20151231Larsen Exhibit 1.pdf

Case No. PAC-E-I5-16
ExhibitNo. I
Witness: Jeffrey K. Larsen
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Jeffrey K. Larsen
December 2015
Rocky Mountain Power
Exhibit No. 1 Page 'l of &l
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
2017 Protocol
Rocky Mountain Power
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Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
I 2017 Protocol
2 I. Introduction:
3 This 2017 PacifiCorp Inter-Jurisdictional Allocation Protocol (the "2017 Protocol") is the
4 result of general agreement that has been reached between representatives of PacifiCorp (or the
5 "Company") and certain Commission staff members, consumer advocates and other interested
6 parties from Idaho, Oregon, Utah, and Wyoming (collectively referred to as the "Parties" or
7 individually as a "Party") regarding issues arising with regards to the 2010 Protocol,
8 PacifiCorp's status as a multi-jurisdictional utility and future inter-jurisdictional allocation
9 procedures.
10 The 2010 Protocol expires at midnight on December 31, 2016. The Parties have
11 determined that it is in their best interest or the interest of PacifiCorp's customers to support a
12 new protocol governing inter-jurisdictional allocation procedures. This 2017 Protocol is
13 designed to provide PacifiCorp, State Commissions, and other interested Parties a transitional
14 allocation method while the impacts of the United States Environmental Protection Agency
15 (EPA) rules governing carbon pollution from existing power plants under section 111(d) of the
16 Clean Air Act (111(d) and other multi-jurisdictional issues are better understood and can be
17 more fully analyzed for their allocation impacts on PacifiCorp and each State. During the term
18 of the 2017 Protocol, PacifiCorp will analyze alternative allocation methods including but not
19 limited to: corporate structure alternatives, divisional allocation methodologies, alternative
20 system allocation methodologies, potential implications of the EPA's final Rule lll(d), and
2I possible formation of a regional independent system operator. PacifiCorp will present its
22 analyses of these issues to the Multi-State Protocol or MSP Workgroup and discuss them at
23 CommissionerForums.
2017 Protocol
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Case No. PAC-E-15-16
Wilness: Jefirey K. Larsen
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During the term of the 2017 Protocol, PacifiCorp commits that its generation and
transmission system will continue to be planned and operated prudently on an integrated basis
designed to achieve a least cost/least risk resource portfolio for PacifiCorp's customers. This
commitment will not prevent PacifiCorp from filing for and requesting State Commission
approval to participate in a regional independent system operator organization.
The 2017 Protocol describes inter-jurisdictional allocation policies and procedures,
which, if applied by each of the States for rate proceedings filed after December 3 1 , 201 6, or as
otherwise agreed to in Section XlV, are intended to better afford, than would otherwise be the
case, PacifiCorp a reasonable opportunity to meet the goal of recovering its prudently incurred
cost of service.
The apportionment, assignment, or allocation of a particular expense or investment, or
allocation of a share of an expense or investrnent, to a State under the 2017 Protocol is not
intended to and will not prejudge the prudence of those costs. Nothing in the 2017 Protocol is
intended to abrogate a State Commission's right and/or obligation to: (l) determine fair, just, and
reasonable rates based upon the law ofthat State and the record established in rate proceedings
conducted by that 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
purposes of allocation of costs and revenues within that State to different customers or customer
classes.
Parties who support the 2017 Protocol do so with the intent to continue to achieve
equitable resolutions to multi-jurisdictional allocation issues that are in the public interest. A
Party's support of the 2017 Protocol will not, however, in any manner negate the necessary
2017 Protocol
Rocky Mountain Power
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Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
1 flexibility of the regulatory process to address changed or unforeseen circumstances, including
2 batnot limited to changes in laws or regulations, and a Party's support of the 2017 Protocol will
3 not bind or be used against that Party if a Party concludes that the 2017 Protocol no longer
4 produces results that are just, reasonable, and in the public interest, or provides the Company
5 with the opportunity to recover its prudently incurred cost of service. Support of the 2017
6 Protocol will not be deemed to constitute an acknowledgement by any Party of the validity or
7 invalidity of any particular method, theory, or principle of regulation, cost recovery, cost of
8 service, or rate design, and no Party will be deemed to have agreed that any particular method,
9 theory, or principle of regulation, cost recovery, cost of service, or rate design employed or
10 implied in the 2017 Protocol is appropriate for resolving any other issues.
11 The 2017 Protocol describes how the costs and revenues, including wholesale
12 transactions, associated with PacifiCorp's generation, transmission, and distribution systems will
13 be assigned or allocated among its six state jurisdictions.
14 Terms that are capitalized in the 2017 Protocol are either defined in the 2017 Protocol or
15 set forth in Appendix A.
16 A table identiffing the allocation factor to be applied to each component of PacifiCorp's
17 revenue requirement calculation is included as Appendix B.
18 The algebraic derivation of each allocation factor is contained in Appendix C.
19 A description and numeric example of how Special Contracts and related discounts will
20 be reflected in rates is set forth in Appendix D.
2l Additional terms specific to each State, including an Equalization Adjustment, are
22 reflected in Section XlV.
2017 Protocol
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1 II. Effective Period and Expiration:
2 The Parties agree to support Commission adoption or use of the 2017 Protocol in all
3 PacifiCorp rate proceedings frled after December 31, 2016, or as otherwise agreed to by Parties
4 in Section XfV, up to and including December 31, 2018.
5 The 2017 Protocol will expire December 31, 2018, unless all State Commissions that
6 approved the 2017 Protocol determine, by no later than March 31, 2017, that the term of the
7 2017 Protocol will be extended by an optional one-year extension through December 31,2019.
8 In determining whether the 2017 Protocol should or should not be extended, each State
9 Commission can take such steps or provide such processes for public input as that Commission
l0 determines to be necessary or appropriate under applicable State laws.
11 A Commissioner Forum will be held annually, beginning in January 2017, to discuss
12 inter-jurisdictional allocation issues and whether the 2017 Protocol should be extended for an
13 additional one-year term, as described above.
14 III. Classification of Resources:
15 All Resource Fixed Costs, Wholesale Contracts, and Shortterm Firm Purchases and Firm
16 Sales will be classified as 75 percent Demand-Related and 25 percent Energy-Related. All Non-
17 Firm Purchases and Sales will be classified as 100 percent Energy-Related.
l8 IV. Allocation of Resource Costs and Wholesale Revenues:
19 Resources will be assigned to one of two categories for inter-jurisdictional allocation
20 purposes: State Resources or System Resources. A complete description of allocation factors to
2l be used is set forth in Appendix B.
22 There are four types of State Resources. The remaining types of Resources are System
23 Resources, which constitute the substantial majority of PacifiCorp's Resources. Benefits and
2017 Protocol
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1 costs associated with each category and type of Resource will be assigned or allocated to
2 Jurisdictions on the following basis:
3 A. State Resources
4 Benefits and costs associated with the four types of State Resources will be
5 assigned as follows:
6 L Demand-Side Management ("DSM") Programs: Costs associated with
7 DSM Programs, including Class I DSM Programs, will be assigned on a
8 situs basis to the Jurisdiction in which the investment is made. Benefits
9 from these programs, in the form of reduced consumption and contribution
10 to Coincident Peak, will be reflected in the Load-Based Dynamic
1l Allocation Factors.
12 2. Portfolio Standards: Costs associated with Resources acquired to comply
13 with a Jurisdiction's Portfolio Standard adopted, either through legislative
t4 enactment or a State's Commission, the portion of which exceeds the costs
15 PacifiCorp would have otherwise incurred, will be assigned on a situs
16 basis to the Jurisdiction adopting the Portfolio Standard.
17 3. Oualifirinq Facility Contracts: Costs associated with Qualifying Facility
18 Contracts, the portion of which exceeds the costs PacifiCorp would have
19 otherwise incurred acquiring Comparable Resources will be assigned on a
20 situs basis to the Jurisdiction that approved the confact.
21 4. Jurisdiction-Specific lnitiatives: Costs and benefits associated with
22 Resources acquired in accordance with a Jurisdiction-specific initiative
23 will be assigned on a situs basis to the Jurisdiction adopting the initiative.
2017 Protocol
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B.
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Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
This includes, but is not limited to, the costs and benefits of incentive
programs, net-metering tariffs, feed-in tariffs, capacity standard programs,
solar subscription programs, electric vehicle programs, and the acquisition
of renewable energy certificates.
System Resources
All Resources that are not State Resources are System Resources and will be
allocated as follows:
1. Generally, all Fixed Costs associated with System Resources and all costs
incurred under Wholesale Contracts will be allocated based upon the
System Generation ("SG") Factor.
2. Generally, all Variable Costs associated with System Resources will be
allocated based upon the System Energy ("SE") Factor.
3. Revenues received by PacifiCorp under Wholesale Contracts will be
allocated based upon the SG Factor.
Equalization Adjustment
The 2017 Protocol includes an Equalization Adjustment to be applied to each
State's revenue requirement, as summaized in Section XlV, for purposes of
ratemaking proceedings filed prior to the expiration of the 2017 Protocol. The
Equalization Adjustment recognizes differences among the States in the 2010
Protocol Agreement implemented in each State and the respective treatment of the
embedded cost differential ("ECD") adjustment - i.e. Baseline ECD, Dynamic
ECD, or no ECD. The 2017 Protocol with the Equalization Adjustment is
C.
6 2017 Protocol
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Witness: Jeffrey K. Larsen
1 designed to allow PacifiCorp the opportunity to equitably allocate revenue
2 requirement components in rate recovery proceedings in the States.
3 V. Re-functionalization and Allocation of Transmission Costs and Revenues
4 Before filing any request to approve a reclassification of facilities as transmission or
5 distribution with FERC, PacifiCorp will submit filings seeking review and authorization of any
6 such reclassification with the State Commissions. The cost responsibility for any assets
7 reclassified under FERC policy will be assigned or allocated consistent with other assets in the
8 relevant function.
9 Costs associated with transmission assets, and firm wheeling expenses and revenues, will
10 be classified as 75 percent Demand-Related, 25 percent Energy-Related and allocated based
11 upon the SG Factor. Non-firm wheeling expenses and revenues will be allocated based upon the
12 SE Factor. In the event that PacifiCorp joins a regional independent system operator, the
13 allocation of transmission costs and revenues may be reevaluated and revised as provided for in
14 Section XIII.
15 VI. Assienment of Distribution Costs:
16 All distribution-related expenses and investment that can be directly assigued will be
17 directly assigned to the State where they are located. Those costs that cannot be directly
18 assigned will be allocated consistent with the factors set forth in Appendix B.
19 VII. Allocation of Administrative and General Costs:
20 Administrative and General Costs, General Plant costs, and tntangible Plant costs will be
2l allocated consistent with the factors set forth in Appendix B.
22 VIII. Allocation of Special Contracts:
23 Revenues associated with Special Contracts will be included in State revenues, and loads
2017 Protocol
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1 of Special Contract customers will be included in Load-Based Dynamic Allocation Factors as
2 appropriate (see Appendix D). Special Contracts may or may not include Customer Ancillary
3 Service Contract attributes. Load curtailments and buy-through arrangements will be handled as
4 appropriate (see Appendix D).
5 IX. Allocation of Gain or Loss from Sale of Resources or Transmission Assets:
6 Any loss or gain from the sale of a Company-owned Resource or transmission asset will
7 be allocated based upon the allocation factor used to allocate the Fixed Costs of the Resource or
8 the transmission asset at the time of its sale. Each Commission will determine the appropriate
9 allocation of loss or gain allocated to that Jurisdiction as between customers and PacifiCorp
10 shareholders.
11 X. State Programs Regardins Access to Alternative Electricitv Suppliers:
12 A. Treatment of Oregon Direct Access Programs:
13 This Section describes treatment of loads lost to Oregon Direct Access Programs during
14 the term of the 2017 Protocol.
15 1. Customers electing PacifiCorp's one- and three-year Oregon Direct
16 Access Programs - The load of customers electing to be served on PacifiCorp's one- and
17 three-year Oregon Direct Access Programs will be included in the Load-Based Dynamic
18 Allocation Factors for all Resources, and the transition cost payments from these
19 customers will be situs assigned to Oregon.
20 2. Customers electing PacifiCorp's five year opt-out program under the
2l Oregon Direct Access Program - The treatment will be consistent with Order No. 15-
22 060, as clarified through Order No. 15-067, of the Oregon Public Utility Commission in
23 Docket UE 267, and Oregon Schedule 296, which allow Oregon Direct Access Program
2017 Protocol
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Customers to permanently opt-out of cost-of-service rates after payment of ten years of
transition costs in Oregon. During the ten-year period for which Oregon Direct Access
Customers are paying hansition costs, the Oregon Direct Access Customers' loads will
be included in Load-Based Dynamic Allocation Factors, and the transition cost payments
from these customers will be situs-assigned to Oregon. At the end of the lO-year period
covered by the transition cost payments, the loads of the Oregon Direct Access
Customers will be excluded from Load-Based Dynamic Allocation Factors. Thereafter,
if an Oregon Direct Access Customer elects to return to Oregon cost-of-service rates by
providing four-years notice under Schedule 267, its load will be included in Load-Based
Dynamic Allocation Factors at the time the customer returns to Oregon cost of service
rates.
3. To the extent Oregon adopts new laws or regulations regarding Oregon
Direct Access Programs, Oregon's treatment of loads lost to Oregon Direct Access
Programs may be re-determined in a manner consistent with the new laws and
regulations. In the event Oregon adopts such new laws or regulations, the Company will
inform the State Commissions and the Parties of the same.
B. Utah Eligible Customer Program:
If, pursuant to Utah Code Annotated Section 54-3-32, an eligible customer in Utah
transfers service to a non-utility energy supplier, the Public Service Commission of Utah will
make determinations under Utah law as contemplated therein. The Company will inform the
State Commissions and the Parties of the Public Service Commission of Utah's determinations.
C. Other State Actions:
In the event any State adopts laws or regulations governing customer access to alternative
2017 Protocol
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Case No. PAC-E-I5-16
Witness: Jeffrey K. Larsen
1 electricity suppliers, the Company will inform the State Commissions and the Parties of the
2 same.
3 XI. Loss or Increase in Load:
4 Any loss or increase in retail load occurring as a result of condemnation or
5 municipalization, sale, or acquisition of new service territory that involves less than five percent
6 of system load, realignment of service territories, changes in economic conditions, or gain or loss
7 of large customers will be reflected in changes in the Load-Based Dynamic Allocation Factors.
8 The allocation of costs and benefits arising from merger, sale, or acquisition transactions
9 proposed by the Company involving more than five percent of system load will be considered on
10 a case-by-case basis in the course of Commission approval proceedings.
11 XII. Commission Regulation of Resources:
12 PacifiCorp will plan and acquire new Resources on a system-wide least-cost, least-risk
13 basis. Prudently incurred investments in Resources will be reflected in rates consistent with the
14 laws and regulations in each State, as approved by individual State Commissions.
15 XI[. Interpretation and Governance:
16 A. Issues of Interpretation
17 If questions of interpretation of the 2017 Protocol arise during rate proceedings, audits of
18 results of PacifiCorp's operations, or both, Parties will attempt, consistent with their legal
19 obligations, to resolve them in good faith in light of the language of the 2017 Protocol and the
20 intent of the Parties.
2l B. Commissioner Forum
22 A Commissioner Forum will be held annually beginning January 2017 to discuss the
23 2017 Protocol and other inter-jurisdictional allocation issues that may arise. All seated
10 2017 Protocol
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I commissioners from each Jurisdiction will be invited to participate in all Commissioner Forums.
2 Each Commissioner Forum will be a public meeting and all interested parties will be
3 allowed to attend. Prior to attending a Commissioner Forum, each Commission can take such
4 steps and provide such process for public input as the Commission determines to be necessary or
5 appropriate under applicable State laws.
6 At the Commissioner Forum, commissioners will be invited to discuss and may make
7 recommendations regarding extension of the 2017 Protocol and other inter-jurisdictional
8 allocation issues that may arise.
9 C. MSP Workgroup
10 The MSP Workgroup will be open to any utility regulatory agency, customer, and other
I 1 person or entity potentially affected by inter-jurisdictional allocation procedures that expresses
12 an interest in participating. The MSP Workgroup may create sub-committees to investigate,
13 evaluate, or make recommendations as to specified issues. MSP Workgroup meetings may be
14 held in person or by telephone.
15 The Company will promptly convene one or more MSP Workgroup meetings: (i) to
16 discuss the possibility of a new inter-jurisdictional allocation agreement if any Commission
17 indicates that the 2017 Protocol should not be extended pursuant to Section II or as a result of
18 new developments pursuant to Section X, (iD to discuss an inter-jurisdictional allocation issue
19 identified by any Commission, or (iii) to discuss any other inter-jurisdictional allocation issue
20 raised by any interested stakeholders. MSP Parties will work in good faith to achieve resolution
2I of any issues brought before the MSP Workgroup.
22 Before each annual Commissioner Forum, PacifiCorp will convene an MSP Workgroup
23 meeting for the purpose of discussing and monitoring emerging inter-jurisdictional allocation
1l 2017 Protocol
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1 issues facing PacifiCorp and its customers, the status and implications of Rule 111(d), orthe
2 development of a regional independent system operator, in order to inform discussions at the
3 Commissioner Forum. PacifiCorp will provide reasonable staffing and resources to provide
4 minutes of any MSP Workgroup meeting, coordinate MSP Workgroup activities and conduct
5 studies and analysis as agreed to by the MSP Workgroup, and as suggested by the Commissioner
6 Forum.
7 D. Proposals for New Inter-Jurisdictional Allocation Procedures
8 Proposals for new inter-jurisdictional allocation procedures, including any changes to the
9 2017 Protocol, ranging from minor modifications to major modifications, may be submitted by
10 any Party or any Commission utilizing the 20t7 Protocol. Proposals shall be provided to the
l l Company for the purpose of circulating the proposals to the other Parties and State Commissions
12 and initiating discussions to attempt to address and resolve specific concerns.
13 If any Party intends to propose a new inter-jurisdictional allocation procedure, the Party
14 will attempt, consistent with their legal obligations, to: (1) bring that proposal to the
15 Commissioner Forum or the MSP Workgroup and (2) resolve the proposal in good faith.
16 A Party's initial support or acceptance of the 2017 Protocol will not bind or be used
17 against that Party if unforeseen or changed circumstances, including new developments pursuant
18 to Section X, cause that Party to conclude that the 2017 Protocol no longer produces just and
19 reasonable results, reasonable cost recovery for the Company, or is not in the public interest.
20 Before a Party asks a Commission to deviate from the terms of the 2017 Protocol, the Parties,
2l will be invited by the Company to enter into a discussion, or series of discussions, to attempt to
22 address and resolve their concerns at MSP Workgroup meetings and/or a Commissioner Forum,
23 consistent with any applicable legal obligations.
t2 2017 Protocol
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Exhibit No. 1 Page 14 of64
Case No. PAC-E-15-16
\Mtness: Jeffrey K. Larsen
E. InterdependencyamongCommissionApprovals
The 2017 Protocol has been developed by the Parties as an integrated, interdependent,
3 organic whole. Support by any Party or Commission of the 2017 Protocol is expressly
4 conditioned upon similar support of the 2017 Protocol by the Commissions of at least the States
5 of Idaho, Oregon, Utah, and Wyoming, without material alteration. If a Commission materially
6 deletes, alters, or conditions approval of the 2017 Protocol, Parties shall promptly meet and
7 discuss the implications of the material alteration, and will have the opportunity to accept or
8 reject continued support of the 2017 Protocol in light of such action.
9 XIV. Additional State-Specific Terms:
10 For the period that the 2017 Protocol remains in effect, a2017 Protocol Adjustment will
l1 be added to each State's annual revenue requirement. For Califomia, Idaho, Utah, and Wyoming,
12 the 2017 Protocol Adjustment is the sum of the Baseline ECD and the Equalization Adjustment.
13 For Oregon,the20lT Protocol Adjustment is the sum of the Baseline ECD, which is dynamic
14 with the parameters described in paragraph three below, and the Equalization Adjustment. The
15 Parties agree to an annual Equalization Adjustment of $9.074 million, with specific State-by-
16 State 2017 Protocol Adjustment impacts as summarized in this table:
Total
201 7 Protocol Baseline ECD ** (9,578) (324) (8,238) * 0 836 (l ,851)
2017 ProtocolEqualiationAdjustrrent 9,074 324 2,600 4,400 150 I
2017 ProtocolAdjustrnent (0) (5,638) 4,400 986 (251)
Revenue Califomia Utah Idaho
* Oregoris 2017 Protocol Baseline ECD is dynamic ard will change over time with the pararnters descnbed inparagraph
3 below. For tlre other states, the 2017 Protocol Baseline ECD is fted and does not change over tinre.** 2017 Protocol Baseline ECD annunts slrown in the table for Califomia, Orego4 ard Wyoming are based on the test
year data as fled by the Conpany in the 2015 Wyoming general rate case (Docket 20000-469-ER- 15) on March 3,
201 5. The anrcunt for Idaho's 20 I 7 Protocol Baselirre ECD is its 201 0 Protocol Fixed ECD anrourt. Utahs 201 7 Protocol
Baseline ECD is zero based on its 201 0 Protocol agreenrent.
t3 2017 Protocol
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Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
State specific implanentation is summarized below:
l. Califomia's 2017 Protocol Adjustment is zero.
2. The Idaho Parties and PacifiCorp agree to an annual Idaho 2017 Protocol Adjustment of
$0.986 million to be added to Idaho's 2017 Protocol revenue requirement. Idaho's
Equalization Adjustment is $0.150 million. The Idaho 2017 Protocol Adjustment shall be
included in base rates through a general rate case beginning January l, 2018, or to the
extent that a case is filed so the rate effective date is later than that date, the Equalization
Adjustment shall be deferred on a monthly basis ($12,500 per month) from January l,
2018, forward as a regulatory asset until the rate effective date of PacifiCorp's next Idaho
general rate case at which time (l) the deferred costs and (2) the ongoing impact of
Idaho's 2017 Protocol Adjustment shall be included in rates.
3. The Public Utility Commission of Oregon Staff ("Commission Staff'), the Citizens'
Utility Board of Oregon ("CUB"), and PacifiCorp ("Oregon Parties"), agree to an Oregon
Equalization Adjustment of $2.6 million. The Oregon Parties agree that Oregon's
Equalization Adjustment of $2.6 million annually (or $216,667 monthly) be deferred
from January 1,2017, until the 2017 Protocol Equalization Adjustment is reflected in
base rates through the Company's next general rate case. The Oregon Parties agree that
the 2017 Protocol Equalization Adjustment deferral will be reflected as a debit (reduction
to the existing credit balance to be returned to customers) in the Open Access
Transmission Tariff ("OATT") revenue deferral account originally established through
docket IJE 246.r The Parties agree that the Company will file a new tariff to return to
I As a result of the stipulation and Commission Order No. 12-493 in docket IJE-246, the Company filed for, and the
Commission approved the Company's application to defer incremental OATT revenues from January l, 2013, until
(Continued...)
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Oregon customers the balance of the OATT revenue deferral, net of the 2017 Protocol
Equalization Adjustment deferral, within 60 days of an Oregon Commission order
approving of the 2017 Protocol. The Company commits to continued evaluation of
alternative inter-jurisdictional allocation methods, including consideration of corporate
structure alternatives, divisional allocation methodologies, and potential implications of
the Environmental Protection Agency's final Rule 1ll(d), and possible formation of a
regional independent system operator. The Company will distribute or present the results
of its analysis, based on information available, no later than March 3I, 201,7. If
PacifiCorp does not distribute or present the results of its analysis on or before March 31,
20L7, for each month the analysis is not provided after that date $216,667 will be credited
to the OATT revenue deferral balance unless otherwise waived by the Commission for
good cause. The Company agrees that during the effective period of this agreement
regarding the 2017 Protocol, the Company will not have any pending general rate case
that requests rates effective before January 1, 2018. Oregon Parties may file for deferrals
during the general rate case stay-out period, but such filings will be subject to the
Commission's guidelines for defenals established in docket UM I147, unless otherwise
authorized by the Commission. This provision will not alter the operation or application
of existing or new rate adjustment mechanisms authorizedby the Commission, including
but not limited to PacifiCorp's Transition Adjustment Mechanism, the Power Cost
Adjustment Mechanism, and the Renewable Adjustment Clause. The Oregon Parties
agree that for the duration of the 2017 Protocol, Oregon's results of operations reports
(...continued)
these revenues are reflected in base rates. Commission OrderNos. 13-045, 14-023, and 15-020 approved the
Company's applications to defer these incremental revenues for 2013, 2014, and 2015, respectively.
l5 2017 Protocol
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and general rate case filings will reflect a Dynamic ECD calculated consistent with the
2010 Protocol inter-jurisdictional allocation methodology with the parameters as
described below:
r For the Company's first Oregon general rate case filing under the 2017 Protocol
(which will be effective no earlier than January l, 2018), the Dynamic ECD value for
Oregon will be set at a level no less than $8.238m (the baseline value of Oregon's
ECD used to negotiate each State's contribution to the 2017 Protocol Equalization
Adjustment), and will be capped at $10.5 million; and
. If the 2017 Protocol is extended to 2019, and the Company files a second Oregon
general rate case using the 2017 Protocol, the Dynamic ECD in that general rate case
filing will be set at a level no less than $8.238m and will be capped at $11.0 million.
The Dynamic ECD provisions apply only to the 2017 Protocol as an integrated
agreement and do not in any way limit or compromise any party's ability to argue for
a different ECD or hydro endowment calculation in any future inter-jurisdictional
allocation methodologies.
The Oregon Parties agree that unless there is formal action by the Public Utility
Commission of Oregon to adopt an alternate allocation methodology by January 1.,2019,
or unless the 2017 Protocol is extended through 2019 under the terms of the 2017
Protocol, PacifiCorp will use the Revised Protocol allocation method for general rate case
frlings in Oregon after January I, 2019. The Oregon Parties have negotiated this
settlement as an integrated agreement. If the Public Utility Commission of Oregon
rejects all or any material portion of this agreement or imposes additional material
conditions in approving this agreement, any of the Oregon Parties are entitled to
t6 2017 Protocol
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withdraw from the settlement. If the Public Utility Commission of Oregon rejects the
2017 Protocol, this agreement terminates upon the date of the order rejecting the 2017
Protocol.
The Utah Parties and PacifiCorp agree to an annual Utah Equalization Adjustment of
$4.4 million and a2017 Protocol Adjustment of the same amount. The Company agrees
that it will not file a Utah general rate case or major plant addition case prior to May 1,
2016, and new rates will not be effective prior to January 1,2017. Utah's 2017 Protocol
Adjustment shall be included in base rates through a general rate case with rates effective
beginning on or after January 1,2017. To the extent that a Utah general rate case or
major plant addition case is filed with a rate effective date later than that date, Utah's
Equalization Adjustment shall be deferred on a monthly basis, (9366,667 per month),
from January 1,2017, forward as a regulatory asset until the rate effective date of
PacifiCorp's next Utah general rate case at which time (l) the deferred costs and (2) the
ongoing impact of Utah's 2017 Protocol Adjustment shall be included in rates. The
deferred cost amortization period will be determined in the first case that the deferral of
the Utah Equalization Adjustment is proposed for inclusion in rates.
The Wyoming Parties and PacifiCorp agree to an annual credit for Wyoming's 2017
Protocol Adjustment of $0.251 million to be netted against Wyoming's 2017 Protocol
revenue requirement. If the Company does not file a general rate case prior to January 1,
2017, Wyoming's Equalization Adjustment of $1.6 million annually shall be deferred, as
a regulatory asset, on a monthly basis, ($133,333 per month), beginning July 1, 2017,
until the rate effective date of PacifiCorp's next Wyoming general rate case, at which
time (1) the deferred costs and (2) Wyoming's ongoing impact of the 2017 Protocol
5.
t7 2017 Protocol
I
2
3
4
5
6
7
8
Rocky Mountain Power
Exhibit No. 1 Page 19 of 64
Case No. PAC-E-15-16
Wtness: Jeffrey K. Larsen
Adjushnent shall be included in rates. The deferred cost amortization period will be
determined in the first case that the defenal of the Wyoming Equalization Adjustnent is
proposed for inolusion in rates. If a Wyoming general rate oase is filed prior to January 1,
2017, then the Wyoming Equalization Adjusturent shall not be deferred and will only be
included in base rates ftom the rate effective date of a general rate case filing occurring
on or after January L,2017. The Wyoming Parties also agree that the Company no longer
is required to file Revised Protocol results (Tab 9) as part of its results of operations
reports effective January 1,2017.
ROCKY MOUNTAIN PACIFIC POWER
A DIVISION OF PACIFICORP
Wo,,o,Bryce Dalley
Yice Pre sident, Re gulation
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Terri Carlock
Deputy Adtttinistrator of ldaho Public
Util ities Commiss ion Stoff
OREGON PIJBLIC UTILMY COMMISSION
Jason W. Jones
Cotmselfor Oregon Public Utility Comrnission
Staff
CMIZENIS UTILITY BOARD OF OREGON
Bob Jenks
Executive Director of Citizens Uttlity Board of
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Chris Parker
Director of Utah Division of Publie Utilities
TJTAH OFFICE OF CONSI,JMER
SERVICES
I.ruAH ASSOCIATION OF ENERGY USERS
Michelle Beck
Director of Utah Offrce of Consumer Services
GaryDodge
Attorrav for Utah Association of Enernt Users
18 2017 Protocol
I
2
aJ
4
5
6
7
8
Rocky Mountain Power
Exhibit No. 1 Page 20 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Adjustment shall be inciuded in rates. The deferred cost amodization period will be
determined in the first case that the deferral of the Wyoming Equalization Adjustment is
proposed for inclusion in rates. If a Wyoming general rate case is filed prior to January I .
2017, then the Wyoming Equalization Adjustment shall not be deferred and will only be
included in base ratss from the rate effective date of a general rate case filing occuring
cn or after January 1, 2017. The Wyoming Panies also agree that the Company no longer
is required to file Revised Protocol results ffab 9) as part of its results of operations
reports effective January l,2Al7.
ROCKY MOUNTATN POWER
A DIVISION OF PACIFICORP
PACIFIC POWER
A DIViSION OF PACITICORP
Jeffrey K. Larsen
Vice President, Regulation
Brvce Dallev / -z
Yice Presidint, aeffion
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Terri Carlock
Deputy Administrator of ldaho Public
Utilities Commission Staff
OREGON PUBLIC UTILITY COMMISSION
Jason W. Jones
Counsetfor Oregon Pubtic Utility Commission
Staff
CITTZENS UTILITY BOARD OF OREGON
Bob Jenks
Executive Director af Citizens Utility Board of
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Chris Parker
Director of Utah Division of Public Utilities
UTAH OFFICE OF CONSUMER
SERVICES
Miehclle BEck
Director of Utah Office of Consumer Services
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Attorney for Utah Association of Enernt Users
l8 2017 Protocol
I
2
3
4
5
6
7
8
Rocky Mountain Power
Exhibit No. 1 Page 21 ot 64
Case No. PAC-E-15-16
Wtness: Jeffrey K. Larsen
Adjustment shall be included in rates. The deferred cost amortization period will be
determined in the first case that the deferral of the Wyoming Equalization Adjustment is
proposed for inclusion in rates. lf a Wyoming general rate case is filed priorto January l,
2017, then the Wyoming Equalization Adjustment shall not be deferred and will only be
included in base rates from the rate effective date of a general rate case filing occuning
on or after January l,zAn . The Wyoming Parties also agree that the Company no longer
is required to file Revised Protocol results (Tab 9) as part of its results of operations
reports effective January 1,2017 .
ROCKY MOTINTAIN POWER
A DIVISION OF PACIFICORP
PACIFIC POWER
A DIVISION OF PACIFICORP
Jeffrey K. Larsen
Vice President, Rogulal ion
Bryce Dalley
Vice President, Regi.tlat ion
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Terri Carlock
Deputy Adntinislralor of ldaho Public
Ut i I i t ie s Comm i ss ion Staff
ORECON PUBLIC UTILITY COMMISSION
Jason W. Jones
Counselfor Oregon Public Utility Conunission
Stalf
CI'TIZENS UTILITY BOARD OF OREGON
Bob Jenks
Erecutive Directar of Citizens Ulility Board of
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Chris Parker
Director af Utah Division of Public Utilities
UTAH OFFICE OF CONSUMER
SERVICES
Michelle Beck
Direclor of Utah Oflice of Cansumer Services
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Atlornev for Utah Association of Enerw Users
l8 2017 Protocol
Rocky Mountain Power
Exhibit No. 'l Page 22 ot 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
I
2
3
4
5
6
7
8
Adjustment shall be included in rates. The deferred oost amortization period will be
determined in the first case that thE deferral of the Wyoming Equalization Adjustment is
proposed for inclusion in rates. If a Wyoming general rate sase is filed prior to January l,
2017, then the Wyoming Equalization Adjustment shall not be deferred and will only be
included in base rates from the rate effective date of a general rate case filing occurring
on or after January 1,2017. The Wyoming P&rties also agree that the Company no longer
is required to file Revised Protocol results (Tab 9) as part of its results of operations
reports effective January 1,2017.
ROCKY MOUNTAIN POWER
A DIVISION OF PACIFICORP
PACIF}C POWER
A DIVISION OF PACIFICORP
Jeffrey K. Larsen
Vice President, Regulation
Bryce Dalley
Vice President, Regulation
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
ORECON PUBLIC UTILITY COMMISSION
Teni Carlock
Deputy Administrator of ldaho Public
Utilities Commission Stalf
ffion W. Jones v
Caunselfor Oregon Public Utility Commission
Staff
CITIZENS UTILITY BOARD OF OREGON
Bob Jenks
Exeeulive Director of Citizens Utility Board of
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Chris Parker
Director of Utah Division of Public Utilities
UTAH OFFICE OF CONSUMER
SERVICES
Michelle Beck
Direetor of Utah Oflice of Consumer Services
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Attornev for Utah Association of Enerw Users
18 2017 Protocol
I
2
3
4
5
6
7
8
Rocky Mountain Power
Exhibit No. 1 Page 23 of 64
Case No. PAC-E-15-16
Witness : Jefftey K. Larsen
Adjustment shall be included in rates. The deferred cost amortization period will be
determined in the first case that the deferral of the Wyoming Equalization Adjustment is
proposed for inclusion in rates. [f a Wyoming general rate case is filed prior to January l,
2017, then the Wyoming Equalization Adjustment shall not be deferred and will only be
included in base rates from the rate effective date of a general rate case filing occurring
on or after January 1,2017 . The Wyoming Parties also agree that the Company no longer
is required to file Revised Protocol results (Tab 9) as part of its results of operations
reports effective January 1,2017.
ROCKY MOUNTAIN POWER
A DIVISION OF PACIFICORP
PACTFIC POWER
A DIVISION OF PACTFICORP
Jeffrey K. Larsen
Vice President, Regulation
Bryce Dalley
Vice President, Regulation
IDAHO PUBLIC UTILTTIES COMMISSION
STAFF
OREGON PUBLIC UTILITY COMMTSSION
Terri Carlock
Deputy Administrator of ldaho Public
Utililies Commission Staff
Jason W. Jones
Counselfor Oregon Public Utility Commission
snff
Executive Director of CitizensrUtility Board of
Oregon
UTAH DIVISTON OF PUBLIC UTILITIES
Chris Parker
Director of Utah Division of Public Utilities
UTAH OFFICE OF CONSUMER
SERVICES
Michelle Beck
Director of Utah Office of Consumer Services
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Attornev for Utah Association of Enerw Users
l8 2017 Protocol
I
,|
J
4
Rocky Mountain Power
Exhibit No. 1 Page 24 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Adjustment shall be included in rates. The defered cost amortization pedod will be
determined in the first case that the deferal of the Wyoming Equalization Adjustment is
proposed for inclusion in rates. If a Wyoming gensral rate case is filed prior to January l,
2017, then the Wyoming Equalization Adjustment shall not be deferred and will only be
included in base rates from the rate effective date of a general rate case filing occurring
on or after January 1,2017 . The Wyoming Parties also agree that the Company no longer
is required to file Revised Protocol results (Tab 9) as pafi of its results of operations
reports effective January t,2Al7.
5
6
7
8
l8
ROCKY MOLINTAIN POWER
A DryISION OF PACtrICORP
PACtrIC POVI/ER
A DIVISION OF PACIFICORP
Jeffrey K. Larsen
Yice P res ident, Resulation
Bryce Dalley
Vice President, Resulatiorz
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
OREGON PUBLIC UTILI?Y COMMISSION
Terri Carlock
Deputy Adminisrator of ldaho Public
U tilities C ommis sio n Stalf
Jason W. Jones
Counselfor Oregon Public Utility Commission
snff
CITIZENS UTILITY BOARD OF ORECON
Bob Jenks
Executive Director of Citizens Utility Board of
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Director of Utah Division of Public Utilities
UTAH OFFICE OT CONSTIMER
SERVICES
Michelle Beck
Director of Utah Ollice of Consumer Sentices
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Attornev for Utah Associatiort of Enersy Users
2017 Protocol
I
2
J
4
5
6
7
8
Rocky Mountain Power
Exhibit No. 1 Page 25 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Adjustment shall be included in rates. The det'erred cost amortization period will be
determined in the first case that the deferral of the Wyoming Equalization Adjustment is
proposcd for inclusion in ratcs. If a Wyoming gencral ratc case is filcd prior to January l,
20t7, then the Wyoming Equalization Adjushnent shall not be deferred and will only be
includcd in basc rates from the rate etlbctive date of a gcncral rate case filing occurring
on or afler January l, 2017 . The Wyoming Parties also agree that the Conpany no longer
is required to tile Revised Protocol results (Tab 91 as part of its results of operations
reports effective January l,2Al7.
ROCKY MOUNTAIN POWER
A DIVISION OF PACIFICORP
PACIFIC POWER
A DIVISION OF PACIFICORP
Jetliey K. Larsen
Vic'e Prcs iden t, Regulotiott
Bryce Dalley
l'ice P res icle n t. Regul o tiott
IDAHO PUBLIC UTILITIES COMMISSION
STAFF
Terri Carlock
Deputy Aclministrqtor o/' Idaho Public
Uti I ities Comnissiort Stulf
OREGON PUBLIC UTILITY COMMISSION
Jason W. .lones
Counsel.fbr Oregon Public Utility Commission
stQ.l.f
CITIZENS UTILITY BOARD OF ORECON
Bob Jenks
E.reartive Director of Citizens Utility Board o.f
Oregon
UTAH DIVISION OF PUBLIC UTILITIES
Chris Parker
Director o/' Utuh Div,isiott o./' Public Utilities
UTAH OFFICE OF CONSUMER
SERVICES
Director ol' Utah Olfice of' Consunter Service.s
UTAH ASSOCIATION OF ENERGY USERS
Gary Dodge
Attorney /br Utqh Associrttion o/'Efiersv Users
l8 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 26 of64
Case No. PAC-E-15-16
Vvitness: Jeftey K. Larsen
WYOMING OFFICE OT CONSUMER
ADVOCATE
Seniar Counsel of Wyoming Office
of Consumer Advocate
Ivan Williams
WYOMING INDUSTRTAL ENERCY
CONSUMERS
Robert M. Pomeroy, Esq.
Thorvald A. Nelson" Esq.
Anoraeys for Wyoming Indas trial Energ;
Consumers
WYOMING PUBLIC SERVICE
COMMISSION STATF
Danell Zlomke
Commis s ion Administrator for Wyoming
Public Serviee Commission
t9 2017 Protocol
WYOMING OFFICE OF CONSUMER
ADVOCATE
WYOMTNG INDUSTRIAL ENERGY
CONSUMERS
Ivan Williams
Senior Counsel of Wyoming Affice
of Consuner Advocate
Robert M. Pomeroy, Esq.
Thorvald A. Nelson, Esq.
Attorneys for Wyoming Industrial Energt
Consumers
WYOMING PUBLIC SERVICE
COMMISSION STAFF
Danell Zlomke
C o mmi s s io n Admini s tr ator for Wyoming
Public Service Commission
Rocky Mountain Power
Exhibit No. 1 Page 27 of 64
Case No. PAC-E-15-'16
Wtness: Jeffrey K. Larsen
t9 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 28 of 64
Case No. PAC-E-15-16
\Mtness: Jeffrey K. Larsen
WYOMING OFFICE OF CONSUMER
ADVOCATE
WYOMING INDUSTRIAL ENERCY
CONSUMERS
Ivan Williams
Senior Counsel of lVyoming Ofice
of Consumer Advocale
Robert M. Pomeroy, Esq.
Thorvald A. Nelson, Esq.
Anorneys for Wyoming Industrial Energt
Consumers
1VYOMING PUBLIC SERVICE
COMMISSION STAFF
{arreiitztoffi}7
C ommis s i o **drt ni s tr at or fo r l{y o m i n g
Public Ssryice Commission
*This signature does not represent the position of any Wyoming Public Service Commission
Commissioner or any Commission staffnot directly involved with the negotiations leadingto
this Settlement Agreement (the *7A17 Protocol").
l9 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 29 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
2017 Protocol - Appendix A
Defined Terms
Rocky Mountain Power
Exhibit No. 1 Page 30 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
2017 Protocol - Appendix A
Defined Terms
For purposes of this 2017 Protocol, these terms will have the following meanings:
*2010 Protocol" means the PacifiCorp inter-jurisdictional allocation method that was
approved by the Idaho, Oregon, Utah, and Wyoming Commissions in 2012 to apply to all
PacifiCorp rate proceedings filed after each commission's approval and before December 31,
2016.
*2017 Protocol Adjustment" means the result of netting the 2016 Baseline ECD against
the $9.074 million Equalization Adjustment for each State's revenue requirement as specified in
Section XIV of the 2017 Protocol. The 2017 Protocol Adjustment is intended to cause
PacifiCorp and each of the States participating in the 2017 Protocol to bear a reasonable
proportion of the allocation shortfall resulting from differences in the 2010 Protocol inter-
jurisdictional allocation procedures utilized by such States.
"Administrative and General Costs" means costs included in FERC accounts 920
through 935.
"Class 1 DSM Programs" means DSM Programs designed to reduce peak loads.
"Coincident Peak" means the hour each month that the combined demand of all
PacifiCorp retail customers is greatest. In States using a historic test period Coincident Peak is
based upon actual, metered load data adjusted for normalized weather conditions and in States
using future test periods Coincident Peak is based upon forecasted norm alized.loads, in both
cases adjusted as appropriate for intemrptibility of Special Contracts.
"Commission" means a utility regulatory commission in a Jurisdiction.
"Commissioner Forum" means an annual public meeting held in January of each year
beginning in 2017 to which all seated commissioners from each Jurisdiction will be invited to
discuss the 2017 Protocol and other inter-jurisdictional allocation issues.
"Company" means PacifiCorp.
Appendix A - 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 31 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
"Comparable Resource" means Resources with similar capacity factors, start-up costs,
and other output and operating characteristics.
ttCustomer Ancillary Service Contracts" means contracts between the Company and a
retail customer pursuant to which the Company pays the customer for the right to curtail service
so as to lower the costs of operating the Company's system.
"Demand-Related" means capital and other Fixed Costs or revenues incurred or
received by the Company in order to be prepared to meet the maximum demand imposed upon
its system.
"Demand-Side Management Programs" or 6'DSM Programs" means programs
intended to reduce electricity use through activities or programs that promote electric energy
efficiency or conseryation, more efficient management of electric energy loads, or reductions in
peak demand.
"Embedded Cost Differential" or "ECD" means the sum of (l) PacifiCorp's total
production costs of Pre-2005 Resources expressed in dollars per megawatt-hour compared to the
Hydro-Electric Resources forecasted production costs expressed in dollars per megawatt-hour
multiplied by the Hydro-Electric Resources megawatt-hours of production, and (2) the
differential between the Pre-2005 Resources dollars per megawatt-hour compared to Mid-
Columbia Contracts forecasted costs in dollars per megawatt-hour multiplied by the Mid-
Columbia Contracts megawatt-hours.
o ooBaseline ECD" means the amount of the ECD for each State to be used in the
determination of the 2017 Protocol Adjustment. For the states of Califomia, and
Wyoming, their Baseline ECD amounts are based on the test year data, as filed by
the Company in the 2015 Wyoming General Rate Case (Docket 20000-469-ER-
15, Exhibit SRM-2), on March 3, 2015. Idaho's Baseline ECD is its 2010
Protocol Fixed ECD amount. Utah's 2017 Protocol Baseline ECD is zero based
on its 2010 Protocol agreement. For Oregon, the Baseline ECD is dynamic with
the parameters described in paragraph three of Section XIV.
, O9pendix A-2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 32 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
. "Dynamic ECD" means the ECD components are updated to the test period
utilized in the filing.
"Energy-Related" means costs and revenues, such as fuel costs and transmission costs,
or sales revenues that vary with the amount of energy delivered by the Company to its customers
during any hour plus any portion of Fixed Costs that have been deemed to have been incurred or
received by the Company in order to meet its energy requirements.
"Equalization Adjustment" means a fixed dollar adjustment to be applied to each
State's revenue requirement as reflected in Section XIV of the 2017 Protocol intended to cause
PacifiCorp and each of the States participating in the 2017 Protocol to bear a reasonable
proportion of the allocation shortfall resulting from differences in current inter-jurisdictional
allocation procedures utilized by such states.
(FERC" means the Federal Energy Regulatory Commission.
"Fixed Costs" means costs incurred by the Company that do not vary with the amount of
energy delivered by the Company to its customers during any hour.
"General Plant" means capital investrnent included in FERC accounts 389 through399.
"Hydro-Electric Resources" means Company-owned hydro-electric plants located in
Oregon, Washington or California.
"Intangible Plant" means capital investment included in FERC accounts 301 through
303.
"Jurisdiction" means any one of the six states where the Company provides retail
service.
"Load-Based Dynamic Allocation Factor" means an allocation factor that is calculated
using States' monthly energy usage and/or States' contribution to monthly system Coincident
Peak.
"Mid-Columbia Contracts" means the various power sales agreements between
PacifiCorp and Public Utility District No. 2 of Grant County, PacifiCorp and Douglas County
Public Utility District, and PacifiCorp and Chelan County Public Utility District, specifically: the
. Appendix A-2017 Protocol
J
Rocky Mountain Power
Exhibit No. 1 Page 33 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Power Sales Contract with Public Utility District No. 2 of Grant County dated May 22, 1956; the
Power Sales Contract with Public Utility District No. 2 of Grant County dated June 22,1959;the
Priest Rapids Project Product Sales Contract with Public Utility District No. 2 of Grant County
dated December 31, 2001; the Additional Products Sales Agreement with Public Utility District
No. 2 of Grant County dated December 31, 2001; the Priest Rapids Project Reasonable Portion
Power Sales Contract with Public Utility District No. 2 of Grant County dated December 31,
2001; the Power Sales Contract with Douglas County Public Utility District dated September 18,
1963; the Power Sales Contract with Chelan County Public Utility District dated November 14,
1957 and all successor contracts thereto.
"Multi-State Protocol Workgroup" or "MSP Workgroup" means a group consisting
of utility regulatory agencies, customers and others potentially affected by inter-jurisdictional
allocation procedures who desire to participate in a cooperative workgroup context and who
agree to comply with reasonable confidentiality and other procedures adopted by the MSP
Workgroup.
ttNon-Firm Purchases and Sales" means transactions at wholesale that are not
Wholesale Contracts or Short-Term Purchases and Sales.
"Oregon Direct Access Customers" means Oregon retail electricity consumers that
procure electricity from a supplier other than PacifiCorp under an Oregon Direct Access
Program.
t'Oregon Direct Access Program" means Oregon laws, regulations and orders that
permit PacifiCorp's Oregon retail consumers to purchase electricity directly from a supplier
other than PacifiCorp.
"Portfolio Standard" means a law or regulation that requires PacifiCorp to acquire: (a)
a particular type of Resource, (b) a particular quantity of Resources, (c) Resources in a
prescribed manner or (d) Resources located in a particular geographic area.
Appendix A - 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 34 of 64
Case No. PAC-E-15-16
\Mtness: Jeffrey K. Larsen
'6Pre-2005 Resources" means Resources (other than Mid-Columbia Contracts and
Hydro-Electric Resources) that were part of the Company's integrated system prior to January l,
2005.
"Qualiffing Facility Contracts" means contracts to purchase the output of small power
production or cogeneration facilities developed under the Public Utility Regulatory Policies Act
of 1978 (PURPA) and related State laws and regulations.
"Resources" means Company-owned and leased generating plants and mines, Wholesale
Contracts, Short-Term Firm Purchases and Firm Sales and Non-firm Purchases and Sales.
'6System Enerry Factor" or "SE Factor" - refer to Appendix B.
"System Generation Factor" or t'SG Factor" - refer to Appendix B.
"Short-Term Firm Purchases and Firm Sales" means physical or financial contracts
pursuant to which PacifiCorp purchases, sells or exchanges firm power at wholesale and
Customer Ancillary Service Contracts that are less than one year in duration.
"Special Contract" means a contract entered between PacifiCorp and one of its retail
customers with prices, terms, and conditions based on the specific circumstances of that
customer. Special Contracts may account for Customer Ancillary Services Contract attributes.
"State" means any state that is utilizing the 2017 Protocol for inter-jurisdictional
allocation purposes, and is intended to include the states of California, Idaho, Oregon, Utah, or
Wyoming.
"State Resourcest' means Resources whose costs are assigned to a single jurisdiction to
accommodate j urisdiction-specifi c policy preferences.
ttSystem Resources" means Resources that are not State Resources and whose
associated costs and revenues are allocated among all States on a dynamic basis.
"Variable Costs" means costs incurred by the Company that vary with the amount of
energy delivered by the Company to its customers during any hour.
Appendix A - 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 35 of 64
*,i3li,]i#$?l;li;ll
"Wholesale Contractst' means physical or financial contracts pursuant to which
PacifiCorp purchases, sells or exchanges firm long-term power and/or energy at wholesale or
Customer Ancillary Service Contracts as discussed in Appendix D.
Appendix A- 2017 Protocol
Rocky Mountain Power
Exhibit No. 1 Page 36 of 64
Case No. PAC-E-'|5-16
\Mtness: Jeffrey K. Larsen
2017 Protocol - Appendix B
Allocation Factor Applied to each
Component of Revenue Requirement
2017 Protocol - Appendix B
Allocation Factor Applied to each Gomponent of Revenue Requirement
Rocky Mountain Power
Exhibit No. 1 Page 37 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
ALLOCATION
FACTOR
FERC
ACCT
Salrs to trltimate Customers
DESCRIPTION
440 Rsidential Sal6
DiEt a$igned . Jurisdiction
Commercial & lndustrial Sal6
Direct assigned - Jurisdiction
Public Sfet & Highway Lighting
Dircct a$igned - Jurisdiclion
Other Sales b Public Authority
Direct a$igned - Jurisdic'lion
lnterdepartmental
Oirect a$igned - Jurisdiction
Sal6 for R6ale
Dirst asigned - Jurisdictjon
Non-Fim
Fim
Pbvision fff Rate Refund
Direct assigned . Jurisdic-tion
Othsr Electrlc Operating Revenues
4* Forfeited Disc@nts & lnteBt
Di€ct asigned - Jurisdiction
Misc Eleclric Revenue
Water Sales
Direct assigned - Jurisdiclion
Other - Commm
Common
454 Rent of Eleckic Property
Dirst assigned - Jurisdiction
Common
Other - Commm
Otrler Eleciric Revenue
Direct assigned - Jurisdiction
Wheeling Non-fm, Other
Common
Vvheling - Fim, Other
Customer Related
lriscellanaous Revenues
41'160 Gain on Sale of Utiliv Plani - CR
Direct a$igned. Jurisdictjon
Prcduclion, Trensmisim
General Office
S
SE
SG
S
SG
SO
SG
SO
SG
SE
SO
SG
CN
S
SG
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 38 of 64
Case No. PAC-E-15-16
Witness: Jeffrev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
4118
41181
421
DESCRIPTION
L6 on Sale of Utillty Plant
Direqt a$igned - Jurisdiclion
Prcduclion, Transmission
Genoral Office
Gain frm Emlssim Allwen6
SO2 Emi$io All@an@sal6
Gain frm Disp6itjon of NOX Credits
NOX Emission Allwane sles
(Gain)/ Lcs on Sale of UIlliy Plant
OirEt Bsigned - Judsdiciiff
Produclim, TEnsi$im
Gereral Otfi@
Customs Related
FERC
ACCT
41170
ALLOCATION
FACTOR
S
SG
so
SE
SE
s
SG
SO
CN
CN
S
SG
SE
SG
SG
SG
SG
SE
S
SG
SE
Miscellaneoua Expenss
4311 lnterest on Cusiorer Deposits
Customs Swice Deposlts
Olrccl 8$igned - Jurisdiclim
Steam Power GamEtlm
500,5O2,504-514 OpffitionSupeMsion&Enginsing
Remalning St€m Plants
Fuel Related
Rmaining st€m planb
Stem FEm Olher SoutG
Nuclca. Power Ggnaratlon
SEem Royalt 6
Nuclear Plants
Pacific Hydrc
East HydD
517 - 532 Nuclear PMer O&M
Othsr Powrr Grno6tlon
546, 54&554 OpeElion Super & Engin*ring
Olher Productiff Plant
il7
Olher Fuel Expens
Direct asigned - Junsdicti$
Fim
Noftfim
Hydraullc Pomr Gcn.tltlo
535-545 HydrcO&M
Oth€r Pow.r Supply
555 Purchased P0s
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 39 of 64
Case No. PAC-E-15-16
Vvitness: Jefirev K. LarsenAllocation Factor Applied to each Gomponent of Revenue Requirement
FERC
AEEI
CUSTOilER ACCOU[fit EXPEI{SE
901 . 905
CUSTOMER SERVICE EXPENSE
DESCRIPTION
System Cmtd & L@d Dispatdr
Other Expqs6
Oths Expsss
DiEt a$igned - Jurisdiclion
Ofls Expqs6
Cholla Tcnsaclion
DiEt a$igned - Jurisdic,tim
Other Distributim
ALLOCATION
FACTOR
SG
S
SG
SGCT
557
TRANSI/lISSION EXPENSE
560,564,566-573 TransmisionO&M
T€nsmission Plant
565 Transmission of Electricity by Othe6
Fim Wh@lirE
Non-Fim Wheling
DISTRIBUTION EXPENSE
580. 598 Disbibutis O&M
Customer A@nts O&M
Dirt a$igned - Jurisdictm
Total Sysitm Custffi Rolated
SG
SE
s
SNPD
S
CN
S
CN
S
CN
S
CN
SO
SG
SG
SG
907. 910
SALES EXPENSE
911.916
Customs Swice O&M
Sal6 Expense O&M
Dir*t asigned - Jurisdic,tion
Total System Custffi Related
Di@t a$igned - Jurisdiction
Total System Custoffi R€lated
ADIIIINISTRATIVE & GEN EXPENSE
920.935 Administmtiw& General Expense
Direcl assigned - Jurjsdictlon
Cusiomer Related
General
FERC Regulatory Expense
DEPRECIATION EXPENSE
403SP Sbam OepHiation
Stem Plants
4O3NP Nuclar DepEiali@
Nucl@r Plaot
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 40 of 64
Case No. PAC-E-15-16
Witness: Jefkev K. LarsenAllocation Factor Applied to each Gomponent of Revenue Requirement -
FERC
ACCT
4030P
4O3GP
AMORTIZATION EXPENSE
DESCRIPTION
Hydo DepEiaiio
Pacific Hydm
Easl HydE
Othtr Produciion Depriado
Oths Producliff Plant
Transmi$ion Oepreiatim
TBnsmission Plant
Disbibutim DepHialion Dir@t assigned - Jurisdiclion
Land & Land Rights
Strlcttres
Ststion Equipment
Storage Batsery Equipment
Poles & TweE
OH Conducto6
UG Coduit
UG Cmductor
Line TEns
Servi@s
MeteB
lnst Cust Pm
L€sd Propery
Street Lighting
GseEl DepGiatim
Disbibutim
Mining Oepreclation
RilainirE Steam Plants
Mining
Pacmc Hydrc
East Hydro
TEnsmisiff
Custmtr Relat€d
GenmlSO
Remaining Mining Plant
Amort of LT Plant - Capital L€s Gen
Diret assigned - Jurisdiction
General
Cuslomer Relatsd
Amort of LT Plant - Cap La* Stem
Steam Productm Plant
Amrt o( LT Plant- lntangible Plant
Distributio
Prcductim, Transi$im
Gaffil
Mining Plant
Customs Related
ALLOCATION
FACTOR
SG
SG
SG
SG
s
s
s
S
S
S
S
S
S
s
S
s
s
SG
SE
SG
SG
SG
CN
SO
S
SO
CN
SG
s
SG
SO
SE
CN
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 41 of 64
Case No. PAC-E-15-16
Allocation Factor Apptied to each component of Revenue n"quirertll?"ss:Jeffrev K' Larsen
407
FERC
ACCT
Taxes Other Then lncom
DEFERRED ITC
41140
41141
lnterost Expense
427
428
429
431
432
DESCRIPTION
Amorl of LT Plant - Mining Plant
Mining Ptant
Amortiation of Other Electric Plant
Pacmc Hydrc
East Hydrc
Amorliation of Oher Electric Plent
Dicct asigned - Jurisdiclion
Amoilation of Plant Acquisitjon Adj
Direct a$igned - Jurisdiction
Produc'tion Ptant
Amort of Pop Lo$es. Unrec Plant. eic
Di@t a$igned - Jurisdiction
Productim, Transi$iff
Trcjan
Til6 Other Than ln@me
Direcl assigned - Jurisdic-tion
Prcperty
System Tax6
Misc Ene€y
Misc Prcductio
Defered lnElrrent Til Credit - Fed
ITC
DefenEd lnB!rent Tax Credit - ldeho
tTc
lnteEt m Long-Tem Debt
Direct asigned - Jurisdictis
lnteEt Expense
Amortlatiq of Debt Dis & Exp
lnlerGt Expense
Amortiatim of Premium on Oebt
tnteBt Expens
O$er lnterst Expense
lnters* Expen$
AFUDC . BorNed
AFUDC
ALLOCATION
FACTOR
SE
SG
SG
SG
TROJP
s
GPS
SO
SE
SG
DGU
DGU
SNP
SNP
SNP
SNP
SNP
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 42 of 64
Case No. PAC-E-15-16
Witness: Jefrev K. LarsenAllocation Factor Applied to each Gomponent of Revenue Requlrement '
lnts€st & Dividonds
4r010 DeferEd ln@m Ta - Fcdml-DR
DtuEl asigned - Jurisdlctff
Elsctic Plant in SwiB
Pacjfic Hydrc
Produdiff, TElMissio
C6bmer R6lat6d
Gsml
Prcperty Tu Blaiod
Miscellan@s
Trcjan
Oistibuton
Mlnirlg Plant'
Bad Debt
Tu DepEjetiff
41011 DefffedlnmTd-StaFDR
DiEt sslgnrd - JurisdEtim
Electic PLnt in Ss/ice
Pao'fic Hydm
Produdim. TEcmisskr
C6bms Rddcd
Gffil
Propsttr Til rdetrd
MbcllarEous
TRian
Distibutio
Mining Pbnt
Bad D€bt
Ta OepHiatir
o.t€red lnm Td - FederaFCR
FERC
ACSI
lntarlrt & Dlvldrnds
419 lntq6t & DMdends
DEFERRED INCOTE TAXES
DESCRIPTION
DiBct Nigned - Judsdlc{ff
El*tic Plent in Sflic€
Padfic Hydrc
Prcduction, TEnsmislon
Customd R€latad
Gqeml
Prcpefly Til clsted
Mascdlarcus
Tmjan
Disfibulim
Mining Plant
Cffiributions in eid ol ffstucfon
Productim, Otiq
Book D€pHlatiff
ALLOCATION
FACTOR
SNP
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJO
SNPD
SE
BADDEBT
TAXDEPR
s
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNPD
SE
BADDEBT
TAXDEPR
s
OITEXP
CN
so
GPS
SNP
TROJD
SNPO
SE
ctAc
SGCT
SCHMDEXP
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 43 of 64
Case No. PAC-E-15-16
Wtness: Jeffrev K. LarsenAltocation Factor Applied to each Gomponent of Revenue Requirement
FERC
ACCT
41111
DESCRIPTION
DtullmTd-StateCR
DirEt a$igned - Jurisdiction
Eledric Plant in Swie
Pacific Hydrc
Producli@, TBnsisiff
Gustoms Rshted
GeneEl
Prcperty Ta related
Miscdlanfls
Tojan
Disbibution
Mining Plant
Cstributims in aid of onsfuc{on
Prcduction, Other
Book Depreiation
9CHEDULE - M ADDITIONS
SCHMAF Additions - Flw Th@gh
Direct a$igned - Jurisdiclion
SCHMIP Additffs - Pffinst
Oir6t asigned - Jurisdictm
Mining rdated
GileEl
Produclion / TEnsmi$itr
DepEiati0
Additids - Tmporary
Okst asigned - Jurisdictiff
Cmbibuliqs in aid of trstruclim
Miscdlanfls
TDjan
Pacific Hydrc
Mining Plant
Prcduclis, T€rsmisis
Properly Tax
Gensal
DepBiation
Distibutiq
Produc{ion, Olher
SCHMAT
SCHEDULE. M DEDUCNONS
SCHMDF Oeduclions - Fl@ Thrugh
Oiret asigned - Jurisdiclis
Prcduciion, TEnsmisim
Pacific HydD
Deducliqs - PmanentSCHMDP
DirEl asigned - Jurisdiciis
Mining Rdaied
Misllatl@s
Gaeral
ALLOCATION
FACTOR
S
DITEXP
SG
SG
CN
SO
GPS
SNP
TROJD
SNPO
SE
crAc
SGCT
SCHMDEXP
s
S
SE
SO
SG
SCHMDEXP
S
crAc
SNP
TROJD
SG
SE
SG
GPS
so
SCHMDEXP
SNPD
SGCT
S
SG
SG
s
SE
SNP
SO
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page ,14 of 64
Case No. PAC-E-1S16
\Mtness: Jeffrev K. LarsenAllocation Factor Applied to each Gomponent of Revenue Requirement
FERC
aeel
SCHMDT
Slato lncoma Taros
40911
4091'l
40910
40910
SLlm Producilon Plilt
310 - 316
Nucldr Productlon Phnt
32S,325
HydEullc Plrnt
33G336
Othor Producllon Plant
340.346
TRANSMISSION PLANT
350-359
DISTRIBUTION PLAIIT
36G,373
ALLOCATION
FACTOR
S
BADOEBT
SNP
SG
SE
SG
GPS
so
TAXDEPR
SNPD
CN
CALCULATED
SG
s
SG
SE
SO
DESCRIPTION
Deduclitrs - Tffiporary
Dirsl a$igned - Ju.isdictitr
Bad Debt
Mis@llantr
Pacific Hydrc
Mining rdated
Prcduction, TEnsmisim
Prcperty Tq
General
DepEiation
Distrlbution
Custmer Related
State ln@me Taxes
ln@me Before Tus
Renilable Eneey Til Credit
FtT Trueup
Rsilable Energy Tax CrEdit
PMI
Freign Tq CEdit
Steam Plants
Nucjsr Plant
Pacific Hydrc
East Hydrc
Other Production Plant
Other Prcduction Plant
Transmi$io Plant
Dir6l asilned - Jutisdiction
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 'l Page 45 of 64
Case No. PAC-E-15-16
\Mtness: Jeftev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
GENERAI- PLANT
389 - 398
DESCRIPTION
Disbibutio
Pacific Hydrc
East Hydro
Prcductio / TEnsmisio
Customs Related
Gtrsl
Mining
Remaining Mining Plant
ALLOCATION
FACTOR
s
SG
SG
SG
CN
so
SE
SE
SE
so
SG
s
s
SG
s
SG
SG
SG
CN
so
SE
s
S
SG
SE
S
SG
S
SG
3991
101 1390
Cml Mine
WIDCO CapitalL€se
WDCO Capital Lease
GensEl Capital Leas6
Direct asigned - Jurisdictim
Genffil
Gensalion / TEnsision
OEanizatim
Dir€l asigned - Jurisdicliff
F6nchi* & Cmst
Direcl a$igned - Jurisdictiff
Productio, TEnsisio
Miscdlan@us lntangible Plant
Dishibutid
Pacific HydD
E6t Hydro
Prcductio / Tasmi$im
Customer Relaled
Genffil
Mining
Ls Ns-Lnility Plant
Direc1 a$igned - Jurisdiction
INTANGIBLE PLANT
30r
302
303
303
Rat3 Brso Addttlons
105 Plant Held For FutuG Use
Dirst asigned - Jurisdiction
Prcduclion, TEnsmislon
Mining Plant
Eleciic Plant Acquisition Adjustmfl b
Oirect a$ign€d - Jurisdiclio
Production Plant
Aeum P@idm ftr Aset Acquisilim Adiuslmen6
Direct a$igned - Jurisdiclim
Produc'tid Plani
1',t4
2017 Protocol - Appendix B
Rocky Mountain Power
Exhibit No. 1 Page 46 of 64
Case No. PAC-E-15-16
Wtness: Jeffrev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
SE
so
SO
S
SE
SE
SE
SE
SE
s
SG
SG
SO
SNPD
SG
SO
SG
S
GPS
SG
SE
SO
25318
Nuclear Fuel
DiHt asigned - Junsdicton
Gfferal
General
Direct asigned - Jurisdicton
Dlcct aslgncd - Jurisdic{ion
Fucl Sbck
Steam Produclim Plant
Fu€l Sbck - Undistibuted
St*m Pmduc0on Plant
DGST Working Capllal Dcposlt
Mining Plent
DG&T Working Capital Deposit
Mining Plant
Prcrc Wo*irE Capital Dep6it
Mining Plant
Mat$ials and Suppli6
Direct asigned - Jurisdictim
Producllon, TEnsmlslon
Mining
Prcduclion - Common
Geneml
DistribuUff
Prcducti0, Oihs
Sbc Expen* Undislributcd
Genffil
Prcvo Worldr€ Capital Oaposit
Prcvo Working Cspltal Oep6il
Prepayments
Dicct a$ign6d - Jurlsdiclion
PDperty Tax
Produciim, Tranillsim
Mining
Gmral
Nuclear Fuel
WEtherizatim
Pssios
Weatheriatim
Wstheriation
128
182W
'r86W
'151
'152
25316
25317
25319
114
2017 Protocol - Appendix B 10
Rocky Mountain Power
Exhibit No. 1 Page 47 of 64
Case No. PAC-E-15-16
Allocation Factor Applied to each Gomponent of Revenue n"qrir"rYlll"ss:Jeffrev K' Larsen
FERC
ACCT
Worklng Crpltal
cwc
owc
131
135
14'l
't43
232
253
25330
230
254105
ALLOCATION
FACTOR
S
SG
SE
SO
SGCT
S
SG
SO
SE
SG
Cash Working Capiial
Mlscoll8noous Rato Bas
18221 Unrcc Plant & Reg Study Cosb
Diret a$igned - Jurisdictim
DESCRIPTION
Misc Regulatory As*ts
DiEl asigned - Jurisdiclim
Produclis. Transmision
Mining
Gmffil
Produclio, Other
Misc Defered Oebits
DiEt asigned - Jurisdiction
Producliq. Tranmission
GaeEl
Mining
Produclion - Cmmon
Di@t a$igned - Jurisdiction
Other Working CapitEl
Cash
Working Funds
Nots RtreiEble
Other A@unts Redveble
A€ounb Payable
A@ounb Payable
A@unB Payable
Defered Hedge
Oher Defered Credits - Mi$
Oher Oefered Credits - Mlsc
ARO Reg Liability
Nucl@r Plant - TDjan
Not6 Rseivable
TDjan Plant
Trcjan Plant
Employre L@ns - Hunter Plant
Prcv lu P.op€rg lnsuEn@
Pov icr lnjuriE & Damag6
SNP
SG
SO
SO
SO
SE
SG
SE
SE
SE
SE
TROJP
TROJD
SG
Rrtc Brs Doductlons
235 Customer Servi€ Depcits
DiECI asbned - Jurisdicliq
2281
2282
S
SO
SO
2017 Protocol - Appendix B 11
Rocky Mountain Power
Exhibit No. 1 Page 48 of 64
Case No. PAC-E-15-16
Wtness: Jeffrev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
ALLOCATION
FACTOR
SO
SE
SG
TROJD
TROJP
TROJD
TROJP
TROJD
SG
CN
SE
s
SG
so
SE
s
SE
SO
s
BADDEBT
SG
CN
SO
SNP
TROJD
SNPD
SE
SG
S
DITBAL
SG
SG
CN
so
SNP
TROJP
TAXDEPR
SCHMDEXP
GPS
crAc
SE
22U2
282
DESCRIPTION
Pov Sor Pereions ard Bflefits
A6um Misc Ops PtrBlack Lung
Mining
Othq Prcductiil
A@m Misc Ops PrcrTrcian
TDjan Plant
FAS 143 ARO Regulatory Liability
Tmjan Plant
Trcjan Plant
Asset R€tirement Obligation
TEjan Plant
Tpjan Plant
Customer Advancs ,q Cmsbuction
Direct asiqned. Jurisdiclion
Production, Transmisid
Cusbmer Related
S02 Emistore
OOls Oefered Credib
DiEt asigned - Jurisdiclion
Productim, TEnsisiq
Genqal
MinirE
Regulatory Liabiliti6
Regulatory Liabiliti6
Regulatory Liabilitis
lnsuEn@ Prcvision
Aeumulated Defered ln@me Ta6
Oirecl a$igned - Jurisdiction
Bad Debt
Pacilic Hydrc
Production, Transmi$ion
Customer Related
General
Miscellansus
Trcjan
Disbibution
Mining Plant
A@umulated Defred lnme Ta6
Production, TEnslsim
A@mulated Deffled lnme TdB
Direcl asigned - Ju.isdiclion
DepHiatifi
Hydro Pacific
Producliff, TBnsisim
Customer Related
Gsml
Misellan@us
Trcjan
DepEiaiion
Depr@iation
S)6tem GrGs Plant
Contribution in Aid of CoEtruc{on
Mining
252
2017 Protocol - Appendix B 12
Rocky Mountain Power
Exhibit No. 1 Page 49 of 64
Case No. PAC-E-15-16
Wtness: Jeffrev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
ALLOCATION
FACTOR
S
DITBAL
SG
SG
CN
SO
SNP
TROJD
SGCT
GPS
SE
tTc84
rTc85
rTc86
rTc88
rrc89
rrc90
SG
SG
SG
SG
SG
SG
S
S
S
S
DESCRIPTION
A@umulated Defened lnme Tas
DirEl signed - Judsdicto
. DepEia[m
l-tydro Pacific
Production, TEnmisio
Customer Related
G6eEl
Misellanms
Trcjan
Prcduction, Other
Poperty Tax
Mining Plant
Accumulat€d lnvstrnent Tax Ccdit
Dircct a$igned - Jurisdlction
lnvstrnent Tax Credits
lnvstrnent Ta Credits
lnvGknent Ta Credib
lnvEtnent Tax Credits
lnvGtrnent Tax Credits
lnvGlment Til Ccdits
Inv6knst Tu Credlb
PRODUCNON PLANT ACCUT OEPRECIATION
108SP Steam Prod Plart A@mulated Depr
Steam Plants
1080P
Nuclar Prod Plant A@mulated Depr
Nuclear Plant
HydEulic Prod Plant A@um Dept
Pacific Hydrc
East Hydrc
Other Prcduc1io Plant - Accum Depr
Ouler Production PIant
TRANS PLANT ACCUM DEPR
'108TP Transmission Plant Acemulated Depr
Tmnsmission Plant
DISTRIBUTION PLANT ACGUM DEPR
Distribution Plant A@umulated Depr
OirEt asigned - Jurisdiction
Uncla$ified Dist Plant - A@t 300
Dirsl a$igned - Jurisdiclion
Uncla$ified Dist Sub Plant - A@t 300
Dir6l asilned - Jurisdictio
LJnclasified Dist Sub Plant - Ac1 300
DiEt asbned - Jurisdictim
108360 - 108373
108D00
108DS
108DP
2017 Protocol - Appendix B 13
Rocky Mountain Power
Exhibit No. 1 Page 50 of 64
Case No. PAC-E-15-16
Witness: Jeffrev K. LarsenAllocation Factor Applied to each Component of Revenue Requirement
FERC
ACCT
GENEML PLANTACCUil DEPR
IOSMP
t08 t399
ACCUM PROVISION FOR AMORTIZATION
OESCRIPTION
Gsml Plant A@umulated Oepr
Oisfibutim
Pacific Hydrc
East Hydrc
Produclion / TEnsmisio
Customs Rehed
GeneEl SO
Mining Plant
Mining Plant A@mulated Depr-
Mlnlng Plant
Ls Cstalia Sftus Depmlatjm
Di@t asigned - Judsdictq
AEUm Oepr - Capital Lase
Goneral
A@um Depr - Capital Ls8s€
Direct asslgned - Jurisdictid
ALLOCATION
FACTOR
S
SG
SG
SG
CN
SO
SE
SE
s
so
S
SG
S
SG
SG
SG
CN
SO
SG
SG
S
SG
SG
so
SE
CN
S
SE
,I11SP
111GP
,I,I1HP
1 1'l tP
111tP
1 1 1399
A6um Prov for Amort"Steam
Stem Plants
A@um Prov for Amorl-GmsEl
Disbibution
Padfic Hydrc
East Hydro
Prcduclion / TEnsmissim
Cusboer Rdated
Geneml SO
A@um Po fur Amort-Hydrc
Pacific Hydo
East Hydro
A6um Prov ior Amorl-lntangible Plant
Disdbrrtim
Pacmc Hydrc
Productim, TralMi$im
Gsml
Mining
Customs Related
L6s Non-Utility Plant
Direct signed - Jurisdicto
A@um Prov tor Amort-Mining
Mining Plant
2017 Protocol - Appendix B 14
2017 Protocol - Appendix C
Allocation Factors
Algebraic Derivations
Rocky Mountain Power
Exhibit No. 1 Page 51 of &l
Case No. PAGE-I5-16
lAlrtness: Jeffrey K. Larsen
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 52 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Allocation Factors
PacifiCorp serves eight jurisdictions. Jurisdictions are represented by the index i = Califomia, Idaho, Oregon, Utah, Washington, Eastern
Wyoming, Western Wyoming, & FERC.
The following assumptions are made in the factor derivations:
It is assumed that the 12CP 0:l to l2) method is used in defining the System Capacity ("SC")
It is assumed that twelve months 0:l to l2) method is used in defining the System Energy C'SE).
In defining the System Generation ("SG") factor, the weighting of75 percent Systern Capacity, 25 percent System Energy is assumed to continue.
While it is agreed that the peak loads & input energy should be temperature adjusted, no decision has been made upon the methodology to do these
adjustrnents.
Svstem Capacitv Factor ((SC")
t2
\r.traSCr=--f1--
\lrar,t,=l /=l
where:
SCi = System Capacity Factor forjurisdiction i.
TAP1 = Temperature Adjusted Peak Load ofjurisdiction i in month j at the time of the System Peak.
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 53 of 6,1
Case No. PAC-E-15-16
\Mtness: Jeffrey K. Larsen
System Energy Factor ("SE")
t2
lrtz,1
.lzr = l--ii-
ZZIAEtii=1 j=l
where:
SEi
TAEii =
Svstem Generation Factor ("SG")
SGi =.75 * .lC+.25'* SE
where:
SGi
SCr
SEi
System Energy Factor forjurisdiction i.
Temperature Adjusted Input Energy ofjurisdiction i in month j.
System Generation Factor forjurisdiction i.
System Capacity for jurisdiction i.
System Energy forjurisdiction i.
Division Generation - Pacific Factor (*DGP')
p6p,= .!.4-
I'o;
where:
DGP:: Division Generation - Pacific Factor forjurisdiction i.
SG, = 56, ili is a Pacific jurisdiction, otherwise
.sG,: = 0.
SG; : Systern Generation for jurisdiction i.
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 54 of 64
Case No. PAC-E-I5-16
Witness: Jeffrey K. Larsen
Division Generation - Utah Factor ("DGU")
DG(ti=JE-
Iro;
where:
DGUi: Division Generation - Utah Factor forjurisdiction i.
SGi = 56,;11 is a Utah jurisdiction, otherwise
SC,: = 0.
SG; = Systern Generation forjurisdiction i.
Svstem Net Plant - Distribution Factor ("SNPD")
PDi- ADPDTsNPDr = eD- ADID)
where:
SNPDi
PDi
ADPDi
PD
ADPD
System Net Plant - Distribution Factor forjurisdiction i.
Distribution Plant - forjurisdiction i.
Accumulated Depreciation Distribution Plant - for jurisdiction i.
Distribution Plant.
Accumulated Depreciation Distribution Plant.
2017 P-otocol - Appendix C
Rocky Mountain Power
Exhibit No. 'l Page 55 of 64
Case No. PAC-E-15-'16
\Mtness: Jeffrey K. Larsen
Svstem Gross Plant - Svstem Factor ("GPS")
GP,S, =
PPi+ PTi+ PDi+ PGi+ PIi
lef'+ PTi+ PDi+ PGi+ PIi)
GP-S, = Gross Plant - System Factor for jurisdiction i.PPi = Production Plant forjurisdiction i.PTi : Transmission Plant for jurisdiction i.PDi = Distribution Plant for jurisdiction i.PGi = General Plant for jurisdiction i.PIi = Intangible Plant forjurisdiction i.
Svstem Net Plant Factor ("SNP")
crrD _ PPi+ PTi+ PDi+ PG+ PIi- ADPI- ADPTi- ADPDT- ADPGi- ADPLottr r -
l(PPt+ PTt+ PDi+ PGi+ PIi- ADPPi- ADPTT- ADPDT- ADPG- ADPI)
SNPi = System Net Plant Factor forjurisdiction i.PPi = Production Plant forjurisdiction i.PTi = Transmission Plant for jurisdiction i.PDi : Distribution Plant for jurisdiction i.PGi : General Plant for jurisdiction i.PIi : Intangrble Plant forjurisdiction i.ADPPi: AccumulatedDepreciationProductionPlantforjurisdictioni.ADPTi= Accumulated Depreciation Transmission Plantforjurisdiction i.ADPDi= AccumulatedDepreciationDistributionPlantforjurisdictioni.ADPGi= Accumulated Depreciation General Plant forjurisdiction i.
ADPIi = Accumulated Depreciation Intangible Plant forjurisdiction i.
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 56 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
Svstem Overhead - Gross Factor ("SO")
SOGi=PPi+ PTi+ PDi+ PGi+ PIi- PPoi- PT,i- PDoi- PGoi- PIoi
i=t
l{ee'* PTt+ PDi+ PGi+ PPi- PPoi- PIoi- PDoi- PG,i- PIoi)
SOG: : System Overhead - Gross Factor forjurisdiction i.PPi : Gross Production Plant for jurisdiction i.PTi : Gross Transmission Plant for jurisdiction i.PDr : Gross Distribution Plant for jurisdiction i.PGi : Gross General Plant for jurisdiction i.PIi : Gross Intangible Plant forjurisdiction i.
PPoi : Gross Production Plant forjurisdiction i allocated on a SO factor.
PToi : Gross Transmission Plant for jurisdiction i allocated on a SO factor
PDa : Gross Distribution Plant for jurisdiction i allocated on a SO factor
PGoi = Gross General Plant for jurisdiction i allocated on a SO factorPIoi = Gross Intangible Plant forjurisdiction i allocated on a SO factor
Income Before Taxes Factor ("IBT")
rDr _ TIBTT
lDIt--
lrnr,
IBTi = Income before Taxes Factor forjurisdiction i.
TIBTi = Total Income before Taxes for jurisdiction i.
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 57 of 6,f
Case No. PAGE-1+16
lMrtness: Jefrey K. Larsen
Bad Debt Exoense Factor ((BADDEBT")
s12,2,sp7,=;f9!n4'
l.nccrou,
BADDEBT: = Bad Debt Expense Factor forjurisdiction i.
ACCT904| = Balance in Account 904 forjurisdiction i.
Customer Number Factor ("CN")
-^r. _ cusTtulvt--
lcusr,
where:CNi : Customer Number Factor forjurisdiction i.
CUSTi = Total Electric Customers forjrnisdiction i.
Contributions in Aid of Construction ("CIAC")
gvg,=SacM'--
lcr.tcue,
where:
cuct
cucNAt
,Or7 P.,o*1- appendix C
Contributions in Aid of Construction Factor forjurisdiction i.
Contributions in Aid of Construction - Net additions for jurisdiction i.
Rocky Mountain Power
Exhibit No. 1 Page 58 of 64
Case No. PAC-E-15-16
\Mtness: Jefftey K. Larsen
Schedule M - Deductions (*SCHMD")
crutt^. - DEPRCiott rlvtut - ;=g
lonenc,
i=1
where:SCHMDi = Schedule M - Deductions (SCHMD) Factor forjurisdiction i.
DEPRC: = Depreciation in Accounts 403.1 - 403.9 for jurisdiction i.
Troian Plant ("TROJP")
TRoJPi - -!ccrl8222t
ltccnvzz,
where:TROJPi = Trojan Plant (TROJP) Factor for jurisdiction i.
ACCT|8222 i : Allocated Adjusted Balance in Account 182.22 for Frisdiction i.
Troian Decommissionine ("TROJD')
TRoJDt = .!CCT22842t
\tccrzzt+2,
where:TROJDi : Trojan Decommissioning (TROJD) Factor for jurisdiction i.
ACCT22842 i : Allocated Adjusted Balance in Account 228.42 for jtisdiction i.
2017 Protocol - Appendix C
Rocky Mountain Power
Exhibit No. 1 Page 59 of 64
Case No. PAC-E-15-16
Wtness: Jeffrey K. Larsen
Tax Depreciation (TAXDEPR) Factor forjurisdiction i.
Tax Depreciation allocated tojurisdiction i.
(Tax Depreciation is allocated based on functional pre merger and post merger splits of plant using Divisional and
Systemallocationsfromabove. Eachjurisdiction'stotalallocatedportionofTaxdepreciationisdeterminedbyits
total allocated ratio of these functional pre and post merger splits to the total Company Tax Depreciation.)
Tax Depreciation ("TAXDEPR")
TAXDEPR.= ,=!:*o"*'
lrexonrru,
where:
TAXDEPRi
TAXDEPMi
Deferred Tax Expense ("DITEXP")
DITEXPT= ,,?'"on'
lorrnxe.t,
where:
DITEXPi
DITEXPAi
2017 Protocol - Appendix C
: Deferred Tax Expense (DITEXP) Factor forjurisdiction i.: Deferred Tax Expense allocated tojurisdiction i.
(Defened Tax Expense 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 Balances. PowerTax allocates Defened Tax
Expense and Deferred Tax Balances to the states based upon a computer run which uses as inputs the preceding
factors. If the preceding factors change, the factors generated by PowerTax change.)
Rocky Mountain Power
Exhibit No. 'l Page 60 of 64
Case No. PAC-E-1t16
\Mtness: Jeffrey K. Larsen
Deferred Tax Balance ("DITBAL")
DrrBALt= ,?IrBAr't,
lorra,tu,
where:
DITBALi : Deferred Tax Balance (DITBAL) 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 Balances. PowerTax allocates Deferred Tax
Expense and Deferred Tax Balances to the states based upon a computer run which uses as inputs the preceding
factors. If the preceding factors change, the factors generated by PowerTax change.)
2017 Protocol - Appendix C l0
Rocky Mountain Power
Exhibit No. 1 Page 61 of 64
Case No. PAC-E-I5-16
Witness: Jeffrey K. Larsen
2017 Protocot - Appendix t)
Special Contracts
Rocky Mountain Power
Exhibit No. 1 Page 62 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
2017 Protocol - Appendix D
Special Contracts
Special Contracts without Ancillary Service Contract Attributes
For allocation purposes Special Contracts without identifiable Ancillary Service Contract attributes are
viewed as one transaction.
Loads of Special Contract customers will be included in all Load-Based Dynamic Allocation Factors.
When intemrptions 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 I
Special Contracts with Ancillary Service Contract Attributes
For allocation purposes Special Contracts with Ancillary Service Contract attributes are viewed as two
transactions. PacifiCorp sells the customer electricity at the retail service rate and then buys the electricity
back during the intem.rption period at the Ancillary Service Contract rate.
Loads of Special Contract customers will be included in all Load-Based Dynamic Allocation Factors.
When intemrptions 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 intemrption did not
occur.
Revenues received from Special Conffact customer, before any discounts for Customer Ancillary Service
attributes of the Special Contract will be assigned to the State where the Special Contract customer is
located.
Discounts from tariffprices provided for in Special Contracts that recognize the Customer Ancillary
Service Contract 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{hrough 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.
2017 Protocol - Appendix D
Rocky Mountain Power
Exhibit No. 'l Page 63 of 64
Case No. PAC-E-15-16
Witness: Jeffrey K. Larsen
2017 Protocol - Appendix D - Table 1
I nterrupti ble Contract Without Anci I lary Service Gontract Attri butes
Effect on Revenue Requirement
Factor Total svstem Jurisdiction 1l Eegc
2 Jurisdictional Loads - No lntenuptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW)
4 Jurisdictional Annual Energy (MWh)
5
6 Jurisdictional Loads - With lnteruptible Seruice - Reflecting Actual lnterruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW)
8 Jurisdictional Annual Energy (MWh)I
10 Special Contracl Customer Revenue and Load - Non lnterruptible Seruice
11 Special Contract Customer Revenue
12 Special Contract Customer Sum of l2 CPs (MW) (lncluded in line 2)
13 Special Contract Annual Energy (MWh) (lncluded in line 3)
't4
1 5 Special Contract Customer Revenue and Load - Wilh lntenuptible Service (75 MW X 500 Hours of lntenuption)
72,000
42,000,000
71,700
41,962,500
$ 20,000,000
900
500.000
$ 16,000,000
$ 16,000,000
600
462,500
M,000.000
24,000
14,000,000
24,000
14,000,000
Jurisdiction 2
36,000
21,000,000
35,700
20,962,500
20,000,000
900
500,000
16,000,000
16.000,000
600
462,500
50.00o/o
50.00%
50.00%
49.9670
49.790/o
49.83o/o
250,000,000
500,000,000
750,000,000
20,000,000
730,000,000
248,777,480
496,912,134
745,689,614
16,000,000
729,689,614
Jurisdiction 3
12,000
7,000,000
12,000
7,000,000
16.670/o
16.67o/o
16.67yo
'16.680/o
16.740/o
16.72o/o
83,333,333
166,666,667
250,000,000
250,000,000
83,074,173
167,029,289
250,103,462
250,103,462
16 Special Contract Customer Revenue
'17 Discount for Ancillary Services
18 Net Cost to Special Contracl Customer
19 Special Contract Sum of 12 CP- Reffecting Aclual lnterruptions (MW) (lncluded in line 7)
20 Special Contract Annual Energy- Reflec{ing Actual lntenuptions (MWh) (lncluded in line 8)
21
$
$
22 System Cost Savings from lnterruption
23
24 Allocation Factors
25 No lnlerruptible Service
26 SE faclor (Calculated from line 4)
27 SC factor (Calculated from line 3)
28 SG factor (line 27'75o/o + line 26'25Yo)
29
30 With lnterruptible Service (Reffecting Actual Physical lnterruptions)
31 SE factor (Calculated fom line 8)
32 SC faaor (Calculated from line 7)
33 SG factor (line 32"75% + line 31-250/,)
34
35
36
37
38 Cost of Seruice
39 Energy Cost
40 Oemand Related Costs
41 Sum of Cost
42
43 Rgvenues
44 Special Contract Revenuo
45 Revenues from all other customers
46
47
48
49
50 Cost of Seruice
51 Energy Cosi
52 Oemand Related Costs
53 Sum of Cost
54
55 Revenues
56 Special Contract Revenue
57 Revenues from all other customers
sE2 100.000/oSC2 100.00o/osG2 100.00%
No lnterruptible Service
500,000,000 $ 166,666,667
1,000,000,000 $ 333,333,333
1.500.000.000 s 500.000.000
$ 20,000,000 $$ 1,480,000,000 $ 500,000,000 $
With lnterruptible Service
sE2 $ 498,000,000$ 166,148,347sG2 $ 998,000,000$ 334,0s8,577$ 1,496,000,000 $ 500,206,924
Situs $ 16,000,000
Situs $ 1.480,000,000 3 500.206.924
SE1
sc1
SG1
100.00%
100.00%
100.00%
33.33olo
33.33%
33.33v"
33.367o
33.470k
33.450/0
$
$
s
a
a
$
SEl $SGl $
$
Situs
Situs
$
$
$
$
a
$
$
$
Appendix D
Rocky Mountain Power
Exhibit No. 1 Page 64 of 64
Case No. PAC-E-15-16
\Mtness: Jeffrey K. Larsen
2017 Protocol - Appendix D - Table 2
lnterruptible Contract With Ancillary Service Contract Attributes
Effect on Revenue Requirement
Factor Total svstem Jurisdiction l
1 5 Special Contract Customer Revenue and Load - With lnteruptible Service (75 MW X 500 Hours of lntenuption)
1 Loads
2 Jurisdictional Loads - No lnteruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW)
4 Jurisdictional Annual Energy (MWh)
5
6 Jurisdiclional Loads - With lntenuptible Service - Reflecting Actual lnteruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW)
8 Jurisdictional Annual Energy (MWh)I
10 Special Contract Customer Revenue and Load - Non lnterruptible Service
11 Special Contract Customer Revenue
12 Special Contract Customer Sum of 12 CPs (MW) (lncluded in line 2)
13 Special Contract Annual Energy (MWh) (lncluded in line 3)
't4
16 Tariff Equivalent Revenue
'17 Ancillary Service Discount for 75 MW X 500 Hours of Economic Curtailment
18 Net Cost to Special Contract Customer
19 Special Contracl Sum of 12 CP- Refecting Actual Interruptions (MW) (lncluded in line 7)
20 Special Contract Annual Energy- Reflec{ing Actual lntenuptions (MWh) (lncluded in line 8)
2'l
22 System Cost Savings from lnterruption
23
24 Allocation Factors
25 No lnterruptible Seruice
26 SE factor (Calculated from line 4)
27 SC faclor (Calculated from line 3)
28 SG factor (line 27*75o/o + line 26"250/o\
?9
30 With lnterruptible Seruice (Reflecting Actual Physical lnterruptions)
31 SE faclor (Calculated from line 8)
32 SC factor (Calculated trom line 7)
33 SG factor (line 32'75ok + line 31'25o/o)
34
35
36
3738@!sc
39 Energy Cost
40 Demand Related Costs
41 Sum ofCost
42
43 Revenues
44 Special Contracl Revenue
45 Revenues from all other customers
sE1 $ 500,000,000$ 166,666.667scl S 1,000,000,000s 333,333,333$ 1,s00,000,000 $ 500,000,000
Situs $ 20,000,000
Situs $ 1,,40,000,000 $ 500,000,000
sEl I 498,000,000$ 166,000,000sG1 $ 998,000,000$ 332,666,667scl $ 2,000,000$ 666,667sE1 $ 2,000,000$ 666,667$ 1,s00,000,000 $ 500,000,000
Situs $ 20,000,000Situs $ 1,la0,000,000$ 500,000,000
71,700
41,962,500
$ 20,000,000
900
500,000
$ 20,000,000
$ 16.000.000
600
462,500
$4,000,000
?4,000
14.000.000
33.33%
33.33%
33.33"/o
33.36%
33.470/0
33.45Yo
72,000 24,00042,000,000 14,000,000
Jurisdiction 2
36,000
21,000,000
35,700
20,962,500
20,000,000
900
500,000
20,000,000
(4,000,000)
16,000,000
600
462,500
50.00%
50.00o/o
50.00%
49.96o/o
49.7gyo
49.83o/o
Jurisdiction 3
12,000
7,000,000
12,000
7,000.000
16.67o/o
16.67o/o
16.67Yo
16.68o/o
't6.740/o
'16.72o/o
83,333,333
1 66,666,667
250,000,000
250,000,000
83,000,000
1 66.333,333
333,333
333,333
250,000,000
250,000,000
$
$
$
SElscl
SG1
'100.00%
100.00%
100_000/"
sE2 100.00%sc2 100.00%sG2 100.00%
No lnterruptible Service
$
$
$
$
$
250,000,000 $
500,000,000 $
750,000,000 $
20,000,000
730.000.000 $
249.000.000 $
499,000,000 $
1,000,000 $
1.000,000 $
750,000,000 $
20,000,000
730.000.000 I
46
47
48
49
50 Cost of SEruice
51 Energy Cost
52 Demand Related Costs
53 Ancillary Seruice Contract - Economic Curtailment (Demand)il Ancillary Service Contract - Economic Curtailment (Energy)
55 Sum of Cost
56
57 Revenues
58 Special Contract Revenue
59 Revenues from all other customers
With lnterruptible Service & Ancillary Service Contract
$
$
$
oI
$
$
Appendix D