34
Issues"). 35
• A process and timeframe to address and attempt to resolve all outstanding issues 36
that the Parties intend to resolve after this 2020 Protocol has been filed with the 37
Commissions and during the Interim Period ("Framework"), including the 38
implementation or resolution of issues associated with a Nodal Pricing Model, 39
Resource planning and new Resource Assignment, Limited Realignment, Special 40
Contracts, post-Interim Period capital additions on coal-fueled Interim Period 41
Resources and other items ("Framework Issues"). The future resolution of 42
Framework Issues, combined with the Implemented Issues and the Resolved Issues, 43
would result in a new allocation methodology for PacifiCorp's six States ("Post-44
Interim Period Method"). 45
The proposed allocation of a particular expense or investment to a State under the 2020 46
Protocol is not intended to and will not prejudge the prudence of that cost or the extent to which 47
any particular cost may be reflected in rates. Nothing in the 2020 Protocol is intended to abrogate 48
any Commission’s right or obligation to: (1) determine fair, just, and reasonable rates based upon 49
applicable laws and the record established in rate proceedings conducted by that Commission; (2) 50
consider the effect of changes in laws, regulations, or circumstances on inter-jurisdictional 51
allocation policies and procedures when determining fair, just, and reasonable rates; or (3) establish 52
different allocation policies and procedures for purposes of allocating costs and revenues within 53
that State to different customers or customer classes. 54
Parties support the 2020 Protocol, but their support will not, in any manner, affect or negate 55
their right to address changed or unforeseen circumstances, including changes in laws or 56
regulations. A Party’s support of the 2020 Protocol will not bind or be used against that Party if a 57
Party concludes that the 2020 Protocol no longer produces results that are just, reasonable, or in 58
the public interest, or does not provide the Company with a reasonable opportunity to recover its 59
prudently incurred cost of service; provided, however, that in raising an objection to the 2020 60
Protocol the Parties agree to first raise any such objection by following the provisions of Section 61
8.4. 62
Support of the 2020 Protocol does not constitute an acknowledgment by any Party of the 63
validity or invalidity of any particular method, theory, or principle of regulation, cost recovery, 64
cost of service, or rate design. No Party will be deemed to have agreed that any particular method, 65
theory, or principle of regulation, Resource acquisition or Reassignment, cost recovery, cost of 66
service, or rate design employed in or implied by the 2020 Protocol is appropriate for resolving 67
any issues other than the inter-jurisdictional allocation of PacifiCorp’s cost of service. The Parties 68
have made no effort to address or consider intra-state cost allocation issues and agree that using 69
the 2020 Protocol for inter-jurisdictional cost allocation purposes does not suggest or require 70
similar treatment be applied to intra-state cost allocations for class cost-of-service purposes for 71
any State. Parties may propose such methods of intra-state class cost-of-service allocations as they 72
deem appropriate. 73
The 2020 Protocol includes the following appendices described briefly below: 74
• Terms that are capitalized in the 2020 Protocol are defined herein, in Appendix A, 75
or in Appendix C. 76
• Appendix B includes tables identifying the allocation factor to be applied to each 77
component of PacifiCorp’s revenue requirement calculation. 78
• Appendix C includes the definition and algebraic derivation of each allocation 79
factor, along with the FERC accounts to which the allocation factor will be applied. 80
• Appendix D is a Memorandum of Understanding among the Parties supporting the 81
Company's acquisition and implementation of a Nodal Pricing Model. 82
• Appendix E includes a table reflecting Commission-approved depreciable lives in 83
effect October 1, 2019, and the Company’s proposed depreciable lives for coal-84
fueled Interim Period Resources in pending depreciation dockets as filed in 85
September 2018. 86
• Appendix F is the Washington Inter-Jurisdictional Allocation Methodology 87
Memorandum of Understanding between the Company and the Washington Parties, 88
which modifies the WCA. 89
• Appendix G includes a description and numeric example of how Special Contracts 90
and related issues will be treated during the Interim Period. 91
2. Timeframes and Effective Periods 92
2.1. Effective Period of the 2020 Protocol 93
For the Interim Period, January 1, 2020 through December 31, 2023, subject to Section 94
2.2.4, the Parties agree to support before their respective Commissions the use of the 2020 Protocol 95
in PacifiCorp regulatory proceedings or filings, subject to exceptions for deferred amounts 96
including, but not limited to, Net Power Costs as set forth in this Agreement. The 2020 Protocol 97
includes an agreed-upon approach for cost allocations to each State that will be used by PacifiCorp 98
in proceedings or filings commenced during the Interim Period, except as provided in Section 99
2.2.5. 100
2.2. Post-Interim Period 101
2.2.1. Commission Approvals for Post-Interim Period Method Obtained 102
Prior to December 31, 2023 103
If each State’s Commission approves a Post-Interim Period Method agreement on or before 104
December 31, 2023, or in the first general rate case after the Post-Interim Period Method agreement 105
is reached,3 the Interim Period will terminate on December 31, 2023, and the Post-Interim Period 106
Method will take effect, subject to Section 2.2.2. 107
2.2.2. Commission Approval Not Granted 108
If any Commission denies PacifiCorp’s request for approval of the Post-Interim Period 109
Method agreement, PacifiCorp will propose an alternative allocation method for the Post-Interim 110
Period for consideration by all the Commissions. Parties are free to take any position regarding 111
3 The Parties understand the California and Washington Commissions will likely consider the Post-Interim Period Method in the first general rate case filed in either State after an agreement has been reached on the Post-Interim
Period Method, and approval may occur after December 31, 2023.
PacifiCorp’s proposal, including proposing alternative allocation methodologies, filing a 112
complaint, or requesting an investigation of PacifiCorp’s proposal. 113
2.2.3. Post-Interim Period Method Agreement Not Reached 114
If the Company determines that it is unlikely that a Post-Interim Period Method agreement 115
will be reached before the end of the Interim Period, then the Company will propose an allocation 116
method for the Post-Interim Period for consideration by the Commissions. Parties are free to take 117
any position regarding PacifiCorp’s proposal, including proposing alternative allocation 118
methodologies, or initiating a complaint or investigation of PacifiCorp’s proposal. 119
2.2.4. Early Commission Approvals of Post-Interim Period Method 120
If a Post-Interim Period Method agreement is reached on or before December 31, 2022, 121
any Post-Interim Period Method agreement will address whether and the degree to which the 122
Company will use the Post-Interim Period Method in regulatory proceedings or filings commenced 123
after December 31, 2022. 124
2.2.5. Regulatory Filings to Implement Post-Interim Period Method 125
Any Post-Interim Period Method agreement will address whether and the degree to which 126
the Company may use the Post-Interim Period Method in regulatory proceedings or filings 127
commenced during the Interim Period while Commission approvals of the Post-Interim Period 128
Method agreement are pending but to be effective after the end of the Interim Period. 129
3. Interim Period Allocation Method 130
The 2017 Protocol expires December 31, 2019.4 The Parties representing interests in the 131
States of California, Idaho, Oregon, Utah, and Wyoming (collectively referred to as the “Five State 132
Parties” and the "Five States") agree that the methodology outlined in the 2017 Protocol being 133
4 As proposed in PacifiCorp's 2019 California general rate case filing, the 2017 Protocol does not expire in
California on December 31, 2019.
used by the Company in 2019 should continue, as outlined and modified in Section 3, during the 134
Interim Period while the Parties continue to negotiate the Framework Issues necessary to develop 135
the Post-Interim Period Method. The Washington Parties agree that the methodology outlined in 136
the WCA being used in 2019 should, subject to the terms included in Appendix F, continue during 137
the Interim Period while the Parties continue to negotiate the Framework Issues necessary to 138
develop the Post-Interim Period Method. 139
For the Five States, the terms of the 2017 Protocol that will be used during the Interim 140
Period under the 2020 Protocol are provided in Section 3.1. The 2017 Protocol terms that are 141
being modified by this Agreement are provided in Section 3.2. 142
3.1. Continuing Terms of the 2017 Protocol for the Five States Interim 143 Period Allocation Methodology5 144
Items included in the Company's results of operations will be allocated on the factors set 145
forth below. The FERC account and allocation factor combinations are included in Appendix B. 146
The algebraic derivation and factor definitions are included in Appendix C. 147
3.1.1. Classification of Interim Period Resources 148
All Fixed Costs of Interim Period Resources will be classified as 75 percent Demand-149
Related and 25 percent Energy-Related. All Non-Firm Purchases and Sales will be classified as 150
100 percent Energy-Related. 151
3.1.2. Allocation of Interim Period Resource Costs and Wholesale Revenues 152
Interim Period Resources will be allocated to one of two categories for inter-jurisdictional 153
allocation purposes: State Resources or System Resources. A complete description of allocation 154
factors to be used is set forth in Appendix B. 155
5 Terminology in Section 3.1 has been modified from the language in the 2017 Protocol to maintain consistency in
the use of terms within the 2020 Protocol.
There are three types of State Resources. The remaining types of Interim Period Resources 156
are System Resources, which constitute the substantial majority of PacifiCorp’s Resources. 157
Benefits and costs associated with each category and type of Interim Period Resource will be 158
assigned or allocated to States on the following basis. 159
3.1.2.1. Interim Period State Resources 160
Benefits and costs associated with the three types of State Resources will be assigned or 161
allocated as follows: 162
• Demand-Side Management (“DSM”) Programs: Costs associated with DSM 163
Programs, including Class 1 DSM Programs, will be allocated on a situs basis to 164
the State in which the investment is made. Benefits from these programs, in the 165
form of reduced consumption and contribution to Coincident Peak, will be reflected 166
in the Load-Based Dynamic Allocation Factors. 167
• Portfolio Standards: The portion of costs associated with Interim Period Resources 168
acquired to comply with a State’s Portfolio Standard adopted, either through 169
legislative enactment or by a State’s Commission, that exceed the costs PacifiCorp 170
would have otherwise incurred, will be allocated on a situs basis to the Jurisdiction 171
adopting the Portfolio Standard. 172
• State-Specific Initiatives: Costs and benefits associated with Interim Period 173
Resources acquired in accordance with a State-specific initiative will be allocated 174
and assigned on a situs basis to the State adopting the initiative. State-specific 175
initiatives include, but are not limited to, the costs and benefits of incentive 176
programs, net-metering tariffs, feed-in tariffs, capacity standard programs, solar 177
subscription programs, electric vehicle programs, and the acquisition of renewable 178
energy certificates. 179
3.1.2.2. Interim Period System Resources 180
All Interim Period Resources that are not State Resources are System Resources and will 181
be allocated as follows: 182
• Generally, all Fixed Costs associated with System Resources and all costs incurred 183
under Wholesale Contracts will be allocated based upon the System Generation 184
(“SG”) Factor. 185
• Generally, all Variable Costs associated with System Resources will be allocated 186
based upon the System Energy (“SE”) Factor. 187
• Revenues received by PacifiCorp under Wholesale Contracts will be allocated 188
based upon the SG Factor. 189
3.1.3. Re-functionalization and Allocation of Transmission Costs and 190
Revenues 191
Before filing any request to approve a reclassification of facilities as transmission or 192
distribution with FERC, PacifiCorp will submit filings seeking review and authorization of any 193
such reclassification with the Commissions. The cost responsibility for any assets reclassified 194
under FERC policy will be assigned or allocated consistent with other assets in the relevant 195
function. 196
Costs associated with transmission assets, and firm wheeling expenses and revenues, will 197
be classified as 75 percent Demand-Related, 25 percent Energy-Related, and allocated based upon 198
the SG Factor. Non-firm wheeling expenses and revenues will be allocated based upon the SE 199
Factor. In the event that PacifiCorp joins a regional independent system operator, the allocation 200
of transmission costs and revenues may be reevaluated and revised as provided for in Section 8.4. 201
3.1.4. Allocation of Distribution Costs 202
All distribution-related expenses and investment that can be directly allocated will be 203
directly allocated to the State where they are located. Those costs that cannot be directly allocated 204
will be allocated consistent with the factors set forth in Appendix B. 205
3.1.5. Allocation of Administrative and General Costs 206
Administrative and General Costs, General Plant costs, and Intangible Plant costs will be 207
allocated consistent with the factors set forth in Appendix B. 208
3.1.6. Allocation of Special Contracts 209
Revenues associated with Special Contracts will be included in State revenues, and loads 210
of Special Contract customers will be included in Load-Based Dynamic Allocation Factors as 211
appropriate (see Appendix G). Special Contracts may or may not include Customer Ancillary 212
Service Contract attributes. Load curtailments and buy-through arrangements will be handled as 213
appropriate (see Appendix G). 214
3.1.7 Miscellaneous Costs and Taxes 215
Miscellaneous costs described below will be allocated as follows: 216
• Generation-related dispatch costs and associated plant will be allocated on the SG 217
Factor. 218
• Miscellaneous regulatory assets and liabilities, and miscellaneous deferred debits 219
will be allocated with the appropriate allocation factor depending on the related 220
assets or underlying costs. 221
Taxes and fees will be allocated as follows: 222
• Income taxes will be calculated using the federal tax rate and PacifiCorp’s 223
combined State effective tax rate. State-specific Schedule M and deferred income 224
tax amounts will be allocated using the Company’s tax software system. Consistent 225
with prior system allocation methods, the Washington Public Utility Tax is 226
allocated using the SO Factor in lieu of a Washington income tax. 227
• Franchise taxes, revenue related taxes, Commission assessments and fees, and 228
usage related taxes are situs or a pass through. 229
• Property taxes are system allocated based on gross plant and allocated on a Gross 230
Plant System ("GPS") Factor. 231
• Generation and fuel-related taxes will be allocated using the SG Factor. 232
• Other taxes such as payroll taxes are embedded in expenses or capital costs. 233
Balances associated with the Trojan Decommissioning will be allocated using the Trojan 234
Decommissioning ("TROJD") Factor. This will not impact State-specific treatment of this item. 235
3.1.8. State Programs Regarding Access to Alternative Electricity Suppliers 236
3.1.8.1. Treatment of Oregon Direct Access Programs 237
This Section describes treatment of loads lost to Oregon Direct Access Programs during 238
the term of the 2020 Protocol. 239
3.1.8.1.1. Customers Electing PacifiCorp’s One- and 240 Three-Year Oregon Direct Access Programs 241
Customer loads electing to be served on PacifiCorp’s one- and three-year Oregon Direct 242
Access Programs will be included in the Load-Based Dynamic Allocation Factors for all Interim 243
Period Resources, and the transition cost payments from these customers will be situs assigned 244
and allocated to Oregon. 245
3.1.8.1.2. Customers Electing PacifiCorp’s Five Year Opt-246 Out Program Under the Oregon Direct Access 247
Program 248
The treatment will be consistent with Order No. 15-060, as clarified through Order No. 15-249
067, of the Oregon Public Utility Commission in Docket UE 267, and Oregon Schedule 296, which 250
allow Oregon Direct Access Consumers to permanently opt-out of cost-of-service rates after 251
payment of ten years of transition costs in Oregon. If an Oregon Direct Access Consumer is paying 252
transition costs during the Interim Period, the Oregon Direct Access Consumer’s load(s) will be 253
included in Load-Based Dynamic Allocation Factors, and the transition cost payments from these 254
consumers will be situs-assigned to Oregon. If any Oregon Direct Access Consumer reaches the 255
end of the 10-year period covered by the transition cost payments during the Interim Period, the 256
load(s) for that Oregon Direct Access Consumer will be excluded from Load-Based Dynamic 257
Allocation Factors. Thereafter, if an Oregon Direct Access Consumer elects to return to Oregon 258
cost-of-service rates by providing four-years notice under Schedule 296, its load will be treated as 259
new load and incorporated in PacifiCorp’s Resource planning process. 260
3.1.8.1.3. New Laws or Regulations 261
To the extent Oregon adopts new laws or regulations regarding Oregon Direct Access 262
Programs, Oregon’s treatment of loads lost to Oregon Direct Access Programs may be re-263
determined in a manner consistent with the new laws and regulations. In the event Oregon adopts 264
such new laws or regulations, the Company will inform the Commissions and the Parties of the 265
same. 266
3.1.8.2. Utah Eligible Customer Program 267
If, pursuant to Utah Code Annotated Section 54-3-32, an eligible customer in Utah transfers 268
service to a non-utility energy supplier, the Public Service Commission of Utah will make 269
determinations under Utah law as contemplated therein. The Company will inform the 270
Commissions and the Parties of the Public Service Commission of Utah’s determinations. 271
3.1.8.3. Other State Actions 272
In the event any State adopts laws or regulations governing customer access to alternative 273
electricity suppliers, the Company will inform the Commissions and the Parties of the same. 274
3.1.9. Loss or Increase in Load 275
Any loss or increase in retail load occurring as a result of condemnation or 276
municipalization, sale or acquisition of new service territory that involves less than five percent of 277
system load, realignment of service territories, changes in economic conditions, or gain or loss of 278
large customers will be reflected in changes in the Load-Based Dynamic Allocation Factors. The 279
allocation or assignment of costs and benefits arising from merger, sale, or acquisition transaction 280
proposed by the Company involving more than five percent of system load will be considered on 281
a case-by-case basis in the course of Commission approval proceedings. 282
3.1.10. Commission Regulation of Interim Period Resources 283
PacifiCorp will plan and acquire new Interim Period Resources on a system-wide risk-284
adjusted, least-cost basis. Prudently incurred investments in Interim Period Resources will be 285
reflected in rates consistent with the laws and regulations in each State, as approved by individual 286
Commissions. 287
3.2. Modifications to the 2017 Protocol During the Interim Period 288
3.2.1. Net Power Costs Filings 289
For Net Power Costs (“NPC”) filings, Parties agree to support use of the allocation 290
methodology in place when the NPC were or will be incurred, to align the timing of the actual 291
costs incurred with the applicable allocation method for cost recovery for that period. The table 292
below summarizes the transition from the 2017 Protocol to the 2020 Protocol for NPC filings. If 293
a Post-Interim Period Method agreement is reached between the Parties, a similar table will be 294
included to summarize the transition for NPC filings from the 2020 Protocol to the subsequent 295
agreement. 296
Allocation Methodology Used for NPC Filings
Filing 2017 Protocol 2020 Protocol Notes
California ECAC 2021 ECAC for the 2022 ECAC for the
California ECAC 2020 ECAC for the 2021 ECAC for the
2020 TAM for the CY2019 2021 TAM for the CY2020
2020 PCAM for the 2021 PCAM for the
2020 EBA for the CY2019 2021 EBA for the CY2020
2020 ECAM for the 2021 ECAM for the
Net Power Costs included in General Rate Cases GRC with rate effective date on or after January 1,
general rate case. The dates included in the table are subject to change based on the California general
2. Washington will use the modified WCA allocation methodology per Appendix F of the 2020
3.3.2. Embedded Cost Differential (“ECD”) and Equalization Adjustment 297
3.3.2.1. ECD 298
The Fixed ECD will continue for Idaho through the end of the Interim Period. The 299
Dynamic ECD for Oregon will continue through the end of the Interim Period, capped at 300
$11,000,000. No ECD adjustment exists for Utah or California. 301
The Wyoming ECD will terminate December 31, 2020. Beginning January 1, 2021, for 302
purposes of the Wyoming energy cost adjustment mechanism (“ECAM”), actual ECD will be zero 303
and the true-up of the Wyoming ECD will not be subject to sharing bands in the Wyoming ECAM. 304
This treatment will continue until the ECD is removed from base rates. 305
3.3.2.2. Equalization Adjustment 306
The Equalization Adjustment addressed in Section XIV of the 2017 Protocol will terminate 307
on December 31, 2019, and no additional Equalization Adjustment amounts will be deferred after 308
that date. The method PacifiCorp will use to collect deferred Equalization Adjustment balances 309
and any related carrying charges has been or will be addressed in appropriate State regulatory 310
proceedings. 311
3.3.3. Costs and Benefits of Qualifying Facilities 312
Costs and benefits of Qualifying Facilities will be treated consistent with the provisions 313
specified in Section 4.4. 314
3.3.4. Allocation of Gain or Loss from Sale of Assets 315
The allocation of any gain or loss from the Company’s sale of assets will be treated 316
consistent with the provisions specified in Section 7. 317
3.3.5. Interpretation and Governance 318
This Agreement will be interpreted and PacifiCorp’s Multi-State Process ("MSP") will be 319
governed by the provisions specified in Section 8. 320
4. Implemented Issues 321
The Parties agree that the following items, described later in this Section 4, will be 322
implemented and effective during the Interim Period: 323
• The process and timing for States' decisions to exit coal-fueled Interim Period 324
Resources; 325
• The process for potential Reassignment of coal-fueled Interim Period Resources 326
among States without Exit Orders; 327
• The process for the allocation of Decommissioning Costs; and 328
• The allocation and assignment of Qualifying Facility Power Purchase Agreements 329
("QF PPAs"). 330
These issues are more thoroughly explained below. 331
4.1. States' Decisions to Exit Coal-Fueled Interim Period Resources 332
PacifiCorp will continue to conduct operational and economic analyses in accordance with 333
applicable regulatory requirements and good utility practice to maintain reliable service on a risk-334
adjusted, least-cost basis for its customers. PacifiCorp anticipates continuing to conduct integrated 335
resource planning, at least biennially. PacifiCorp also anticipates continuing to undertake 336
depreciation studies on a five-year cycle. If these analyses affect the depreciable lives or 337
operational lives of Interim Period Resources in the future, Parties may address such effects 338
through appropriate regulatory proceedings before the Commissions. Nothing in this Agreement 339
affects PacifiCorp’s rights and obligations to make prudent decisions regarding operation of its 340
assets and system in accordance with applicable law. The Parties further agree that PacifiCorp’s 341
coal-fueled Interim Period Resource Closure dates may be informed by new information that 342
becomes available as a result of other regulatory filings or actions, including integrated resource 343
plans or State and federal energy policies. Nothing in this Agreement affects or limits any Party’s 344
ability to raise any prudence issues with regards to PacifiCorp’s decisions regarding Closure of an 345
Interim Period Resource. 346
Subject to the possible effects of Limited Realignment, the Parties agree to the following 347
procedures for the Company's coal-fueled Interim Period Resources. 348
4.1.1. Allocation of Costs at Closure 349
Upon Closure of a coal-fueled Interim Period Resource, each State that is receiving benefits 350
and is allocated costs associated with the coal-fueled Interim Period Resource at the time of 351
Closure shall continue to be allocated its share of the remaining costs of the coal-fueled Interim 352
Period Resource in accordance with this 2020 Protocol, which may include the remaining net book 353
value and Commission-approved Decommissioning Costs. The existence of an Exit Order does 354
not change this allocation, and all States assigned benefits and allocated costs from the coal-fueled 355
Interim Period Resource at the time of Closure will be allocated actual costs. Therefore, if every 356
State is being assigned benefits and allocated costs from a coal-fueled Interim Period Resource at 357
the time of Closure, every State will be allocated, in accordance with the method set forth in this 358
Agreement, all the actual costs associated with that coal-fueled Interim Period Resource and its 359
Closure. This can occur, for example, if every State (excepting Washington as discussed in Section 360
4.1.4) issues an Exit Order with the same Exit Date for a particular coal-fueled Interim Period 361
Resource. This can also occur, for example, if PacifiCorp pursues Closure of a coal-fueled Interim 362
Period Resource prior to a State Exit Date. No Party, by virtue of this Agreement, waives its right 363
to investigate and analyze whether the Company’s decision to continue operation or continue an 364
ownership interest is prudent, regardless of the anticipated Closure dates in the tables in Section 365
4.1.3. 366
4.1.2 Exit Orders 367
The Parties, representing diverse and varied interests, have worked in good faith to create 368
a process that allows for States to pursue differing resource portfolios in the future, including 369
decisions to transition out of coal-fueled Interim Period Resources while mitigating resulting 370
effects to the Company and other States. A Commission may issue an Exit Order specifying an 371
Exit Date in a proceeding for approval of this Agreement, a depreciation docket, a rate case, or any 372
other appropriate proceeding.6 A Commission Order or other determination that a coal-fueled 373
Interim Period Resource will reach the end of its depreciable life without a specific determination 374
6 An Exit Order is not required from a Commission if a coal-fueled Interim Period Resource is not included in
PacifiCorp’s rates in that State.
that the State will exit the Interim Period Resource shall not constitute an Exit Order. Provided 375
PacifiCorp secures all applicable approvals, a Company decision to close a coal-fueled Interim 376
Period Resource earlier than previously anticipated does not require the issuance of an Exit Order. 377
An Exit Order does not, by itself, result in Reassignment of shares of a coal-fueled Interim Period 378
Resource to other States or affect an Exiting State’s responsibility for its share of the then-379
remaining net book value of the Interim Period Resource that is being exited. 380
To provide the Company and States without Exit Orders time to consider the options and 381
address the potential Reassignment of the coal-fueled Interim Period Resource, as set forth in 382
Section 4.2, under this Agreement an Exit Order should provide at least four-years of notice7 from 383
the date of the Exit Order to the Exit Date. After an Exit Date, the Exiting State will no longer be 384
allocated any new costs8 and will no longer be assigned any benefits associated with that coal-385
fueled Interim Period Resource, and no other State will be allocated the Exiting State’s share of 386
costs nor receive the Exiting State’s assigned benefits associated with that coal-fueled Interim 387
Period Resource, unless the costs and benefits are accepted through a Commission Order on 388
Reassignment. Until the Exit Date, an Exiting State shall continue to be assigned the benefits of 389
that coal-fueled Interim Period Resource and shall be allocated costs associated with that coal-390
fueled Interim Period Resource in accordance with this 2020 Protocol or as determined through 391
the Framework process, which may include costs associated with any remaining net book value, 392
prudently incurred capital additions, prudently incurred Operations and Maintenance ("O&M") 393
expense, and prudently incurred or reasonably estimated Decommissioning Costs. 394
7 Subject to the provisions in Sections 4.1.3 and 4.1.4. 8 New costs are costs incurred after the Exit Date to maintain or operate the coal-fueled Interim Period Resource beyond that date. Any costs associated with the operation of a coal-fueled Interim Period Resource and incurred prior to the Exit Date that are allocated to the Exiting State as determined through the 2020 Protocol and that have
not yet been collected from customers in that State are still that State's responsibility.
An Exit Order establishes the Exit Date that PacifiCorp will use to propose the allocation 395
of Decommissioning Costs, allocation of capital additions costs, and any other associated costs 396
related to the exit from a coal-fueled Interim Period Resource as outlined in the 2020 Protocol. 397
PacifiCorp will timely propose to Parties from an Exiting State a method to address the treatment 398
of these costs for ratemaking, such that costs and benefits remain matched in customer rates. 399
Following receipt of an Exit Order, the Company will file in accordance with Section 4.2 400
to allow States without Exit Orders the opportunity to evaluate the potential Reassignment of the 401
coal-fueled Interim Period Resource. For regulatory efficiency, Section 4.1.3 establishes 402
timeframes for addressing Exit Orders from coal-fueled Interim Period Resources by Oregon and 403
the potential Reassignment of those resources to other States. 404
4.1.3 Oregon Exit Dates 405
The Oregon Parties and the Company agree to recommend that the dates shown in the 406
tables in this Section 4.1.3 be used in Oregon for service and depreciable lives, and for establishing 407
Oregon's Exit Dates for all coal-fueled Interim Period Resources. 408
4.1.3.1 Coal-Fueled Interim Period Resources Not Operated by 409 PacifiCorp Subject to Common Closure Dates, Oregon 410 Exit 2023-2027 411
PacifiCorp anticipates that Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, and 412
Colstrip Unit 4 will have common Closure dates for all States. If PacifiCorp effectuates Closure 413
at Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, or Colstrip Unit 4 on or before the 414
applicable dates identified in the table below, each State will be allocated its share of the costs and 415
benefits of that coal-fueled Interim Period Resource with no transfer of cost responsibility or 416
decommissioning liability among States, in accordance with Section 4.1.1. 417
PacifiCorp and the Oregon Parties agree to recommend to the Oregon Commission that the 418
dates shown in the table below be used for establishing Oregon's Exit Dates and Oregon 419
depreciable lives for Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, and Colstrip Unit 420
4. 421
Coal-Fueled Interim Period Resource Name Anticipated Closure Date
Cholla Unit 4 January 1, 2023
Craig Unit 1 December 31, 2025
Craig Unit 2 December 31, 2026
Colstrip Unit 3 December 31, 2027
Colstrip Unit 4 December 31, 2027
PacifiCorp and the Oregon Parties agree that PacifiCorp will make best efforts to effectuate 422
Closure of the units identified above by the anticipated Closure dates, but the Company may need 423
additional time for Closure of Craig Units 1 and 2 and Colstrip Units 3 and 4 due to its joint-owner 424
agreements, and Cholla Unit 4 due to other contractual requirements. 425
If PacifiCorp has received an Exit Order from Oregon for Craig Unit 1, Craig Unit 2, 426
Colstrip Unit 3, or Colstrip Unit 4 with the same Exit Date as the date set forth in the table above 427
and PacifiCorp does not effectuate Closure by such date, Oregon may elect, at its option, to: 428
• Continue to take an allocation and assignment of the costs and benefits of such unit 429
for one additional year following the specified Exit Date; or 430
• Discontinue taking an allocation and assignment of the costs and benefits of such 431
unit as of the specified Exit Date. 432
Under either election, Oregon will continue to be subject to an allocation of actual 433
Decommissioning Costs if Closure of the unit is effectuated within such one-year period. If 434
Closure of the unit is not effectuated within such one-year period, Oregon will be allocated 435
Decommissioning Costs based on the estimates established pursuant to Section 4.3. 436
Oregon will be allocated actual Decommissioning Costs if Closure of Cholla Unit 4 occurs 437
on or before January 1, 2023. If Cholla Unit 4 operates beyond January 1, 2023, Oregon will be 438
allocated only estimated Decommissioning Costs as of January 1, 2023. 439
4.1.3.2. Coal-Fueled Interim Period Resources Operated by 440 PacifiCorp, Oregon Exit Through 2027 441
The Oregon Parties and the Company agree to recommend to the Oregon Commission that 442
the Exit Date for each coal-fueled Interim Period Resource shown in the following table should be 443
used in Oregon for establishing Oregon's Exit Dates and Oregon depreciable lives for these coal-444
fueled Interim Period Resources, subject to the other provisions of this Section 4.1. 445
Coal-Fueled Interim Period Resource Recommended Oregon Exit Date
Jim Bridger 1 December 31, 2023
Jim Bridger 2 December 31, 2025
Jim Bridger 3 December 31, 2025
Jim Bridger 4 December 31, 2025
Naughton 1 December 31, 2025
Naughton 2 December 31, 2025
Dave Johnston 1 December 31, 2027
Dave Johnston 2 December 31, 2027
Dave Johnston 3 December 31, 2027
Dave Johnston 4 December 31, 2027
Oregon Parties and the Company will strive to have Exit Orders issued on or before 446
December 15, 2020, for the coal-fueled Interim Period Resources reflected in the table above to 447
allow the Company to make filings in the other States in accordance with Section 4.2. If 448
PacifiCorp effectuates Closure for any of the units no later than the dates in the table above, then 449
the provisions of 4.1.1 will apply. 450
4.1.3.3. Coal-Fueled Interim Period Resources, Oregon Exit 451 Date 2028 - 2029 452
The Oregon Parties and the Company agree that the recommended Exit Dates for the coal-453
fueled Interim Period Resources shown in the following table should be used in Oregon for 454
establishing Oregon's Exit Dates and Oregon depreciable lives for these coal-fueled Interim Period 455
Resources for purposes of this Agreement, subject to the other provisions of this Section 4.1. 456
Coal-Fueled Interim Period Resource Name Recommended Oregon Exit Date
Hunter 1 December 31, 2029
Hunter 2 December 31, 2029
Hunter 3 December 31, 2029
Huntington 1 December 31, 2029
Huntington 2 December 31, 2029
Wyodak December 31, 2029
Oregon Parties and the Company will strive to have Exit Orders issued by the Oregon 457
Commission issued by December 31, 2023, for the coal-fueled Interim Period Resources reflected 458
in the table above to allow the Company to make the necessary filings in other States in accordance 459
with Section 4.2. If PacifiCorp effectuates Closure for any of the units no later than the dates in 460
the table above, then the provisions of 4.1.1 will apply. 461
4.1.4. Washington Exit Orders 462
The Washington Clean Energy Transformation Act ("CETA") requires coal-fueled Interim 463
Period Resources to be out of Washington rates by December 31, 2025. Section 6.4 of the 464
Framework Issues addressing Limited Realignment is intended to facilitate the removal of coal-465
fueled Interim Period Resources from Washington rates and address the Washington-allocated 466
share, per the System Generation-Fixed (“SGF”) Factor, as defined in Appendix C, of all coal-467
fueled Interim Period Resources whether or not those resources are included in Washington rates. 468
Washington Commission approval of the 2020 Protocol will constitute an Exit Order for 469
Washington, unless modified by Reassignment or Limited Realignment, with an Exit Date of 470
December 31, 2023, for Jim Bridger Unit 1, and December 31, 2025, for Jim Bridger Units 2-4 471
and Colstrip Unit 4. PacifiCorp and the Washington Parties agree that an Exit Order is not required 472
from the Washington Utilities and Transportation Commission for any coal-fueled Interim Period 473
Resources not currently in Washington rates, and PacifiCorp can evaluate seeking Reassignment 474
upon approval of the 2020 Protocol by the Washington Commission. 475
4.1.5. Establishment of Exit Dates for Hayden Units 1 and 2 476
On or before February 1, 2021, the Company will make State-specific recommendations 477
to Commissions for the treatment of Hayden Units 1 and 2. If PacifiCorp effectuates Closure for 478
Hayden Units 1 and 2, then the provisions of 4.1.1 will apply, subject to applicable legal 479
requirements. 480
4.2. Reassignment of Coal-Fueled Interim Period Resources 481
4.2.1 Company Proposals for Reassignment 482
After receipt of any Exit Order, PacifiCorp shall analyze whether it is reasonable to 483
continue to operate the affected coal-fueled Interim Period Resource for customers in one or more 484
of the States without Exit Orders. PacifiCorp may propose Reassignment of a greater share of the 485
coal-fueled Interim Period Resource to such State(s) to match State load and resource balance, or 486
request issuance of an Exit Order.9 PacifiCorp shall provide its analysis to Parties in each 487
applicable State and may make a filing with the Commission in each State that, as yet, has not 488
entered an Exit Order for such coal-fueled Interim Period Resource consistent with the timeframes 489
set forth in Sections 4.1 and this Section. If PacifiCorp seeks Reassignment, the analysis shall be 490
accompanied by recommendations as to an anticipated Closure date if Reassignment is accepted 491
9 Provided PacifiCorp secures all applicable approvals, PacifiCorp may effectuate Closure of a Resource without
requesting issuance of any Exit Order.
for such coal-fueled Interim Period Resource. Recommended Reassignments, if proposed, should 492
include a range of options, including fallback options based on the potential that one Commission 493
may reject PacifiCorp's recommendation while another Commission may accept the primary 494
recommendation. Notwithstanding this Section 4.2.1, realignment of certain Interim Period 495
Resources serving Washington will be determined subject to resolution of the Limited Realignment 496
Framework Issue or Section 4.1.4 as applicable. 497
4.2.2 Process and Timing 498
Consistent with Section 4.1, for those coal-fueled Interim Period Resources, with an Exit 499
Date on or before December 31, 2027, the filings including the Company's analysis and 500
recommendations are targeted to occur by February 1, 2021. For those coal-fueled Interim Period 501
Resources with an Exit Date after December 31, 2027, and on or before December 31, 2029, the 502
filings including the Company's analysis and recommendations are targeted to occur by June 30, 503
2024, for Exit Orders that are received by December 31, 2023. Where possible, PacifiCorp will 504
make such filings concurrently in each State without an Exit Order so that each unit or plant can 505
be analyzed as a whole. To the extent a delay to these targeted filing dates is necessary, the 506
Company will provide notice to the Parties and Commissions explaining the reason and expected 507
filing dates. For coal-fueled Interim Period Resources with Exit Orders with different Exit Dates, 508
the Company will provide its analysis to the States without Exit Orders within six months after the 509
date any Exit Order is issued by any Commission, subject to the provisions of Section 4.1.4 for the 510
Washington Exit Orders. 511
If PacifiCorp makes filings pursuant to this Section in multiple States without Exit Orders, 512
then within 60 days from the date the last Commission issues an order pertaining to such filings, 513
PacifiCorp will submit a supplemental filing with each Commission in the State(s) without Exit 514
Orders summarizing the decisions made by each Commission and PacifiCorp’s recommendations 515
regarding the implications. 516
4.2.3 Effects of Commission Decisions Regarding Assignment 517
If one or more Commissions have entered orders accepting, collectively, one-hundred 518
percent10 of the cost allocation of a coal-fueled Interim Period Resource beyond any Exit Date, the 519
costs and benefits of the coal-fueled Interim Period Resource after such Exit Date shall be 520
Reassigned to the States in accordance with the approved Reassignment as specified in the 521
applicable Commission Orders. Supplemental filings will reflect the final Reassignment of each 522
coal-fueled Interim Period Resource as a result of the Reassignment process and Commission 523
Orders. 524
If two or more Commissions have entered orders requesting, collectively, more than one-525
hundred percent11 of the cost allocation and associated benefits of a coal-fueled Interim Period 526
Resource beyond any Exit Date, the Company will recommend a pro-rata Reassignment up to one 527
hundred percent in accordance with the approved Reassignment as specified in the applicable 528
Commission Orders. Supplemental filings will reflect this pro-rata treatment of each coal-fueled 529
Interim Period Resource as a result of the pro-rata Reassignment process for further review and 530
approval by the Commissions. 531
If Commissions do not agree to accept one-hundred percent cost allocation, collectively, of 532
a coal-fueled Interim Period Resource beyond an Exit Date, as part of its supplemental filings, the 533
Company will provide its recommendations on the treatment of any shortfall in the Reassignment 534
10 Based on PacifiCorp’s ownership interest in the coal-fueled Interim Resource, whether wholly-owned or jointly-owned. 11 Based on PacifiCorp’s ownership interest in the coal-fueled Interim Resource, whether wholly-owned or jointly-
owned.
of a coal-fueled Interim Period Resource or recommendations on capacity reductions through 535
Closures for further Commission consideration. 536
In the event of either common Exit Dates for all States or Closure as a result of the 537
Reassignment process or other appropriate regulatory proceedings, the provisions of Section 4.1.1 538
will apply. 539
4.3. Decommissioning Costs 540
4.3.1. Process for Determining Decommissioning Cost Allocation 541
4.3.1.1. Decommissioning Studies 542
The Company intends to undertake a contractor-assisted engineering study of 543
decommissioning costs and to make best efforts to complete the study by January 15, 2020, to 544
estimate appropriate Decommissioning Cost reserve requirements for the Jim Bridger, Dave 545
Johnston, Hunter, Huntington, Naughton, Wyodak, and Hayden coal-fueled Interim Period 546
Resources. Colstrip will also be included in the contractor-assisted engineering study of 547
decommissioning costs, and the Company will make best efforts to complete that portion of the 548
study by March 15, 2020. The Company will provide the information from the study to the States 549
as a supplemental filing in all applicable depreciation dockets. The study results will be used to 550
inform the Company’s recommendation on the amount of Decommissioning Cost responsibility 551
to be allocated to States for coal-fueled Interim Period Resources that States exit at different times. 552
The Company will retain and make available the Decommissioning Studies in future regulatory 553
proceedings. 554
4.3.1.2. Decommissioning Studies Update 555
The Company intends to undertake the same process to complete an update to the 556
Decommissioning Studies by no later than June 30, 2024, to estimate appropriate 557
Decommissioning Cost reserve requirements for the Craig, Hunter, Huntington, and Wyodak coal-558
fueled Interim Period Resources (collectively with the studies discussed in the paragraph above 559
constituting the Decommissioning Studies), which will be incorporated into a Company-sponsored 560
depreciation study. The Company will retain and make available the Decommissioning Studies 561
update in future regulatory proceedings. 562
4.3.1.3. Commission Determination of Decommissioning Costs 563
No Party will be bound by the Decommissioning Cost estimates in the Decommissioning 564
Studies undertaken pursuant to Paragraphs 4.3.1.1 and 4.3.1.2, and final determination of each 565
State’s just and reasonable Decommissioning Cost allocation for each coal-fueled Interim Period 566
Resource will remain exclusively with each Commission and will be determined in the 567
depreciation dockets in which the Decommissioning Costs are included.12 568
4.3.1.4. Decommissioning Costs Allocation 569
For coal-fueled Interim Period Resources having a common operating life across all States, 570
each State shall be allocated its share of actual Decommissioning Costs based on either an SG 571
Factor (if closed during the Interim Period) or an Assigned Production ("AP") Factor, adjusted for 572
any Reassignment or Limited Realignment effects (if closed after the Interim Period). For coal-573
fueled Interim Period Resources that do not have a common operating life across all States, each 574
Exiting State shall be allocated, using either an SG Factor (if closed during the Interim Period) or 575
an AP Factor, adjusted for any Reassignment or Limited Realignment effects (if closed after the 576
Interim Period), that State’s share of estimated Decommissioning Costs based on the 577
Decommissioning Studies described in Sections 4.3.1.1 and 4.3.1.2. If the Decommissioning 578
Costs ordered to be included in the reserve balance established for an Exiting State are less than 579
the estimated Decommissioning Costs allocated to that Exiting State as specified above, such 580
12 For California, Decommissioning Costs will be addressed in PacifiCorp’s next general rate case.
difference shall not be allocated to any other State under any circumstance. If PacifiCorp 581
effectuates Closure of a coal-fueled Interim Period Resource after one or more States have exited 582
from the Resource, the Company may, with the burden of proof and subject to PacifiCorp 583
supporting its proposal in testimony,13 propose to allocate to and collect from each State that is 584
participating in that Resource at the time of Closure that State’s share, based on either an SG Factor 585
(if closed during the Interim Period) or an AP Factor, adjusted for any Reassignment or Limited 586
Realignment effects (if closed after the Interim Period), of actual Decommissioning Costs less the 587
regulatory liabilities for Exiting States including interest as described in Section 4.3.2 and less any 588
difference between the reserve balance established for each Exiting State and the estimated costs 589
allocated to each Exiting State as described above. Parties in such State(s) may take any position 590
regarding a Company request to recover Decommissioning Costs. 591
4.3.2. Accounting for Decommissioning Costs Reserve Balances when All 592 States Do Not Exit a Unit 593
After an Exit Date by some but not all States, the estimated Decommissioning Costs 594
reserves allocated to the Exiting State(s) associated with a coal-fueled Interim Period Resource 595
unit, from which that State is exiting, will be accounted for as a regulatory liability that is excluded 596
from rate base. Interest will be accrued on that regulatory liability at the Company’s then-597
authorized weighted average cost of capital14 for each State that continues to participate in that 598
coal-fueled Interim Period Resource after an Exit Date until the decommissioning work on that 599
unit is completed. 600
13 PacifiCorp’s testimony will identify and explain the variances between estimated and actual Decommissioning Costs.
14 Not to exceed the maximum carrying charge allowed by applicable law or Commission Order.
4.3.3. Accounting for Interim and Final Retirements 601
Before any State exits a coal-fueled Interim Period Resource, but no later than December 602
31, 2021, the Company shall propose to the Parties a process for separately accounting for removal 603
costs associated with interim retirements and final Decommissioning Costs in its accounting 604
system. Each State may determine the regulatory treatment for such removal costs in appropriate 605
proceedings. 606
4.3.4. Individual State Review Process 607
Any Party, at its discretion and cost, may pursue actions it deems necessary or appropriate 608
to review and evaluate the Decommissioning Studies or Decommissioning Costs and may take any 609
positions based on its review and findings. If a Commission issues an order identifying an 610
independent evaluator for the Decommission Studies, and the Commission Order provides for the 611
deferral and later recovery in rates of the cost of the independent evaluator, the Company agrees 612
to initially pay for this independent evaluation. 613
4.4. Qualifying Facilities 614
The allocation of QF PPAs shall be treated in accordance with Sections 4.4.1 and 4.4.2 of 615
this 2020 Protocol, superseding Section (IV)(A)(3) of the 2017 Protocol. For Washington, QF 616
PPAs will be assigned and allocated consistent with the terms of Appendix F during the Interim 617
Period. Other than addressing the allocation of the costs and assignment of benefits of QF PPAs 618
among the States, this 2020 Protocol does not restrict or affect any Commission's jurisdiction over 619
any agreement or interaction between QFs and the Company. QF PPAs shall be treated in the 620
following manner for allocation and assignment purposes. 621
4.4.1. Existing QF PPAs 622
QF PPAs fully executed15 or as to which a legally enforceable obligation exists16 on or 623
before December 31, 2019 ("Existing QF PPAs") will remain system assigned and allocated, 624
subject to any Limited Realignment in Section 6.4, until the end of 2029, after which time they 625
will be situs assigned and allocated to the State having jurisdiction over the QF PPA for avoided 626
cost pricing (“State of Origin”). 627
4.4.1.1. Wyoming QF Adjustment 628
The Company agrees to include: (1) a $5 million adjustment, annually, to reduce Net Power 629
Costs in Wyoming customer rates17 beginning January 1, 2021, until December 31, 2022; and (2) 630
a $7.175 million adjustment, annually, to reduce Net Power Costs in Wyoming customer rates from 631
January 1, 2023, until December 31, 2029.18 This adjustment will terminate on or before 632
December 31, 2029, or upon issuance of any order by the Wyoming Commission that changes 633
Wyoming’s treatment of the Implemented Issues or the Resolved Issues from the terms of the 2020 634
Protocol. The adjustment shall be made solely at the Company’s expense and not allocated to any 635
other States. 636
4.4.2. New QF PPAs 637
QF PPAs fully executed or as to which a legally enforceable obligation exists after 638
December 31, 2019, (“New QF PPAs”) will be situs assigned and allocated for ratemaking 639
proceedings pertaining to periods beginning on or after January 1, 2020, to the State of Origin. 640
15 Fully executed means executed and delivered by each party to the other party. 16 Any such legally enforceable obligation date must be confirmed by an order from the applicable Commission
issued prior to the end of the Interim Period. 17 The Wyoming QF adjustment will be included in the base ECAM costs forecasted in a general rate case with rates
effective on or after January 1, 2021. The Wyoming QF adjustment will be trued up in the ECAM at 100% (sharing-bands do not apply). 18 The Wyoming QF adjustment shall be removed from base ECAM costs on December 31, 2029, or as otherwise specified in Section 4.4.1.1, so that no adjustment flows through to customers in rates after that date unless it was
deferred in the ECAM prior to December 31, 2029.
4.4.2.1. Interim Period Treatment – Pre-Nodal Pricing Model 641
For the Interim Period, the energy output of New QF PPAs will be dynamically allocated 642
per this agreement using the SG Factor, priced at a forecasted reasonable energy price defined 643
below, and any cost of a New QF PPA above the forecasted reasonable energy price will be situs 644
assigned and allocated to the State of Origin. The forecasted reasonable energy price is a single 645
blended market price derived from the Company's Official Forward Price Curve ("OFPC"), scaled 646
for hourly prices, that was used for setting QF pricing for the New QF PPA. The single blended 647
market price is calculated by applying the appropriate weighting to the hourly scaled prices from 648
the OFPC for each market hub. The weightings per market hub are identified in the table below. 649
The weighting will be applied by month and by heavy load hours (“HLH”) and light load hours 650
(“LLH”). The forecasted reasonable energy price, used for allocation purposes, shall be 651
established at the time a QF PPA is fully executed. 652
4.4.2.2. Post-Interim Period Treatment 653
After the conclusion of the Interim Period, assuming resolution and Commission approval 654
of all Framework Issues, the Parties agree that New QF PPAs will be situs assigned and the costs 655
Market Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
COB 0.00% 0.55% 1.34% 0.82% 3.45% 4.01% 8.41% 3.69% 8.58% 0.97% 1.79% 1.20%
Mid Columbia 24.42% 30.21% 55.74% 63.22% 70.84% 87.39% 81.05% 83.85% 75.88% 42.27% 34.30% 40.74%
Palo Verde 1.52% 2.53% 1.07% 0.66% 0.54% 0.03% 0.76% 1.89% 1.85% 2.55% 3.45% 0.30%
Four Corners 64.72% 58.68% 35.94% 27.40% 16.15% 5.75% 4.12% 2.17% 3.82% 45.79% 52.88% 44.47%
Mead 0.18% 0.13% 1.23% 1.46% 1.52% 1.74% 1.95% 3.30% 6.64% 0.33% 0.12% 0.57%
Mona 9.16% 7.90% 2.94% 2.03% 1.79% 0.74% 0.01% 0.18% 1.82% 7.82% 7.46% 2.18%
NOB 0.00% 0.00% 1.75% 4.40% 5.72% 0.33% 3.70% 4.92% 1.41% 0.27% 0.00% 10.54%
Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
Market Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
COB 0.00% 0.99% 5.17% 3.53% 15.50% 15.16% 5.97% 1.21% 0.31% 2.43% 3.44% 1.16%
Mid Columbia 58.74% 60.10% 76.58% 66.36% 71.82% 80.41% 85.52% 92.26% 83.27% 62.78% 66.30% 59.09%
Palo Verde 0.00% 1.12% 0.42% 0.04% 0.39% 0.40% 2.71% 3.04% 0.00% 0.92% 1.91% 2.30%
Four Corners 33.45% 34.66% 13.63% 26.49% 10.44% 3.30% 5.35% 2.39% 11.60% 27.69% 26.36% 29.65%
Mead 0.00% 0.06% 0.94% 0.44% 0.93% 0.47% 0.25% 0.00% 0.00% 0.57% 0.00% 0.00%
Mona 7.81% 3.07% 1.54% 2.41% 0.92% 0.27% 0.00% 1.11% 4.82% 5.61% 1.99% 7.80%
NOB 0.00% 0.00% 1.71% 0.73% 0.00% 0.00% 0.20% 0.00% 0.00% 0.00% 0.00% 0.00%
Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
Market Hub Weighting by Month - LLH
Market Hub Weighting by Month - HLH
and benefits will be allocated and assigned per the methodology developed through the Framework 656
process in Section 6.2. 657
5. Resolved Issues - Post-Interim Period Implementation 658
The Parties agree, conditioned upon reaching agreement on a Post-Interim Period Method 659
on the future allocation treatment described in this Section 5 for certain benefits, revenues, costs, 660
and investments. As stated in Section 2, these Resolved Issues of the 2020 Protocol are intended 661
to take effect with the implementation of the Post-Interim Period Method. Parties acknowledge 662
that conditions may change materially in unforeseen ways during the Interim Period and that it 663
may be necessary to re-evaluate Resolved Issues as part of the Post-Interim Period Method. The 664
Resolved Issues are identified below. 665
5.1. Generation Costs 666
Following the Interim Period, a fixed share of the Interim Period Resources will be 667
assigned to serve load in each State. The costs and benefits, including environmental attributes, 668
associated with each Interim Period Resource will be allocated and assigned in accordance with 669
the Interim Period Resources fixed allocation provisions (Section 5.1.1), Reassignment of coal-670
fueled Interim Period Resources (Section 4.2), and Limited Realignment (Section 6.4). 671
5.1.1. Interim Period Resources Fixed Allocation 672
Interim Period Resources will be assigned and allocated to States based on the SGF Factor 673
for each State as defined in Appendix C. The load information used to determine the SGF Factor 674
is subject to modification for the inclusion or exclusion of Special Contract loads as determined 675
through the Framework process for resolution of issues addressed in Section 6.3. The SGF Factor 676
is used to develop the AP Factor for each unit. Additionally, Interim Period Resources will be 677
subject to the Limited Realignment as outlined in Section 6.4 and the Reassignment of Interim 678
Period Resources as outlined in Section 4.2. Any such Assignment of Interim Period Resources, 679
along with the Limited Realignment and the Reassignment of Interim Period Resources, will be 680
subject to the following: 681
• Accumulated depreciation for Interim Period Resources will be allocated per the 682
AP Factor. State-specific accumulated depreciation that has been tracked by the 683
Company due to increased depreciation expenses will be treated as situs to the State 684
and offset its Resource costs until that State exits from an Interim Period Resource. 685
• Accumulated deferred income taxes and excess deferred income taxes will be 686
allocated per the Company's tax software system, using the AP Factor. State-687
specific accumulated deferred income taxes and excess deferred income taxes that 688
have been tracked by the Company due to increased depreciation expense will be 689
treated as situs to the State and offset that State’s Resource costs until that State 690
exits from an Interim Period Resource. 691
• All O&M expenses that are associated with a specific Interim Period Resource will 692
be allocated per the AP Factor. 693
• All generation-related O&M expenses that cannot be allocated to a specific Interim 694
Period Resource through an AP Factor, such as general office generation 695
management expenses, will be allocated to States based on an Assigned Production 696
Operations and Maintenance (“APOM”) Factor, calculated as each States' relative 697
share of direct-allocated generation O&M expenses. There will be three separate 698
APOM factors based on FERC classifications, with the APOMS used for steam 699
generation (FERC accounts 500 - 514), APOMH used for hydro generation (FERC 700
accounts 535-545) and APOMO used for other generation (FERC accounts 546 - 701
554). The APOM factor calculations are shown in Appendix C and also included 702
in Appendix B, Column 5. 703
• Property tax will continue to be allocated based on gross plant using the GPS Factor 704
as calculated in Appendix C and included in Appendix B, Column 5. 705
• All other rate-base items associated with Interim Period Resources will be allocated 706
consistent with the Interim Period Resource allocations using the AP Factor. 707
5.1.2. New Resources Fixed Assignment 708
New Resources include any Resources that are not in commercial operation before the end 709
of the Interim Period. All costs and benefits associated with new Resources, subject to the 710
qualification below, will be allocated and assigned to States based on a fixed assignment under the 711
process to be determined in Section 6.1 – Resource Planning and New Resource Assignment. The 712
Parties agree that a transitional period is necessary to change the cost allocation for future new 713
Resources that are planned for by the Company, and that any new Resource reaching commercial 714
operation before the end of the Interim Period will be treated the same as Interim Period Resources 715
for allocation purposes under the terms of this Agreement. 716
5.2. Transmission Costs 717
The costs associated with transmission assets, except as addressed in Section 6.1, will be 718
dynamically allocated among States on the System Transmission (“ST”) Factor, generally 719
calculated based on a classification of costs as 75 percent Demand-Related and 25 percent Energy-720
Related, and based on twelve monthly Coincident Peaks, using weather-normalized retail peak and 721
energy data, as more thoroughly defined in Appendix C. 722
All revenues recovered through PacifiCorp's Open Access Transmission Tariff or other 723
transmission rate schedules approved by the FERC will be allocated based on the ST Factor. 724
The 2020 Protocol does not preclude PacifiCorp from participating in any independent 725
transmission organization, regional transmission organization, or other similar wholesale 726
transmission market subject to the jurisdiction and oversight of the FERC. 727
5.3. Distribution Costs 728
All distribution-related expenses and capital costs that can be directly allocated will be 729
directly allocated to the States where the related distribution facilities are located. Those 730
distribution expenses that cannot be directly allocated will be allocated among States on a System 731
Net Plant Distribution ("SNPD") factor, as shown in Appendix B. 732
5.4. System Overhead Costs 733
Costs that support more than one function, such as generation, transmission, or distribution 734
plant, will continue to be allocated on the System Overhead (“SO”) Factor after the Interim Period 735
but will be calculated based on an equal one-third weighting of the System Capacity (“SC”) Factor, 736
System Energy Factor, and System Gross Plant Distribution (“SGPD”) Factor, as shown in 737
Appendix B. 738
5.5. Administrative and General Costs 739
Administrative and General Costs, General Plant costs, and Intangible Plant costs, both 740
expenses and investments, which can be directly allocated will be directly allocated to the 741
appropriate State(s). Those costs that cannot be directly allocated will be allocated among States 742
consistent with the factors set forth in Appendix B. 743
5.6. Other Allocation Issues 744
Items included in the Company's results of operations, other than those that are specifically 745
called out herein, will continue to be allocated on the same factors used in the 2017 Protocol. The 746
FERC account and allocation factor combinations are included in Appendix B. The algebraic 747
derivation and factor definitions are included in Appendix C. 748
The following miscellaneous changes will be made to be consistent with the other 749
allocation changes: 750
• Communication equipment allocated on the System Generation Factor during the 751
Interim Period will change to either the SE Factor (generation-related) or ST Factor 752
(transmission-related) depending on the nature of the equipment for which the 753
communication equipment is utilized. 754
• Contributions In Aid of Construction (“CIAC”) currently allocated on the SG 755
Factor will change to either the AP factor for generation-related CIAC or the ST 756
Factor for transmission related CIAC. 757
• Generation-related dispatch costs and associated plant will be allocated on the SE 758
Factor. 759
• Miscellaneous regulatory assets and liabilities, and miscellaneous deferred debits 760
will be allocated with the appropriate allocation factor depending on the related 761
assets or underlying costs. Miscellaneous regulatory assets and liabilities, and 762
miscellaneous deferred debits currently allocated on the SG Factor, will change to 763
the AP Factor for generation-related and ST Factor for transmission-related items. 764
Taxes and fees will be allocated as follows: 765
• Income taxes will be calculated using the federal tax rate and PacifiCorp’s 766
combined State effective tax rate. State specific Schedule M and deferred income 767
tax amounts will be allocated using the Company’s tax software system. Consistent 768
with prior system allocation methods, the Washington Public Utility Tax is 769
allocated using the SO Factor in lieu of a Washington income tax. 770
• Franchise taxes, revenue related taxes, Commission assessments and fees, and 771
usage related taxes are situs or a pass through. 772
• Property taxes are system allocated based on gross plant and allocated on the GPS 773
Factor. 774
• Generation and fuel related taxes will follow the assignment of the Resource. 775
• Other taxes such as payroll taxes are embedded in the cost of expense or capital. 776
Balances associated with the Trojan Decommissioning will be allocated using the Trojan 777
Decommissioning Fixed ("TROJDF") Factor. This will not affect State-specific treatment of this 778
item. 779
5.7. Demand-Side Management Programs 780
Costs associated with DSM Programs, including Class 1 DSM Programs, will continue to 781
be allocated on a situs basis to the State in which the investment is made. The benefits from these 782
programs will flow back to the State through Net Power Costs or through reduced or delayed future 783
capacity needs that will be addressed in the development and implementation of the process 784
identified in Section 6.1. 785
5.8. State-Specific Initiatives 786
Costs and benefits resulting from a State-specific initiative will continue to be allocated 787
and assigned on a situs basis to the State adopting the initiative. Historically, these have included, 788
but are not limited to, programs such as incentive programs and customer and community energy 789
generation programs, but have not included local fees or taxes related to the ongoing operation of 790
existing transmission and generation facilities within a State. As new issues arise, PacifiCorp will 791
bring each issue to the MSP Workgroup to discuss whether each issue is a State-specific initiative, 792
and, if not, whether a different allocation method is appropriate. 793
6. Framework Issues 794
The Parties acknowledge that certain components of the Post-Interim Period Method are 795
not resolved by this Agreement, including Resource Planning and new Resource Assignment, Net 796
Power Costs / Nodal Pricing Model, the treatment of Special Contracts, post-Interim Period capital 797
additions, and other issues related to the transition from a dynamically-allocated system generation 798
portfolio to fixed generation portfolios. As part of the 2020 Protocol, the Parties agree to the 799
following processes and timeframes to address remaining, unresolved Framework Issues and to 800
request approval of a new Post-Interim Period Method agreement by the Commissions. The 801
Company will file for Commission consideration and approval of a new Post-Interim Period 802
Method in accordance with Section 2. The general understanding reached by the Parties as to 803
process and timelines for Framework Issues is as follows. 804
6.1. Resource Planning and New Resource Assignment 805
Continued operation, planning, and dispatch of the Company's system as an integrated six-806
State system, to the greatest extent practicable, will likely be beneficial to PacifiCorp's customers. 807
However, because of differing State policies requiring or excluding certain generation resources, 808
it appears infeasible to continue serving customers with a common generation portfolio and 809
dynamically allocating system costs. Continued dynamic allocation of all system costs in this 810
environment could result in increased costs for some States, if not all. Accordingly, allocating 811
costs and assigning benefits associated with generation capacity will require assignment of specific 812
Resources, and potentially certain transmission assets, to a specific State or States. The goal is to 813
allow PacifiCorp to meet its legal requirements as a public utility in each State in a risk-adjusted, 814
least-cost manner, while striving to mitigate cost impacts to other States. 815
PacifiCorp will continue to plan for capacity and operating needs, both for the entire 816
interstate system and for each State. PacifiCorp will work with Parties to develop: 817
• A planning process that optimizes risk-adjusted, least-cost resource portfolios on a 818
system basis to the extent practicable, while meeting individual State requirements 819
and maintaining system reliability; and 820
• A process that assigns benefits and allocates costs of specific new Resources added 821
in order to meet an individual State’s needs. 822
Parties will evaluate these processes in light of existing or new Commission regulatory 823
processes governing Resource planning, procurement, and investment approval. 824
6.2. Net Power Costs / Nodal Pricing Model (“NPM”) 825
A method to track the costs and benefits of Resource portfolios which may differ for each 826
State will be necessary in the future to maintain the benefits of system dispatch as much as 827
practicable. Specifically, after the Interim Period when States may no longer participate in a 828
common Resource portfolio, a NPM may be used to track cost causation and receipt of benefits by 829
each State for rate-making purposes. 830
Consistent with and in consideration of the Nodal Pricing Model Memorandum of 831
Understanding in Appendix D, the Company agreed to begin the development of an NPM with a 832
third-party vendor and will use best efforts to implement the NPM by the end of January 2021, for 833
purposes of total-Company day-ahead scheduling. Parties intend for this to provide some time and 834
experience with the NPM before it may be used for rate making as part of the Post-Interim Period 835
Method.19 836
The Company will also use best efforts to implement a model that can forecast NPC based 837
on the NPM concept. During the Interim Period, this model may be used by the Company for 838
forecast analysis of NPC. After the Interim Period, the Company intends to propose the use of this 839
model for NPC forecasts in applicable rate-making proceedings. 840
6.3. Special Contracts 841
The Company will continue to work in good faith with the Special Contract customers to 842
develop one or more proposals for consideration by the Parties on the treatment of Special 843
Contracts’ loads, costs, and benefits as part of the Framework Issues and will make best efforts to 844
present a proposal to Parties by September 1, 2021, with the intention of incorporating such 845
proposal into the Post-Interim Period Method. 846
6.4. Limited Realignment 847
The Parties agree to investigate during the Interim Period the potential Limited 848
Realignment of Interim Period Resources among the States. Limited Realignment is intended to 849
address, among other potential issues, the transition of Washington retail customers away from 850
coal-fueled Interim Period Resource in compliance with the Washington CETA by realigning 851
Interim Period Resources, including natural gas-fueled Interim Period Resources. 852
6.5. Post-Interim Period Capital Additions – Coal-Fueled Interim 853 Period Resources 854
For a coal-fueled Interim Period Resource for which one or more States have an Exit Date 855
that differs from the depreciable life or Exit Date ordered in any other State, a process is needed 856
19 NPM is intended to be used for total Company system dispatch when it is fully functional and operational and will
impact system Net Power Costs that flow through State NPC balancing accounts.
for determining the cost allocation for capital investments made in the Resources subsequent to 857
the Interim Period and prior to the Exit Date for each State. The Parties have agreed to evaluate, 858
but have not accepted, the following Company straw proposal for post-Interim Period capital 859
investments, information about which is provided here not for Commission approval but to inform 860
future discussions. 861
6.5.1. PacifiCorp Straw Proposal - Post-Interim Period Capital Investment 862 Allocation Exceptions 863
For post-Interim Period incremental capital investments that are made primarily for the 864
purpose of extending the life of a coal-fueled Interim Period Resource beyond a State’s Exit Date 865
for that Resource, including but not limited to those associated with achieving compliance with 866
environmental requirements or those necessitated by catastrophic failure, such investments would 867
not be allocated to States that have issued such Exit Orders and would be allocated based on the 868
percentage shares of the coal unit Reassignment process addressed in Section 4.2 or as otherwise 869
determined for States that continue to participate in the coal-fueled Interim Period Resource. 870
For these incremental capital investments made primarily for the purpose of repairing a 871
coal-fueled Interim Period Resource following a catastrophic failure of the Interim Period 872
Resource, such investments would not be allocated to and no generation or benefits will be 873
assigned to States that have issued Exit Orders for that Resource. Parties in States not allocated 874
costs for such investments would support recovery of any remaining net book value and 875
Decommissioning Costs. 876
6.5.2. PacifiCorp Straw Proposal - Incremental Capital Investments Made 877 Between 2024 and the Exit Date Where Exit Date is On or Before 878 December 31, 2027 879
For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit 880
Date on or before December 31, 2027, capital investments made in such Interim Period Resource 881
after the Interim Period and prior to the Exit Date, would be allocated to an Exiting State based on 882
the AP Factor, adjusted for any Limited Realignment impacts agreed to, and pro-rated for the 883
number of years remaining based on the longest life ordered in any State's depreciation docket or 884
rate case by December 31, 2020, for such Interim Period Resource. States without Exit Orders in 885
such Interim Period Resource would be allocated the remaining amount of capital investment 886
based on proportional shares of the AP factor for the States that will be participating in the coal-887
fueled Interim Period Resource after an Exit Date. For example, if a State’s Exit Order establishes 888
an Exit Date four years from the date the capital investment is in-service, and the Interim Period 889
Resource has the longest remaining life in another State of ten years, the State with the Exit Order 890
would be allocated four-tenths of that State’s share of the cost of the qualifying capital investment. 891
Each State’s allocation of such capital investments would be subject to a prudence review based 892
on the cost to be allocated to each State consistent with this Section. 893
6.5.3. PacifiCorp Straw Proposal - Incremental Capital Investments Made 894 in 2024 and 2025 Where Exit Date is After 2027 895
For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit 896
Date after 2027, capital investments made in such Interim Period Resource after the Interim Period 897
and through December 31, 2025, would be allocated to all States based on the AP Factor, adjusted 898
for any Limited Realignment impacts agreed to, and prudence of such capital investments for 899
States with Exit Orders would be determined based on the life established for such Interim Period 900
Resource in the Exit Order. This would allow for the reasonable allocation of capital and operating 901
costs for the Interim Period Resource during a period of time while PacifiCorp pursues the process 902
established in Section 4.2. 903
6.5.4. PacifiCorp Straw Proposal - Incremental Capital Investments Made 904 Between 2026 and the Exit Date Where the Exit Date is After 2027 905
For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit 906
Date after 2027, capital investments made in such Interim Period Resource after December 31, 907
2025, and until the Exit Date, would be allocated to an Exiting State based on the AP Factor, 908
adjusted for any Limited Realignment impacts agreed to, and pro-rated for the number of years 909
remaining based on the longest life ordered in any State's depreciation docket, Reassignment 910
proceeding, or rate case as of December 31, 2025. States that will be participating in the coal-911
fueled Interim Period Resource after an Exit Date would be allocated the remaining amount of any 912
capital investment based on the AP Factor calculated for that coal-fueled Interim Period Resource. 913
7. Allocation of Gain or Loss from Sale of Assets 914
Any gain or loss from the sale of Company-owned assets will be allocated among or to 915
States based upon the proportional allocation or assignment of the asset at the time of the execution 916
date of the sale agreement. Each Commission will determine the appropriate allocation of the gain 917
or loss allocated to that State as between PacifiCorp's customers and shareholders. For assets that 918
have been Reassigned for less than one calendar year as of the execution date of the sale agreement, 919
States will be allocated the gain or loss as if the asset had remained a System Resource. 920
8. Interpretation and Governance 921
8.1. Issues of Interpretation 922
Parties will attempt, consistent with their legal obligations, to resolve questions of 923
interpretation of the 2020 Protocol, in good faith in light of the language of the 2020 Protocol and 924
the intent of the Parties. 925
8.2. Workgroups 926
8.2.1. Framework Issues Workgroup 927
PacifiCorp will schedule and convene meetings with Parties to continue negotiations of the 928
Framework Issues, which may occur in person or remotely. 929
8.2.2. Multi-State Process Workgroup 930
Consistent with Sections 8.4 or 8.5 of this Agreement, the Company will notify Parties and 931
other MSP participants if it determines a need exists to convene the MSP Workgroup to address 932
general allocation issues or complaints related to the 2020 Protocol. Any Party to this Agreement, 933
State utility regulatory agency, or other stakeholder can participate in the MSP Workgroup. The 934
MSP Workgroup may create sub-committees to investigate or evaluate or make recommendations 935
as to specified issues. MSP Workgroup meetings may be held in person or remotely. 936
8.3. Commissioner Forum 937
The 2017 Protocol included a mandatory requirement to hold an annual Commissioner 938
Forum each January during the pendency of that agreement. Under this 2020 Protocol, 939
Commission Forums are not required. A Commission or the MSP Workgroup may request such a 940
meeting of Commissioners. If a Commissioner Forum is requested, all seated commissioners from 941
each State will be invited to participate. Commissioner Forums will be public meetings, and all 942
interested parties will be allowed to attend. Before attending a Commissioner Forum, each 943
Commission can take such steps and provide such process for public input as the Commission 944
determines is necessary or appropriate under applicable State laws. 945
8.4. Proposals to Change the 2020 Protocol during the Interim Period 946
The Parties agree not to propose or support changes to the 2020 Protocol applicable to the 947
Interim Period based on a Party’s dissatisfaction with a reasonably foreseeable outcome from 948
implementation of the 2020 Protocol. Before proposing an alternative or modification to the 2020 949
Protocol based primarily on changed or unforeseen circumstances, each Party agrees to first make 950
the proposal to the Parties and attempt in good faith to resolve the concern before asking a 951
Commission to change the 2020 Protocol. The provisions of this Section 8.4 will apply to any 952
State agency only to the extent consistent with the State agency’s statutory obligations. 953
Proposals for modifications to the 2020 Protocol may be submitted to the Company by any 954
Party. Proposals received by the Company shall be circulated in a timely manner to the other 955
Parties and the Company shall initiate discussions to attempt to address and resolve specific 956
concerns. 957
8.5. Replacement of the 2020 Protocol 958
If any stakeholder that is not a Party to this Agreement objects to the use of the 2020 959
Protocol after approval by the Commissions or proposes a new inter-jurisdictional allocation 960
procedure, PacifiCorp may convene the MSP Workgroup and hold discussions to attempt to 961
address and resolve the concerns at an MSP Workgroup meeting(s). 962
8.6. Interdependency Among Commission Approvals 963
The 2020 Protocol has been developed and negotiated by the Parties as an integrated, 964
interdependent whole. Support by any Party of the 2020 Protocol is expressly conditioned upon 965
approval without material alteration of the 2020 Protocol by all Commissions in the States that 966
PacifiCorp has sought approval.20 If any Commission disapproves, alters, or conditions approval 967
of the 2020 Protocol, Parties shall promptly meet and discuss the implications of that Commission's 968
action. PacifiCorp shall report to the Parties any Commission Order of another State concerning 969
the 2020 Protocol. Parties agree to recommend to each Commission that approval of the 2020 970
Protocol be conditioned on other Commissions approving the 2020 Protocol without change. 971
20 California has historically reviewed allocation methodologies in conjunction with a general rate case.
PacifiCorp’s next regulatory-mandated general rate case will not be filed until 2021 at the earliest.
EXECUTION VERSION
973 9. Compliance with Resource Laws
974 PacifiCorp asserts that the 2020 Protocol complies with the requirements of current
975 resource laws of all of the States and will not shift risk of compliance among PacifiCorp's States.
976 If a future change in law, cowt decision, or Commission decision results in the Company's
977 reasonable belief that compliance with all applicable laws cannot be achieved, the Company will
978 raise its concerns with the Parties and/or convene an MSP Workgroup meeting to address the issue.
979 10. Signatures of Parties to the 2020 Protocol
980 This 2020 Protocol is entered into by each Party on the date entered below such Party's
981 signature.
PACIFICORP
en ic resident,
Strategic Business Planning
Date: November 22, 2019
IDAHO CONSERVATION LEAGUE
Date: -------------
46
ALLIANCE OF WESTERN ENERGY
CONSUMERS
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Date: -------------
EXECUTION VERSION
973 9. Compliance with Resource Laws
974 PacifiCorp asserts that the 2020 Protocol complies with the requirements of current
975 resource laws of all of the States and will not shift risk of compliance among PacifiCorp's States.
976 If a future change in law, court decision, or Commission decision results in the Company's
977 reasonable belief that compliance with all applicable laws cannot be achieved, the Company will
978 raise its concerns with the Parties and/or convene an MSP Workgroup meeting to address the issue.
979 10. Signatures of Parties to the 2020 Protocol
980 This 2020 Protocol is entered into by each Party on the date entered below such Party's
981 signature.
PACIFICO RP
n 1 ident, .
Strategic Business Planning
Date: November 22. 2019
IDAHO CONSERVATION LEAGUE
TI tie: ~-~-------~-
Date: ------~-----
46
ALLIANCE OF WESTERN ENERGY
CONSUMERS
s/JJ::~
Title: Ako"' V\.e..'--f , (
Date: ll / Z-~ 11 Vt
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Title: ------------
Date: ~-----------
EXECUTION VERSION
973 9. Compliance with Resource Laws
974 PacifiCorp asserts that the 2020 Protocol complies with the requirements of current
975 resource laws of all of the States and will not shift risk of compliance among PacifiCorp's States.
976 If a future change in law, court decision, or Commission decision results in the Company's
977 reasonable belief that compliance with all applicable laws cannot be achieved, the Company will
978 raise its concerns with the Parties and/or convene an MSP Workgroup meeting to address the issue.
979 10. Signatures of Parties to the 2020 Protocol
980 This 2020 Protocol is entered into by each Party on the date entered below such Party's
981 signature.
PACIFICO RP
Date: November 22, 2019
IDAHO CONSERVATION LEAGUE
Date: /U~t' .... 6r.,. Z 7 20!7 I
46
ALLIANCE OF WESTERN ENERGY
CONSUMERS
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
EXECUTION VERSION
973 9. Compliance with Resource Laws
974 PacifiCorp asserts that the 2020 Protocol complies with the requirements of current
975 resource laws of all of the States and will not shift risk of compliance among PacifiCorp's States.
976 If a future change in law, court decision, or Commission decision results in the Company's
977 reasonable belief that compliance with all applicable laws cannot be achieved, the Company will
978 raise its concerns with the Parties and/or convene an MSP Workgroup meeting to address the issue.
919 10. Signatures of Parties to the 2020 Protocol
980 This 2020 Protocol is entered into by each Party on the date entered below such Party's
98 l signature.
PACIFICORP
Date: November 22, 2019
IDAHO CONSERVATION LEAGUE
By: ---
Title:
-------~-~~~-
Date: ------------
46
ALLIANCE OF WESTERN ENERGY
CONSUMERS
By:
Title:
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
By: JtJ\.5U.,.
Title: lld.,~~ kllilrbestllv·~
Date: I J /~to/ U>l'l ~I
EXECUTION VERSION
IDAHO IRRIGATION PUMPERS INTERWEST ENERGY ALLIANCE ASZ? .
By g~ By:
Title: lkla/'VI '°// Title:
Date: 1z,! z,LL!J-Date:
MONSANTO COMPANY NORTHWEST & INTERMOUNTAIN
POWER PRODUCERS
By: By:
Title: Title:
Date: Date:
NORTHWEST ENERGY COALITION
By: ~y:
Title: Title:
Date: Date:
OREGON CITIZENS' UTILITY BOARD OREGON PUBLIC UTILITY COMMISSION
STAFF
By: By:
Title: Title:
Date: Date:
47
IDAHO IRRIGATION PUMPERS
ASSOCIATION
By: ------------
Title: ------------
Date: ------------
MONSANTO COMPANY
By: ------------
Title: ------------
Date:. -----------
NORTHWEST ENERGY COALITION
By: ------------
Title: ------------
Date: -----------
OREGON CITIZENS' UTILITY BOARD
By: ------------
Title: ------------
Date: ------------
47
EXECUTION VERSION
NORTHWEST & INTERMOUNTAIN
POWER PRODUCERS
By: ------------
Title: ------------
Date: ------------
By: ------------
Title: ------------
Date: ------------
OREGON PUBLIC UTILITY COMMISSION
STAFF
By: ------------
Title: ------------
Date: ------------
IDAHO IRRIGATION PUMPERS ASSOCIATION
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
POWER PRODUCERS
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
STAFF
By: ________________________________
Title: ________________________________
Date: _______________________________
_____________________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
Attorney for Monsanto
11/26/2019
EXECUTION VERSION
IDAHO IRRIGATION PUMPERS INTERWEST ENERGY ALLIANCE
ASSOCIATION
By: By:
Title: Title:
Date: Date:
MONSANTO COMPANY NORTHWEST & INTERMOUNTAIN
POWER PRODUCERS
By: By:
Title: Title:
Date: Date:
NORTHWEST ENERGY COALITION
By: By:
Title: Title:
Date: Date:
OREGON CITIZENS' UTILITY BOARD OREGON PUBLIC UTILITY COMMISSION
STAFF
By: Et a~ By:
Title: e~~e-u"iJ.J~ ~-r""c -/c:J/ Title:
Date: I Lj 2/ f-?o It/ Date:
47
EXECUTION VERSION
IDAHO IRRIGATION PUMPERS INTERWEST ENERGY ALLIANCE
ASSOCIATION
By: By:
Title: Title:
Date: Date:
MONSANTO COMPANY NORTHWEST & INTERMOUNTAIN
POWER PRODUCERS
By: By:
Title: Title:
Date: Date:
NORTHWEST ENERGY COALITION
By: By:
Title: Title:
Date: Date:
OREGON CITIZENS' UTILITY BOARD OREGON PUBLIC UTILITY COMMISSION
STAFF
By: By: ~Mfv
Title: Title: A<tt~~ A~~ ~eVtUi~
ii
Date: Date: 1 \ [i-~ f \ c4
47
EXECUTION VERSION
PJ\CTFTCORP JDAHO TNDUSTRTAL PACKAGING CORPORATION OF
CUSTOMERS AMERICA
By: ~~ L tJJA;_ By:
Title: A -t-+ o..,....,.. ~ '/
I Title:
Date: \ \ -)._ ~ -2-.0l~ Date:
POWDER RlVER BASTN RESOURCE RENEWABLE NORTHWEST
COUNCIL
By: By:
Title: Title:
Dale: Date:
SIERRA CLUB UTA! I ASSOCIATION OF ENERGY USERS
By: By:
Title: Title:
Date: Date:
UTAH CLEAN ENERGY UTAH DJVISTON OF PUBLIC UTILITIES
By: By:
Title: Title:
Date: Date:
48
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
By: ________________________________
Title: ________________________________
Date: _______________________________
AMERICA
By: ________________________________
Title: ________________________________
Date: _______________________________
COUNCIL
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
Staff Attorney
November 26, 2019
PACIFICORP IDAHO INDUSTRIAL
CUSTOMERS
By:
Title: ------------
Date: -------------
POWDER RIVER BASIN RESOURCE
COUNCIL
Title: ------------
Date: ------------
SIERRA CLUB
By: -----~-----~
Title: -------------
Date: ------------
UTAH CLEAN ENERGY
By: ----~-----~
Title: ------------
Date: ------------
48
EXECUTION VERSION
PACKAGING CORPORATION OF
AMERICA
Title: ------------
Date: ------------
RENEWABLE NORTHWEST
By: ----------~
Title:
Date: ------------
UTAH ASSOCIATION OF ENERGY USERS
UTAH DIVISION OF PUBLIC UTILITIES
By: ------------
Title: -------------
Date: ------------
EXECUTION VERSION
PACIFICORP IDAHO INDUSTRIAL PACKAG ING CORPORATION OF
CUSTOMERS AMERICA
By: By:
Title: Title:
Date: Date:
POWDER RIVER BASIN RESOURCE RENEWABLE NORTHWEST
COUNCIL
By: By:
Title: Title:
Date: Date:
SIERRA CLUB UTAH ASSOCIATION OF ENERGY USERS
By: By:
Title: Title:
Date: Date:
UTAH CLEAN ENERGY UTAH DIVISION OF PUBLIC UTILITIES
By~~ -By:
Title: S+iPt A-r~V)~~ Title:
Date: ll J 1--:± L l PJ Date: r ,
48
EXECUTION VERSION
PACIFICORP IDAHO INDUSTRIAL PACKAGING CORPORATION OF
CUSTOMERS AMERICA
By: By:
Title: Title:
Date: Date:
POWDER RIVER BASIN RESOURCE RENEWABLE NORTHWEST
COUNCIL
By: By:
Title: Title:
Date: Date:
SIERRA CLUB UTAH ASSOCIATION OF ENERGY USERS
By: By:
Title: Title:
Date: Date:
UTAH CLEAN ENERGY UTAH DIVISION OF PUBLIC UTILITIES
By: By:~
Title: Title: 'i>rfl~t-~
Date: Date: 1t/l-o/if
48
EXECUTION VERSION
UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVICES
CONSUMERS
By: By: ru~u9xdd .<
Title: Title: Di:rtl{t>v
Date: Date: (t,i1--(1
VOTE SOLAR WASHINGTON PUBLIC COUNSEL
By: By:
Title: Title:
Date: Date:
WASHINGTON UTILITIES & WESTERN RESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
By: By:
Title: Title:
Date: Date:
WOLVERINE FUELS WYOMING INDUSTRIAL ENERGY
CONSUMERS
By: By:
Title: Title:
Date: Date:
49
UTAH INDUSTRIAL ENERGY CONSUMERS
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
TRANSPORTATION COMMISSION STAFF
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
CONSUMERS
By: ________________________________
Title: ________________________________
Date: _______________________________
Senior Staff Attorney
November 27, 2019
EXECUTION VERSION
UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVICES
CONSUMERS
By: By:
Title: Title:
Date: Date:
VOTE SOLAR WASHINGTON PUBLIC COUNSEL
By: By:
Title: Title:
Date: Date:
WASHINGTON UTILITIES & WESTERN RESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
By: By:
Title: Title:
Date: Date:
WOLVERINE FUELS WYOMING INDUSTRIAL ENERGY
CONSUMERS
By: ~ By:
Title: Chit( ~t lf~,.~/llC •ff'-'A-Title:
Date: \l/-z.t,IL2 Date:
49
UTAH INDUSTRIAL ENERGY CONSUMERS
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
TRANSPORTATION COMMISSION STAFF
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
By: ________________________________
Title: ________________________________
Date: _______________________________
CONSUMERS
By: ________________________________
Title: ________________________________
Date: _______________________________
Attorney for WIEC
November 25, 2019
EXECUTION VERSION
WYOMING OFFICE OF CONSUMER WYOMING PUBLIC SERVICE
ADVOCATE COMMISSION STAFF
By: M/J!zl~~ By ~~
Title: 47~~ Title: ~fc:Z_I/ ~ /112_fl)e;1-L .
Date: 11/a~/ il()/lj_ Date: II ·2 S-· 20/f__
By: By:
Title: Title:
Date: Date:
By: By:
Title: Title:
Date: Date:
By: By:
Title: Title:
Date: Date:
50
APPENDIX A
Definitions
For purposes of this Agreement, the following terms will have the following meanings: 1
• “2017 Protocol” refers to the 2017 PacifiCorp Inter-Jurisdictional Allocation Protocol. 2
• “2020 Protocol” refers to the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol. 3
• “Administrative and General Costs” means costs included in FERC accounts 920 through 935. 4
• “Assigned Production Factor” or “AP” means States' assigned share of a Resource (see Appendix 5
C for more details). 6
• “Assigned Production - Operations and Maintenance Factor” or “APOM Factor” means the 7
State allocated share of all generation related operating and maintenance expenses that cannot be 8
associated with a specific Resource, such as general office generation management expenses, that 9
will be allocated to States calculated as each State's relative share of directly allocated generation 10
operating and maintenance expenses for steam, hydro, and other generation functions (see Section 11
5.1.1 and Appendix C for more details). 12
• “Class 1 Demand-Side Management” or “Class 1 DSM” means dispatchable or scheduled firm 13
DSM resources, sometimes referred to as direct load control programs. 14
• “Closure” means either PacifiCorp’s termination of ownership interest in a Resource, permanent 15
cessation of operations of a Resource, permanent cessation of receipt of energy from a Resource, or 16
otherwise retirement of a Resource. 17
• “Coincident Peak” means the hour each month that the combined demand of all PacifiCorp retail 18
customers is greatest, adjusted for normal weather conditions. The hour of coincident peak is 19
calculated assuming weather normalized retail load, and as it relates to generation allocation factors, 20
it includes adjustments for Class 1 DSM and Special Contract curtailments. In calculating the 21
coincident peak for the System Transmission Factor, the only adjustment will be for weather 22
normalization. 23
• “Commission” means a utility regulatory commission in a State. 24
• “Commissioner Forum” means the meeting of Commissioners from all States, the goal of which 25
is to provide an update from the MSP Workgroup. Such a forum is not required by the 2020 Protocol. 26
• “Commission Order” means a formal determination issued by a State Commission consistent with 27
its authority as provided by a State's statutes or administrative rules. 28
• “Company” means PacifiCorp. 29
• “Contributions in Aid of Construction” or “CIAC” means contributions from customers to pay 30
their share of a capital construction project above the amount their retail rates justify. CIAC is a 31
reduction to rate base, (see Appendix C for more detail). 32
• “Customer Ancillary Services” means products or services that may be provided by a customer to 33
the Company, such as in which the Company has the right to curtail electric service to the customer 34
so as to lower the costs of operating the Company’s system. 35
• “Customer Ancillary Service Contracts” means contracts between the Company and a retail 36
customer pursuant to which the Company pays the customer for Customer Ancillary Services 37
• “Decommissioning Costs” means the costs of removal and environmental remediation or 38
reclamation - net of any salvage value realized - required at the time a generation resource is 39
physically retired. 40
• “Decommissioning Studies” means the engineering studies carried out in advance of planned coal-41
fueled Interim Period Resource Reassignment filings in February of 2021 and June of 2024, in order 42
to identify the final Decommissioning Cost liabilities of Exiting States, as specifically identified in 43
Section 4.3.1. 44
• “Demand-Related” describes capital and other fixed costs incurred by the Company in order to be 45
prepared to meet the maximum demand imposed upon its system. 46
• “Demand-Side Management Programs” or “DSM Programs” means programs intended to 47
reduce electricity use through activities or programs that promote electric energy efficiency or 48
conservation, more efficient management of electric energy loads, or reductions in peak demand. 49
• “Embedded Cost Differential” or “ECD” means the sum of PacifiCorp’s production costs of pre-50
2005 resources as defined in the 2010 Protocol, excluding west side hydro, Mid-Columbia Contracts, 51
and Qualified Facility contracts, referred to as "all other generation resources" expressed in dollars 52
per megawatt-hour compared to west hydro-electric resources production costs expressed in dollars 53
per megawatt-hour with the difference multiplied by the hydro-electric resources megawatt-hours 54
of production, and the differential between the all other generation resources dollars per megawatt-55
hour compared to Mid-Columbia Contracts costs dollars per megawatt-hour multiplied by the Mid-56
Columbia Contracts megawatt-hours. 57
◦ “Dynamic Embedded Cost Differential” or “Dynamic ECD” means the ECD components 58
are updated to the test period utilized in the filing. 59
◦ “Fixed Embedded Cost Differential” or “Fixed ECD” means the ECD amount for a State 60
is set at a point of time and not updated. 61
• “Energy Imbalance Market” or “EIM” means the multi-Balancing Authority Area (BAA) real-62
time market operated by the California Independent System Operator (CAISO) that balances 63
electricity supply and demand every five minutes by choosing the least-cost resource to serve system 64
load. 65
• “Energy-Related” means variable costs incurred by the Company in order to deliver the energy 66
required to serve customers. 67
• “Existing QF PPAs” is defined in Section 4.4.1 of the agreement. 68
69
• “Exit Date” means the date, established in an Exit Order entered by a Commission, on which 70
PacifiCorp intends to discontinue the allocation of costs and assignment of benefits of a coal-fueled 71
Interim Period Resource to the State issuing the Exit Order. 72
• “Exiting State” means a State with a final order from a State Commission approving the exit from 73
a coal-fueled Interim Period Resource on a date certain. 74
• “Exit Order” means an order entered by a Commission establishing an Exit Date consistent with 75
the 2020 Protocol. 76
• “Extended Day-Ahead Market” or “EDAM” means a market currently still in development that 77
will address ramping needs between intervals and uncertainty that can occur between the day-ahead 78
and real-time markets. 79
• “FERC” means the Federal Energy Regulatory Commission. 80
• “Five States” means the States of California, Idaho, Oregon, Utah, and Wyoming. 81
• “Fixed Costs” means costs incurred by the Company that do not vary with the amount of energy 82
delivered by the Company to its customers during any hour. 83
• “Framework” is defined in Section 1 of the Agreement. 84
• “Framework Issue” is defined in Section 1 of the Agreement. 85
• “General Plant” means capital investment included in FERC accounts 389 through 399. 86
• “Implemented Issues” is defined in Section 1 of the Agreement. 87
• “Intangible Plant” means capital investment included in FERC accounts 301 through 303. 88
• “Interim Period” is defined in Section 2 of the Agreement. 89
• “Interim Period Resource” means Resource in commercial operation, or with a contract delivery 90
date, as applicable, during the Interim Period. 91
• “Limited Realignment” means the assignment of Interim Period Resources among PacifiCorp 92
States that differ from assignment using the SGF Factor. 93
• “Load-Based Dynamic Allocation Factor” means an allocation factor that is calculated using 94
States’ monthly energy usage and/or States’ contribution to monthly system Coincident Peak. 95
• “Mid-Columbia Contracts” means the various power sales agreements between PacifiCorp and 96
Public Utility District No. 2 of Grant County, PacifiCorp and Douglas County Public Utility District, 97
and PacifiCorp and Chelan County Public Utility District, specifically: the Power Sales Contract 98
with Public Utility District No. 2 of Grant County dated May 22, 1956; the Power Sales Contract 99
with Public Utility District No. 2 of Grant County dated June 22, 1959; the Priest Rapids Project 100
Product Sales Contract with Public Utility District No. 2 of Grant County dated December 31, 2001; 101
the Additional Products Sales Agreement with Public Utility District No. 2 of Grant County dated 102
December 31, 2001; the Priest Rapids Project Reasonable Portion Power Sales Contract with Public 103
Utility District No. 2 of Grant County dated December 31, 2001; the Power Sales Contract with 104
Douglas County Public Utility District dated September 18, 1963; the Power Sales Contract with 105
Chelan County Public Utility District dated November 14, 1957, and all successor contracts thereto. 106
• “MSP Workgroup” means a group of regulators, the Company, and other interested stakeholders 107
that convenes to discuss the assignment or allocation of PacifiCorp revenues, costs, and investments 108
among the States. 109
• “Multi-State Process” or “MSP” means the ongoing Company-led convening of Parties from all 110
six States in which it operates to consider issues related to fair cost allocations among the States. 111
• “Net Power Costs” or “NPC” means PacifiCorp’s fuel and wheeling expenses and costs and 112
revenues associated with long-term Wholesale Contracts, Short-Term Purchases and Sales and Non-113
Firm Purchases and Sales. 114
“New QF PPA” is defined in Section 4.4.2 of the Agreement. 115
• “Nodal Pricing Model” or “NPM” means a method for pricing electricity proposed by the 116
Company that is based on the marginal cost ($/MWh) of serving the next increment of demand at a 117
given pricing node consistent with existing transmission constraints and the performance 118
characteristics of resources. 119
• “Nodal Pricing Model Memorandum of Understanding” or “NPM MOU” means the agreement 120
among the Parties on the prudence of the Company's proceeding to implement the Nodal Pricing 121
Model that may be adopted for the calculation of net power costs (NPC) through a new inter-122
jurisdictional cost-allocation methodology. 123
• “Non-Firm Purchases and Sales” means transactions at wholesale that are not Wholesale Contracts 124
or Short-Term Purchases and Sales. 125
• “Open Access Transmission Tariff” means PacifiCorp's Open Access Transmission Tariff on file 126
with FERC. 127
• “Operations and Maintenance” or “O&M” means costs incurred by the Company to maintain its 128
assets that are expensed as defined by FERC. 129
• “Oregon Direct Access Consumer” means Oregon retail electricity consumers that procure 130
electricity from a supplier other than PacifiCorp under an Oregon Direct Access Program. 131
• “Oregon Direct Access Program” means Oregon laws, regulations, and orders that permit 132
PacifiCorp’s Oregon retail consumers to purchase electricity directly from a supplier other than 133
PacifiCorp. 134
• “Party” or “Parties” means certain State Commission staff members, regulatory agencies, 135
customers, consumer advocates, conservation organizations, and other interested parties from 136
California, Idaho, Oregon, Utah, Washington, and Wyoming who have executed this Agreement. 137
• “Portfolio Standard” means a law or regulation that requires PacifiCorp to acquire: (a) a particular 138
type of Resource, (b) a particular quantity of Resources, (c) Resources in a prescribed manner or (d) 139
Resources located in a particular geographic area. 140
• “Post-Interim Period Method” means the resolution of the Framework Issues combined with the 141
Implemented Issues and the Resolved Issues are all intended to result in the new allocation 142
methodology for PacifiCorp's six States. 143
• “Post-Interim Period Resources” means Resources that begin commercial operation, or with a 144
contract or delivery date, as applicable, after the end of the Interim Period. 145
• “Qualifying Facility" or “QF” means small power production or cogeneration facilities developed 146
under the Public Utility Regulatory Policies Act of 1978 (PURPA) and related State laws and 147
regulations. 148
• “Qualifying Facility Power Purchase Agreement” or “QF PPA” means contracts to purchase the 149
output of a Qualifying Facility by the Company. 150
• “Reassignment”, “Reassign”, or “Reassigned” means assigning benefits from an Exiting State's 151
share of a coal-fueled Interim Period Resource to those States with Commission orders to accept the 152
cost responsibility allocation for the Exiting State’s portion of the coal-fueled Resource. 153
• “Resolved Issues” is defined in Section 1 of the Agreement. 154
• “Resource” means a Company-owned generating unit, plant, mine, long-term Wholesale Contract, 155
Short-Term Purchase and Sale, Non-firm Purchase and Sale, or QF contract. 156
• “Short-Term Firm Purchases and Firm Sales” means physical or financial contracts pursuant to 157
which PacifiCorp purchases, sells, or exchanges firm power at wholesale and Customer Ancillary 158
Service Contracts that are less than one year in duration. 159
• “Short-Term Purchases and Sales” means physical or financial contracts pursuant to which 160
PacifiCorp purchases, sells, or exchanges firm power at wholesale and Customer Ancillary Service 161
Contracts that are less than one year in duration. 162
• “Special Contract” means a contract entered into between PacifiCorp and one of its retail customers 163
with prices, terms, and conditions different from otherwise-applicable tariff rates. Special Contracts 164
may provide for a value consideration to the customer to reflect attributes of Customer Ancillary 165
Service Contracts. 166
• “State” means California, Oregon, Idaho, Utah, Washington, or Wyoming. 167
• “State Resources” means Interim Period Resources whose costs are assigned to a single 168
jurisdiction to accommodate jurisdiction-specific policy preferences. 169
• “System Energy Factor” or “SE Factor” is defined in Appendix C. 170
• “System Generation-Fixed Factor” or “SGF Factor” is defined in Appendix C. 171
• “System Gross Plant Distribution Factor” or “SGPD Factor” is defined in Appendix C. 172
• “System Net Plant-Distribution Factor” or “SNPD Factor” is defined in Appendix C. 173
• “System Overhead Factor" or “SO Factor” is defined in Appendix C. 174
• “System Resources” means Interim Period Resources that are not State Resources and whose 175
associated costs and revenues are allocated among all States on a dynamic basis. 176
• “System Transmission Factor” or “ST Factor” is defined in Appendix C. 177
• “Trojan Decommissioning” means costs associated with decommissioning the Trojan Plant. 178
• “Trojan Decommissioning Fixed Factor” or (“TROJDF”) is defined in Appendix C. 179
• “Trojan Plant” means the now-decommissioned nuclear plant for which the Company is still 180
recovering costs. 181
• “Variable Costs” means costs incurred by the Company that vary with the amount of energy 182
delivered by the Company to its customers during any hour. 183
• “Washington Public Utility Tax” means a Washington tax on public service businesses, including 184
businesses that engage in transportation, communications, and the supply of energy, natural gas, and 185
water. The tax is in lieu of the business and occupation (B&O) tax. 186
• “West Control Area Inter-jurisdictional Allocation Methodology” or “WCA” means the 187
allocation protocol methodology used by Washington to allocate costs consistent with its Balancing 188
Area Authority-based principles governing the assets deemed to serve Washington. 189
•“Wholesale Contracts” means physical or financial contracts pursuant to which PacifiCorp 190
purchases, sells, or exchanges firm power at wholesale and Customer Ancillary Service Contracts.191
APPENDIX B
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
440
Retail Revenues Direct assigned - Jurisdiction S S
Commercial & Industrial Sales
Retail Revenues Direct assigned - Jurisdiction S S
Public Street & Highway Lighting
Retail Revenues Direct assigned - Jurisdiction S S
Other Sales to Public Authority
Retail Revenues Direct assigned - Jurisdiction S S
Retail Revenues Direct assigned - Jurisdiction S S
Wholesale Sales Direct assigned - Jurisdiction S S
Non-Firm SE AP, NP
Firm SG AP, NP
Provision for Rate Refund
Direct assigned - Jurisdiction S S
Transmission SG ST
Other Electric Operating Revenues
450 Forfeited Discounts & Interest
Retail Revenues Direct assigned - Jurisdiction S S
Misc Electric Revenue
Retail Revenues Direct assigned - Jurisdiction S S
Other - Common SO SO
Retail Revenues Direct assigned - Jurisdiction SG AP
Rent of Electric Property
Retail Revenues Direct assigned - Jurisdiction S S
Common SG ST
Other - Common SO SO
Other Electric Revenue
Retail Revenues Direct assigned - Jurisdiction S S
Wheeling Non-firm, Other SE ST
Common SO SO
Wheeling - Firm, Other SG ST
Customer Related CN CN
Interdepartmental
Water Sales
Allocation Factors by Account by Revenue Requirement Components
2020 Protocol - Appendix B
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
41160 Gain on Sale of Utility Plant - CR
Distribution S S
Production SG AP
Transmission SG ST
General Office SO SO
Loss on Sale of Utility Plant
Distribution S S
Production SG AP
Transmission SG ST
General Office SO SO
Gain from Emission Allowances
SO2 Emission Allowance sales SE AP
Gain from Disposition of NOX Credits
NOX Emission Allowance sales SE AP
(Gain) / Loss on Sale of Utility Plant
Distribution S S
Production SG AP
Transmission SG ST
General Office SO SO
Customer Related CN CN
Miscellaneous Expenses
4311 Interest on Customer Deposits
Customer Service Deposits CN CN
Direct assigned - Jurisdiction S S
Steam Power Generation
500, 502, 504-514 Operation Supervision & Engineering
Steam Plants O&M SG AP, APOMS
Steam plants Fuel SE AP, APOMS
Steam From Other Sources
Steam Royalties SE AP, APOMS
Nuclear Power Generation
517 - 532
Nuclear Plants O&M SG AP
Hydraulic Power Generation
535 - 545
Pacific Hydro O&M SG AP, APOMH
East Hydro O&M SG AP, APOMH
Other Power Generation
546, 548-554 Operation Super & Engineering
Other Production Plant SG AP, APOMO
Other Fuel Expense SE AP, APOMO
Fuel Related
Nuclear Power O&M
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
555
Tracking Mechanisms S S
Firm SG AP, NP
Non-firm SE AP, NP
System Control & Load Dispatch
Other Expenses SG SE
Direct assigned - Jurisdiction S S
Other Expenses SE SE
Other Expenses SG APOMS, APOMH, APOMO
Cholla Transaction SGCT AP
TRANSMISSION EXPENSE
560-564, 566-573
Transmission Plant O&M SG ST
Transmission of Electricity by Others
Firm Wheeling SG ST
Non-Firm Wheeling SE ST
GRID Management Charge SG SE
DISTRIBUTION EXPENSE
580 - 598
Direct assigned - Jurisdiction S S
Other Distribution SNPD SNPD
CUSTOMER ACCOUNTS EXPENSE
901 - 905 Customer Accounts O&M
Direct assigned - Jurisdiction S S
Total System Customer Related CN CN
CUSTOMER SERVICE EXPENSE
907 - 910 Customer Service O&M
Direct assigned - Jurisdiction S S
Total System Customer Related CN CN
SALES EXPENSE
911 - 916
Direct assigned - Jurisdiction S S
Total System Customer Related CN CN
ADMINISTRATIVE & GEN EXPENSE
920-935 Administrative & General Expense
Direct assigned - Jurisdiction S S
Customer Related CN CN
Mine SE AP
FERC Regulatory Expense SG ST
General SO SO
Transmission O&M
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
403SP
Steam Plants SG AP
Nuclear Plant SG AP
Pacific Hydro SG AP
East Hydro SG AP
Other Production Depreciation
Other Production Plant SG AP
Transmission Depreciation
Transmission Plant SG ST
Distribution Depreciation Direct assigned - Jurisdiction
Land & Land Rights S S
Structures S S
Station Equipment S S
Storage Battery Equipment S S
Poles & Towers S S
OH Conductors S S
UG Conduit S S
UG Conductor S S
Line Trans S S
Services S S
Meters S S
Inst Cust Prem S S
Leased Property S S
Street Lighting S S
Distribution S S
Steam Plants SG AP
Mining SE AP
Pacific Hydro SG AP
East Hydro SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Mining Plant SE AP
Hydro Depreciation
General Depreciation
Mining Depreciation
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
404GP Amort of LT Plant - Capital Lease Gen
Direct assigned - Jurisdiction S S
General SO SO
Customer Related CN CN
Amort of LT Plant - Cap Lease Steam
Steam Production Plant SG AP
Amort of LT Plant - Intangible Plant
Distribution S S
Production SG AP
Transmission SG ST
General SO SO
Mining Plant SE AP
Customer Related CN CN
Amort of LT Plant - Mining Plant
Mining Plant SE AP
Amortization of Other Electric Plant
Pacific Hydro SG AP
East Hydro SG AP
Amortization of Other Electric Plant
Direct assigned - Jurisdiction S S
Amortization of Plant Acquisition Adj
Direct assigned - Jurisdiction S S
Production Plant SG AP
Amort of Prop Losses, Unrec Plant, etc.
Direct assigned - Jurisdiction S S
Production, SG AP
Transmission SG ST
Taxes Other Than Income
408 Taxes Other Than Income
Direct assigned - Jurisdiction S S
Property GPS GPS
System Taxes SO SO
Misc Energy SE AP
Misc Production SG AP
DEFERRED ITC
41140 Deferred Investment Tax Credit - Fed
ITC DGU DGUF
Deferred Investment Tax Credit - Idaho
ITC DGU DGUF
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
427 Interest on Long-Term Debt
Direct assigned - Jurisdiction S S
Interest Expense SNP SNP
Amortization of Debt Disc & Exp
Interest Expense SNP SNP
Amortization of Premium on Debt
Interest Expense SNP SNP
Other Interest Expense
Interest Expense SNP SNP
AFUDC SNP SNP
Interest & Dividends
419
Interest & Dividends SNP SNP
DEFERRED INCOME TAXES
41010 Deferred Income Tax - DR
Direct assigned - Jurisdiction S S
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
Bad Debt BADDEBT BADDEBT
Tax Depreciation TAXDEPR TAXDEPR
Interest & Dividends
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
41110 Deferred Income Tax -CR
Direct assigned - Jurisdiction S S
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
Contributions in Aid of Construction CIAC CIAC
Production, Other SGCT AP
Book Depreciation SCHMDEXP SCHMDEXP
SCHEDULE - M ADDITIONS
SCHMAF Additions - Flow Through
Direct assigned - Jurisdiction S S
Additions - Permanent
Direct assigned - Jurisdiction S S
Mining related SE AP
General SO SO
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Depreciation SCHMDEXP SCHMDEXP
Additions - Temporary
Direct assigned - Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Contributions in Aid of Construction CIAC CIAC
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Non-Coal and Gas Production SG AP
Mining Plant SE AP
Coal and Gas Production SG AP
Transmission SG ST
Property Tax GPS GPS
General SO SO
Depreciation SCHMDEXP SCHMDEXP
Distribution SNPD SNPD
Production, Other SGCT AP
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
SCHMDF Deductions - Flow Through
Direct Assigned - Jurisdiction S S
Coal and Gas Production SG AP
Transmission SG ST
Non-Coal and Gas Production SG AP
Deductions - Permanent
Direct Assigned - Jurisdiction S S
Mining Related SE AP
Depreciation SCHMDEXP SCHMDEXP
Miscellaneous SNP SNP
General SO SO
Deductions - Temporary
Direct Assigned - Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Miscellaneous SNP SNP
Non-Coal and Gas Production SG AP
Mining related SE AP
Coal and Gas Production SG AP
Transmission SG ST
Property Tax GPS GPS
General SO SO
Depreciation TAXDEPR TAXDEPR
Distribution SNPD SNPD
Customer Related CN CN
State Income Taxes
40911
40911 Income Before Taxes CALCULATED CALCULATED
Renewable Energy Tax Credit SG AP
FIT True-up S S
Renewable Energy / Production Tax Credit SG AP
PacifiCorp Minerals Inc.SE AP
Foreign Tax Credit SO SO
Steam Production Plant
310 - 316
Steam Plants SG AP
Nuclear Production Plant
320-325
Nuclear Plant SG AP
Hydraulic Plant
330-336
Pacific Hydro SG AP
East Hydro SG AP
Steam Plants
Nuclear Plant
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
340-346 Other Production Plant
Other Production Plant - Situs S S
Other Production Plant SG AP
TRANSMISSION PLANT
350-359
Transmission Plant SG ST
DISTRIBUTION PLANT
360-373
Direct assigned - Jurisdiction S S
GENERAL PLANT
389 - 398
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP, SE
Transmission SG ST
Customer Related CN CN
General SO SO
Mining SE AP
Mining Plant SE AP
General Gas Line Capital Leases
Capital Lease SG AP
General Capital Leases
Direct assigned - Jurisdiction S S
General SO SO
Generation SG AP
Transmission SG ST
INTANGIBLE PLANT
301
Direct assigned - Jurisdiction S S
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
Miscellaneous Intangible Plant
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Mining SE AP
Other SG SGF
Organization
Franchise & Consent
Distribution Plant
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
303
Direct assigned - Jurisdiction S S
Rate Base Additions
105 Plant Held For Future Use
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
Mining Plant SE AP
Electric Plant Acquisition Adjustments
Direct assigned - Jurisdiction S S
Production Plant SG AP
Transmission SG ST
Accum Provision for Asset Acquisition Adjustments
Direct assigned - Jurisdiction S S
Production Plant SG AP
Transmission SG ST
Direct assigned - Jurisdiction S S
General SO SO
General SO SO
Direct assigned - Jurisdiction S S
Direct assigned - Jurisdiction S S
Steam Production Plant SE AP
Fuel Stock - Undistributed
Steam Production Plant SE AP
UAMPS Working Capital Deposit
Mining Plant SE AP
DG&T Working Capital Deposit
Mining Plant SE AP
Provo Working Capital Deposit
Mining Plant SE AP
Weatherization
Pensions
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
154 Materials and Supplies
Direct assigned - Jurisdiction S S
Production, SG AP
Transmission SG ST
Mining SE AP
Production - Common SG AP
General SO SO
Distribution SNPD SNPD
Production, Other SG AP
Stores Expense Undistributed
General SO SO
Provo Working Capital Deposit
Provo Working Capital Deposit SG AP
Direct assigned - Jurisdiction S S
Property Tax GPS GPS
Production SG AP
Transmission SG ST
Mining SE AP
General SO SO
Misc Regulatory Assets
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
Mining SE AP
General SO SO
Production, Other SGCT AP
Other SG SGF
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Production - Common SG AP
Other SG SGF
Working Capital
CWC
Direct assigned - Jurisdiction S S
Cash SNP SNP
Working Funds SG AP
Notes Receivable SO SO
Other Accounts Receivable SO SO
Cash Working Capital
Misc Deferred Debits
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
232 Accounts Payable SO SO
Accounts Payable SE AP
Accounts Payable SG ST, AP, SGF
Other Deferred Credits - Misc SE AP
Other Deferred Credits - Misc SE AP
ARO Reg Liability SE AP
Rate Base Deductions
235 Customer Service Deposits
Direct assigned - Jurisdiction S S
Prov for Property Insurance
Prov for Property Insurance SO SO
Prov for Injuries & Damages
Prov for Injuries & Damages SO SO
Prov for Pensions and Benefits
Prov for Pensions and Benefits SO SO
Accum Misc Oper Prov-Black Lung
Other Production SG AP
FAS 143 ARO Regulatory Liability
ARO S S
Trojan Plant TROJD TROJDF
Asset Retirement Obligation
Trojan Plant TROJD TROJDF
Customer Advances for Construction
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
Customer Related CN CN
S02 Emissions SE AP
Other Deferred Credits
Direct assigned - Jurisdiction S S
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Insurance Provision SO SO
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
190 Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
Accumulated Deferred Income Taxes
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction S S
Depreciation DITBAL DITBAL
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Depreciation TAXDEPR TAXDEPR
Depreciation SCHMDEXP SCHMDEXP
System Gross Plant GPS GPS
Contribution in Aid of Construction CIAC CIAC
Mining SE AP
Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction S S
Depreciation DITBAL DITBAL
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Production, Other SGCT AP
Property Tax GPS GPS
Mining Plant SE AP
Accumulated Investment Tax Credit
Direct assigned - Jurisdiction S S
Investment Tax Credits ITC84 ITC84
Investment Tax Credits ITC85 ITC85
Investment Tax Credits ITC86 ITC86
Investment Tax Credits ITC88 ITC88
Investment Tax Credits ITC89 ITC89
Investment Tax Credits ITC90 ITC90
Investment Tax Credits SG SGF
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
108SP Steam Prod Plant Accumulated Depr
Steam Plants SG AP
Nuclear Prod Plant Accumulated Depr
Nuclear Plant SG AP
Hydraulic Prod Plant Accum Depr
Pacific Hydro SG AP
East Hydro SG AP
Other Production Plant - Accum Depr
Other Production Plant SG AP
TRANS PLANT ACCUM DEPR
108TP Transmission Plant Accumulated Depr
Transmission Plant SG ST
DISTRIBUTION PLANT ACCUM DEPR
108360 - 108373 Distribution Plant Accumulated Depr
Direct assigned - Jurisdiction S S
Unclassified Dist Plant - Acct 300
Direct assigned - Jurisdiction S S
Unclassified Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction S S
Unclassified Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction S S
GENERAL PLANT ACCUM DEPR
108GP General Plant Accumulated Depr.
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO SO
Mining Plant SE AP
Mining Plant Accumulated Depr.
Mining Plant SE AP
Accum Depr - Capital Lease
General SO SO
Accum Depr - Capital Lease
Direct assigned - Jurisdiction S S
2020 Protocol - Appendix B
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
111SP Accum Prov for Amort-Steam
Steam Plants SG AP
Accum Prov for Amort-General
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO SO
Accum Prov for Amort-Hydro
Pacific Hydro SG AP
East Hydro SG AP
Accum Prov for Amort-Intangible Plant
Distribution S S
Pacific Hydro SG AP
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Customer Related CN CN
Direct assigned - Jurisdiction S S
Accum Prov Amort - Capital Leases
Distribution S S
Production SG AP
General SO SO
2020 Protocol - Appendix B
APPENDIX C
Definitions of Allocation Factors
Factors without an effective period will be used during and after the Interim Period.
i denotes count of jurisdictions. j denotes count of month in a year. N is the number of regulatory
jurisdictions that the Company operates in and allocates costs to.
Assigned Production Factor (“AP”) – Effective after Interim Period 𝐴𝐴𝐴𝐴𝑖𝑖=𝑆𝑆𝑆𝑆𝑆𝑆𝑖𝑖∑𝑆𝑆𝑆𝑆𝑆𝑆𝑖𝑖𝑥𝑥𝑖𝑖=1
where: APi = Assigned Production Factor for jurisdiction i.
SGFi = System Generation – Fixed Factor for jurisdiction i.
x = Number of jurisdictions that are assigned the unit.
The AP factor may be calculated by unit of Resources, group of Resources, or for specific periods of capital investments. The AP factor may change over time as allocations change due to jurisdictions accepting a larger or smaller assignment in units that lead to the change in the value of x.
For example, 1. Assuming a unit is assigned to States A, B and C out of six jurisdictions in year 1, and theirSGF factors are
SGFA = 25%, SGFB = 45%, and SGFC = 15%, respectively, then 𝐴𝐴𝐴𝐴𝐴𝐴=25%25%+45%+15%=29.4%
𝐴𝐴𝐴𝐴𝐵𝐵=45%25%+45%+15%=52.9%
𝐴𝐴𝐴𝐴𝐶𝐶=15%25%+45%+15%=17.6%
2.Assuming the unit is later assigned to States B and C only, then the AP factors will change to𝐴𝐴𝐴𝐴𝐴𝐴=0% 𝐴𝐴𝐴𝐴𝐵𝐵=45%45%+15%=75%
𝐴𝐴𝐴𝐴𝐶𝐶=15%45%+15%=25%
3.Assuming the unit is later assigned to C only, then the AP factors will change to𝐴𝐴𝐴𝐴𝐴𝐴=0% 𝐴𝐴𝐴𝐴𝐵𝐵=0% 𝐴𝐴𝐴𝐴𝐶𝐶=15%15%=100%
Accounts using AP factor: Sales for Resale (447), Water Sales (453), Miscellaneous Revenue (41160,
41170, 4118, 41181, 421), Generation (500-555, 557), Administrative and General Expense (920-935), Depreciation Expense (403SP, 403NP, 403HP, 403OP, 403GP, 403MP) Amortization Expense (404SP, 404IP, 404HP, 404MP 406-407), Taxes Other Than Income (408), Deferred Income Tax Expense (41010, 41110), Schedule M, Income Taxes (40910, 40911), Generation Plant (310-346), General Plant (389-399), Intangible Plant (302-303), Plant Held for Future Use (105), Electric Plant Acquisition Adjustments (114-
115), Fuel Stock (151-152), Materials and Supplies (154), Mining Working Capital Deposits (25316-25319), Prepayments (165), Misc. Regulatory Assets (182M), Misc. Deferred Debits (186M), Working Capital (135, 232, 25330, 230, 245105), Accum Misc Oper Prov-Black Lung (22841), Customer Advances for Construction (252), SO2 Emissions (25398), Other Deferred Credits (25399), Regulatory Liabilities ARO Regulatory Liability (254105), Accumulated Deferred Income Taxes (190, 281-283),
Accumulated Depreciation (108SP, 108NP, 108HP, 108OP, 108GP, 108MP), Accumulated Provision for
Amortization (111SP, 111GP, 111HP, 111IP, 111390)
Assigned Production Factor of New Resources – Effective after Interim Period Initial values of AP factors for all new resources will be addressed as part of the Framework discussions
on Resource Planning.
Assigned Production Hydro – O&M Factor (“APOMH”) – Effective after Interim Period 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖=𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖∑𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1where: APOMHi = Assigned Production Hydro O&M Factor for jurisdiction i. PPOMHi = Sum of all hydro production plant O&M costs allocated to
jurisdiction i using the AP factors.
N = Number of jurisdictions.
The APOMH factor is used to allocate hydro generation related O&M costs that cannot be allocated to a specific hydro resource through an AP factor, calculated as each States’ relative share of direct-allocated
hydro generation and maintenance expenses.
Accounts using APOMH factor: Hydro (535-545, 557)
Assigned Production Other – O&M Factor (“APOMO”) – Effective after Interim Period 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖=𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖∑𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1where: APOMOi = Assigned Production Other O&M Factor for jurisdiction i.
PPOMOi = Sum of all other production plant O&M costs allocated to
jurisdiction i using the AP factors.
N = Number of jurisdictions. The APOMO factor is used to allocate other generation related O&M costs that cannot be allocated to specific other production Resource through an AP factor, calculated as each States’ relative share of
directly-allocated other production generation and maintenance expenses. Accounts using APOMO factor: Other Generation (546-554, 557) Assigned Production Steam – O&M Factor (“APOMS”) – Effective after Interim Period 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑆𝑆𝑖𝑖=𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑆𝑆𝑖𝑖∑𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑆𝑆𝑖𝑖𝑁𝑁𝑖𝑖=1
where:
APOMSi = Assigned Production Steam O&M Factor for jurisdiction i.
PPOMSi = Sum of all steam production plant O&M costs allocated to jurisdiction i using the AP factors. N = Number of jurisdictions.
The APOMS factor is used to allocate steam generation related O&M costs that cannot be allocated to
specific steam resource through an AP factor, calculated as each States’ relative share of direct-allocated steam generation and maintenance expenses. Accounts using APOMS factor: Generation (500-514, 557)

Bad Debt Expense Factor (“BADDEBT”)
𝐵𝐵𝐴𝐴𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝑖𝑖=𝐴𝐴𝐴𝐴𝐴𝐴𝐵𝐵904𝑖𝑖∑𝐴𝐴𝐴𝐴𝐴𝐴𝐵𝐵904𝑖𝑖𝑁𝑁𝑖𝑖=1
where: BADDEBTi = Bad Debt Expense Factor for jurisdiction i. ACCT904i = Balance in FERC Account 904 for jurisdiction i.
N = Number of jurisdictions.
The BADDEBT Factor is calculated by dividing the FERC account 904 Uncollectible Accounts amount for a jurisdiction by the total 904 amount for all jurisdictions. The factor allocates tax related costs for bad debt related expenses.
Accounts using BADDEBT factor: Deferred Income Tax Expense (41010), Schedule M, Accumulated Deferred Income Taxes (190) Contributions in Aid of Construction Factor (“CIAC”) 𝐴𝐴𝐶𝐶𝐴𝐴𝐴𝐴𝑖𝑖=𝐴𝐴𝐶𝐶𝐴𝐴𝐴𝐴𝐶𝐶𝐴𝐴𝑖𝑖∑𝐴𝐴𝐶𝐶𝐴𝐴𝐴𝐴𝐶𝐶𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1
where:
CIACi = Contributions in Aid of Construction Factor for jurisdiction i.
CIACNAi = Contributions in aid of construction – net additions for jurisdiction i.
N = Number of jurisdictions.
The CIAC Factor is calculated by dividing the contribution in aid of construction net additions for a jurisdiction by the total contribution in aid of construction net additions for all jurisdictions. The factor allocates tax related costs for contributions in aid of construction.
Accounts using CIAC factor: Deferred Income Tax Expense (41110), Schedule M, Accumulated Deferred Income Taxes (282) Customer Number Factor (“CN”) 𝐴𝐴𝐶𝐶𝑖𝑖=𝐴𝐴𝐶𝐶𝑆𝑆𝐵𝐵𝑖𝑖∑𝐴𝐴𝐶𝐶𝑆𝑆𝐵𝐵𝑖𝑖𝑁𝑁𝑖𝑖=1
where:
CNi = Customer Number Factor for jurisdiction i.
CUSTi = Total electric customers for jurisdiction i. N = Number of jurisdictions. The Customer Number Factor is calculated using the ratio of number of customers for a jurisdiction to the
total number of electric customers for all jurisdictions. The factor is used to allocate customer related costs. Accounts using CN factor: Gain / Loss on Sale of Utility Plant (421), Customer Service Deposits (4311), Other Electric Revenue (456), Customer Account Expense (901-905), Customer Service Expense (907-
910), Sales Expense (911-916), Administrative and General Expense (920-935), General Plant Depreciation (403GP), Amortization Intangible Plant (404IP), Deferred Income Tax Expense (41010, 41110), Schedule M, General Plant (389-398), Intangible Plant (303), Customer Advances for Construction (252), Accumulated Deferred Income Taxes (190, 282-283), General Plant Accumulated Depreciation (108GP), Accumulated Provision for Amortization (111IP)

Deferred Tax Balance Factor (“DITBAL”) 𝐵𝐵𝐶𝐶𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝑖𝑖=𝐵𝐵𝐶𝐶𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖∑𝐵𝐵𝐶𝐶𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1
where:
DITBALi = Deferred Tax Balance Factor for jurisdiction i. DITBALAi = Deferred tax balance allocated to jurisdiction i. (Deferred tax balance is allocated by a run of PowerTax based upon the above factors. PowerTax is a computer software package used to
track deferred tax expense & deferred tax balance.)
N = Number of jurisdictions. The DITBAL Factor is used to allocate deferred tax balances to jurisdictions.
Accounts using DITBAL factor: Accumulated Deferred Income Taxes (282, 283)

Division Generation – Pacific Factor (“DGP”) 𝐵𝐵𝑆𝑆𝐴𝐴𝑖𝑖=𝑆𝑆𝑆𝑆∗𝑖𝑖∑𝑆𝑆𝑆𝑆∗𝑖𝑖𝑁𝑁𝑖𝑖=1
where: DGPi = Division Generation – Pacific Factor for jurisdiction i. SG*i = SGi if i is a pre-merger Pacific Power jurisdiction, otherwise 0.
SGi = System Generation Factor for jurisdiction i.
N = Number of jurisdictions. The DGP Factor is calculated as the ratio of the pre-merger Pacific Division’s SG factor for a jurisdiction divided by the sum of the pre-merger Pacific Division’s SG factors.
The DGP factor is only used in calculating the dynamic ECD Division Generation – Utah Factor (“DGU”) 𝐵𝐵𝑆𝑆𝐶𝐶𝑖𝑖=𝑆𝑆𝑆𝑆∗𝑖𝑖∑𝑆𝑆𝑆𝑆∗𝑖𝑖𝑁𝑁𝑖𝑖=1
where:
DGUi = Division Generation – Utah Factor for jurisdiction i. SG*i = SGi if i is a pre-merger Utah Power jurisdiction, otherwise 0. SGi = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
After the Interim Period, the factor is determined by the average of the four-year historical value from 2018 to 2021, or 2019 to 2022 if the Interim Period is extended. The DGU Factor is calculated as the ratio of the pre-merger Utah Power jurisdiction’s SG factor for a
jurisdiction divided by the sum of the pre-merger Utah Power jurisdiction’s SG factors.
The only accounts using DGU factor are Deferred Investment Tax Credits (41140, 41141) Gross Plant System Factor (“GPS”) 𝑆𝑆𝐴𝐴𝑆𝑆𝑖𝑖=𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖∑(𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖)𝑁𝑁𝑖𝑖=1
where: GPSi = Gross Plant System Factor for jurisdiction i.
PPi = Production plant for jurisdiction i.
PTi = Transmission plant for jurisdiction i.
PDi = Distribution plant for jurisdiction i. PGi = General plant for jurisdiction i. PIi = Intangible plant for jurisdiction i.
N = Number of jurisdictions.
The GPS Factor is used to allocate property taxes. It is calculated using the ratio of gross plant for a jurisdiction divided by the total gross plant for all jurisdictions.
The accounts using GPS factor: Taxes Other Than Income Taxes (408), Deferred Income Tax Expense
(41010, 41110), Schedule M, Prepayments (165), Accumulated Deferred Income Taxes (282, 283)
Nodal Pricing Assignment of Net Power Costs (“NP”)
Costs listed as allocated by NP in Appendix B are costs that will be allocated through the Nodal Pricing Model.
Accounts using NP factor: Sales for Resale (447), Purchased Power (555)
Schedule M – Depreciation Expense Factor (“SCHMDEXP”) 𝑆𝑆𝐴𝐴𝐴𝐴𝐴𝐴𝐵𝐵𝑖𝑖=𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖∑𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1where:
SCHMDi = Schedule M – Depreciation Expense Factor for jurisdiction i.
DEPRCi = Depreciation in FERC Accounts 403.1 - 403.9 for jurisdiction i. N = Number of jurisdictions.
The SCHMDEXP factor is used to allocate Schedule M items related to depreciation expense.
The accounts using SCHMDEXP factor: Deferred Income Tax Expense (41110), Schedule M, Accumulated Deferred Income Taxes (282)
System Capacity Factor (“SC”) 𝑆𝑆𝐴𝐴𝑖𝑖=∑𝐵𝐵𝐴𝐴𝐴𝐴𝑖𝑖𝑖𝑖12𝑖𝑖=1∑ ∑𝐵𝐵𝐴𝐴𝐴𝐴𝑖𝑖𝑖𝑖12𝑖𝑖=1𝑁𝑁𝑖𝑖=1where: SCi = System Capacity Factor for jurisdiction i. TAPij = Weather-normalized peak load of jurisdiction i at the time of the
system peak in month j. During the Interim Period, the peak load is
further adjusted to exclude the peak load of Class 1 Demand Side Management programs and interruptible peak load of the special contracts as defined in the 2017 Protocol. N = Number of jurisdictions.
The SC factor is calculated based on the relative capacity requirements of each State as determined based on 12 monthly Coincident Peaks that is used to calculate the System Generation and System Transmission factors
System Energy Factor (“SE”)
𝑆𝑆𝐵𝐵𝑖𝑖=∑𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖𝑖𝑖12𝑖𝑖=1∑ ∑𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖𝑖𝑖12𝑖𝑖=1𝑁𝑁𝑖𝑖=1where:
SEi = System Energy Factor for jurisdiction i.
TAEij = Weather-normalized energy at input of jurisdiction i in month j.
N = Number of jurisdictions.
The SE factor is used to allocate energy-related costs and is calculated as the ratio of the weather-
normalized energy at input for a jurisdiction divided by the total weather-normalized energy at input for all jurisdictions.
Accounts using SE factor for Interim period: Sales for Resale (447), Other Electric Revenue (456), Miscellaneous Revenue (4118, 41181), Steam Plants Fuel (501), Steam from Other Sources (503), Other
Fuel Expense (547), Purchased Power (555), Transmission of Electricity by Others (565), Administrative and General Expense (920-935), Depreciation Expense (403MP), Amortization Expense (404IP, 404MP),Taxes Other Than Income (408), Deferred Income Tax Expense (41010, 41110), Schedule M, Federal Income Tax True-Up (40910), General Plant (389-399), Intangible Plant (303), Plant Held for Future Use (105), Fuel Stock (151, 152), Working Capital – Mining related (25316, 25317, 25319),
Materials and Supplies (154), Prepayments – Mining related (165), Misc. Regulatory Assets – Mining Related (182M), Misc. Deferred Debits – Mining related (186M), Accounts Payable (232), Other Deferred Credits Misc. (25330, 230, 25399), ARO Regulatory Liability (254105), SO Emissions (25398), Regulatory Liabilities (254), Accumulated Deferred Income Taxes (190, 282-283), General Plant Accumulated Depreciation 108GP, Accumulated Provision for Amortization (111IP, 111MP)
Accounts using SE factor after Interim period: System Control & Load Dispatch (556), Other Expenses (557), Transmission of Electricity by Others - GRID Management Charge (565)
System Generation Factor (“SG”) – Effective during the Interim Period 𝑆𝑆𝑆𝑆𝑖𝑖= 0.75 ∗𝑆𝑆𝐴𝐴𝑖𝑖+ 0.25 ∗𝑆𝑆𝐵𝐵𝑖𝑖
where:
SGi = System Generation Factor for jurisdiction i. SCi = System Capacity Factor for jurisdiction i. SEi = System Energy Factor for jurisdiction i.
The SG factor is used to allocate generation and transmission costs. It is calculated using a weighting of
75% of the SC factor and 25% of the SE factor for a jurisdiction.
Accounts using the SG factor: Sales for Resale (447), Provision for Rate Refund (449), Other Electric
Operating Revenue (453, 454 ,456), Miscellaneous Revenue (41160, 41170, 421), Generation Expense
(500, 502, 504-514, 517-532, 535-545, 546, 548-554, 555, 556, 557), Transmission Expense (560-564,
566-573, 565), Administrative and General Expense (920-935), Depreciation Expense (403SP, 403NP,
403HP, 403OP, 403TP, 403GP), Amortization Expense (404SP, 404HP, 404IP 406, 407), Taxes Other
Than Income (408), Deferred Income Tax Expense, (41010, 41110), Schedule M, Renewable Energy Tax
Credit (40911), Federal Income Tax True-Up (40910), Generation Plant (310-316, 320-325, 330-336, 340-
346), Transmission Plant (350-359), General Plant (389-398, 1011390), Intangible Plant (302-303), Plant
Held for Future Use (105), Electric Plant Acquisition Adjustments (114-115), Materials and Supplies
(154), Working Capital Deposit (25318), Prepayments (165), Misc. Regulatory Assets (182M), Misc.
Deferred Debits (186M), Working Capital (135, 232), Accumulated Misc. Operating Provision Other
(22841), Customer Advances for Construction (252), Other Deferred Debits (25399), Accumulated
Deferred Income Taxes (190, 281-283), Accumulated Investment Tax Credit (255), Accumulated
Depreciation (108SP, 108HP, 108OP, 108TP, 108GP), Accumulated Provision for Amortization (111SP,
111GP, 111HP, 111IP, 111390)
System Generation Factor – Fixed (“SGF”) – Effective after Interim Period
Based on actual SG allocation factors for the most recent four calendar years available prior to the end of
the Interim Period. The SGi factor is as defined above.) 𝑆𝑆𝑆𝑆𝑆𝑆𝑖𝑖=PY1𝑆𝑆𝑆𝑆𝑖𝑖+ PY2𝑆𝑆𝑆𝑆𝑖𝑖+ PY3𝑆𝑆𝑆𝑆𝑖𝑖+ PY4𝑆𝑆𝑆𝑆𝑖𝑖4where:
SGFi = System Generation – Fixed Factor for jurisdiction i.
Prior Year (PY) 1 SGi = PY1 System Generation Factor for jurisdiction i.
Prior Year (PY) 2 SGi = PY2 System Generation Factor for jurisdiction i.
Prior Year (PY) 3 SGi = PY3 System Generation Factor for jurisdiction i.
Prior Year (PY) 4 SGi = PY4 System Generation Factor for jurisdiction i.
For Example: If the Interim Period ends December 31, 2023, then (PY) 1 = calendar year 2022, (PY) 2 = calendar year 2021, (PY) 3 = calendar year 2020, and (PY) 4 = calendar year 2019.
Accounts using SGF factor: Intangible Plant (303), Misc. Regulatory Assets (182M), Misc. Deferred
Debits (186M), Working Capital (232), Accumulated Investment Tax Credit (255)
System Gross Plant Distribution Factor (“SGPD”) – Effective after Interim Period 𝑆𝑆𝑆𝑆𝐴𝐴𝐵𝐵𝑖𝑖= 𝑆𝑆𝐴𝐴𝐵𝐵𝑖𝑖∑𝑆𝑆𝐴𝐴𝐵𝐵𝑖𝑖𝑁𝑁𝑖𝑖=1where:
SGPDi = System Gross Plant Distribution Factor for jurisdiction i.
GPDi = Gross plant distribution for jurisdiction i.
N = Number of jurisdictions.
This factor is calculated by taking the ratio of gross distribution plant for a jurisdiction by the total gross
distribution plant for all jurisdictions.
There are no accounts allocated using the SGPD factor. This factor is used to calculate the SO factor after the Interim period.
System Net Plant - Distribution Factor (“SNPD”) 𝑆𝑆𝐶𝐶𝐴𝐴𝐵𝐵𝑖𝑖=𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖∑(𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖)𝑁𝑁𝑖𝑖=1where:
SNPDi = System Net Plant – Distribution Factor for jurisdiction i.
PDi = Distribution plant – for jurisdiction i.
ADPDi = Accumulated depreciation distribution plant - for jurisdiction i. N = Number of jurisdictions.
The SNPD factor is used to allocate non situs distribution costs. The factor is calculated as the ratio of net
distribution plant for a jurisdiction by the total net distribution plant for all jurisdictions.
Accounts using the SNPD factor: Distribution O&M (580-598), Deferred Income Tax Expenses (41010,
41110), Schedule M, Materials and Supplies – Distribution (154), Accumulated Deferred Income Taxes (190) System Net Plant Factor (“SNP”) 𝑆𝑆𝐶𝐶𝐴𝐴𝑖𝑖=𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐴𝐴𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝑆𝑆𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐶𝐶𝑖𝑖∑(𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐴𝐴𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐵𝐵𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝑆𝑆𝑖𝑖+ 𝐴𝐴𝐵𝐵𝐴𝐴𝐶𝐶𝑖𝑖)𝑁𝑁𝑖𝑖=1
where: SNPi = System Net Plant Factor for jurisdiction i. PPi = Production plant for jurisdiction i.
PTi = Transmission plant for jurisdiction i.
PDi = Distribution plant for jurisdiction i. PGi = General plant for jurisdiction i. PIi = Intangible plant for jurisdiction i.
ADPPi = Accumulated depreciation production plant for jurisdiction i.
ADPTi = Accumulated depreciation transmission plant for jurisdiction i.
ADPDi = Accumulated depreciation distribution plant for jurisdiction i. ADPGi = Accumulated depreciation general plant for jurisdiction i. ADPIi = Accumulated depreciation intangible plant for jurisdiction i.
N = Number of jurisdictions.
The SNP factor is used to allocate interest expense and miscellaneous deferred tax treatment. The factor is calculated by taking the ratio of the system net plant balance for a jurisdiction divided by the total system net plant balance for all jurisdictions.

Accounts using SNP factor: Interest Expense (427-429, 431, 432), Deferred Income Tax Expenses (41010, 41110), Schedule M, Working Capital – Cash (131), Accumulated Deferred Income Taxes (190, 282, 283) System Overhead Factor (“SO”) – Effective after Interim Period 𝑆𝑆𝐴𝐴𝑖𝑖= 𝑆𝑆𝐴𝐴𝑖𝑖+𝑆𝑆𝐵𝐵𝑖𝑖+𝑆𝑆𝑆𝑆𝐴𝐴𝐵𝐵𝑖𝑖3
where:
SOi = System Overhead Factor for jurisdiction i.
SCi = System Capacity Factor for jurisdiction i.
SEi = System Energy Factor for jurisdiction i.
SGPDi = System Gross Plant Distribution for jurisdiction i.
The SO factor is used to allocate system overhead costs. The SO factor used after the Interim period is
calculated by taking the sum of the SC, SE and SGPD factor for a jurisdiction and dividing by three.
Accounts using SO factor after Interim period: Other Electric Operating Revenue (451, 454, 456), Miscellaneous Revenue (41160, 41170, 421), Administrative and General Expense (920-935), Depreciation Expense (403GP), Amortization Expense (404GP, 404IP), Deferred Income Tax Expenses
(41010, 41110), Schedule M, Federal Income Tax True-Up (40910), General Plant (389-398, 1011390),
Intangible Plant (303), Materials and Supplies (154), Stores Expense Undistributed (163), Prepayments (165), Misc. Regulatory Assets (182M), Misc. Deferred Debits (186M), Working Capital (141, 232), Rate Base Deduction Provisions (2281-2283), Other Deferred Credits (25399), Regulatory Liabilities (254),
Accumulated Deferred Income Taxes (190, 282, 283), Accumulated Depreciation (108GP, 1081390),
Accumulated Provision for Amortization (111GP, 111IP)
System Overhead Factor (“SO”) – Effective during the Interim Period 𝑆𝑆𝐴𝐴𝑖𝑖=𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖−𝐴𝐴𝐴𝐴𝑜𝑜𝑖𝑖−𝐴𝐴𝐵𝐵𝑜𝑜𝑖𝑖−𝐴𝐴𝐵𝐵𝑜𝑜𝑖𝑖−𝐴𝐴𝑆𝑆𝑜𝑜𝑖𝑖−𝐴𝐴𝐶𝐶𝑜𝑜𝑖𝑖∑(𝐴𝐴𝐴𝐴𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝐵𝐵𝑖𝑖+𝐴𝐴𝑆𝑆𝑖𝑖+𝐴𝐴𝐶𝐶𝑖𝑖−𝐴𝐴𝐴𝐴𝑜𝑜𝑖𝑖−𝐴𝐴𝐵𝐵𝑜𝑜𝑖𝑖−𝐴𝐴𝐵𝐵𝑜𝑜𝑖𝑖−𝐴𝐴𝑆𝑆𝑜𝑜𝑖𝑖−𝐴𝐴𝐶𝐶𝑜𝑜𝑖𝑖)𝑁𝑁𝑖𝑖=1where: SOi = System Overhead Factor for jurisdiction i. PPi = Gross production plant for jurisdiction i. PTi = Gross transmission plant for jurisdiction i.
PDi = Gross distribution plant for jurisdiction i.
PGi = Gross general plant for jurisdiction i. PIi = Gross intangible plant for jurisdiction i. PPoi = Gross production plant for jurisdiction i allocated on a SO factor.
PToi = Gross transmission plant for jurisdiction i allocated on a SO factor.
PDoi = Gross distribution plant for jurisdiction i allocated on a SO factor.
PGoi = Gross general plant for jurisdiction i allocated on a SO factor. PIoi = Gross intangible plant for jurisdiction i allocated on a SO factor. N = Number of jurisdictions.
The SO factor is used to allocate system overhead costs. The SO factor used during the Interim period is calculated by taking the gross plant allocated to a jurisdiction, excluding the plant amounts allocated on SO, and dividing it by the total gross plant for all jurisdictions, excluding plant amounts allocated on SO, for all jurisdictions.
Accounts using SO factor during the Interim period: Other Electric Operating Revenue (451, 454, 456), Miscellaneous Revenue (41160, 41170, 421), Administrative and General Expense (920-935), Depreciation Expense (403GP), Amortization Expense (404GP, 404IP), Deferred Income Tax Expenses (41010, 41110), Schedule M, Federal Income Tax True-Up (40910), General Plant (389-398, 1011390),
Intangible Plant (303), Materials and Supplies (154), Stores Expense Undistributed (163), Prepayments
(165), Misc. Regulatory Assets (182M), Misc. Deferred Debits (186M), Working Capital (141, 232), Rate Base Deduction Provisions (2281-2283), Other Deferred Credits (25399), Regulatory Liabilities (254), Accumulated Deferred Income Taxes (190, 282, 283), Accumulated Depreciation (108GP, 1081390), Accumulated Provision for Amortization (111GP, 111IP)
System Transmission Factor (“ST”) – Effective after Interim Period 𝑆𝑆𝐵𝐵𝑖𝑖= 75%∗𝑆𝑆𝐴𝐴𝑖𝑖+25%∗𝑆𝑆𝐵𝐵𝑖𝑖
where:
STi = System Transmission Factor for jurisdiction i.
SCi = System Capacity Factor for jurisdiction i.
SEi = System Energy Factor for jurisdiction i.
The ST factor is used to allocate transmission related costs after the Interim period. It is calculated using a weighting of 75% of the SC factor and 25% of the SE factor for a jurisdiction.
Accounts using ST factor: Provision for Rate Refund (449), Operating Revenue (454), Other Electric
Revenue (456), Miscellaneous Revenue (41160, 41170, 421), Transmission Expense (560-564, 566-573),
Transmission of Electricity by Others (565), Administrative & General Expense (920-935), Depreciation
Expense (403TP, 403GP), Amortization Expense (404IP, 407), Deferred Income Tax Expenses (41010, 41110), Schedule M, Transmission Plant (350-359), General Plant (389-398, 1011390), Intangible Plant (302, 303), Plant Held for Future Use (105), Electric Plant Acquisition Adjustments (114-115), Material and Supplies (154), Prepayments (165), Misc. Regulatory Assets (182M), Misc. Deferred Debits (186M), Working Capital (232), Customer Advances for Construction (252), Other Deferred Credits (25399),
Accumulated Deferred Income Taxes (190, 281-283), Accumulated Depreciation (108TP, 108GP), Accumulated Provision for Amortization (111TP, 111GP, 111IP) Tax Depreciation Factor (“TAXDEPR”) 𝐵𝐵𝐴𝐴𝑇𝑇𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝑖𝑖=𝐵𝐵𝐴𝐴𝑇𝑇𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖∑𝐵𝐵𝐴𝐴𝑇𝑇𝐵𝐵𝐵𝐵𝐴𝐴𝐷𝐷𝐴𝐴𝑖𝑖𝑁𝑁𝑖𝑖=1
where: TAXDEPRi = Tax Depreciation Factor for jurisdiction i.
TAXDEPRAi = Tax depreciation allocated to jurisdiction i.
(Tax depreciation is allocated based on functional pre-merger and post-merger splits of plant using Divisional and System allocations from above. Each jurisdiction’s total allocated portion of tax depreciation is determined by its total allocated ratio of these
functional pre- and post-merger splits to the total Company tax
depreciation.)
N = Number of jurisdictions. The TAXDEPR factor allocates depreciation related tax costs.

Accounts using TAXDEPR: Deferred Income Tax Expense (41010) Schedule M, Accumulated Deferred Income Taxes (282) Trojan Decommissioning Factor (“TROJD”) 𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑖𝑖=𝐴𝐴𝐴𝐴𝐴𝐴𝐵𝐵22842𝑖𝑖∑𝐴𝐴𝐴𝐴𝐴𝐴𝐵𝐵22842𝑖𝑖𝑁𝑁𝑖𝑖=1
where: TROJDi = Trojan Decommissioning Factor for jurisdiction i.
ACCT22842i = Allocated adjusted balance in FERC Account 228.42 (Accumulated
Provision for Decommissioning Trojan) for jurisdiction i.
N = Number of jurisdictions. The TROJD factor is used to allocate decommissioning related costs associated with the Trojan plant.

Accounts using TROJD: Deferred Income Tax Expenses (41010, 41110), Schedule M, FAS 143 ARO Regulatory Liability – Trojan Plant (254105), Asset Retirement Obligation – Trojan Plant (230), Accumulated Deferred Income Taxes (190, 283) Trojan Decommissioning Fixed Factor (“TROJDF”)
Effective after Interim Period Based on actual TROJD allocation factors for the most recent four calendar years available prior to the end of the Interim Period. (The TROJDi factor is as defined above.)

𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑆𝑆𝑖𝑖=PY1𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑖𝑖+ PY2𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑖𝑖+ PY3𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑖𝑖+ PY4𝐵𝐵𝐷𝐷𝐴𝐴𝑇𝑇𝐵𝐵𝑖𝑖4where:
TROJDFi = Trojan Decommissioning– Fixed Factor for jurisdiction i. Prior Year (PY) 1 TROJDi = PY1 Trojan Decommissioning Factor for jurisdiction i. Prior Year (PY) 2 TROJDi = PY2 Trojan Decommissioning Factor for jurisdiction i. Prior Year (PY) 3 TROJDi = PY3 Trojan Decommissioning Factor for jurisdiction i.
Prior Year (PY) 4 TROJDi = PY4 Trojan Decommissioning Factor for jurisdiction i.
For Example: If the Interim Period ends December 31, 2023, then (PY) 1 = calendar year 2022, (PY) 2 = calendar year 2021, (PY) 3 = calendar year 2020, and (PY) 4 = calendar year 2019.The TROJDF factor is used to allocate decommissioning related costs associated with the Trojan plant.
Accounts using TROJDF: Deferred Income Tax Expenses (41010, 41110), Schedule M, FAS 143 ARO
Regulatory Liability – Trojan Plant (254105), Asset Retirement Obligation – Trojan Plant (230), Accumulated Deferred Income Taxes (190, 283)
APPENDIX D
Nodal Pricing Model Memorandum of Understanding
EXECUTION VERSION
PacifiCorp's Nodal Pricing Model Memorandum of Understanding
Introduction
I. PacifiCorp and the undersigned parties (Parties) enter into this Memorandum of
Understanding (MOU) to acknowledge their support, as described below, of PacifiCorp's
investment in the development and implementation of a Nodal Pricing Model (NPM) that may be
adopted for the calculation of net-power costs (NPC).
Background
2. PacifiCorp is a multi-jurisdictional electric utility that is serving customers in
California, Idaho, Oregon, Utah, Washington, and Wyoming.
3. Generally, PacifiCorp has allocated costs among those states using an inter-
jurisdictional cost allocation methodology.
4. PacifiCorp's current inter-jurisdictional cost allocation methodology, the 2017
PacifiCorp Inter-Jurisdictional Allocation Protocol (2017 Protocol), was adopted by the applicable
regulatory commissions in Idaho, Oregon, Utah, and Wyoming in 2016, and set a process for
developing a new inter-jurisdictional cost allocation methodology through a working group of
stakeholders consisting of utility regulatory agencies, customers, and certain others potentially
affected by inter-jurisdictional allocation procedures, known as the Multi-State Process Workgroup
(MSP Workgroup). 1 Washington has used the West Control Area Inter-Jurisdictional Allocation
1 PacifiCorp anticipates that California will adopt the 2017 Protocol in 2019.
I
2020 Protocol -Appendix D
EXECUTION VERSION
Methodology for the purposes of cost allocations since 2007. California currently uses the Revised
Protocol, but a decision on adoption of the 20 I 7 Protocol is pending before the commission.
5. Discussions among the MSP Workgroup for the potential extension of the 2017
Protocol and/or a new inter-jurisdictional cost allocation methodology are being held.
6. In late-2017, PacifiCorp presented the MSP Workgroup with a proposaUo track
NPC through a NPM concept designed to facilitate each state's energy policies and unique resource
portfolios while still seeking to maintain the benefits of system dispatch and optimization.
PacifiCorp also indicated a potential for the NPM to provide increased dispatch efficiencies.
7. PacifiCorp's NPM proposal is to use a third-party day-ahead dispatch model to
determine the schedules for each of its generation resources to serve state loads on a least-cost
basis, while tracking costs and benefits associated with the different resource portfolios used to
serve PacifiCorp's load in each state. PacifiCorp has been in discussions with the California
Independent System Operator (CAISO) to provide the day-ahead dispatch model.
8. To allow for the anticipated implementation of NPM for potential ratemaking by
2023, PacifiCorp has determined that it must now invest related capital, incur related operations
and maintenance expenses, and pay related ongoing grid management charges. Attached as
Exhibit A to this MOU is a description of the type of work that PacifiCorp anticipates undertaking.
The Parties understand that the list is preliminary and is not intended to be a complete list.
2
2020 Protocol -Appendix D 2
EXECUTION VERSION
Agreement
9. As described in this MOU, the Parties affirm support for PacifiCorp's reasonable
and prudent investment of related capital funds, related operations and maintenance expenses, and
the related ongoing grid management charges to develop and implement an NPM. Exhibit B to
this MOU is an estimate of the investments and ongoing-costs PacifiCorp anticipates it will make
or incur through this effort and an explanation of the anticipated benefits, including cost-savings
and compliance with state policy directives impacting resource portfolio decisions. The Parties
agree that, based on the information provided by PacifiCorp, PacifiCorp's decision to invest capital
funds and pay ongoing grid management charges to develop and implement an NPM is reasonable
and prudent. However, the Parties do not necessarily agree that any specific investment or
expenditure is reasonable or prudent and the Parties reserve all rights to audit, review, and
challenge any specific investment or expenditure as unreasonable or imprudent in appropriate
regulatory commission proceedings.
10. The Parties agree the associated grid management costs will be booked in Federal
Energy Regulatory Commission (FERC) Account 565, which is included in PacifiCorp's NPC.
NPM related costs will be allocated among the PacifiCorp states as follows2:
2 References to "SG Factor" and "SE Factor" in the following table are to the System Generation Factor and the
System Energy Factor, respectively, as used in the currently-applicable cost allocation protocol in each state, or any
successor factors. References to "Fixed SG Factor" are to a proposed Fixed SG Factor that the Parties currently
anticipate may be established as part of a future interstate cost allocation protocol.
3
2020 Protocol -Appendix D 3
EXECUTION VERSION
Time Period
NPM Associated January I, 2020 Through the
Costs Effective Date of a New Beginning upon the Effective
Lnterjurisdictional Cost Date of a New Interstate Cost
Allocation Protocol3 Allocation Protocol
CAISO Grid SG Factor SE Factor Management Charge
Capitalized Start-Up
Costs for PacifiCorp SG Factor Fixed SG Factor
ESM4
Capitalized CAISO SG Factor Fixed SG Factor Imolementation Fee
Ongoing Operations
and Maintenance SG Factor SE Factor
Expense
Otherwise, this MOU shall not limit the positions any Party may take regarding how nodal pricing
may be used to allocate costs amongst the states before any applicable state regulatory commission.
11. The Company shall use its best efforts to provide adequate training and
documentation regarding the NPM such that Parties may understand, review, and audit NPM-
derived NPC. The NPM, however, is based on CAISO FERC-jurisdictional market model to which
PacifiCorp does not have and cannot provide access. For regulatory purposes, the Company will
retain CAISO advisory schedules and documentation of any decision to materially deviate from
those advisory schedules. The Company further agrees to provide training and facilitate access to
the Company's forecasting model for any appropriate party for regulatory purposes.
3 The Parties are currently negotiating towards a possible extension of the 2017 fnter-jurisdictional Allocation
Methodology (subject to some possible changes), until a future interstate cost allocation protocol becomes effective,
which the Parties currently expect may be January I, 2023 or January I, 2024.
4 PacifiCorp's Energy Supply Management (ESM) is the business unit responsible for scheduling and dispatching
PacitiCorp's generation resources to serve retail load and buy/sell in wholesale energy and capacity markets.
4
2020 Protocol -Appendix D 4
EXECUTION VERSION
12. The Parties acknowledge that this MOU does not address any other aspect of the
on-going negotiations regarding an extension of the 2017 Protocol or a new inter-jurisdictional
cost allocation methodology. By executing this MOU, no Party is agreeing to any other issue not
agreed to in this MOU.
13. This MOU may be executed in counterparts and each signed counterpart constitutes
an original document.
14. The obligations of any state agency that is a party to this MOU shall be interpreted
in a manner consistent with its statutory authority and responsibilities, and any explanation and
support provided in this MOU or in any regulatory proceeding shall be consistent with its statutory
authority and responsibility.
15. This MOU is entered into by each Party on the date entered below such Party's
signature.
PAClFlCORP
Organization
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2020 Protocol -Appendix D 5
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2020 Protocol -Appendix D 8
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2020 Protocol -Appendix D 10
EXHIBIT A
Nodal Pricing Model Statement of Work
Introduction
EXECUTION VERSION
PacifiCorp has requested the CAISO provide a design proposal for a NPM that can be used to clear
energy supply and demand bids for the PacifiCorp Balancing Authority Areas (BAA)1 one day
ahead. The CAlSO proposes to leverage its existing Day-Ahead Market (DAM) technology
platform, the market full network model, and data interfaces available in the real-time Energy
Imbalance Market (EIM) to provide the NPM solution. PacifiCorp is currently an EIM Entity
participating in the EIM and has already developed systems and data interfaces with the EIM in
submitting data and receiving settlement statements. Consequently, the proposed solution would
require an expansion of PacifiCorp's bidding, scheduling, and settlement systems for the NPM,
while gaining full access to the most advanced security constrained unit commitment tool currently
used in the CAISO's DAM.
Nodal Pricing Model
Currently, the CAISO's DAM footprint is limited to the CAISO BAA (CISO). Although supply
and demand schedules in the external BAAs are not optimized, they are modeled as fixed in the
DAM to produce an accurate market and power flow solution. The CAJSO, as the Reliability
Coordinator, receives the demand forecast and generation schedules for the next day from EIM
BAAs and external BAAs, as well as the Area-To-Area Net Schedule Interchange between BAAs.
For the NPM solution, the CAISO proposes to include in the DAM footprint the PacifiCorp BAAs,
i.e. PACW and PACE, which are modeled as individual BAAs in the EIM. Using similar market
features and technology optimization algorithm approaches employed in the EIM, the DAM will
produce optimal unit commitment and hourly energy schedules for supply resources in PACW and
PACE, subject to a power balance constraint for each of these BAAs, in addition to the power
balance constraint for CISO and active transmission network constraints in CISO, PACE, and
PACW. Energy transfers between PACW and PACE will be optimally scheduled, subject to
applicable scheduling limits, whereas the net energy transfer to or from CISO will be fixed at zero,
to prevent energy exchange between CISO and PacifiCorp that may impact the CAlSO's DAM
solution.
As an intended standard feature of the DAM, the CAISO will also be able to optimally schedule
ancillary services to meet the corresponding requirements in PACW and PACE, by designating
these BAAs as separate ancillary services regions with distinct requirements.
The ancillary services are the following:
• Regulation up and down;
• Spinning Reserve; and
• Non-Spinning Reserve
1 PacifiCorp operates two BAAs, PacifiCorp East BAA (PACE) and PacifiCorp West BAA (PACW).
2020 Protocol -Appendix D 11
EXECUTION VERSION
All ancillary services have a I 0-minute ramping requirement, which is shared among the upward
ancillary services. Both Spinning Reserves and Non-Spinning Reserves are contingency reserves,
but Non-Spinning Reserve can also be provided by offiine resources that can start up within 10
minutes. The upward ancillary services procurement is cascaded so that spin can meet non-spin
requirements, and regulation up can meet both spin and non-spin requirements, to minimize the
overall procurement cost.
Advisory Pricing
The day-ahead settlement for the NPM is advisory, i.e. not financially binding between PacifiCorp
and CAISO. Day-ahead energy and ancillary service prices for PacifiCorp resources will be
published in CAISO Market Results Interface for PacifiCorp, but they will not be published in
Open Access Same-time Information System (OASIS) in the public domain. Similarly, the
publication of Locational Marginal Prices at PACW and PACE pricing nodes (generally referred
to as PNodes) will be suppressed in OASIS.
2020 Protocol -Appendix D 12
EXECUTION VERSION
EXHIBIT B
PacifiCorp's Estimated Costs of the Nodal Pricing Model
CAISO Grid Management Charge or Service Fee -$8 to I 0 million per year
Capitalized PacifiCorp Start-Up Costs for Energy Supply Management and Settlement
Processing -$3 to $5 million with I 00% applicable to a future Extended Day-Ahead Market
(EDAM)
Capitalized CAISO Implementation Fee -$1 to $2 million (based on Energy Imbalance Market,
or EIM, implementation fee) one-time cost
Ongoing Operations and Maintenance Expense -$500,000 -$700,000 per year
Benefits of the Nodal Pricing Model
The NPM is being developed to allocate actual PC as states move to unique generation
portfolios. The NPM is intended to help preserve the system benefit of operating as a single
system.
CAISO's existing technology platform is intended to reduce both schedule and budget risk to
quickly implement the NPC allocation methodology that PacifiCorp is seeking to implement
based on the NPM solution.
In addition to providing a method to allocate NPC, the NPM potentially offers the following
benefits from using the CAISO market optimization tool:
• It provides more granular dispatch information resulting in anticipated operational cost
savings.
• It allows PacifiCorp to leverage CAlSO's independence as a third party market provider.
• It guarantees that the solution outcome is consistent with the CAlSO EIM market
solution since it is using the same exact tool and input data.
• It leverages the effort and money used to build and maintain a complex and granular
Real-time network model that is used in the actual market run.
• It utilizes the same schedule data for internal and external resources inform ing the
potential for unscheduled loop flows and is informative when performing congestion
management and potentially enforcing physical flow transmission constraints.
Lastly, if the CAI SO offers a Day-Ahead Market to external entities for optional participation,
the NPM solution development would allow PacifiCorp to seamlessly participate in the CAlSO
EDAM, if and when PacifiCorp decides to join that market.
2020 Protocol -Appendix D 13
APPENDIX E
Coal-Fueled Interim Period Resource Depreciation Lives
Unit In Service
Depreciation Depreciation
Capacity
(MW)
Physical
Location
OR Other States
PP
States (1)
RMP States
Lives Addressed by Section 4.1.3.1
(1) The life of coal plants for Washington is addressed in Section 4.1.4.
APPENDIX F
Washington Inter-Jurisdictional Allocation Methodology
Memorandum of Understanding
The Washington Inter-Jurisdictional Allocation Methodology Memorandum of Understanding
Introduction
PacifiCorp d/b/a Pacific Power and Light Company (PacifiCorp or Company), Staff of the
Washington and Utilities and Transportation Commission (Staff), Public Counsel Unit of the Washington State Attorney General’s Office (Public Counsel) and Packaging Corporation of America (PCA), have executed this agreement (the Parties or, individually, a Party) enter into this Memorandum of Understanding (Agreement) to acknowledge their support for certain
adjustments to the West Control Area Inter-Jurisdictional Allocation Methodology (WCA).
Background
PacifiCorp is a multi-jurisdictional electric utility that provides services in six states (California,
Idaho, Oregon, Utah, Wyoming, and Washington). Staff is participating in PacifiCorp’s Multi-
State Process (MSP), working towards the Company’s goal of developing a common cost allocation methodology amongst these six states. Currently, Washington uses the WCA for determining which costs are eligible for recovery in rates from customers in Washington.1
As approved by the Washington Utilities and Transportation Commission (Commission), the
WCA isolates the costs and revenues associated with assets located in the Company’s west “control area” or “PacifiCorp West Balancing Authority Area” (PACW), and allocates to Washington a proportionate share of the costs and revenues based primarily on Washington’s relative contribution to demand and energy requirements. The WCA includes loads, generation and transmission assets, and wholesale contracts for facilities located in California, Oregon, and
Washington. It also includes transmission and generation assets located outside of California, Oregon, and Washington that are electrically located in PACW. The WCA excludes all loads and assets located within PacifiCorp’s East Balancing Authority Area (PACE).
In the context of inter-jurisdictional cost allocation, the Commission will consider a resource to
be used and useful to Washington customers2 if the resource “provides quantifiable direct or
indirect benefits to Washington [ratepayers] commensurate with its costs.”3 To modify the WCA methodology, “any changes should be considered in the context of an overall review of that methodology.”4 Additionally, Parties must demonstrate that “any changes proposed more closely
aligns with the allocation of costs based on causation[.]”5 Finally, “the party advocating for the
change must make a detailed a persuasive showing demonstrating that the proposed change is appropriate.”6
1 Prior to the WCA methodology being approved in Docket UE-061546, PacifiCorp proposed the Revised Protocol
as its cost allocation methodology in Docket UE-050684. The Revised Protocol presented costs as an integrated six-state system. The Commission rejected the Revised Protocol because there was not sufficient evidence in the record that the methodology complied with the legal requirements in RCW 80.04.250. See generally UE-050684, Order 04. 2 See RCW 80.04.250
3 Docket UE-050684, Order 04 ¶ 68.
4 Docket UE-130043, Order 05 ¶ 92–94. 5 Id.
6 Id.
2020 Protocol - Appendix F 1
Foundation for this Agreement
In this memorandum of understanding, the Parties agree to support certain modifications to the
WCA in the Company’s forthcoming rate case provided the Company can demonstrate that the
modifications within this agreement provide beneficial resources to Washington customers that are used and useful. In particular, the Parties agree to support these modifications if PacifiCorp can demonstrate these modifications provide quantifiable direct or indirect benefits to Washington customers, and that these benefits are commensurate with their costs.7 The Parties
agree to work collaboratively with PacifiCorp as they make this demonstration. However, as the
party advocating for these changes, PacifiCorp bears the legal and factual burden to sufficiently demonstrate that these modifications better align the cost allocation methodology with the principles described above in its forthcoming general rate case.
This demonstration may include the following benefits:
•A diverse generation portfolio, including an increase in high capacity renewablegeneration.
•Over 170 interconnections with other BAAs and transmission operators providing accessto market hubs for wholesale energy transactions (e.g., Mid-C, COB, Mona, Four-Corners and Palo Verde).
•Greater Energy Imbalance Market (EIM) benefits.
•Efficiencies, such as retail load characteristics and variable resource diversity, whichminimize operational costs and reduce the need to build for reserves and blackstartcapability for each state.
•Washington recently enacted Senate Bill 5116, the Clean Energy Transformation Act
(CETA) which, among other things, requires the elimination of coal-fired resources fromPacifiCorp's electric rates by December 31, 2025. PacifiCorp’s proposed modification tothe WCA will facilitate a reasonable path towards PacifiCorp’s compliance with CETA.8
Based on this understanding, the Parties agree to the following:
Agreement
1.Implementation. This Agreement includes modifications to the WCA subject to
approval by the Commission.
7 The Commission has stated that one way the Company can demonstrate this is “through historical system operation or modeling of the system showing that Eastside plant costs added to Washington rates would be offset by reductions to other cost categories (e.g., power costs), such that overall costs to Washington ratepayers would be no
more than without the Eastside resources.” Docket UE-050684, Order 04 ¶ 69 (emphasis added). 8 CETA also sets a policy of 100 percent clean energy by 2045. RCW 19.405.050. Additionally, CETA establishes an interim target of 100 percent greenhouse gas (GHG) neutral by 2030, and allows utilities to meet this requirement through 80 percent non-emitting energy and an alternative compliance option, including up to 20 percent unbundled
renewable energy credits. RCW 19.405.040.
2020 Protocol - Appendix F 2
1.1. PacifiCorp will file a rate case that allows for rates to go into effect (after suspension) on or before January 1, 2021. This rate case will use this MOU as the basis for any proposed modifications to the WCA.
2.Prudence. The proposed allocation of a particular expense or investment under thisAgreement is not intended to and will not prejudge, or prevent any party from taking aposition on, the prudence of those costs or the extent to which any particular cost may be
reflected in rates. Nothing in this Agreement is intended to abrogate the Commission’s
right or obligation to: (1) determine fair, just, and reasonable rates based upon applicablelaws and the record established in rate proceedings conducted by the Commission; (2)consider the impact of changes in laws, regulations, or circumstances on inter-jurisdictional allocation policies and procedures when determining fair, just, and
reasonable rates; or (3) establish different allocation policies and procedures for purposesof allocating costs and revenues to different customers or customer classes.
3.Quantification and Analytical Support. The Parties agree to work collaboratively andin good faith to agree on the quantification and analytical support necessary for the
Company to meet its legal and factual burden.
3.1. This analysis should be substantially completed before the filing of the general ratecase referenced in section 1.1 and with enough time to reasonably allow parties to review the analysis.
3.2. Before the general rate case referenced in section 1.1 is filed, if a Party determines that the Company’s quantification and analytical support does not demonstrate that the Company can meet its legal and factual burden, Parties have the option to withdraw their support from this agreement.
3.3. After the general rate case referenced in section 1.1 is filed, if a Party determines that this agreement does not result in fair, just and reasonable rates for Washington customers, a party may withdraw from this agreement. The withdrawing Party must provide testimony in the general rate case explaining why this agreement does not
result in fair, just and reasonable rates for Washington Customers.
3.4. In the event of a Party’s withdrawal, the remaining Parties may continue to support this Agreement for approval in any proceeding before the Commission.
4.System Transmission. The Parties agree that all existing system transmission9 costs and
benefits will be allocated using the System Generation (SG) factor as specified inAttachment 1.
4.1. Rate Impacts: To mitigate the immediate overall rate impact to Washington
customers in the rate case referenced in Section 1.1, Parties agree to support the
framework of the following phase-in approach:
9 Existing transmission includes any transmission asset that is in service as of December 31, 2019.
2020 Protocol - Appendix F 3
4.1.1. An incremental allocation of one-third of existing transmission costs and benefits, which are not currently allocated to Washington under the current WCA methodology, will be included in the rate case referenced in Section 1.1.
4.1.2. An incremental allocation of an additional one-third of existing transmission costs and benefits, which are not currently allocated to Washington, will be included in a separate tariff rider with a rate effective date on or before January 1, 2022.
4.1.3. An incremental allocation of an additional one-third of existing transmission costs and benefits, which are not currently allocated to Washington, will be included in a general rate case or through an amendment to the separate tariff rider set forth in Section 4.1.2 with a rate effective date on or before January 1,
2023.
4.1.3.1. The incremental allocation in 4.1.3 will exclude the costs and benefits of all transmission-voltage, radial lines connecting resources not otherwise included in Washington rates to PacifiCorp’s interconnected, network transmission system. If PacifiCorp is required to include a portion of a
transmission line in its interconnected, network transmission system for open access transmission service due to a subsequent generation or load interconnection, PacifiCorp may request to include such portion of the assets in a subsequent rate case.
4.1.4. The separate tariff rider described above will remain in place until the fully allocated cost of transmission costs as described in Section 4 is included in rates through a general rate case.
4.2. New Transmission. Any new transmission10 incremental to the existing
transmission described and included in Section 3, will be system-allocated using the SG factor as specified in Attachment 1.
4.2.1. Similar to the methodology outlined in 4.1.3.1, Transmission which can be
demonstrated to be used primarily for the transmission of power from
generation assets which are not assigned to Washington under the WCA, as modified by this Agreement, will be excluded from this and any other allocation to Washington.
4.3. Analytical Support. As a part of the analytical support in Section 4, the Company
will quantify the differences between total depreciation and ADIT balances using a WCA Allocation of transmission and the system allocation above.
10 “New” shall constitute assets used and useful for Washington customers after December 31, 2019.
2020 Protocol - Appendix F 4
5.Non-Emitting Resources. The Parties agree that all existing and new non-emittingresources will be dynamically allocated using the SG Factor specified in Attachment 1.
5.1. Assignment. If by December 31, 2023, none of the Parties to this agreement have
signed a new cost allocation methodology with the Company, then the Company
agrees to engage in collaborative conversations with the Parties and other interested Washington stakeholders to explore the following:
5.1.1. An Assignment method for new resources for the purposes of the WCA; and,
5.1.2. A methodology to allocate fixed shares of existing non-emitting resources.
6.Net Power Costs (NPC). Forecasted NPC for ratemaking purposes will be consistentwith Sections 1,4,5,6, and 7 of this agreement. Additionally, Washington customers will
receive all direct and indirect benefits associated with their proportional system-allocated
share of existing transmission, including Energy Imbalance Market benefits.
6.1. Actual NPC. Actual NPC for ratemaking purposes will include only the generationresources included in Washington rates and will be calculated using a spreadsheet.
6.2. Qualifying Facilities. The costs and benefits of Power Purchase Agreements for Qualifying Facilities (QF PPAs) will continue to be situs assigned to the state having jurisdiction over the QF PPA for cost responsibility, renewable energy credit assignment and resource planning.
7.Accelerated Depreciation. PacifiCorp and Staff agree to support a final depreciationdate of December 31, 2023, for Bridger Units 1-4, Colstrip 4 and any transmission assetsassociated solely with the interconnection of these units to the transmission network. Thisdate does not represent a date of estimated closure, changes in operations, or the end of
the assignment to Washington of either benefits or costs associated with these plants.Public Counsel and PCA reserve the right to make a recommendation on the depreciationfor Bridger Units 1-4, Colstrip, and any transmission assets associated solely with theinterconnection of these units to the transmission network in PacifiCorp’s forthcominggeneral rate case.
7.1. Capital Investments. Washington will continue to be allocated a WCA share ofongoing capital investments expenses for these plants, excluding incremental capital investments that are made primarily for the purpose of extending the life of these plants. Incremental capital investments that are made primarily for the purpose of
extending the life of these plants includes, but is not limited to, those associated with achieving compliance with environmental requirements or those necessitated by catastrophic failure.
7.2. Deadline for Removal. Consistent with RCW 19.405.030, PacifiCorp will remove
from Washington rates all costs and benefits associated with Bridger units 1-4 and Colstrip unit 4 no later than December 31, 2025.
2020 Protocol - Appendix F 5
7.3. Resource Flexibility. The dates articulated in this section are agreed upon by parties to facilitate the removal of coal from Washington Rates by 2025, and provide the flexibility that may allow for early compliance with CETA.
8. Decommissioning Cost. Washington will continue to be allocated ongoing and expecteddecommissioning expenses for a WCA share of Jim Bridger Units 1-4 and Colstrip Unit4.
8.1. Colstrip Engineering Study. The Company will provide by March 30, 2020, an
independent engineering study of estimated decommissioning costs for Colstrip.
8.2. Jim Bridger Engineering Study. The Company will provide by January 15, 2020, an independent engineering study of estimated decommissioning costs for Jim
Bridger.
8.3. Cost Assignment. To facilitate the allocation of decommissioning costs, Parties agree to support a system allocation of the costs associated with an independent engineering study in 8.1 and 8.2.
9.This agreement proposes modifications to the WCA, which serves as the basis forallocating costs in Washington. PacifiCorp will allocate costs based on the WCAconsistent with the modifications in this Agreement for ratemaking purposes inWashington unless a different cost allocation method is approved by the Commission.
10.Each Party to this Agreement represents that they are signing this Agreement in goodfaith and that they intend to abide by the terms of this Agreement.
11.This Agreement may be executed in counterparts and each signed counterpart constitutes
an original document.
12.Attachment 1 contains updated allocation factors consistent with this Agreement.
13.This Agreement is entered into by each Party on the date entered below such Party's
signature.
2020 Protocol - Appendix F 6
PACIFICORP
By:
Title: ____________________________
STAFF OF THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION
By:
Title: ____________________________
PUBLIC COUNSEL
By:
Title: ____________________________
Date:
PACKAGING CORPORATION OF AMERICA
By:
Title: ____________________________
Date:
2020 Protocol - Appendix F 7
2020 Protocol - Appendix F 8
The Washington Inter-Jurisdictional Allocation Methodology Memorandum of Understanding,
Page 7 of7
PACIFICORP
By. J~===-Title: Vi v;;:;~
PUBLIC COUNSEL
Title: -----------
Date: __________ _
STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
Date: __________ _
PACKAGING CORPORATION OF AMEY: By:~
Title: A-f±o-t:vt.~
Date: \ I I v & I ' q L
2020 Protocol - Appendix F 9
The Washington Inter-Jurisdictional Allocation Methodology Memorandum of Understanding,
Page 7 of7
PACIFICORP
By:_~~~~~~~~~-
Title: -----------
Date: __________ _
PUBLIC COUNSEL
By:_~~~~~~~~~-
Title: -----------
Date: __________ _
STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
By: ___ L?it_~_r._~-~~~~·-•
Title: '/)"""-tf,..1 1'~~ ~~
Date: A/nr. :l ;J, .2t711
PACKAGING CORPORATION OF
AMERICA
By:~~~~~~~~~~-
Title: -----------
Date: -----------
Assistant Attorney General
11/21/2019
The Washington Inter-Jurisdictional Allocation Methodology Memorandum of Understanding,
Page 7 of 7
PACIFICORP
Title: ___________ _
Date: ------------
Title: ___________ _
Date: ------------
STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
Title: ___________ _
Date: -----------~
PACKAGING CORPORATION OF
AMERICA
By: ___________ _
Title: ___________ _
Date: ------------
APPENDIX G
Special Contracts
Special Contracts without Ancillary Service Contract Attributes
For allocation purposes, Special Contracts without identifiable Customer Ancillary Service attributes are viewed as one transaction.
Loads of Special Contract customers will be included in all Load-Based Dynamic Allocation Factors.
When interruptions of a Special Contract customer’s service occur, the reduction in load
will be reflected in the host jurisdiction’s Load-Based Dynamic Allocation Factors.
Actual revenues received from Special Contract customer will be assigned to the State where the Special Contract customer is located.
See example in Table 1.
Special Contracts with Customer Ancillary Service Attributes
For allocation purposes, Special Contracts with Customer Ancillary Service attributes are
viewed as two transactions. PacifiCorp sells the customer electricity at the retail service
rate and then buys the electricity back during the interruption period at the Customer Ancillary Service Contract’s rate.
Loads of Special Contract customers will be included in all Load-Based Dynamic
Allocation Factors.
When interruptions of a Special Contract customer’s service occur, the host jurisdiction’s Load-Based Dynamic Allocation Factors and the retail service revenue are calculated as
though the interruption did not occur.
Revenues received from Special Contract customer, before any discounts for Customer Ancillary Services attributes of the Special Contract, will 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 Ancillary Services attributes of the Contract, and payments to retail customers for Customer Ancillary Services will 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 curtailment, the load, costs, and revenue associated with a customer buying through economic curtailment will be excluded
from the calculation of State revenue requirements. The cost associated with the buy-
through will be removed from the calculation of net power costs, the Special Contract customer load associated with the buy-through will be not be included in the calculation of Load-Based Dynamic Allocation Factors, and the revenue associated with the buy-through will not be included in State revenues.
Table 1
Interruptible Contract Without Ancillary Service Contract Attributes
Effect on Revenue Requirement
~ Total s:i:stem Jurisdiction 1 Jurisdiction 2
1 Loads
2 Jurisdictional Loads -No Interruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW) 72,000 24,000 36,000
4 Jurisdictional Annual Energy (MWh) 42,000,000 14,000,000 21,000,000
5
6 Jurisdictional Loads -With Interruptible Service -Reflecting Actual Interruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW) 71,700 24,000 35,700
8 Jurisdictional Annual Energy (MWh) 41,962,500 14,000,000 20,962,500
9
10 Special Contract Customer Revenue and Load -Non Interruptible Service
11 Special Contract Customer Revenue s 20,000,000 s 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 -Wrth Interruptible Service (75 MW X 500 Hours of Interruption)
16 Special Contract Customer Revenue $ 16,000,000 s 16,000,000
17 Discount for Ancillary Services
18 Net Cost to Special Contract Customer s 16,000,000 s 16,000,000
19 Special Contract Sum of 12 CP-Reflecting Actual Interruptions (MW) (Included in line 7) 600 600
20 Special Contract Annual Energy-Reflecting Actual Interruptions (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 Interruptible Service
26 SE factor (Calculated from line 4) SE1 100.00% 33.33% 50.00%
27 SC factor (Calculated from line 3) SC1 100.00% 33.33% 50.00%
28 SG factor (line 27'75% +line 26*25%) SG1 100.00% 33.33% 50.00%
29
30 Wrth Interruptible Service (Reflecting Actual Physical Interruptions)
31 SE factor (Calculated from line 8) SE2 10000% 33.36% 49.96%
32 SC factor (Calculated from line 7) SC2 10000% 33.47% 49.79%
33 SG factor (line 32'75% +line 31*25%) SG2 100.00% 33.45% 49.83%
34
35
36 No Interruptible Service
37
38 Cost of Service
39 Energy Cost SE1 s 500,000 ,000 $ 166,666,667 s 250,000,000
40 Demand Related Costs SG1 $ 1,000,000,000 $ 333,333,333 s 500,000 ,000
41 Sum of Cost $ 1,500,000,000 $ 500,000,000 s 750,000,000
42
43 Revenues
44 Special Contract Revenue Situs s 20,000,000 s 20,000,000
45 Revenues from all other customers Situs s 1,480,000,000 s 500,000,000 $ 730,000,000
46
47
48 With Interruptible Service
49
50 Cost of Service
51 Energy Cost SE2 s 498,000,000 $ 166, 148,347 s 248,777,480
52 Demand Related Costs SG2 s 998,000 ,000 $ 334,058,577 s 496,912, 134
53 Sum of Cost $ 1,496,000,000 $ 500,206,924 s 745,689,614
54
55 Revenues
56 Special Contract Revenue Situs s 16,000,000 s 16,000,000
57 Revenues from all other customers Situs s 1,480,000,000 s 500,206,924 $ 729,689,614
2020 Protocol -Appendix G 3
Jurisdiction 3
12,000
7,000,000
12,000
7,000,000
16.67%
16.67%
16.67%
16.68%
16.74%
16.72%
s 83,333,333
$ 166,666,667
$ 250,000,000
s 250,000,000
s 83,074,173
s 167,029,289
$ 250, 103,462
s 250,103,462
Table 2
Interruptible Contract With Ancillary Service Contract Attributes
Effect on Revenue Requirement
~ Total s:i:stem Jurisdiction 1 Jurisdiction 2
1 Loads
2 Jurisdictional Loads -No Interruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW) 72,000 24,000 36,000
4 Jurisdictional Annual Energy (MWh) 42,000,000 14,000,000 21,000,000
5
6 Jurisdictional Loads -With Interruptible Service -Reflecting Actual Interruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW) 71,700 24,000 35,700
8 Jurisdictional Annual Energy (MWh) 41,962,500 14,000,000 20,962,500
9
10 Special Contract Customer Revenue and Load -Non Interruptible Service
11 Special Contract Customer Revenue s 20,000,000 s 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 -Wrth Interruptible Service (75 MW X 500 Hours of Interruption)
16 Tariff Equivalent Revenue $ 20,000,000 s 20,000,000
17 Ancillary Service Discount for 75 MW X 500 Hours of Economic Curtailment s (4,000,000)
18 Net Cost to Special Contract Customer s 16,000,000 s 16,000,000
19 Special Contract Sum of 12 CP-Reflecting Actual Interruptions (MW) (Included in line 7) 600 600
20 Special Contract Annual Energy-Reflecting Actual Interruptions (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 Interruptible Service
26 SE factor (Calculated from line 4) SE1 100.00% 33.33% 50.00%
27 SC factor (Calculated from line 3) SC1 100.00% 33.33% 50.00%
28 SG factor (line 27'75% +line 26*25%) SG1 100.00% 33.33% 50.00%
29
30 Wrth Interruptible Service (Reflecting Actual Physical Interruptions)
31 SE factor (Calculated from line 8) SE2 10000% 33.36% 49.96%
32 SC factor (Calculated from line 7) SC2 10000% 33.47% 49.79%
33 SG factor (line 32'75% +line 31*25%) SG2 100.00% 33.45% 49.83%
34
35
36 No Interruptible Service
37
38 Cost of Service
39 Energy Cost SE1 s 500,000 ,000 $ 166,666,667 s 250,000,000
40 Demand Related Costs SG1 $ 1,000,000,000 $ 333,333,333 s 500,000 ,000
41 Sum of Cost $ 1,500,000,000 $ 500,000,000 s 750,000,000
42
43 Revenues
44 Special Contract Revenue Situs s 20,000,000 s 20,000,000
45 Revenues from all other customers Situs s 1,480,000,000 s 500,000,000 $ 730,000,000
46
47
48 With Interruptible Service & Ancillary Service Contract
49
50 Cost of Service
51 Energy Cost SE1 s 498,000,000 $ 166,000,000 s 249,000,000
52 Demand Related Costs SG1 s 998,000 ,000 $ 332,666,667 s 499,000,000
53 Ancillary Service Contract -Economic Curtailment (Demand) SG1 $ 2,000,000 $ 666,667 s 1,000,000
54 Ancillary Service Contract -Economic Curtailment (Energy) SE1 $ 2,000,000 $ 666,667 s 1,000,000
55 Sum of Cost $ 1,500,000,000 $ 500,000,000 s 750,000,000
56
57 Revenues
58 Special Contract Revenue Situs s 20,000,000 s 20,000,000
59 Revenues from all other customers Situs s 1,480,000,000 s 500,000,000 $ 730,000,000
2020 Protocol -Appendix G 4
Jurisdiction 3
12,000
7,000,000
12,000
7,000,000
16.67%
16.67%
1667%
16.68%
16.74%
16.72%
s 83,333,333
$ 166,666,667
$ 250,000,000
s 250,000,000
s 83,000,000 s 166,333,333
$ 333,333
$ 333,333
$ 250,000,000
s 250,000,000