20210129Kinney Exhibit 8 Schedule 1-12.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-21-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 8
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) SCOTT J. KINNEY

FOR AVISTA CORPORATION

(ELECTRIC)

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www.caiso.com │ 250 Outcropping Way, Folsom, CA 95630 │ 916.351.4400
California Independent System Operator Corporation
December 11, 2019
The Honorable Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Re: California Independent System Operator Corporation
Filing of CAISO Rate Schedule No. 6037
Docket No. ER20-____-000
Dear Secretary Bose:
The California Independent System Operator Corporation (“CAISO”)
submits for filing and acceptance an agreement (“Implementation Agreement”)
dated April 25, 2019, between the CAISO and Avista Corporation (“Avista”).1
The Implementation Agreement sets forth the terms under which the CAISO will
extend its existing real-time energy market systems to provide imbalance energy
service to Avista, pursuant to the CAISO’s Energy Imbalance Market (“EIM”)
tariff.2 Under the Implementation Agreement, Avista will compensate the CAISO
for its share of the costs of system changes, software costs, and other
configuration activities. The CAISO requests that the Commission accept the
Implementation Agreement effective April 1, 2020, so that the extension of the
real-time energy market to include Avista may proceed towards implementation
no later than April 1, 2022.3
I.Background
The EIM provides other balancing authority areas the opportunity to
participate in the real-time market for imbalance energy that the CAISO operates
in its own balancing authority area. PacifiCorp’s balancing authority areas
(PacifiCorp East and PacifiCorp West) were the first two to join the EIM. The
EIM market rules went into effect on October 24, 2014, for the first trading day
1 The CAISO submits the Implementation Agreement pursuant to Section 205 of the
Federal Power Act, 16 U.S.C. § 824d.
2 The EIM tariff provisions are set forth primarily in Section 29 of the CAISO Tariff.
3 See Implementation Agreement, Section 1; see also CAISO Tariff, Section 29.2(b).
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November 1, 2014.4

The EIM has continued to develop and attract the interest of a diverse
array of participants throughout the Western Interconnection. NV Energy joined
on December 1, 2015, Puget Sound Energy Inc. and Arizona Public Service
Company began participation on October 1, 2016, Portland General Electric
Company followed on October 1, 2017, and the Idaho Power Company joined
concurrently with Powerex Corp. on April 4, 2018. The Balancing Authority of
Northern California (“BANC”) commenced phase 1 EIM participation in April
2019. Also, the Salt River Agricultural Improvement and Power District and the
City of Seattle, by and through its City Light Department (“Seattle City Light”)
intend to commence EIM participation in April 2020. NorthWestern Energy, the
City of Los Angeles Department of Water and Power, Public Service Company of
New Mexico, and the Turlock Irrigation District intend to commence EIM
participation in April 2021, concurrent with BANC phase 2. Other entities,
including the Bonneville Power Administration, Tucson Electric Power, and
Tacoma Power, will commence EIM participation along with Avista in the spring
of 2022.5

II. The Implementation Agreement

The Implementation Agreement details the contractual terms, including the
scope of work and the agreed-upon fee, under which the CAISO will take the
steps necessary to incorporate Avista into the EIM consistent with the identified
key milestones and associated payment provisions.6 The Implementation
Agreement is modeled after implementation agreements previously accepted by
the Commission and, therefore, adopts provisions substantially similar to those
which have been filed with and accepted by the Commission.7

Under the Implementation Agreement, the CAISO and Avista must
complete a variety of project tasks necessary for implementation by April 1, 2022.

4 See Cal. Indep. Sys. Operator Corp., 149 FERC ¶ 61,005 (2014).
5 EIM participation materials are at https://www.westerneim.com/Pages/About/default.aspx.
6 See Implementation Agreement, Sections 3-4 and Exhibit A.
7 See Cal. Indep. Sys. Operator Corp., 143 FERC ¶ 61,298 (2013); Cal. Indep. Sys.
Operator Corp., 147 FERC ¶ 61,200 (2014), Cal. Indep. Sys. Operator Corp., 151 FERC ¶ 61,158
(2015), Cal. Indep. Sys. Operator Corp., 152 FERC ¶ 61,090 (2015), Cal. Indep. Sys. Operator
Corp., 154 FERC ¶ 61,020 (2016); Cal. Indep. Sys. Operator Corp., 155 FERC ¶ 61,311 (2016);
Commission Letter Order, Docket No. ER17-868-000 (Mar. 14, 2017); Commission Letter Order,
Docket No. ER17-1300-000 (May 18, 2017); Commission Letter Order, Docket No. ER17-2120-
000 (Sept. 7, 2017); Cal. Indep. Sys. Operator Corp., 160 FERC ¶ 61,058 (2017); Commission
Letter Order, Docket No. ER17-2559-000 (Nov. 16, 2017); Commission Letter Order, Docket No.
ER19-1080-000 (Apr. 5, 2019); Commission Letter Order, Docket No. ER20-95-000 (Dec. 4,
2019).
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The parties chose this date to provide sufficient time for completion of all
expected activities based on the size, complexity, and compatibility of Avista,
including filing a certification of readiness with the Commission. The specific
tasks may be modified by mutual agreement of the parties.8

The Implementation Agreement specifies that Avista will pay a fixed
implementation fee of $300,000, subject to completion of six specific milestones
for recovery of the portion of the costs attributable to the CAISO’s effort to
configure its real-time market systems and incorporate Avista into the EIM.9 The
methodology that the CAISO used to determine the implementation fee for Avista
is the same methodology that the CAISO used to determine all of the previously
accepted implementation fees for the other EIM participants described above.

The implementation fee is based on the CAISO’s estimate of the costs it
will incur to configure its real-time energy market to function as the EIM available
to all balancing authority areas in the Western Electricity Coordinating Council
(“WECC”).10 The components of that estimate are described in the Declaration
of April D. Gordon, the CAISO’s Director of Financial Planning and Procurement,
which is included with this filing as Attachment B, and are summarized below.

Implementation Costs (in thousands of dollars)
Energy management system
1,000
2,000
Hardware upgrades 500
Production software modifications 1,000
Network configuration and mapping 500
Integration 500
1,500
System performance tuning 250
Training and operations readiness 150
Project management 100
Total $19,650

Using this estimate, the CAISO derived a rate that allocates the $19.65
million to potential entrants into the EIM according to their proportionate share of
the total WECC load (excluding the CAISO’s load), using updated data reported

8 Implementation Agreement, Section 3.
9 Id., Section 4.
10 The total estimated cost is a projection assuming the total work effort remains stable.
Implementations either completed or underway are not considered in this estimate.
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to WECC. The CAISO then applied this fee to Avista’s share of the updated
WECC load (exclusive of the CAISO) to account for the Avista implementation
fee.

The $300,000 implementation fee is just and reasonable because it
allocates a portion of the overall cost to Avista in an amount proportionate to
Avista’s share of the benefits that will ensue from the EIM, as measured by
usage. In addition, as explained in Ms. Gordon’s declaration, the CAISO
confirmed the reasonableness of the resulting allocation by comparing it with an
estimate of the costs the CAISO projects it will incur to configure its real-time
energy market to function as the EIM that serves both the CAISO and Avista.
This comparison confirmed that the fee reasonably represents those costs, even
though certain costs may not be triggered by the Avista implementation but may
instead be incurred by the CAISO to incorporate other entrants. In future
implementations, the CAISO will confirm that the rate is reasonable by
conducting a similar comparison of the total implementation costs with the
individual entity costs.

The Implementation Agreement also provides for adjustment of the fixed
implementation fee by mutual agreement of the parties in the event that the
CAISO’s actual or expected costs exceed the estimate that forms the basis of the
implementation fee.11 This provision allows for appropriate consideration of the
allocation of costs associated with incorporation of Avista into the EIM. At the
same time, the requirement for Avista to agree to any increase in the
implementation fee ensures that Avista’s share of those costs remains
reasonable. The Implementation Agreement therefore reflects a reasonable
balance of the parties’ interest in preserving a level of cost certainty for Avista,
while appropriately allocating the costs of implementing the EIM.

The Implementation Agreement represents a binding commitment of the
parties. As such, it provides a workable framework for the parties to resolve any
differences and to make course corrections along the way. On the other hand,
the Implementation Agreement recognizes that the parties are entering into the
agreement on a voluntary basis and circumstances may arise that interfere with
the incorporation of Avista into the EIM through the planned process.
Accordingly, the Implementation Agreement allows either party to terminate the
agreement for any or no reason, provided it has first entered into good-faith
discussions for 30 days in an effort to resolve any differences.12 This and other

11 Implementation Agreement, Section 4. See also Commission Letter Order, Docket No.
ER14-1350-000 (Apr. 8, 2014) (accepting amendment to EIM implementation agreement
between the CAISO and PacifiCorp, to increase the PacifiCorp implementation fee to cover
additional scope identified in the stakeholder process). PacifiCorp’s request for additional scope
is the only instance thus far where an amendment of the implementation fee has been necessary.
12 Implementation Agreement, Section 2.
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December 11, 2019
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related provisions mean that the parties must work closely together to achieve
the goal of implementing Avista into the EIM in a timely manner.

The Implementation Agreement also includes general provisions that
round out the parties’ commitments. These general provisions address
confidentiality (Section 5), limitations of liability (Section 6), representations and
warranties (Section 7), general provisions such as those regarding notices,
amendments, etc. (Section 8), venue (Section 9), communication (Section 10),
and dispute resolution (Section 11).

III. Next Steps

Following the Commission’s acceptance of the Implementation Agreement,
the CAISO will incorporate Avista into the EIM. Avista’s implementation will be
subject to the CAISO tariff readiness requirements and the filing of a certificate of
readiness with the Commission.13 The CAISO will also take into consideration
lessons learned from the prior implementations, as the readiness criteria
represent the baseline for measuring the readiness of each new EIM entity’s
processes and systems for EIM participation.

Avista will continue to engage with its customers prior to participation in the
EIM. The CAISO expects that Avista will make any necessary modifications to
its open access transmission tariff in advance of the implementation date. The
CAISO recognizes that this effort will involve Avista working with interested
parties to facilitate implementation of the EIM, and the CAISO will engage in that
effort as Avista considers it appropriate.

IV. Effective Date

The CAISO requests that the Implementation Agreement be made
effective on April 1, 2020.

V. Request for Waivers

The CAISO submits that the filing substantially complies with the
requirements of section 35.13 of the Commission’s rules applicable to filings of
this type.14 The CAISO respectfully requests waiver of any such requirement to
the extent this filing does not satisfy that requirement. In particular, the CAISO
requests waiver of the requirement to submit Period 1 and Period 2 schedules,
because the implementation fee is a one-time fee that is not based on historical
data in Period 1 schedules or on the projections in Period 2 schedules. In any
event, good cause exists to waive filing requirements that are not material to the

13 See CAISO Tariff, Section 29.2(b).
14 18 C.F.R. § 35.13.
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Commission’s consideration of the Implementation Agreement.

VI. Service

The CAISO has served copies of this filing upon all scheduling
coordinators, Avista, the California Public Utilities Commission, and the California
Energy Commission. In addition, the CAISO has posted the filing on the CAISO
website.

VII. Contents of Filing

The following attachments, in addition to this transmittal letter, support the
instant filing:

Attachment A Implementation Agreement; and

Attachment B Declaration of April D. Gordon, Director of
Financial Planning and Procurement

VIII. Correspondence

Pursuant to Rule 203(b)(3) of the Commission’s Rules of Practice and
Procedure,15 the CAISO requests that all correspondence, pleadings, and other
communications concerning this filing be served upon the following:

John C. Anders
Assistant General Counsel
California Independent System
Operator Corporation
250 Outcropping Way
Folsom, CA 95630
Tel: [phone]
Fax: [phone]
E-mail: [e-mail]

15 18 C.F.R. § 385.203(b)(3).
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IX. Conclusion

The CAISO respectfully requests that the Commission accept this filing
and permit the Implementation Agreement, CAISO Rate Schedule No. 6037, to
be effective April 1, 2020, as requested. If there are any questions concerning
this filing, please contact the undersigned.

Respectfully submitted,

By: /s/ John C. Anders
Roger E. Collanton
General Counsel
Burton A. Gross
Deputy General Counsel
John C. Anders
Assistant General Counsel
California Independent System
Operator Corporation
Tel: [phone]
Fax: [phone]
Email: [e-mail]

Attorneys for the California
Independent System Operator
Corporation

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 2, Page 7 of 7
FEDERAL ENERGY REGULATORY COMMISSION
Washington, D.C. 20426
OFFICE OF ENERGY MARKET REGULATION
In Reply Refer To:
California Independent System Operator
Corporation
Docket No. ER20-567-000
Issued: February 19, 2020
John C. Anders
California Independent System Operator Corporation
250 Outcropping Way
Folsom, CA 95630
Reference: Energy Imbalance Market Implementation Agreement
On December 11, 2019, the California Independent System Operator Corporation
(CAISO) filed an Energy Imbalance Market (EIM) Implementation Agreement
(Implementation Agreement) with Avista Corporation (Avista). The Implementation
Agreement sets forth the terms under which CAISO will extend its real-time energy
market systems to provide imbalance energy services to Avista pursuant to CAISO’s EIM
tariff provisions. Under the Implementation Agreement, Avista will compensate CAISO
for its share of costs of related system changes, software licenses, and other configuration
activities. The Implementation Agreement is accepted for filing, effective April 1, 2020,
as requested.1
The filing was noticed on December 11, 2019, with comments, protests, or
interventions due on or before January 2, 2020. No protests or adverse comments were
filed. Notices of intervention and unopposed timely filed motions to intervene are
granted pursuant to the operation of Rule 214 of the Commission’s Rules of Practice and
Procedure (18 C.F.R. § 385.214). Any opposed or untimely filed motion to intervene is
governed by the provisions of Rule 214.
This action does not constitute approval of any service, rate, charge, classification,
or any rule, regulation, or practice affecting such rate or service provided for in the filed
1 California Independent System Operator Corporation, FERC FPA Electric Tariff,
CAISO Rate Schedules, Rate Schedule No. 6037, Avista EIM Implementation
Agreement, 0.0.0.
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Schedule 3, Page 1 of 2
documents; nor shall such action be deemed as recognition of any claimed contractual
right or obligation affecting or relating to such service or rate; and such acceptance is
without prejudice to any findings or orders which have been or may hereafter be made by
the Commission in any proceeding now pending or hereafter instituted by or against
CAISO.
This action is taken pursuant to the authority delegated to the Director, Division of
Electric Power Regulation - West, under 18 C.F.R. § 375.307. This order constitutes
final agency action. Requests for rehearing by the Commission may be filed within 30
days of the date of issuance of this order, pursuant to 18 C.F.R § 385.713.
Issued by: Steven T. Wellner, Director, Division of Electric Power Regulation - West
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PREPARED FOR:
TECHNOLOGY
ASSESSMENT
S R
PROPRIETARY AND
CONFIDENTIAL
DECEMBER 21,
2018
AUTHORS:
BRIAN HOLMES AND ZACH
GILL SANFORD
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 1 of 30
Table of Contents
1 Executive Summary ............................................................................................................................... 3
2 Technology Approach ........................................................................................................................... 6
2.1 Assumptions .................................................................................................................................. 6
2.2 Recommended Continuation of Existing Solutions ....................................................................... 7
2.2.1 Variable Energy Resource Forecast ....................................................................................... 7
2.2.2 Demand Forecast .................................................................................................................. 9
2.2.3 Nucleus for Deal Capture & Risk and Position Management ............................................... 9
2.2.4 Additional Nucleus Impacts ................................................................................................ 11
2.2.5 ADSS for Generation Schedule Optimization ...................................................................... 11
2.2.6 New Instance of MV-90....................................................................................................... 11
2.2.7 Oracle Utilities Enhancements ............................................................................................ 12
2.3 Recommended Purchased COTS / Vendor Solutions .................................................................. 12
2.3.1 Generation Outage Management System .......................................................................... 13
2.3.2 Transmission Outage Management System ....................................................................... 13
2.3.3 Participating Resource Scheduling Coordinator Bidding & Scheduling System.................. 14
2.3.4 Dispatch Integration to EMS ............................................................................................... 14
2.3.5 EIM Entity Scheduling Coordinator Scheduling System ...................................................... 15
2.3.6 Participating Resource Scheduling Coordinator Settlement System .................................. 15
2.3.7 EIM Entity Scheduling Coordinator Settlement & Allocations System ............................... 16
2.4 In-House or Contract Custom Development ............................................................................... 17
2.4.1 ADSS Enhancements ........................................................................................................... 17
2.4.2 Avista Integration ................................................................................................................ 18
2.4.3 Custom Reporting ............................................................................................................... 18
2.4.4 Other In-House Enhancements ........................................................................................... 19
3 Estimated Costs ................................................................................................................................... 19
3.1 Existing Application Cost Estimates ............................................................................................ 19
3.2 COTS / Vendor Cost Estimates .................................................................................................... 20
3.3 In-House or Custom Development Cost Estimates ..................................................................... 22
3.3.1 ADSS Cost Estimates ........................................................................................................... 22
3.3.2 Integration Cost Estimates .................................................................................................. 23
3.3.3 Custom Reporting ............................................................................................................... 24
4 Proposed High-Level Schedule ............................................................................................................ 25
5 Conclusion ........................................................................................................................................... 25
6 Addendum – Supplemental Cost Analysis .......................................................................................... 27
6.1 Planning, Requirement & Procurement Phase ........................................................................... 27
6.2 Generation & Network Modeling ............................................................................................... 27
6.3 Network & IT Infrastructure for Applications ............................................................................. 28
6.4 Generation and Intertie Equipment Upgrades & Communications ........................................... 29
6.5 Project Implementation .............................................................................................................. 30
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
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1 Executive Summary
This report summarizes current cost estimates for Avista to join the Western Energy Imbalance Market
(EIM). The focus is the technology solutions, including integration, required for effective EIM
participation. During the analysis it was determined that Nucleus could not practically be enhanced to
provide many of the required functions. Therefore, the analysis estimates the cost and effort to procure
and implement Commercial, Off-the-Shelf (COTS) solutions and integrate those solutions. These cost
estimates are detailed in the main body of the report and summarized on Line 1 through 5 of Table 1.
During the project, Avista requested other costs be estimated to create a more comprehensive cost
picture. Additional cost estimates for system procurement, network modeling, communication
infrastructure, generator upgrades and internal and consulting labor for EIM technology implementation
and other Project functions are described in the Addendum and summarized on Line 6 through 20 of
Table 1.
This report, the associated end-to-end technology overview diagram, the estimating model and
schedule describes the assumptions, decisions and conclusions which underpin the values in Table 1. An
Executive Summary of the considerations for each of the line items is included as Table 2.
This report provides Budgetary Cost estimates (+/- 25%) for the currently identified scope. The analysis
focused on the planned incremental EIM technology components. Detailed requirements were not
developed as part of this effort and full impact assessments to existing functionality were not in scope.
Avista will need to proceed with this detailed analysis if a decision is made to pursue EIM membership.
Following the development of detailed requirements, the estimates can be refined.

Document is no longer concidered confidential
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Table 1 – Summary Budgetary Cost Estimate for EIM Technology Projects
Line Cost Estimate Category
Project & Procurement
Solutions & Services
(in $,000)
Project & Procurement
Avista Internal Labor
(in Hours)
Post-Project Recurring
Services & Avista Labor
(in $,000)
1 Vendor EIM Software Solutions $2,100 - $4,500 9,000 - 21,900 $500 - $1,100
2 Avista ADSS Enhancement Effort Included 9,600 - 14,400
3 Avista Internal Integration Effort Included 8,200 - 12,300
4 Custom Reporting Allowance Included 2,000
5 Other Avista Software Enhancements Included 8,000 - 12,000
6 Dedicated Security & Architecture $0 3,300 - 4,900 $50 - $100
7 Miscellaneous Software & Hardware Costs $330 - $715 0 $25 - $100
8 Network for Vendor & CAISO $150 - $420 2,400 - 1,750 $400 - $730
9 Program Leadership, Management & SMEs $3,200 - $4,900 7,000 - 9,000
10 System Selection & Procurement $500 - $810 6,800 - 8,800
11 Full Network Model for EIM $40 800 $50
12 Generation Participation & Cost Modeling Included 2,000 - 3,500
13 OATT, MBR & ISO Agreements $105 - $190 1,300 - 2,300
14 Training & OCM Included 4,800 - 8,500
15 Transmission Meters & Data Collection $340 5,200 $18
16 Network Improvements for Metering $210 - $2,000 2,600 $15
17 Incremental Permanent Avista FTEs $0 7,400 $2,500
18 EIM Membership & Ongoing Fees $290 0 $120
19 Generation Metering from GPSS $3,000 - $4,500
20 Dispatch Integration from GPSS $1,200 - $1,400
Total $11,500 - $20,100 80,000 - 120,000 $3,700 - $4,700
Document is no longer concidered confidential
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Table 2 – Executive Summary of Included Cost Estimates
Line Exec Summary
1 7 applications; Avista effort estimated two ways - prior project and simple WBS; less
consulting, architecture and security shown separately.
2 Represents 18 estimated items; 9 additional uncertainty placeholders included; 50%
contingency included in upper range.
3 Represents 25 estimated interfaces; 9 additional uncertainty placeholders included; 50%
contingency included in upper range.
4 Placeholder for reporting not covered by vendors or vendor customizations to create required
reports and analysis tools and an allowance for deprecation impacts on Nucleus.
5 Represents 6 estimated items including the Oracle MDM estimate from Avista; 50%
contingency included in upper range.
6 Dedicated cloud architect and security engineer provided by IT; no contingency added to
range.
7 Additional ADSS hardware; firewalls; unanticipated software and integration placeholder; no
contingency added to range.
8 New dedicated CAISO, AWS and Azure connections; meter data collection costs; minor BUCC
improvements; cost and effort low/high are inverted; no contingency.
9 Consulting SI services; Avista Leads for Merchant, Grid Ops, IT, GPSS and OCM plus Directors;
adj to reflect "overhead" portion; no contingency added to range.
10 Consulting for Program initiation, requirements and system selection; estimated Avista
participation based on simple WBS method in (1); no contingency added to range.
11 EIM share of FNM costs; additional costs for RC integration not included and are described in
a separate report; 20% contingency added.
12 High level estimate for basic modeling, GPSS cost gathering (45%) and participation strategy
definition (35%); includes 20% contingency on upper side of range.
13 Assumes only basic changes to prior EIM OATTs; full MBR cost but that may not be fully
incremental; includes 20% contingency on upper side of range.
14 Time for the recipients; costs for creation is in consulting and vendor costs and Avista
Leadership overhead; includes 20% contingency on upper side of range.
15 New meters; communications for sites other than Network / T1; backend MV90 work for both
generation and transmission; 20% contingency.
16 New T1 communications for 67% of transmission locations and 36% of generation locations;
HPV required at 35% of combined locations; no contingency added to range.
17 11-13 new FTEs in Power Supply, Ops, Accounting, Compliance and ET; incremental IT in (6);
project costs include a portion of ramp in period; no contingency.
18 Integration fees and ongoing Grid Management Charges; no contingency.
19 High and Low side metering and transformer upgrades at 11 facilities.
20 EIM Master PLC at 6 locations and reprogramming of the existing unit level PLCs.

Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 5 of 30
2 Technology Approach
As identified in the EIM Technology Inventory and End-to-End EIM flow diagram, Avista will need a
mixture of procured and in-house developed applications for EIM participation. Additionally, Avista will
need to participate in development of the interfaces to connect existing and new applications.
2.1 Assumptions
In developing the estimates presented in this report, Utilicast converted Avista Labor to costs based on
the following assumptions.
Table 3 – Labor Rate Assumption
Category Rate
ADSS Development $80
Nucleus Development $90
Integration Development $100
Network Modeling $100
All Other Avista Labor $100
Consulting (Range based on Expertise) $185 - $235

Contingency has been applied to some estimates based on a variety of factors – including the source of
the estimate, the factors considered in establishing estimate ranges, the level of uncertainty and Avista
requests. The contingency values in Table 4 are incorporated in the estimates:
Table 4 – Contingency Assumptions
Line Category Contingency
1 Vendor EIM Software Solutions 20%
2 Avista ADSS Enhancement Effort 50%
3 Avista Internal Integration Effort 50%
4 Custom Reporting Allowance 0%
5 Other Avista Software Enhancements 50%
6 Dedicated Security & Architecture 0%
7 Miscellaneous Software & Hardware Costs 0%
8 Network for Vendor & CAISO 0%
9 Program Leadership, Management & SMEs 0%
10 System Selection & Procurement 0%
11 Full Network Model for EIM 0%
12 Generation Participation & Cost Modeling 20%
13 OATT, MBR & ISO Agreements 20%
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 6 of 30
Line Category Contingency
14 Training & OCM 20%
15 Transmission Meters & Data Collection 20%
16 Network Improvements for Metering 20%
17 Incremental Permanent Avista FTEs 0%
18 EIM Membership & Ongoing Fees 0%
19 Generation Metering from GPSS 20%
20 Dispatch Integration from GPSS 0%

Many estimates are driven in part by project duration. As shown in more detail in Section 4, the EIM
project is anticipated to begin with a Planning and Procurement phase in 2019. Avista’s team will begin
ramping up in early 2019 through mid-2019 with Consulting support generally beginning in mid-2019.
The main implementation phase of the project is anticipated to begin in early 2020 and continue
through an April 2022 implementation.
2.2 Recommended Continuation of Existing Solutions
2.2.1 Variable Energy Resource Forecast
Avista currently has two large Variable Energy Resources (VER) on the system, Palouse Wind and Solar
Select, and is in active negotiations with one additional significant VER resource which would be online
prior to the anticipated EIM membership in April 2022. Additionally, Avista has a significant amount of
VER generation in the interconnection queue.
Avista’s current forecasting for facilities anticipated to be online by April 2022 are:
1. Palouse: Avista currently receives Real-Time VER forecasts for the Palouse Wind resource from
two forecast providers, Meteologica and Vaisala and imports the forecast to ADSS via API. The
Meteologica forecast is provided by Palouse Wind and the Vaisala forecast is contracted for
separately by Avista. The Real-Time Merchant operator has discretion to use either forecast in
bilateral trading decisions.
2. Solar Select: Avista currently only receives Day-Ahead forecasts from Solar Select. Avista does
not have an additional backstop forecast for this facility.
3. New Wind Resource R: Forecasting approach is To Be Determined.
Based on current EIM rules, the following are required for VER Resources:
1. An hourly Base Schedule with a target snapshot around T-60 to the beginning of hour T (this
requirement may be updated to 15-minute granularity with the proposed Day-Ahead Market
Enhancements project).
2. A 15-minute granularity forecast refreshed every 15 minutes with a target snapshot around T-40
to each Fifteen Minute Market (FMM) interval beginning T.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 7 of 30
3. A 5-minute granularity forecast refreshed every 5 minutes with a target snapshot around T-10 to
each Real-Time Dispatch (RTD) interval beginning T.
For Palouse, there are two simple options for meeting the EIM requirements:
Meteologica has existing functionality to produce 5-minute granular forecasts every 5-minutes. This can
be used to meet all CAISO requirements. Meteologica has an existing real-time production input from
the resource telemetry which can be incorporated in the forecasts but this is not provided by Avista. If
an enterprise solution is implemented, a new interface to provide telemetry for all VER to the VER
Forecast provider will be needed.
Based on the Vaisala website, it appears that Vaisala only offers 10-minute granularity and 10-minute
refresh capability at this time, which could satisfy CAISO requirements for Base Scheduling and for the
RTPD/FMM submission but does not meet CAISO requirements for RTD. However, CAISO is in the
process of rolling out a short-term persistence VER Forecast offering. In this approach, CAISO will
snapshot the CAISO State Estimator output (adjusted by a reference curve for solar resources) of the
VER resource immediately prior to the RTD snapshot. Early CAISO analysis suggests that this simple
persistence model, which eliminates all potential data transfer lag, is generally superior to other
methods. In combination with the Visala produced forecast, this would meet EIM requirements. If Avista
selects Vaisala, there may be some enhancement costs. Budget for an interface to supply Real-Time
telemetry to Vaisala has been included.
CAISO currently only accepts a single VER forecast for each resource, so a single selection would be
needed for CAISO submissions (Avista’s bilateral trading decisions could continue to use either forecast).
The chosen forecast provider could be provisioned with the necessary EIM Entity certificate and
interface directly with CAISO, or the forecast sent to the EIM Entity Scheduling Coordinator (EESC)
Scheduling System to then submit to CAISO. Utilicast recommends a direct to CAISO integration
approach to eliminate the time lag and potential point of failure associated with routing the forecast
through an additional system. The integration costs estimates do not include an estimate for integrating
the VER forecast with the EIM Entity Scheduling System.
For Solar Select, changes will be needed and a solution for new Wind Resource R will also require a
forecast that meets the requirements. Avista anticipates going forward that any new VER resources will
have the obligation to provide a forecast that is compatible with market needs. However, depending on
the number of new VER resources, a consistent enterprise solution may be needed at some point.
Meteologica and Visala would be natural options to provide this service but Avista may wish to consider
a Request For Proposal (RFP) process. A trial period to assess the accuracy of different providers during
an RFP is recommended.
Since this effort was identified late in the process, will likely replace existing costs and is anticipated to
be small relative to the work, a cost estimate has not been prepared.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 8 of 30
2.2.2 Demand Forecast
Avista should utilize its existing Balancing Authority Area (BAA) demand forecast, produced in ADSS as a
blend of Pattern Recognition Technologies (PRT) forecast vendor and internally produced forecasts for
Merchant Balancing in Day-Ahead and for the T-75 and T-55 Sufficiency Tests.
For the binding balancing test at T-40, the EIM Entity should use the CAISO Demand Forecast due to the
Under / Over Scheduling Penalty treatment defined in the CAISO Tariff. Any EIM Entity COTS application
Avista might select will support obtaining the CAISO Demand forecast and balancing to that forecast.
While Avista should opt to use the CAISO forecast due to the Tariff provisions, the CAISO does accept
Demand Forecast submissions from the EIM Entity and will evaluate them for accuracy. If Avista’s
forecast is more accurate than the CAISO forecast in a systematic way, the CAISO may adopt Avista’s
forecast as its own.
Per discussions during the project, Avista would like to supply its own BAA forecast to the CAISO for
accuracy consideration. This will require an interface to submit 5-minute granular forecasts on a rolling
5-minute basis to the CAISO forecast application (ALFS - Automated Load Forecast System). Based on
discussions, the cost estimate in this report is based on an ADSS interface with the EIM Entity Scheduling
Coordinator (EESC) Scheduling System, which will then submit to CAISO. Any EIM Entity COTS application
Avista might select will support submitting the BAA Demand forecast to CAISO. This will result in a
submission lag and Avista may consider the effort to develop a direct to CAISO Demand Forecast
submission interface but for this estimate we have assumed the data is routed through the EESC
Scheduling System.
2.2.3 Nucleus for Deal Capture & Risk and Position Management
The existing Nucleus solution currently performs several functions which will be required for EIM. The
following functions are recommended to continue through the EIM implementation:
 Record Bilateral Deals
 Manage Preschedule and Term positions
 Record CAISO Non-EIM Market Awards
 Monitor GHG Position & Mark to Market
 Electronic Quarterly Reporting (EQR) for Bilateral Transactions
 Report Net Scheduled Interchange
The Bilateral and CAISO Non-EIM Market Awards (which are essentially Bilateral Deals with CAISO which
must be tagged) will continue to be captured in Nucleus as the system of record for Deal Capture. These
transactions will continue to be tagged per WECC rules via webTag. Nucleus will then provide the
Bilateral Deals (or a summarized obligation of the Bilateral Deals) to ADSS for Real-Time balancing.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 9 of 30
Nucleus will also continue to provide the 7 Day-Ahead Load Forecast and Unit Commitment information
the Reliability Coordinator (RC).1
ADSS will then schedule Avista generation to Balance against total obligations, including the Demand
Forecast and the Bilateral Deals. ADSS will assume primary responsibility for Merchant Balancing
responsibilities for CAISO Day-Ahead through T-55, though the Participating Resource Scheduling
Coordinator (PRSC) Scheduling System will ultimately be the system of record, including manual
adjustments and market impacts. The EESC Scheduling System will be the system of record for BAA
Balancing at T-40. Nucleus will cease to perform balancing functions in Real-Time. An impact assessment
of deprecating this functionality is needed to determine downstream impacts.
Nucleus will also continue to track Greenhouse Gas (GHG) obligations which are incurred due to Bilateral
/ Tagged transactions as well as credit purchased by Avista. EIM may also create GHG obligations. To
maintain a complete view of the GHG position and mark that position to market, Nucleus will need to
obtain the GHG obligations incurred as a result of EIM activities. A new interface to import EIM GHG
obligations from the PRSC Settlement System is included in the integration estimate.
Nucleus will continue to perform EQR for Bilateral / Tagged transactions. EIM will create new
transactions to include in EQR. These calculations will be performed by the PRSC Settlement System and
exported in spreadsheet format. Avista will then manually merge the Bilateral EQR and EIM EQR data.
No cost estimate for an API is included.
Nucleus also currently serves as a key integration point for ADSS. Based on the initial assessment, it does
not appear that a change to this approach is required to support EIM. However, Avista is planning to
implement a managed API to facilitate integration going forward for data that is a straight pass-through
from Nucleus. Data that requires transformation in Nucleus may not make sense to migrate until a
broader Nucleus replacement effort is scoped. Decoupling Nucleus and ADSS via a Managed API makes
sense as a foundational project but is not an EIM specific project. Therefore, the costs are not included
in the EIM estimates.
Nucleus also currently provides Risk Management and Mark to Market functionality. EIM is an
imbalance market which should be responsible for a small percentage of Avista’s purchases and sales.
EIM transactions are Real-Time only and do not have a forward component. Additionally, EIM
transactions are settled within three business days and invoiced on a weekly basis. At this time, EIM
impacts to the overall measurement of Risk has not been identified. One aspect to note is that EIM
settlements for third party Transmission Customers in the Avista BAA will be settled with Avista. As a
result, Avista will be floating the EIM invoice obligations on behalf of these parties for some period of
time. If Avista continues to invoice Transmission Customer monthly rather than weekly in line with
CAISO invoicing, the float is larger.
Nucleus currently supports the determination and reporting of Net Scheduled Interchange (NSI) to the
WECC (Western Electricity Coordinating Council) Interchange Tool (WIT) for the calculation of
1 Note that there may be changes required as part of the RC change from Peak RC to CAISO, but those impacts are
not EIM impacts.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 10 of 30
Inadvertent Energy transfers. The EIM dispatch of Energy Transfer System Resources (ETSRs) is
considered scheduled interchange and must now be included in this calculation. An interface to provide
this value to Nucleus is included in the estimate.
2.2.4 Additional Nucleus Impacts
It may be possible to leverage the new tools to perform some other functions that Nucleus performs
today. Avista should consider what functions it might want to remove from Nucleus and include them as
optional requirements, to be priced separately, in the RFP for the new tools to evaluate vendor
offerings. Functionality that is deprecated from Nucleus may have downstream impacts and an impact
assessment should be conducted for any deprecated functions.
Given the central role of Nucleus in Avista’s technology footprint it is likely that there will be some
changes required to address functions that will no longer be performed in Nucleus, such as the impact
from balancing no longer being performed in Nucleus, cited above. While a complete impact assessment
is needed, a placeholder budget of $100,000 is included to address potential impacts.
2.2.5 ADSS for Generation Schedule Optimization
Avista should utilize existing Avista Decision Support System (ADSS) functionality for resource base
schedule creation. ADSS currently models the complex hydro constraints and operating characteristics
of Avista’s generation fleet. Some updates will be required to produce the desired output for EIM, but
these are much smaller than implementing a new COTS optimization solution. Therefore, ADSS is best
positioned to produce generation resource base schedules based on its existing optimization
functionality and the enhancements identified.
Once determined, the generation base schedules would be submitted to the PRSC Bidding and
Scheduling System and the EESC Scheduling System, requiring interfaces to be developed between ADSS
and these vendor solutions.
This approach relies on ADSS to produce the Base Schedules for all Avista-owned and contracted
generation Resources and pass the Non-Participating Resources (NPRs) schedules to the EESC for
submission. An alternative to this approach is to designate all Avista Resources as Participating
Resources (PRs). In doing so, the Merchant would then be responsible for submitting all Avista Resource
Base Schedules to CAISO and the EESC could obtain the Base Schedules directly from Base Schedule
Aggregation Portal system (BSAP). This alternative can be explored during the design phase with the
vendors and might reduce integration costs. In this report, Utilicast has included estimates for two
interfaces, one to the PRSC Scheduling System and the other to the EESC Scheduling System.
2.2.6 New Instance of MV-90
Avista should implement a new instance of MV-90 to serve as a collection system for EIM meter data.
This new MV-90 instance will serve as the head-end system for generation, interchange, and imbedded
load meter data read by Avista for EIM meter submission. MV-90 will need to interface with the meter
data communication systems polling these meters and with the EIM Meter Data Management (MDM)
solution identified in the following section.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 11 of 30
2.2.7 Oracle Utilities Enhancements
Avista should enhance and utilize its existing Oracle Utilities vendor solution for EIM Meter Data
Management (MDM). The MDM will interface with Avista’s OSISoft Process Information (PI) system,
meter data downloaded from the BPA Customer Portal, Hourly Actual Interchange checkouts values
from Nucleus, and the new instance of MV-90 described in the following section. Validation, Estimating,
and Editing (VEE) will be performed on the EIM meter data, with the PI sourced data validated by
shaping 5-minute average values to hourly meter values. The VEE meter data will be aggregated to the
Resource ID level, as registered with CAISO, including the EIM Load Aggregation Point (ELAP) Avista BAA
load calculation, which will be adjusted to account for transmission losses. The aggregated meter data
will be sent to the EESC Settlement System for submission to CAISO, unless Avista determines the
additional cost of this desired functionality in the EESC Settlement System is too expensive, in which
case the EIM MDM will need to interface directly with CAISO systems.
2.3 Recommended Purchased COTS / Vendor Solutions
This section identifies solutions recommended for purchase through a competitive RFP process. These
designations are also identified in the EIM Technology Inventory. The sub-sections identify some of the
major considerations identified in establishing the proposed approach.
In general, the following criteria were important in the determination of a purchase recommendation:
 Required CAISO Expertise – Some applications and integrations require considerable expertise in
the CAISO markets, technologies and integration standards. Avista has learned a considerable
amount on this project, but, as the design and development would likely require considerable
outside consulting resources, Avista is better off selecting from existing vendors. For some of
the more complex components required for EIM, custom development is likely to entail major
risks to scope, schedule and budget.
 Vendor Solution Maturity – A small set of vendors have been developing EIM solutions over the
past four years and there are likely to be more than 10 EIM Entities which precede Avista. Some
of the EIM vendor applications execute fairly standard functionality. Even when that
functionality is complex, if Avista is likely to require minimal customized development from the
standard solution, then there is greater benefit to choosing an established solution.
 Maintenance Burden – The CAISO markets are constantly changing. Major changes are released
once a year in the Fall Release, with smaller changes about every quarter. There are dozens of
planned market enhancements which will impact multiple CAISO applications – in particular,
Bidding, Scheduling, Dispatch and Settlements. CAISO only supports two versions of interfaces
(current and immediately prior). Sharing these upgrade costs with multiple participants sharing
a common vendor solution will lower maintenance costs. Avista should be careful in the RFP
process to clearly understand vendor offerings for complying with ongoing CAISO changes.
 Development Fit to Existing Avista Technology – Avista has some in-house applications and
established vendor products. When EIM requirements were closer to the natural footprint of
existing in-house solutions, in-house solution enhancements are recommended. When the
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 12 of 30
required EIM functionality is not similar to the natural footprint of an existing solution, vendor
solutions were preferred.
The trend for the EIM applications listed below is to use a vendor-hosted / cloud-based delivery model
in most cases. The vendor cost estimates in this report assume that all of the applications identified in
this section, with the exception of the EMS integration which is an existing on-premise solution, are
vendor-hosted / cloud-based. Of these solutions, the most commonly deployed on-premise solutions
are the Outage Management solutions.
2.3.1 Generation Outage Management System
Avista should consider purchasing a Generation Outage Management System (GOMS) to replace Avista’s
in-house developed Generation Outage Coordinator (GOC). Generation outages in EIM are a bit different
than the traditional outage definition; they are more akin to availability management. The ability to
control resource availability in the market through outages is critical to success. Another key aspect of
GOMS in EIM is keeping up with Ambient Derates. ADSS appears to be well positioned to supply this
information. To do so ADSS modifications and integration to the GOMS is required.
Purchasing a COTS GOMS to manage outage scheduling / workflows, development of outage calendars
and CAISO integration is preferred to updating / developing this functionality in GOC or ADSS.
Additionally, a GOMS, which is integrated with CAISO, will facilitate submission of outages for RC
purposes after Avista becomes an RC customer of CAISO, rather than continuing the manual process
currently used for Peak Outage submission. Other scoped integration points with the GOMS are also
discussed in Section 3.3.2.
Though there are distinct differences in the underlying data model, workflows and permission structure
between GOMS and TOMS there are also many overlapping features. Every other EIM participant has
selected the same vendor for both Generation and Transmission outage management. It is likely that
Avista will want to select a single vendor for both GOMS and TOMS as well.
This system may be implemented prior to EIM to support Avista processes and RC functionality,
depending on resource availability, but it is unlikely to be ready for RC Parallel Operations in Summer
2019. It is likely that Avista will need to rely on a modification to the current manual process for filing
outages with Peak for some time before cutting over to the new GOMS. The definition of this manual
process is beyond the scope of this assessment.
2.3.2 Transmission Outage Management System
Avista currently uses the Control Room Outage Window (CROW) outage management software for
Operator Logging and managing Transmission Outages, along with spreadsheets. This application
doesn’t integrate directly with CAISO’s outage management system so Avista needs to evaluate
purchasing a third-party interface application or consider purchasing a new Transmission Outage
Management System (TOMS) that currently integrates directly with CAISO. Integration with CAISO for
outage management is critical for EIM participation, as providing timely and accurate transmission
rating information is critical to success. A COTS TOMS will also support the outage scheduling and
approval process and typically will have several reporting features to develop outage calendars.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 13 of 30
The basis for all transmission information in EIM is the Full Network Model (FNM). A TOMS should use
the EIM FNM as the data foundation of the FNM equipment identifiers, which will be required for
outage submissions to CAISO.
Though there are distinct differences in the underlying data model, workflows and permission structure
between GOMS and TOMS there are also many overlapping features. Every other EIM participant has
selected the same vendor for both Generation and Transmission outage management. It is likely that
Avista will want to select a single vendor for both GOMS and TOMS as well. If the Merchant team has
access to the Outage Management system for Generation, a strong permission structure is required to
ensure that Transmission information cannot be viewed by the Merchant team.
This system may be implemented prior to EIM to support Avista processes and RC functionality
depending on resource availability, but it is unlikely to be ready for RC Parallel Operations in Summer
2019. It is likely that Avista will need to rely on a modification to the current manual process for filing
outages with Peak for some time before cutting over to the new TOMS. The definition of this manual
process is beyond the scope of this assessment.
2.3.3 Participating Resource Scheduling Coordinator Bidding & Scheduling System
Avista should purchase a PRSC Bidding & Scheduling System. The proposed approach includes retaining
and extending the optimization functionality in ADSS and using the PRSC Bidding & Scheduling System
primarily as an interface to CAISO. The functionality for Bid and Schedule exchange with CAISO is very
similar to the full market functionality, so vendor solutions are more robust than just the EIM
capabilities. This solution will likely also support the RC schedule submission requirements going
forward. There are many Avista-CAISO interfaces required for this solution, so leveraging a vendor to
insulate Avista from CAISO application changes is also beneficial.
Given Avista will be retaining ADSS, integration between ADSS and the PRSC Scheduling System will be
required and is included in the estimates. An alternative would be to extend ADSS to perform the CAISO
data exchange. However, the complexity of the BSAP and Scheduling Infrastructure Business Rules (SIBR)
interfaces is substantial and it is best to use existing and vendor-maintained COTS interfaces to
accomplish these tasks.
Additionally, the cost estimated in this report anticipate that PCI Gen Manager is retained as the CAISO
full market intertie bidding solution. It is likely that PCI would seek to license the EIM module separately
from the existing solution, but Avista should review the contract. Given the similarity between the
bidding and results functionality between EIM and the full CAISO market, Avista should include
specifications for CAISO full market intertie bidding in the RFP process to assess vendor offerings to
provide a consolidated platform.
2.3.4 Dispatch Integration to EMS
Avista should purchase the GE EMS integration and processing capability for CAISO dispatch signals
provided through the Automated Dispatch System (ADS) to EIM participants. Automated processing and
centralized communication of the 5-minute dispatch signals from the market is critical for EIM
participation, as timely relaying of dispatches to Participating Resources is critical to success.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 14 of 30
Additionally, integration of the adjustment to Net Scheduled Interchange (NSI) due to the Dynamic ETSR
transfers must be integrated to EMS to calculate Area Control Error (ACE).
2.3.5 EIM Entity Scheduling Coordinator Scheduling System
Avista should purchase an EESC Scheduling System. The process of aggregating tags to Resource IDs for
Base Scheduling and Real-Time Interchange Scheduling and communicating this information with the
ISO is both critical to EIM success and very complex. Three software vendors have provided this
functionality – OATI, MCG and PCI. Each of these vendors had considerable experience developing
solutions for the CAISO market and the first implementation of each of these solutions was challenging,
expensive and had a number of defects discovered in production. These solutions have been refined
through subsequent implementations. There are many Avista-CAISO interfaces required for this
solution, so leveraging a vendor to insulate Avista from CAISO application changes is also beneficial.
2.3.6 Participating Resource Scheduling Coordinator Settlement System
Avista should purchase a PRSC Settlement System. The processing of the EIM settlements is complex.
Avista has an existing vendor solution (PCI) for this functionality for the CAISO intertie business. The EIM
system will have many and more complex charge codes to process, but the overall workflow is the same.
It is likely that PCI would seek to license the EIM module separately from the existing solution, but Avista
should review the contract.
The PRSC Settlement System will be an important data hub. The assessment also included an evaluation
of the currently specified CAISO OASIS and Customer Market Results Interface (CMRI) reports. There is a
considerable amount of data critical for evaluating market results contained in these reports and a
settlement system vendor will typically consume this data and maintain the interfaces with the CAISO as
they are updated. Avista should be specific in its expectations with vendors during the RFP regarding
OASIS and CMRI functionality.
There are essentially three classes of Settlement Systems:
1. Solutions which support the basic parsing of the settlement data and basic verification of the
settlement amounts with limited consumption of OASIS and CMRI data.
2. Solutions which also provide advance shadow settlements capabilities which allow users to
analyze charges in more detail with more consumption of OASIS and CMRI data and some
abilities to integrate settlement and market result data for analysis.
3. Solutions which also provide advance analytics capabilities to identify profitability and
adjustments to strategy through robust integration of multiple data sources.
More robust solutions are typically more expensive. Avista should include requirements for each of
these in the RFP and evaluate whether bundling the analytics capabilities with the settlement solution is
cost effective, or if a more basic settlement system with database access would allow Avista to better or
more cost effectively analyze results.
Aside from parsing the Settlement Data, performing Shadow Settlements and potentially providing
analytics capability, a PRSC Settlement Solution should also include
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 15 of 30
 Approval Workflows
 Dispute Support and Lifecycle Management
 Invoice Processing and Reconciliation
 Meter Data Acquisition from CAISO’s MRI-S
 EIM GHG obligation tracking
 EIM EQR calculations
2.3.7 EIM Entity Scheduling Coordinator Settlement & Allocations System
Avista should purchase an EESC Settlement System. The processing of the EIM Settlement charges is
complex. Additionally, the EESC will be required to allocate CAISO charges to its Transmission Customers
(TCs) – becoming in essence a mini-ISO settlement department in the process. This is complex
functionality and requires integration with the EESC Scheduling System and the Tagging system.
Depending on the whether Avista prefers a single vendor for these three functions or different vendors,
Avista may need to play a role in the integration. Based on the analysis, Avista prefers to keep options
open for vendor selection and therefore an estimate is included for this interface in Section 3.3.2.
For the EESC Settlement System, the analytical capabilities are not nearly as important as they are with
the PRSC Settlement System. However, the system should still support
 Approval Workflows for CAISO and TC Calculated Amounts
 Dispute Support and Lifecycle Management, including on behalf of 3rd Parties
 CAISO Invoice Processing and Reconciliation
 Creation of EIM Invoices for Transmission Customers2
 Meter Data Acquisition from MRI-Ss
Avista should include requirements for the EESC Settlement System to submit and synchronize meter
data with MRI-S in the RFP and evaluate whether routing the Meter Data through the EESC Settlement
system is preferable to having the EIM MDM directly submit and sync meter data with CAISO.
The same vendors which offer EESC Settlement applications also offer PRSC Settlement applications and
there may be benefits to choosing the same vendor for both solutions. However, this is not required and
several EIM participants have selected different vendors for EESC and PRSC Settlements.
The emphasis of the EESC Settlement System is on transforming the CASIO settlements into TC
Allocations and the related workflows to manage the creation of TC Settlement Statements and TC
Invoices throughout the dispute and resettlement period. The PRSC Settlement System has a greater
emphasis on analysis. If all Avista Generation Resources are treated as PRs, then Avista can get a
complete picture of Generation performance in a single system, decreasing the need for a common
2 It may be possible to consolidate EIM TC invoicing with settlement and invoicing for other Transmission Services.
This consolidation has not been scoped in this assessment but Avista may wish to include this as an optional feature
in the RFP for this solution or include it on a roadmap for future capabilities.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 16 of 30
platform (Merchant tag settlements will still be determined by the EESC Settlement System and sent to
the Merchant TC).
In some cases, EIM entities have seen the integration between the EESC Scheduling System and the EESC
Settlement System as more important than a common platform with the PRSC Settlement System. This
“bid-to-bill” connection can be especially helpful when validating tagged schedule submission / status /
timing between the Market and Settlements to ensure that TC Allocations are accurate.
Another consideration is the alignment of the personnel that will be performing Merchant Analysis and
TC Allocation functions. Despite the different focus of the applications, there is a considerable overlap in
the data and processes. If there is a single team that is tasked with this work, a common platform will
reduce training needs and ease the ability for team members to assist and backup each other. If these
are distinct teams (e.g. if the Merchant Analyst sits on or near the Merchant Trade Floor) the need for a
single vendor solution is lessened.
2.4 In-House or Contract Custom Development
In addition to the new applications described in Section 2.3, several in-house development efforts were
identified and estimated. This section describes the functionality identified for in-house development.
2.4.1 ADSS Enhancements
Avista should enhance existing ADSS functionality for Base Schedule and Bid creation. ADSS currently
models the complex hydro constraints and operating characteristics of Avista’s generation fleet and
Avista has extensively researched vendor solutions and has not found satisfactory alternatives.
Therefore, ADSS is best positioned to produce pre-hour optimal Base Schedules and Bids based on its
existing optimization functionality.
ADSS optimal schedule determination will be enhanced to include functionality to create Base Schedules
anticipated to meet CAISO Demand Forecasts and Flex Ramp Requirements. However, the approach
used for estimation is a simplification from the CAISO Flex Ramp approach in a number of ways to
achieve a tradeoff between accuracy and cost (e.g. using an Ancillary Service (A/S) type product rather
than a direct ramp rate evaluation, using prior period Base Schedules as the initial condition). This
approach can be evaluated going forward.
ADSS will need to be enhanced to produce EIM compliant 4-part bids for each PR, specifically: the
energy bid, minimum load cost, startup cost, and the GHG adder. This will be straightforward for
thermal resources but will require additional development for the hydro resources. Once produced, the
bids would be submitted to the PRSC Bidding and Scheduling System, requiring an interface to be
developed between ADSS and this vendor solution. Based on the evaluation, ADSS also has the required
information to calculate Ambient Derates for both gas and hydro resources. The Resource Level
capabilities will be exported to the GOMS for submission to the CAISO. Synchronizing outages back from
either the Avista GOMS or the CAISO OMS to allow validation and reporting in ADSS is desirable and has
been included in the cost estimates but could be optional. Direct integration with the CAISO is generally
intended to be avoided, if possible, so the initial preferred approach for discussion with the GOMS
vendor is that this synchronization is with the GOMS.
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 17 of 30
Due to Market timelines, a full ADSS optimization may not be run for the T-75 and T-55 balancing
submissions by the PRSC. Additionally, the EESC Scheduling System is responsible for the T-40 balancing.
ADSS will be enhanced to create a simplified balancer screen and logic to economically zero imbalance.
Estimates are included for these enhancements assuming that ADSS will then push the results directly to
the EESC Scheduling System. This approach should be validated with the EESC Scheduling System vendor
to evaluate whether off the shelf functionality might meet the EESC needs, potentially saving
development of one interface.
During this evaluation, 18 enhancements were identified and estimated (see Table 8). For each
enhancement, an effort estimate was identified for Requirements, Design, Development and Testing.
Due to uncertainty in the Requirements, COTS vendor selections and the Managed API approach and in
accordance with Avista estimating guidelines, 50% contingency has been added to the ADSS
enhancement estimates. Additionally, it is likely that additional enhancements points will be identified
as Avista defines the detailed functional requirements. Therefore, an additional nine enhancements
(three hard, three medium and three easy) are included in the estimated effort.
2.4.2 Avista Integration
Avista procured COTS and in-house solutions will need to integrate, allowing for automated and timely
communications of data between solutions to successfully participation in EIM. Some estimated
integrations between various COTS solutions may be de-scoped if a single vendor is chosen, while other
integrations will persist regardless of the chosen vendor solutions. For example, Avista EIM meter data
in Oracle Utilities will need to be passed to the EESC Settlement System via an integration between
these two solutions.
During this evaluation, 25 interfaces were identified and estimated (see Table 9). For each interface, an
effort estimate was identified for Requirements, Design, Development and Testing. Due to uncertainty
in the Requirements, COTS vendor selections and the Managed API approach and in accordance with
Avista estimating guidelines, 50% contingency has been added to the interface estimates. Additionally, it
is likely that additional integration points will be identified as Avista defines the detailed functional
requirements and develops a greater understanding of the impacts to existing or deprecated Nucleus
functionality, Real-Time situational awareness and reporting and analysis needs. Therefore, an
additional nine interfaces (three hard, three medium and three easy) are included in the estimated
effort.
2.4.3 Custom Reporting
To properly assess the EIM results and adjust behavior to optimize market results, Avista will need to
update existing reporting capabilities, develop new reports and develop new situational awareness
tools. Some of these functions are likely to be provided by the CAISO reporting applications and some by
the vendor solutions. It is likely that Avista will need to augment those capabilities using PI, Tableau or
other reporting solutions. The preferred location for the source data cannot be established until the
reporting requirements are clearer, but it is likely not Nucleus. This custom reporting would be created
by Avista in-house resources.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 18 of 30
2.4.4 Other In-House Enhancements
Various Avista in-house solutions or existing COTS solutions will need to be enhanced in support of EIM
participation. Some of these enhancements may be adequately covered by existing COTS functionality,
for example meter data validation rules, but have been estimated for Avista internal work for now until
detailed determinations can be made on the scope of such uses.
3 Estimated Costs
This section provides high-level estimated costs for the proposed solution.
3.1 Existing Application Cost Estimates
Effort estimates were prepared for some additional existing application and in-house development.
Effort was broken down by project phase. The summary effort, including contingency, is presented in
Table 5. Additional details are provided in the Requirements Inventory.
Table 5 – Estimated In-House Enhancement Budgetary Cost by Function
# Name Est Effort
(in hours)
53 Track GHG Payments and Open Position 400
55 Process Generation Meter Data: Gather data and perform VEE 1,600
56 Process Generation Meter Data: Apply correction factors 500
57 Process Transmission Meter Data 800
60 Oracle MDM Setup 5,100
70 Oracle MDM Integration 1,700
78 Misc Meter Processor 500
54.3 Nucleus Impacts Placeholder 1,000
Estimated EIM Other In-House Effort 12,000

The approach to VER Forecasting is still to be determined. No cost estimate is included in this report. No
changes to the Demand Forecast were identified.
The proposed solution for MV-90 to be the primary meter data acquisition will require incremental
license and maintenance costs. Though these costs will support both Transmission and Generation
meter data acquisition, these costs are accounted for in line 15 of Table 1 – Summary Budgetary Cost
Estimate for EIM Technology Projects. Oracle MDM license and maintenance pricing is based on a per
meter approach. Because the Oracle MDM is the solution for the AMI project and Avista has already
acquired many licenses, there is no incremental cost anticipated for the small increase in EIM meters.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 19 of 30
Table 6 – Estimated License & Maintenance for Existing Applications
# Solution License
($,000)
Maintenance
($,000)
VER Forecast $0 $0
Demand Forecast $0 $0
MV-90 License & Maintenance $115 $18
Oracle MDM $0 $0
GE EMS $0 $0
Estimated License & Maintenance for Existing Applications $115 $18

3.2 COTS / Vendor Cost Estimates
Table 7 provides budgetary level costs for the identified COTS solutions. Detailed requirements were not
in scope for this project and no vendor bids were solicited. The high-level ranges provided are based on
prior EIM implementations and include license and vendor labor.
The range is quite wide for some of the solutions. Some of the main reasons for the range are:
 The vendor capabilities in some areas vary significantly. For example, for the PRSC Settlement
Solution, a basic solution might be implemented for quite a bit less than one that incorporates a
more robust analytics platform. For a settlements and analytics application, this may represent
good value. In other cases, such as more robust bidding support, this may not provide value to
Avista given the anticipated enhancements to ADSS.
 In some cases, the variation may also be explained partially by the upfront costs versus the
recurring costs and how much ongoing change is covered by the recurring charges – the same
vendor may not be at the top or bottom of both ranges.
 The level of support for configuration / customization during implementation assumed also can
vary quite a bit. Some vendors implementation costs have been scaled to account for estimated
Change Orders.
Avista business and technology team labor is also estimated for each of the solutions. Two methods
were used for the estimate.
The first approach used is a top-down approach using a previous project as a reference.
 The Avista labor required for the recent PCI Settlement System implementation was compared
to the vendor costs. The vendor license, vendor implementation and Avista internal labor costs
were about one third each (after adding in an estimate for some labor which was not coded
correctly in the time tracking system). Since the COTS estimates are inclusive of license and
vendor implementation costs, a ratio of 0.5 was applied to estimate the base Avista labor.
 The PCI Settlement System implementation appears to be a simpler project in terms of the
configuration required than the solutions identified for EIM. Based on the level of configuration
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 20 of 30
required for a given EIM solution, the Avista base labor was scaled up by an additional 10% to
50%, depending on the solution.
 Calculations were performed on the pre-contingency high and low license and implementation
cost estimates.
 This approach includes Business Owner and Project Management effort to the extent that those
individuals recorded time to the project.
 This approach estimates only the project labor and cannot be used for the procurement labor
since the data does not exist.
 As described below in the second approach, the effort for the Security Engineer and Cloud
Architect are deducted from the total. The following deductions are used:
o Security – Project – 1,600 hours
o Architecture – Project – 700 hours
The second approach used is a bottom up approach using a reference project.
 The PRSC Scheduling System project was broken down into 30 tasks. Ten tasks relate to the
Avista and consultant efforts for procurement (e.g. requirements, system selection) and 20 tasks
relate to the Avista and consultant effort for Implementation (e.g. design, testing, process
definition).
 For each task, three roles were identified – a primary driver / doer, SME / workshop participant
and reviewer / approver. For each role, the number of individuals and the anticipated effort was
estimated.
 After a total was calculated for each phase, the other COTS implementations were scaled based
on how difficult they appear to be relative to the PRSC Scheduling System using the same ratios
as in the first method. An exception is the Dispatch Integration to EMS, for which a lower ratio
was used since the effort is much simpler than the PRSC Scheduling effort.
 This approach incorporates both consultant and Avista effort. To isolate the Avista effort, the
estimated consulting share was deducted from the total to determine the Avista share.
 This approach incorporates both Avista Security Engineer and Cloud Architecture effort. Avista
has requested a dedicated line item for these efforts because the plan is to pursue a single /
dedicate point of contact for the EIM Program. As effort estimate was identified for these roles
in the reference PRSC Scheduling System project and scaled to the other projects using the same
ratios described above.
o Security – Procurement – 600 hours; Project – 1,600 hours
o Architecture – Procurement – 600 hours; Project – 700 hours
The ranges in Table 1Table 7 are derived from the first method with the values from the second method
landing about 80% of the way toward the high side of the range.
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 21 of 30
Table 7 – Estimated COTS Budgetary Cost Range by Solution
Solution
Estimated License
& Implementation
(in $,000)
Avista Internal
Labor
(in hours)
Estimated Annual
Recurring Charges
(in $,000)
Gen Outage Management (GOMS) $300 - $450 800 - 2,500 $30 - $100
Trans Outage Management (TOMS) $400 - $550 1,300 - 2,900 $50 - $150
PRSC Bidding & Scheduling System $150 - $600 800 - 2,500 $75 - $175
EESC Scheduling System $400 - $750 1,900 - 3,500 $100 - $175
PRSC Settlement System $125 - $650 1,000 - 2,900 $50 - $175
EESC Settlement System $300 - $575 1,400 - 3,500 $75 - $175
Dispatch Integration to EMS $100 - $200 300 - 400 No Change

Sum of Lows & Sum of Highs $1,775 - $3,725 7,500 - 18,200 $380 - $950
Contingency 20% 20% 20%
Range with Contingency $2,100 - $4,500 9,000 - 21,900 $500 - $1,100

3.3 In-House or Custom Development Cost Estimates
3.3.1 ADSS Cost Estimates
Effort estimates were prepared for each of the ADSS enhancements identified. Effort was broken down
by project phase. The summary effort, including contingency, by function is presented in Table 8. Given
that detailed requirements have not been defined, it is likely that additional enhancements will be
identified as the project progresses. A placeholder for nine additional enhancements – three hard, three
medium and three easy – is included to account for the current uncertainty in the eventual solution.
Additional details are provided in the Requirements Inventory.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 22 of 30
Table 8 – Estimated ADSS Enhancement Budgetary Cost by Function
# Name Est Effort
(in hours)
1.2 CAISO Master File Data Model 500
6.2 Ambient Derate Provision 500
6.4 Outage Synch 600
16.1 Determine Flex Ramp Requirements for Base Schedule Determination 1,000
16.4 Process Flex Ramp Uncertainty 400
16.5 Process BAA Demand Forecast 300
16.6 Compare BAA Demand Forecast to Internal Forecast 400
17.2 Create 4-Part Bids: Data Structure 500
17.3 Create 4-Part Bids: Fossil Cost to CAISO Bid Logic 800
17.4 Create 4-Part Bids: Hydro Cost to CAISO Bid Logic 1,600
17.5 Create 4-Part Bids: CAISO Bid Rule Pre-Checking 600
17.6 Create 4-Part Bids: CAISO Bid Creation UI 600
17.7 Create 4-Part Bids: CAISO Bid Creation Workflow 400
18.2 Create Balancing Stack: Data Structure 500
18.3 Create Balancing Stack: Create Stack Segments 800
18.4 Create Balancing Stack: Order Stack Segments 800
20 Provide Balancing Stack to Transmission Operations 300
23 Generation Auto Balancer 1,000
200s Allocation for Scope Uncertainty 3,000
Estimated EIM ADSS Enhancement Effort 14,400

3.3.2 Integration Cost Estimates
Effort estimates were prepared for each of the integration points agreed for scoping. Effort was broken
down by project phase and was conservatively estimated. The summary effort, including contingency, is
presented in Table 9. Several more potential interfaces were identified during the analysis. Many of
these are anticipated to be included in the “out of the box” vendor solutions.
Given that detailed requirements have not been defined, it is likely that additional interfaces will be
identified as the project progresses. A placeholder for nine additional interfaces – three hard, three
medium and three easy – is included to account for the current uncertainty in the eventual solution.
Additional details are provided in the Requirements Inventory.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 23 of 30
Table 9 – Estimated Integration Budgetary Cost by Interface
# Name To <> From Est Effort
(in hours)
3.2 Derate Transmission EMS >> TOMS 600
5.2 Suggest Generation Outages EMS >> GOMS 500
6.3 Outage Sync GOMS >> ADSS 500
10 Obtain NPR Base Schedules ADSS >> EESC Sched System 500
16.2 Obtain Flex Ramp Uncertainty PRSC Sched System >> ADSS 400
16.3 Obtain BAA Demand Forecast PRSC Sched System >> ADSS 500
21.1 Retrieve RT RS Results EESC Sched System >> PRSC Sched System 400
25 Receive Balancing Stack ADSS >> EESC Sched System 500
34 Tag Snapshot for TC Allocations EESC Sched System >> EESC Settle System 500
35 Receive Gen and ETSR Dispatches CAISO ADS >> EMS 100
52 Import GHG Settlement PRSC Settlement >> Nucleus 400
58 Export Generation SQMD MV-90 >> Oracle Utilities MDM 400
59 Export Transmission SQMD PI >> Oracle Utilities MDM 400
61 Submit SQMD to CAISO Oracle Utilities MDM >> CAISO MRI-S 500
64 Receive PR Invoice Amounts PRSC Settle System >> Oracle Financials 100
65 Receive EE Invoice Amounts EESC Settle System >> Oracle Financials 100
69 Obtain PR Base Schedules ADSS >> PRSC Sched System 500
71 Send 4-Part Bids ADSS >> PRSC Sched System 600
72 Send Load Forecast ADSS >> EESC Sched System 500
75 Telemetry for VER EMS or PI >> VER Forecast 400
76 VER Forecast Alternate Path VER Forecast >> EESC Sched System 400
79 Hourly Checkout Value Nucleus >> Oracle MDM 400
200s Allocation for Scope Uncertainty Overall implementation work 3,300
Estimated EIM Integration Effort 12,300
3.3.3 Custom Reporting
A placeholder budget is included to account for the development of new reports and new situational
awareness tools to assess the EIM results and adjust behavior to optimize market results.
Table 10 – Estimated Custom Reporting Budgetary Cost Placeholder
# Name Est Effort
(in hours)
54.1 Key Performance Indicator Placeholder 1,000
54.2 Situational Awareness Placeholder 1,000
Estimated EIM Other In-House Effort 2,000
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 24 of 30
4 Proposed High-Level Schedule
Based on the number of solutions which need to be implemented, Avista’s resource availability,
procurements timelines and the EIM implementation timeline, a preliminary high-level schedule has
been developed to support technology prioritization discussions which is shown as Figure 1.
Figure 1 – High Level EIM Schedule

5 Conclusion
Several Avista in-house systems were evaluated for possible enhancements and integrations as
alternative EIM solutions to vendor systems. Specifically, the existing functionality of Nucleus and ADSS
were considered for EIM solutions.
Based on the required EIM functionality, complexity of that functionality and maintenance required for
on-going EIM changes as the market is enhanced, Nucleus is not an option for the core EIM solutions.
Nucleus will be enhanced, as identified in this report, to support EIM impacts to certain Energy Trading
and Risk Management (ETRM) and other existing functions.
Based on the current EIM assessment efforts, and known requirements, it’s anticipated that the new
EIM solutions will have some overlap with existing Nucleus functions. Identifying the downstream
impacts of retiring Nucleus functionality was not included in this assessment, and will require additional
investigation during COTS products are reviewed and implemented. Avista may also choose to include
optional functionality in the RFP for the EIM solutions to evaluate if the new tools can replace existing
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 25 of 30
Nucleus functions. Analysis of EIM impacts on existing Nucleus functions should be in-scope for the
Requirements gathering process.
The project team determined that the existing functionality of ADSS and custom nature of hydro
resource optimization made ADSS a prime candidate system for creating generation bids and schedules
rather than vendor solutions, since the hydro optimization would be a custom vendor implementation
largely duplicating existing ADSS functions.
Several of Avista’s planned commercial software procurement are best leveraged for EIM solutions in
addition to their original scope. Specifically, Avista’s planned GOMS and TOMS vendor solutions should
be aligned with EIM requirements to streamline their implementation and subsequent use for EIM
participation.

Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 26 of 30
6 Addendum – Supplemental Cost Analysis
Following the initial Technology Assessment, Avista requested the analysis be broadened to include Very
Rough Order of Magnitude (VROM) estimates for a number of other efforts and costs which will be
incurred either for EIM or contemporaneous with EIM. This Addendum attempts to summarize the
additional effort and cost estimates, the source of the estimate and the level of confidence in the
estimated value.
6.1 Planning, Requirement & Procurement Phase
Avista anticipates using 2019 to further plan the project and begin the procurement process for the
required systems in anticipation of implementation work beginning in 2020.
To support this effort, additional consulting resources are anticipated. As a placeholder, budget for one
resource from April 1, 2019 through December 31, 2019 is included.
Avista will also participate in the planning and procurement process. The bottom up approach to
estimating the PRSC Scheduling System effort described in Section 3.2 was used to estimate Avista’s
labor. Using the 10 tasks related to procurement (e.g. requirements, system selection), an initial effort
estimate was determined. The anticipated consulting effort applicable to system selection was deducted
from the total to derive an Avista-specific estimate.
This estimate assumes that a single procurement and contracting specialist is assigned from Avista to
support all the EIM related procurement since there will be a number of similarities across these
procurement efforts. Further, it was assumed that all vendors would have existing Master Service
Agreements (MSAs) with Avista. If new MSAs need to be negotiated, additional effort will be required.
These costs are summarized on line 10 of Table 1 – Summary Budgetary Cost Estimate for EIM
Technology Projects. Please see Avista – Integration EIM Cost Summary tabs “1a, 10. Vendor Software”
and “9b, 10. Consulting” for additional details.
6.2 Generation & Network Modeling
Separate from the Technology Assessment, an evaluation of updates and improvements to the Full
Network Model (FNM) required for EIM participation was conducted. The analysis also included
implementation of State Estimation (SE) and Real-Time Contingency Analysis (RTCA) and hardware to
support these functions. Only the FNM upgrades are EIM-related. The other functions are necessary due
to the RC Transition and other Avista objectives. These costs are summarized on line 11 of Table 1 –
Summary Budgetary Cost Estimate for EIM Technology Projects. Please see Avista – Integration EIM Cost
Summary tab “11. FNM” for additional details.
Implementation of EIM will also require generation performance and cost modeling. Avista has begun
this effort through the supplemental EIM Planning project by beginning to develop a Resource
Participation Strategy. For EIM, many aspects of the generation resources will need to be modeled for
the CAISO Master File. Additionally, several kinds of costs will need to be determined or refined (Heat
Rates, Maintenance Costs). A placeholder budget is included for this effort. These costs are summarized
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 27 of 30
on line 12 of Table 1 – Summary Budgetary Cost Estimate for EIM Technology Projects. Please see Avista
– Integration EIM Cost Summary tab “12. Gen Cost Modeling” for additional details.
A major topic in EIM is the need to provide Settlement Quality Meter Data (SQMD). A separate project
was undertaken to assess the current state of Avista's Generation and Intertie Metering equipment
including Current Transformers (CT), Potential Transformers (PT) and Meters as well as the compliance
with the EIM requirements. For the Generation meters, a separate modernization project has already
been authorized. However, based on the assumptions in that business case, current progress and the
EIM Requirements, GPSS has provided an updated estimate for generation metering as part of this
effort. Additionally, Meter swaps are anticipated at several intertie locations. These costs are
summarized on line 15 and 19 of Table 1 – Summary Budgetary Cost Estimate for EIM Technology
Projects. Please see Avista – Integration EIM Cost Summary tabs “15. Transmission Meters” and “19, 20.
Gen Controls and Meters” for additional details.
In the EIM, it is important to maximize the resources which can be offered to the Market and to be able
to follow 5-minute dispatch instructions. Avista’s current plant communications and infrastructure (PLC,
RTU, SCADA) may not support the requirements at some locations. A placeholder budget provided by
GPSS is included for these enhancements. These costs are summarized on line 20 of Table 1 – Summary
Budgetary Cost Estimate for EIM Technology Projects. Please see Avista – Integration EIM Cost Summary
tab “19, 20. Gen Controls and Meters” for additional details.
6.3 Network & IT Infrastructure for Applications
With the current direction of the Technology Assessment leveraging cloud-based deployments, network
availability and performance will be key to the performance of the COTS applications. Additionally,
connectivity to the CAISO is critical. Avista’s IT team’s estimated costs to support enhanced connectivity
for the COTS solutions, communications with CAISO and an allowance for MV-90 capabilities at the Back
Up Control Center (BUCC) in case MV90 is on the SCADA network. If MV90 is on the ET network, the
backup will be in San Jose. AWS/Azure estimates were used for the COTS solutions; Avista already has a
dedicated network connection to OATI’s data center. These costs are divided into the following
categories:
 Incremental Internet Connectivity and Dedicated Circuits – Additional networking for generation
control, connectivity with CAISO and connectivity to the Azure and AWS clouds as well as BUCC
improvements were budgeted. Budgetary costs for this upgrade were provided by Avista.
 ADSS Hardware – The current EIM vision includes ADSS becoming a central system in the hourly
schedule and bid creation process and upgrading the Hardware at the San Jose location is
recommended. Budgetary costs for this upgrade were provided by Avista.
 Dedicated Project Resources – A dedicated Security Engineer and a dedicated Cloud Architect
were included by Avista.
 Miscellaneous Costs – A small placeholder for additional firewalls, integration services and
unidentified software were included by Avista.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 28 of 30
These costs are summarized on line 6, 7 and 8 of Table 1 – Summary Budgetary Cost Estimate for EIM
Technology Projects. Please see Avista – Integration EIM Cost Summary tabs “6-7. IT VROMs” and “8, 16.
Network VROMs”.
6.4 Generation and Intertie Equipment Upgrades & Communications
EIM requires revenue metering at both generation and intertie locations. At this time, the preferred
approach to retrieving the meter data for Avista owned meters at generation and intertie locations is to
poll the revenue meter using MV-90 using IP. To date, 52 locations have been identified as potentially
requiring communications upgrades.
 About half of the intertie locations currently use dial-up connections to communicate meter
data to Mission. Continued use of the existing dial-up modems for certain locations (those with
a Bulk Electric System (BES) Low Impact designation, as opposed to no BES impact designation)
require that equipment to be isolated from control equipment under the new NERC CIP
Standard 003-6.
 The current Avista Standard is to replace dial-up modems with T1 connections. If T1 connections
are used, High Voltage Protection (HVP) may be required. If so, it would substantially increase
the cost. A site by site assessment is needed to determine HPV requirements. In some locations,
cellular modems might be feasible. This option has not been assessed.
 Some locations, including most of the generation locations, may not have a BES impact. If there
is no BES impact, dial-up connections may still be feasible.
 Using a “backup meter” which is isolated from SCADA connectivity might be feasible. BPA has
used this approach in some cases.
 For EIM it may be possible to use the existing SCADA data combined with the existing BAA
hourly check-out values to calculate a settlement quality actual interchange value. This would
not be possible for the generation locations. Idaho Power Company (IPC) has used this approach
in some cases. However, significant data losses are possible with this approach and may not be
acceptable.
 Avista may decide upgrading communications capabilities is advisable as part of a general
modernization effort regardless of EIM requirements.
A site-by-site analysis is required to define the preferred approach. At this time, a placeholder VROM is
included based on the following:
 Network and Communications for Generation Controls and Metering – Site by site analysis of
the 28 identified generation locations has not been completed and the cost estimates in this
report are approximates based on the share of locations that is likely to need a T1 connection
(10) and the number of sites likely to require HVP for that connection (8). Other approaches are
under consideration (e.g. cellular, separate circuits for dial-up capability). Aside from EIM
requirements, CIP 3-6 standard will impose some communication requirements, which may
indicate a T1 connection is the best option. Until Avista can complete a site by site analysis, or
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 29 of 30
decide to fund all upgrades to a corporate standard to achieve O&M savings, these costs
estimates should be interpreted cautiously.
 Network & Communications for Transmission Metering – Site by site analysis of the 24 identified
transmission locations has not been completed and the cost estimates in this report are
approximates based on the share of locations that is likely to need a T1 connection (16) and the
number of sites likely to require HVP for that connection (10). A higher proportion of
Transmission locations was anticipated to require T1 and HPV than generation due to the higher
likelihood that the locations are BES locations. Until Avista can complete a site by site analysis,
or decide to fund all upgrades to a corporate standard to achieve O&M savings, these costs
estimates should be interpreted cautiously.
These costs are summarized on line 16 of Table 1 – Summary Budgetary Cost Estimate for EIM
Technology Projects. Please see Avista – Integration EIM Cost Summary tab “8, 16. Network VROMs”.
6.5 Project Implementation
The EIM Program will also require daily management and coordination, strategy definitions, extensive
training and Organizational Change Management (OCM). New sections of the Avista Open Access
Transmission Tariff (OATT) must be filed with FERC and a Market Base Rate (MBR) study performed.
Consulting resources are anticipated to provide Program Management support and Subject Matter
Expertise across the project. Several new permanent FTEs will also be added during the project and
become part of ongoing operations.
These costs are summarized on line 9, 13, 14 and 18 of Table 1 – Summary Budgetary Cost Estimate for
EIM Technology Projects. Please see Avista – Integration EIM Cost Summary tabs “9a. Prog Management
and Leader” and “9b, 10. Consulting” and “13. OATT and MBR” and “14. Training and OCM” and “18.
CAISO Fees”.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 4, Page 30 of 30
PREPARED FOR:
METERING
ASSESSMENT
S R
PROPRIETARY AND
CONFIDENTIAL
DECEMBER 2018
AUTHORS:
BRIAN HOLMES AND ZACH
GILL SANFORD
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 1 of 34
Table of Contents
1 Executive Summary ............................................................................................................................... 3
2 Requirements and Considerations ........................................................................................................ 5
2.1 CAISO Metering Requirements ..................................................................................................... 5
2.1.1 Metered Entity Registration .................................................................................................. 5
2.1.2 Applicable Metering Requirements ...................................................................................... 5
2.1.3 Generation Registration and Size Threshold ........................................................................ 5
2.1.4 SQMD Plan ............................................................................................................................ 6
2.1.5 Equipment Rating Data ......................................................................................................... 7
2.1.6 Equipment Burden Ratings ................................................................................................... 7
2.1.7 Meter Memory Requirements .............................................................................................. 8
2.1.8 Metering Granularity ............................................................................................................ 8
2.1.9 Meter Submission at Resource ID Level ................................................................................ 9
2.1.10 Pseudo-Tie Meters and Load Meter Calculation ................................................................ 13
2.1.11 Meter Channels ................................................................................................................... 14
2.2 Key Metering Considerations ...................................................................................................... 15
2.2.1 Expected Point of Measurement and Compensation Factors ............................................ 15
2.2.2 Metering Granularity Impact .............................................................................................. 17
2.2.3 Insufficient Accuracy and Correction Factors ..................................................................... 17
2.2.4 Insufficient Granularity of non-Avista owned Interchange Meters .................................... 18
2.2.5 Metering of Jointly-Owned Generation .............................................................................. 18
3 Metering Approach ............................................................................................................................. 19
3.1 Generation, Avista-Owned .......................................................................................................... 19
3.2 Generation, 3rd Party-Owned .................................................................................................... 23
3.3 Interchange, Avista-Owned ........................................................................................................ 26
3.4 Interchange, 3rd Party-Owned ................................................................................................... 29
4 Estimated Costs ................................................................................................................................... 32
4.1 Avista Participating Resources .................................................................................................... 32
4.2 Other Metering & Network Costs ............................................................................................... 33

Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 2 of 34
1 Executive Summary
Avista requested Utilicast perform an assessment of meters and associated equipment within the scope
of California Independent System Operator (CAISO) requirements for Energy Imbalance Market (EIM)
participation and adherence to those requirements. Initially, Avista was interested in assessing only the
meters at its owned generation facilities. During the course of the project, Avista requested the original
scope of assessed meters be expanded to include all generation and interchange meters related to EIM
participation.
This project focused on inventorying the characteristics and configurations of existing meters, current
transformers (CTs), potential transformers (PTs), and associated communications at generation and
interchange sites in the Avista Balancing Authority Area (BAA). Avista made a business decision during
this assessment to evaluate the equipment relative to the CAISO metering requirements rather than the
various Local Regulatory Authority (LRA) metering requirements. Therefore, these equipment
characteristics and configurations were compared to the CAISO metering requirements stated in the
current version of the CAISO Metering Business Practice Manual1 (BPM) at the time of the project. Any
gaps in adherence to these requirements and unknown equipment ratings are identified in this report
along with proposed steps to address these gaps and determine unknowns through metering projects,
equipment tests, or requests to CAISO for requirement exemptions.
A high-level scope and cost estimate for metering projects, generation controls, and meter data
communications were produced by Avista staff based on input from Utilicast. The budgetary level cost
estimate for EIM related metering projects is presented in Table 1.
Table 1: Summary Budgetary Cost Estimate for EIM Metering Projects
Cost Estimate Category Project
(in $,000)
Post-Project Recurring
Services and Avista Labor
(in $,000)
Generation Meter Projects $3,000 - $4,500
Generation Control Projects $1,200 - $1,400
Transmission Meter Projects & Data
Collection $340 $18
Network Improvements for Metering $210 - $2,000 $15
Total $5,490 – 7,280 $33

Costs presented in this report are further described in the EIM Technology Assessment report delivered
by Utilicast in a separate scope of work.
Avista has already budgeted $3.4M for the expected cost of generation meter projects in a separate
Business Case and the costs in this report are not additive. By contrast, Avista has not yet budgeted for
1 CAISO Metering Business Practice Manual Version 18, Revised May 24, 2018
https://bpmcm.caiso.com/BPM%20Document%20Library/Metering/BPM%20for%20Metering_v18_Clean.docx
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 3 of 34
the expected cost of interchange meter projects, plant controller upgrades or network enhancements,
so those efforts represent new costs.

Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 4 of 34
2 Requirements and Considerations
EIM participation will require Avista to certify to the accuracy of installed metering equipment at
generation and interchange sites in its BAA, with the Avista EIM metering program subject to annual
self-audits. Avista may establish the procedures of its annual self-audit plan at its own discretion,
although CAISO must approve the audit plan. Additionally, CAISO retains the right to audit the Avista
EIM metering program, including its self-audit records.
The CAISO metering requirements are stated in the CAISO Metering BPM. While many requirements are
identified in this report, it is not intended to be exhaustive in listing all applicable requirements. In
addition to these stated requirements, there are several considerations for metering configuration that
are key to Avista’s successful EIM participation, which are described in this section.
2.1 CAISO Metering Requirements
2.1.1 Metered Entity Registration
CAISO provides the option for EIM Entities to choose between two metered entity registration types,
ISO Metered Entity (ISOME) and Scheduling Coordinator Metered Entity (SCME). Utilicast recommends
Avista register as a SCME, as this allows Avista to continue engineering, installing, testing, and gathering
data for meters in scope for EIM participation. Selecting the ISOME option would relinquish these roles
to CAISO-certified personnel and require Avista to pay for the metering services and provide site access
to these external personnel. It is also notable that all EIM Entities to date have registered as SCMEs, to
Utilicast’s knowledge. During the metering assessment, Avista indicated its intent to register as a SCME,
so the metering assessment was performed with the assumption that Avista will be a SCME.
As part of this SCME registration, Avista will need to execute a registration agreement, requiring the
Avista signee to attest to the accuracy of its submitted Settlement Quality Meter Data (SQMD) Plans.
2.1.2 Applicable Metering Requirements
CAISO allows EIM SCMEs to choose between adhering to CAISO metering requirements and LRA
metering requirements. Avista’s applicable LRAs are state utility commissions. Avista made a business
decision during this assessment to evaluate the equipment relative to the CAISO metering requirements.
2.1.3 Generation Registration and Size Threshold
CAISO allows EIM participants some discretion on which generation capacity to be registered in the EIM.
Very small resources may be excluded from all EIM involvement, including resource registration, the Full
Network Model (FNM), base schedules, and meter submission. CAISO requires this threshold be set
between 1 MW and 10 MWs.
During the metering assessment, Avista decided to set the minimum capacity threshold for resource
registration at 3 MW. This threshold was chosen since it corresponds to the specified threshold for
requiring Supervisory Control And Data Acquisition (SCADA) in the Avista Small Generator
Interconnection Procedures (SGIP) and the excluded resources were deemed to have negligible impact
on Avista operations since, at the time of this assessment, their total capacity is less than 7 MW.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 5 of 34
The exclusion of these generators from resource registration will be appear as negative load in the
Avista load forecast and real-time operations for the EIM. Therefore, Avista should subtract these
resources’ historical output from the Avista historical load actuals submitted to CAISO for its load
forecast engine to ensure greater forecast accuracy.
All generation within the Avista BAA above the 3 MW capacity threshold must be registered with
submitted and approved SQMD Plans, regardless of ownership and EIM participation.
2.1.4 SQMD Plan
To join EIM, the Entity must complete a SQMD Plan and receive CAISO approval for each registered
Resource ID. Each Participating Resource (PR), Non-Participating Resource (NPR), and scheduling tie will
be assigned a Resource ID, with scheduling ties being comprised of physical interchange points
aggregated to Avista-defined locations. The Avista-completed SQMD Plans2 will include information such
as meter granularity, meter and instrumentation accuracy, loss compensation, meter audit and test
plans, calculations, single line meter diagrams, and descriptions of data collection and Validation,
Editing, and Estimating (VEE). The descriptions of data collection do not require detailed diagrams of the
communication pathway, but should include a description of communication networks, meter data
head-end and Meter Data Management (MDM) systems leading to daily SQMD data submission to
CAISO systems for settlement.
As part of the SQMD plan submission, Avista will need to provide a Single Line Diagram (SLD) that shows
the station configuration and specifically the locations of all relevant transformers, meters and station
service. The SLD must either be stamped by a Professional Engineer (PE) or, if modifications have been
made since the original construction, an Avista PE may attest to the accuracy of the SLDs.
As part of the EIM implementation project, Avista should prioritize the early submission of the first
SQMD Plan to allow for sufficient review and revision time between CAISO and Avista staff, which may
take several months of revision and discussion to finalize3. Furthermore, CAISO staff may request
clarification or modification of the plans in a manner that could impact all SQMD Plans and the
underlying EIM meter program, requiring substantial project work to address. Once one SQMD Plan has
been approved, much of the content may be utilized for all other plans, as the description of the audit
plan, data collection, and VEE should be common to the majority of meters, easing the submission of
subsequent plans. Any expected exemptions should also be discussed early in the implementation
project to ensure acceptance or a change in project work as necessary.
2 CAISO’s tutorial of SQMD Plan template is posted at
https://www.caiso.com/Documents/SQMDResourceTemplateTutorial.pdf
The SQMD Plan template is posted at https://www.caiso.com/Documents/SQMDPlanTemplate.docx
3 To begin the SQMD process, Avista must obtain a New Resource Implementation (NRI) number. To obtain this
number, Avista must have an assigned Resource IDs. However, EIM Entities DO NOT have to follow the full NRI
process if they are SCMEs.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 6 of 34
2.1.5 Equipment Rating Data
The equipment ratings specified in the CAISO Metering BPM, such as accuracy and burden ratings, must
be determined by Avista for EIM participation. The CAISO Metering BPM rating requirements are
specified by accuracy and burden classes, as defined in the IEEE C57.13 Standard Requirements for
Instrument Transformers. If the equipment ratings for any meters, CTs, or PTs used for EIM metering are
unable to be found, then Avista must either replace the equipment having unknown attributes, or attest
to the likely attributes based on known information, such as other installations of similar equipment
having known attributes, test data, or other sources of engineering judgement.
Avista should undertake all reasonable measures to establish the accuracy of the equipment. At one
time CAISO was aggressive in requiring nameplate information for all equipment. However, in more
recent EIM implementations CAISO has been somewhat more willing to accept management attestation
in a sworn affidavit that states the assumed accuracy “to the best of my knowledge” with a duty to
update if new information becomes available. The assessment of validated equipment ratings and
equipment lacking the necessary rating data are provided in section 3.
The core requirements for metering equipment are:
 Meter
o 0.2 Accuracy class
o 60 days storage for meter data
o 5-minute interval granularity for Participating Resources and Interchange
 CT
o +/- 0.3% accuracy at burden of 0.1 - 1.8 ohms, 10% - 100% rated current, or
o Optional +/- 0.15% accuracy at burden of 0.1 - 1.8 ohms, 5% - 100% rated current
 PT
o +/- 0.3% accuracy through burden rating ZZ (400 Volt-Amperes secondary at 0.85 power
factor) at 90% through 110% of nominal voltage, or
o Optional +/- 0.15% accuracy through burden rating Y (75 Volt-Amperes secondary at
0.85 power factor) at 90% through 110% of nominal voltage
Avista may use equipment which does not meet the requirements but doing so will require Avista to
calculate a “correction factor” to apply to the meter data. The correction factor does not increase
accuracy – it is a penalty which reduces the observed readings to ensure that the metered output is not
overstated. See section 2.2.3 for more detail on correction factors.
2.1.6 Equipment Burden Ratings
Avista has identified several installed CTs and PTs with burden ratings less than the CAISO requirements
of B1.8 and ZZ, respectively. However, this equipment may have sufficiently low burden connected to
their circuits to retain their rated accuracy, pending further validation by Avista engineers. While the
CAISO-stated burden ratings may exceed these installations, Avista should be able to utilize this
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 7 of 34
equipment with low connected burden in accordance with item b of the following excerpt from
Attachment B Section A6 of the CAISO Metering BPM:
Where the connected burden of a metering circuit exceeds the burden rating of a CT or [PT] or if an
existing instrument transformer does not meet the minimum CAISO accuracy requirements, then
one of the actions listed below must be taken:
a. Replace the instrument transformer(s) with higher burden rated revenue class units; or
b. Reduce the burden on the circuit to comply with the name plate of existing instrument
transformer(s); or
c. Apply correction factors to the meter to adjust the meter’s registration to compensate for
inaccuracies.
In accordance with item b of the above excerpt, if Avista can document in the SQMD plan that the
connected burden of these CTs and PTs and demonstrate it is less than the equipment burden rating,
then the installed equipment can be utilized without replacement or correction factors. See section 3 for
lists of equipment with lower burden ratings that require validation of the connected burden.
2.1.7 Meter Memory Requirements
Avista has identified several installed meters with memory storage less than the CAISO requirement of
60 days storage. Avista should consider either replacing these meters, upgrading their memory, or
maximizing the use of the existing memory and applying for an exemption from the CAISO requirement.
In the latter case, Avista has identified the increased storage potential if the number of stored channels,
see section 2.1.11 for detail on meter channels, are minimized to meet the CAISO requirements and
dispense with any additional data. For example, if an interchange meter records the load at a substation,
then only the single channel reading the import of energy for load need be recorded for EIM purposes.
If Avista chooses to retain these meters with insufficient memory, an exemption should be submitted
for CAISO’s review early in the implementation project, to ensure sufficient time to adjust project work
if CAISO rejects the request. The exemption request should describe the rationale for the decision and
proposed mitigation plan. For example, Avista could describe its plan to replace these meters as
associated site work occurs, and in the meantime, a process for sending field technicians for a local
meter read in a timely fashion prior to reaching the memory limitation, should communications fail to
read the meter.
2.1.8 Metering Granularity
Generation registered as a Participating Resource (PR) and BAA Interchange metering must be
submitted to CAISO at a 5-minute granularity, while Non-Participating Resource (NPR) metering may be
recorded at a 5-minute, 15-minute, or 60-minute granularity. BAA load metering, termed EIM Load
Aggregation Point (ELAP) load, is determined as the net summation of all generation and interchange
meter values and cannot be submitted to CAISO at a more granular level than the least granular meter
data. For example, if all PR, NPR, and interchange meters record at 5-minute granularity except one NPR
meter that records at 15-minute granularity, then the CAISO would require the ELAP meter be
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 8 of 34
submitted at 15-minute granularity. See section 2.2.2 for a description of meter granularity impact on
EIM participation.
In the EIM, the CAISO deems the Merchant largely responsible for PRs and the Transmission Operator,
termed the EIM Entity, responsible for NPRs. One possible generation Resource registration strategy
that simplifies scheduling and analysis is to register all Avista owned generation as Participating
Resources. To do so would require Avista to satisfy the granularity requirements of Participating
Resources for all generation.
In some cases, the CAISO has permitted profiling of a Revenue Quality value at a greater granularity to
be profiled to a 5-minute granularity using other data (e.g. SCADA) but this is not typically permitted.
The only cases we know of involve resources which have some other pre-existing revenue quality
checkout process, such as Mid-Columbia (Mid-C) and Colstrip.
2.1.9 Meter Submission at Resource ID Level
CAISO requires meter data to be submitted at the registered Resource ID level.
To the extent Avista records multiple meters for one Resource ID, these values will need to be netted to
a single meter data set for submission to CAISO. For example, if two physical generators are metered
individually at their gross output, have a separately metered station service onsite, and are registered as
a single Resource ID, then all three meters will be combined into a single meter value recording the two
generators’ output net of station service.4
Following are three examples to illustrate options for a station with a configuration similar to Noxon.
These simplified examples and single line drawings are intended to provide an overview of the choices
and tradeoffs and are not ready for SQMD submission. These examples assume that all equipment
accuracy requirements are satisfied. If some of the equipment is not revenue quality, then the
correction factors would also need to be applied.
If Noxon were to participate as an aggregate resource and utilize its existing unit-level metering, Avista
would net the five generation meters and two station service meters, as depicted in Figure 1 with
metered locations depicted by the letter “m” and described in the following equations5:
Noxon aggregate resource meter = G1 + G2 + G3 + G4 + G5 – SS1 – SS2
Where G# is the meter for unit # and SS# is the meter for station service #

4 Netting of station service is permitted but only certain categories of use which are deemed “required” for the
operation of the station are approved for this treatment (e.g. pumps, excitation). Other categories of use that
might be tied to a generator (e.g. fish hatcheries at a hydro facility) do not qualify for station service netting and
would need to be excluded from the netting, unless the generator is classified as behind-the-meter generation in
its interconnection agreement. Onsite load for behind-the-meter generation may be netted from generation.
5 Avista may also need to calculate station and transformer loss factors to “compensate” the observed values to
simulate that “the meter” is on the high-side of “the GSU”. This detail is not shown in these simplified examples.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 9 of 34
More specifically, the channels would be netted as follows (see section 2.1.11 for detail on meter
channels):
Noxon aggregate resource meter ch_4 = G1_ch_4 + G2_ch_4 + G3_ch_4 + G4_ch_4 + G5_ch_4
– G1_ch_1 – G2_ch_1 – G3_ch_1 – G4_ch_1 – G5_ch_1 – SS1_ch_1 – SS2_ch_1
Noxon aggregate resource meter ch_1 = 0
Where ch_# is the submitted channel number
By contrast, if Noxon were to participate as an aggregate resource and utilize high-side metering
recording the output at each of its three Generator Step-Up transformers (GSUs) net of station service
by virtue of the metering location, then Avista would net the three high-side meters, as depicted in
Figure 2 and described in the following equations:
Noxon aggregate resource meter ch_4 = GSU_A_ch_4 + GSU_B_ch_4 + GSU_C_ch_4
– GSU_A_ch_1 – GSU_B_ch_1 – GSU_C_ch_1
Noxon aggregate resource meter ch_1 = 0
m
Station
Service
m
m
G1
mmmm
m
G2
GSU A
m
G3
mmmm
m
G4
GSU B
To Switchyard To Switchyard
mmmm
m
G5
GSU C
To Switchyard
Figure 1 : Noxon Aggregate Registration with Unit Level Metering
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 10 of 34
Station
ServiceG1
mmmm
G2
GSU A
G3
mmmm
G4
GSU B
To Switchyard To Switchyard
mmmm
G5
GSU C
To Switchyard
m m m

Figure 2: Noxon Aggregate Registration with High Side Metering
A revenue quality meter provides data to the VEE process. Once VEE has been performed, the data is
deemed settlement quality, will be submitted to CAISO for settlement, and is subject to an approved
SQMD plan. Other non-revenue quality meter reads may be used to allocate or distribute settlement
quality data but are not provided to CAISO directly. If Avista records a single revenue quality meter for
multiple Resource IDs, the data set will need to be allocated to the Resource ID level according to a
documented process that is approved by CAISO. Such an allocation process could be based on non-
revenue quality meter data recording at the unit level so long as the submitted meter data itself is
collected from the single revenue quality meter. For example, if Noxon participates as individual units
and the metering of units 1 and 2 is at the high side of GSU A, while each unit has an individual non-
revenue quality meter recording gross output, as depicted in Figure 3 and described in the example
equations below:
GSU A meter = 9.5 MWh; G1 meter = 4 MWh; G2 meter = 6 MWh, then
G1 “meter” allocation = GSU_A * G1 / (G1 + G2) = 9.5 * 4 / (4 + 6) = 3.8 MWh
G2 “meter” allocation = GSU_A * G2 / (G1 + G2) = 9.5 * 6 / (4 + 6) = 5.7 MWh
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 11 of 34
Station
Service
m
G1
mmmm
m
G2
GSU A
To Switchyard
m

Figure 3: Noxon Individual Unit Registration with High Side Metering
Figure 4 depicts the decision tree for the metering configuration of a resource site, considering high-side
versus low-side metering and aggregate versus unit level resource registration using Noxon as an
example. Refer to the Noxon metering examples above for more detail on the metering configurations
for various resource registrations. Refer to section 2.2.1 for detail on compensation factors accounting
GSU losses for low-side metering installations.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 12 of 34
Participating
Resource Site
High-Side
Metering
Low-Side
Metering
Aggregate
Resource
Registration
Unit Level
Resource
Registration
Aggregate
Resource
Registration
Unit Level
Resource
Registration
Install and Sum
High-Side Metering
Install Unit Level Metering as needed
(non-revenue) and sub-allocate High-
Side Meter values utilizing Unit Level
Meters for proportional allocation
Sum Low-Side
Metering as needed
and Compensate
for GSU Losses
Install Unit Level Metering as needed,
Compensate for GSU Losses, and
allocate SS load to Unit-Level Meter
Data to submit Net Production

Figure 4: Metering Configuration Decision Tree
Similar to the requirement to submit generation meter data by Resource ID, Avista interchange
metering must be aggregated to a scheduling tie. These scheduling ties will be registered with CAISO as
a System Resource ID, typically corresponding to Avista’s OASIS posted paths6. Careful review of these
scheduling tie aggregations should be performed to ensure the net of submitted interchange metering
for EIM includes all Avista points of interchange and equals Net Actual Interchange energy accounting
records.
2.1.10 Pseudo-Tie Meters and Load Meter Calculation
Pseudo-tie generators modeled in the FNM will be registered as type Gen, whereas any generators not
modeled, typically those electrically distant from the CAISO FNM footprint, will be registered as type Tie
Gen (TG). Currently, EIM participant shares of Colstrip are registered as TGs since the CAISO FNM does
not extend into Eastern Montana. However, with the expected EIM participation of NorthWestern
6 Avista’s OASIS posted paths, Effective January 1, 2018 are depicted in
https://www.oasis.oati.com/woa/docs/AVAT/AVATdocs/AVA_OASIS_POR_POD_Effective_01-01-18.pdf
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 13 of 34
Energy, the Montana footprint will be added to the FNM and Colstrip likely re-registered as type Gen.
Thus, it is likely that all Avista BAA generators will be registered as type Gen.
Any pseudo-tie generators registered as type Gen, as
opposed to type TG, require a corresponding
scheduling tie registration to submit a counterflow to
the physical interchange meter. Pseudo-tie generation
meters will be submitted twice, once for the generator
resource ID and again as a counterflow for the
scheduling tie ID. As depicted in Figure 5, internal
generation and pseudo-tie generation will be metered
and the generation production values submitted to
CAISO. Additionally, pseudo-tie meters function as
interchange meters, measuring the generation
production as a BAA export, as the generation
physically wheels through external BAAs before
returning to the Avista BAA as a metered import at the
contiguous boundary.
For example, given CAISO’s definition of BAA load as
generation minus exports plus imports, a pseudo-tie
generator value of 5 MW is accounted in load as 5
MW generation plus 5 MW metered import at the contiguous boundary minus 5 MW pseudo-tie meter
export (counterflow), equaling 5 MW once this netting in the load calculation occurs. CAISO recalculates
BAA load independent of the EIM Entity load meter submission, and thus requires the submission of
pseudo-tie meters as both generation and interchange to net correctly.
Finally, Avista BAA load must be calculated as the net of all generation and interchange metering, equal
to generation plus imports minus exports. CAISO defines this BAA load meter as the ELAP and requires
its submission in two forms, once as the net of generation and interchange without any loss factor
applied and again as the net of generation and interchange divided by the number one plus a
transmission system loss factor, likely defined as the 3% loss factor stated in Avista’s OATT7. Existing EIM
participants have also utilized their respective OATT-stated loss factor for this calculation.
2.1.11 Meter Channels
CAISO does not require the submission of Volt Ampere Reactive (VARs) for EIM participation, only active
power, measured as kilowatt hours (kWh) or megawatt hours (MWh). Meters record these values on
separate registers, termed channels, to distinguish between produced and consumed energy. These
values may be recorded on any meter channel, but must be submitted on the following meter channels:
 Channel 1 for consumed or exported active power
7 Avista Open Access Transmission Tariff (OATT), Effective August 1, 2018, sections 15.7 and 28.5
https://www.oasis.oati.com/woa/docs/AVAT/AVATdocs/OATT_Effective_8-1-2018.pdf
Figure 5: Pseudo-Tie Meter
Station Service Load
Within Avista BAA
Avista BAA
m
Wheel thru External BAA
mInternal
Gen
Pseudo
-tie
Gen
Pseudo-Tie Meter:
 Generation
 Interchange import
 Interchange export
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 14 of 34
 Channel 4 for generated or imported active power
Therefore, Avista’s MDM solution will need to transpose the received channels to match CAISO’s
required designations if they differ.
CAISO does not accept non-zero meter values on channel 4 for the load meter submission, therefore all
channel 4 values for the ELAP meter should always be submitted as zero values.
CAISO does not accept non-zero meter values on channel 1 for generation meters, even if station service
consumption exceeds generation production for a given interval. Therefore, channel 1 for all generation
meters should always be submitted as zero values.
For intervals where station service exceeds generation, the station service load of internal generation is
already metered by interchange imports and other internal generation, and thus does not need to be
submitted from the generation meter read. By contrast, the station service for pseudo-tie generation
should be submitted on channel 1 for the corresponding interchange metering, to include the station
service as Avista BAA load. As depicted in Figure 5, station service for a pseudo-tie generator is
measured as an import by the interchange meter at the generation site, while an internal generator only
has the generation meter on therefore does not need to submit load values for its station service when
it exceeds generation.
2.2 Key Metering Considerations
2.2.1 Expected Point of Measurement and Compensation Factors
CAISO expects Base Schedules, Dispatch Operating Targets (DOTs) and meter data to all correspond to
the high side, transmission voltage level of a Resource ID. Furthermore, any station service load fed from
a similar electrical location, such as a generator bus or high side of the same substation, may be netted
from the data (as if the metering point was physically on the high side of the GSU). To the extent the
point of scheduling, dispatch, generator control and metering differ from this expected point of
measurement, calculations should be performed to account for these differences to prevent dispatch
and settlement error.
For example, if the CTs and PTs for a generator meter are measuring output at the low voltage side of
the GSU, the meter values should be adjusted to compensate for the calculated losses through the GSU,
which are typically determined from GSU manufacturer data or GSU test data. Transformer losses are
typically calculated as the sum of no-load losses and load-losses, expressed as:
NLL + I2R
No-Load Losses + Current-squared * Resistance
No-load losses are set at a constant value of watts and load-losses as a function of resistance, a constant
ohm value, multiplied by current squared. This resulting equation would be programmed in the
associated meter as the compensation factor.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 15 of 34
Several Avista generation sites meter Station Service (SS) load at the low-side of the SS transformer,
with the high-side of the SS transformer connected to a generator bus. If these existing meter
installations are utilized for SQMD submission, compensation factors should be applied to the metered
values accounting for both the SS transformer and GSU losses. An accurate calculation would program
the SS meter to add the SS transformer losses compensation, increasing the effective SS load, and
subtract the SS load from GSU load-losses for the associated generator meters, since SS load nets
generator production flowing through the GSU, reducing GSU load-losses. This calculation of
compensation factors with interaction between multiple meters may be practicably difficult, instead
requiring approximations to account for the contribution of multiple generators and SS load to GSU
load-losses. The following equations are example calculations to accurately compensate for SS
transformer and GSU losses utilizing a low-side SS meter and two low-side generator meters, similar to
the Noxon unit 1 & 2 and SS depiction in Figure 3.
For unit-level Resource IDs, allocating transformer losses and SS load half-and-half to each resource8:
SS_meter_data (SS transformer compensated) = SS_load + NLLSS_transformer + ISS2R
GSU current (IGSU) = G1_current + G2_current – SS_transformer_compensated_SS_current
GSU_losses = NLLGSU + IGSU2R
G1 compensated meter data = G1_meter – GSU_losses/2 – SS_meter_data/2
G2 compensated meter data = G2_meter – GSU_losses/2 – SS_meter_data/2
For an aggregate Resource ID:
SS_meter_data (SS transformer compensated) = SS_meter + NLLSS_transformer + ISS2R
GSU current (IGSU) = G1_current + G2_current – SS_transformer_compensated_SS_current
GSU_losses = NLLGSU + IGSU2R
Aggregate Resource ID meter data = G1_meter + G2_meter – GSU_losses – SS_meter_data
Alternatively, CTs and PTs could be installed at the high voltage side of the GSU to avoid the need for
loss compensation factors. Furthermore, if station service load for the generator is fed from a separate
station service transformer located at the same substation, and therefore electrically similar to the
resource, the station service should be metered and netted from the generator meter value, as
described in section 2.1.9. By contrast, if the metering location reads generation net of station service,
such as high side metering, then station service does not need to be metered separately.
Any compensation factors applied to EIM meter data should be documented, including the calculating
device or software, source document for compensation factor, and rationale for applying the
8 The allocation logic for GSU losses and SS load to unit-level Resource IDs should be more sophisticated than half-
and-half to address operation with one generation online and the other offline, as a half-and-half allocation would
result in half of the GSU losses and SS being unaccounted for due to allocation to an offline generator
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 16 of 34
compensation. This documentation will be included in the SQMD Plan and self-audited EIM meter
program. The CAISO Metering BPM Attachment B Section C describes the loss compensation
methodologies.
2.2.2 Metering Granularity Impact
CAISO allows for NPR metering to be recorded at a 5, 15, or 60-minute granularity. However, the ELAP
meter must be submitted at the least granular level of the underlying meters that sum to the load value.
The majority of CAISO charge codes settle at a 5-minute granularity, so any load or NPR meters
submitted at 15-minute or 60-minute granularity is distributed evenly to the corresponding 5-minute
intervals for settlements, resulting in accumulation of extra revenues or deficits in CAISO neutrality
accounts due to price differences between 5-minute intervals that do not tie out to corresponding
changes in submitted meter values. These neutrality accounts are largely settled with the EIM Entity and
therefore do not result in a material financial risk. However, load meter submission that is less granular
than 5-minutes greatly complicates shadow settlement and issue spotting, as the lack of data granularity
masks underlying causes of settlement or metering errors that are crucial to resolve in a timely fashion.
Finally, Avista has determined it is relatively inexpensive to re-program or change out a meter to enable
5-minute granularity meter data. Therefore, Utilicast recommends Avista proceed with its plan to submit
5-minute granular meter data for all NPRs so it may submit 5-minute granular ELAP meter data.
2.2.3 Insufficient Accuracy and Correction Factors
If any meters, CTs, or PTs used for EIM metering lack a sufficient accuracy rating to meet CAISO metering
requirements, the equipment will either need to be replaced with compliant equipment or a correction
factor applied. A correction factor for insufficiently accurate metering equipment is effectively a penalty
on metered production to account for the gap in accuracy between the installed equipment and CAISO
requirements.
The CAISO Metering BPM Attachment B Sections D3-D6 describe the calculation of correction factors to
adjust for deficiencies in CT and PT accuracy. Whatever the deficiency in accuracy, an accuracy rating
must be determined in order to apply the appropriate correction factor and utilize the deficient
equipment for EIM metering. If the accuracy or burden rating of equipment is unknown, correction
factor field tests should be performed to establish the accuracy at the connected burden. Any total
meter equipment error equal to or less than 0.6%, as calculated according the referenced CAISO
sections, does not require a correction factor to be applied, while any calculated error greater than 0.6%
must be applied as a correction factor to the recorded meter data, reducing the submitted quantities by
the correction factor percentage.
The financial impact of correction factors being applied to PRs may be substantial, as this production
could be exported on EIM transfers, resulting in a reduction in market revenues due to the required
penalty in submitted production compared to the scheduled exported EIM energy received by other EIM
participants.
By contrast, the financial impact of correction factors applied to NPRs is small, as any MWh deficit in
submitted NPR production would result in a corresponding decrease in the Avista ELAP meter.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 17 of 34
Therefore, any lost revenues on the NPR settlement would be largely regained in the load-related
settlements. To the extent the NPR Locational Marginal Prices (LMPs) are lower than the ELAP LMPs due
to congestion, there is some risk that a portion of the transmission congestion revenue rebates in
settlement would be allocated to an EIM participant other than Avista due to EIM transfers. Collectively,
these risks appear small.
2.2.4 Insufficient Granularity of non-Avista owned Interchange Meters
While interchange metering is required to be recorded with 5-minute granularity, CAISO has consistently
allowed EIM participants to exempt interchange meters owned by other parties from this requirement.
Non-EIM participants typically record interchange metering at 60-minute granularity to align with NERC
standard requirements for hourly interchange meter check-out.
In lieu of meeting this EIM requirement, the alternate approach taken by most EIM participants to
submit 5-minute granular interchange metering is to calculate average 5-minute meter values in PI from
the instantaneous MW telemetry reads, compare the sum of the 5-minute averages to the settlement
quality hourly check-out values, and adjust the 5-minute averages as necessary to align with hourly
values in the MDM. For most recent EIM implementations, this exemption has only been allowed for
interchange meters not owned by the EIM entrant, so Avista-owned interchange meters would need to
comply with the standard 5-minute granularity requirements.
2.2.5 Metering of Jointly-Owned Generation
Avista is a joint-owner of Colstrip generation and joint offtaker of Mid-C generation. Existing EIM
participants, namely PacifiCorp, Puget Sound Energy, and Portland General Electric, are also joint
participants in these generation projects and have successfully exempted the associated generator
meters from CAISO’s metering requirements. In each case, the metering is not owned by any current
EIM participant and the metered offtake of individual participants is not determined directly by physical
meters. Rather, Colstrip and Mid-C metered offtakes are determined by logical meters calculated by
allocation computers. These allocation computers dynamically apportion the metered generation based
on each participant’s approved dispatch such that the physical meters are not indicative of the
individual participant’s generation.
The typical meter calculation for Colstrip and Mid-C projects has been similar to the suggested approach
for non-Avista owned interchange meters described in section 2.2.4. CAISO has requested single line
metering diagrams for these facilities and a description of the determination and validation of the
participant’s metered share for existing EIM participants. Based on Avista’s research, it appears that the
standard for Mid-C SLD submission established by PGE is not high and Avista should be able to satisfy
the Mid-C SQMD relatively easily.
Given NorthWestern Energy’s planned EIM participation, slated for April 2021, and their ownership of
the Colstrip generation meters, it is possible that the metering configuration and allowed exemption for
Colstrip may change prior to Avista’s EIM implementation. Avista should discuss these impacts to
Colstrip metering with Northwestern Energy as their implementation progresses.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 18 of 34
3 Metering Approach
This section summarizes the current metering configuration for each generator and point of interchange, identifies gaps in compliance with
CAISO requirements and proposes methods to address the identified gaps. The following four sub-sections group together Avista-owned and 3rd
Party-owned generation and interchange, as these grouped facilities tend to share common statuses and proposed solutions.
3.1 Generation, Avista-Owned
While most of the Avista-owned generation meter equipment was inventoried during this project, much of the equipment nameplate data was
insufficient. The equipment with insufficient information or yet to be inventoried is marked unknown in the following table, with suggested next
steps indicated in the “Determine Unknown” column. Table 6 in section 4 summarizes proposed generator metering projects. Post Falls
generation has no proposed metering projects, due to its planned NPR status it should have its meters replaced or upgraded to be 5-minute
capable, with compensation factors and correction factors applied as necessary.
The listed meters are a subset of the inventoried meters, selected to record net generation for EIM purposes. For example, Post Falls units 1-5
each have gross unit-level metering, which are also metered net of station service. Only the Post Falls 1-5 net metering is listed, as it could
record net generation for EIM purposes without the use of the unit-level 1-5 gross meters. Station Service (SS) metering voltage is noted in
parenthesis to indicate whether the metering is on the generator bus or SS bus. If the SS metering is on the SS bus, then the metered values
should be compensated for losses across both the SS transformer and GSU. See section 2.2.1 for more detail on SS transformer and GSU loss
compensation.
Equipment attributes marked “Y” under EIM Compliance Status indicates the attribute meets or exceeds CAISO metering requirements, while
“Unk” indicates the attribute is unknown due to either insufficient nameplate information or yet to be inventoried.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 19 of 34
Table 2: Generation Metering Status, Avista-Owned
Generator Meter
EIM Compliance Status Proposed Next Steps
CT
Accuracy CT Burden PT
Accuracy
PT
Burden Meter Determine Unknown
Determine
Connected
Burden
Post Falls 1-5 Net Meter Unk Unk Unk Unk 5-min capable with
memory upgrade Test CTs and PTs
Post Falls Unit 6 Y Y Unk Unk Not 5-min capable Test PTs
Noxon Unit 1 Y Y Unk Unk Not 5-min capable Test PTs
Noxon Unit 2 Y Y Unk Unk Not 5-min capable Test PTs
Noxon Unit 3 Y Y Unk Unk Not 5-min capable Test PTs
Noxon Unit 4 Y Y Unk Unk Not 5-min capable Test PTs
Noxon Unit 5 Unk Unk Y N, Y < ZZ 5-min capable with
memory upgrade Test CTs PTs
Noxon SS A (480 V) Y Y N, 0.6 <
0.3 class
N, W <
ZZ 5-min capable PTs
Noxon SS B (480 V) Y Y N, 0.6 <
0.3 class
N, W <
ZZ 5-min capable PTs
Cabinet Unit 1 Unk Unk Unk Unk 5-min capable Test CTs and PTs
Cabinet Unit 2 Unk Unk Unk Unk Not 5-min capable Test CTs and PTs
Cabinet Unit 3 Unk Unk Unk Unk Not 5-min capable Test CTs and PTs
Cabinet Unit 4 Unk Unk Unk Unk Not 5-min capable Test CTs and PTs
Cabinet SS A (480 V) Unk Unk Unk Unk Not 5-min capable Test CTs and PTs (if CT & PT
nameplate incomplete)
Cabinet SS B (480 V) Unk Unk Unk Unk Not 5-min capable Test CTs and PTs (if CT & PT
nameplate incomplete)
Nine Mile Unit 1 Y N, 0.5 < 1.8 Y N, Z < ZZ 5-min capable CTs & PTs
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 20 of 34
Generator Meter
EIM Compliance Status Proposed Next Steps
CT
Accuracy CT Burden PT
Accuracy
PT
Burden Meter Determine Unknown
Determine
Connected
Burden
Nine Mile Unit 2 Y N, 0.5 < 1.8 Y N, Z < ZZ 5-min capable CTs & PTs
Nine Mile Unit 3 Y N, 0.5 < 1.8 Y N, Y < ZZ Not 5-min capable CTs & PTs
Nine Mile Unit 4 Y N, 0.5 < 1.8 Y N, Y < ZZ Not 5-min capable CTs & PTs
Nine Mile SS 1 (480 V) Unk Unk Unk Unk 5-min capable Include changeout in SS 2
project if possible, test if not
Nine Mile SS 2 Future N/A, future installation, suggest the scope include revenue quality equipment as alternative to high-side metering
project
Upper Falls Unit Y Y Y N, Y < ZZ 5-min capable with
memory upgrade PTs
Upper Falls SS (240 V) Unk Unk N/A N/A 5-min capable with
memory upgrade
Suggest only utilizing gross meter, as SS
metering equipment is unknown and SS
load is negligible
Long Lake Unit 1 Y Y Unk Unk Not 5-min capable Test PTs
Long Lake Unit 2 Y Y Y N, Y < ZZ Not 5-min capable PTs
Long Lake Unit 3 Y Y Unk Unk Not 5-min capable Test PTs
Long Lake Unit 4 Y Y Unk Unk Not 5-min capable Test PTs
Long Lake SS A (4 kV) Unk Unk Unk Unk Not 5-min capable Include changeout in SS
project if possible, test if not

Long Lake SS B (4 kV) Unk Unk Y N, Y < ZZ Not 5-min capable PTs
Little Falls Unit 1 Y Y Y N, Y < ZZ 5-min capable PTs
Little Falls Unit 2 Y Y Y N, Y < ZZ 5-min capable PTs
Little Falls Unit 3 Y Y Y N, Y < ZZ 5-min capable PTs
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 21 of 34
Generator Meter
EIM Compliance Status Proposed Next Steps
CT
Accuracy CT Burden PT
Accuracy
PT
Burden Meter Determine Unknown
Determine
Connected
Burden
Little Falls Unit 4 Y Y Y N, Y < ZZ
5-min capable
following planned
project
PTs
Little Falls SS 1 (480 V) N N, 0.9 < 1.8 N N, W <
ZZ 5-min capable CTs & PTs
Little Falls SS 2 (480 V) N N, 0.9 < 1.8 N N, W <
ZZ 5-min capable CTs & PTs
Monroe Street Unit Y N, 0.1 < 1.8 Y N, Z < ZZ 5-min capable CTs & PTs
Monroe Street SS
(14.4 kV) Unk Unk Y N, Z < ZZ 5-min capable PTs
Kettle Falls Biomass Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls CT Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1A1
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1A2
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1A3
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1B2
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1B3
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Kettle Falls SS 1B4
(13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 22 of 34
Generator Meter
EIM Compliance Status Proposed Next Steps
CT
Accuracy CT Burden PT
Accuracy
PT
Burden Meter Determine Unknown
Determine
Connected
Burden
Boulder Park Net Meter Unk Unk Y N, Y < ZZ 5-min capable with
memory upgrade
Test CTs (if GSU nameplate
incomplete) PTs
Northeast Gross Meter Y Y Y N, Y < ZZ 5-min capable with
memory upgrade PTs
Northeast SS (480 V) Unk Unk Unk Unk 5-min capable with
memory upgrade Test CTs and PTs
Rathdrum Unit 1 Unk Unk Unk Unk 5-min capable Test CTs and PTs
Rathdrum Unit 2 Unk Unk Unk Unk 5-min capable Test CTs and PTs
Rathdrum SS 1 (13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Rathdrum SS 2 (13.8 kV) Unk Unk Unk Unk 5-min capable Test CTs and PTs
Unk = Unknown; SS = Station Service

3.2 Generation, 3rd Party-Owned
While most of the 3rd Party-owned generation meter equipment was inventoried during this project, much of the equipment nameplate data
was insufficient. The equipment with insufficient information or yet to be inventoried is marked unknown in the following table, with suggested
next steps indicated in the following table. Table 6 in section 4 summarizes proposed generator metering projects. Planned NPRs have no
proposed metering projects, and should have their meters replaced or upgraded to be 5-minute capable, with compensation factors and
correction factors applied as necessary.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 23 of 34
Table 3: Generation Metering Status, 3rd Party-Owned
Generator
Meter
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-
program
Meter
Replace Meter
or Upgrade
Memory
Compe
nsate to
hi-side
Coyote
Springs
High-Side
Y Y Y Y Not 5-min
capable X
Lancaster
Net Meter Y Unk Y Unk 5-min capable
CTs & PTs
nameplate
burden
CTs & PTs X
Palouse
Wind Y Y Y Y
5-min capable
with memory
upgrade
X
Solar
Select Y N, 0.5
< 1.8 Y N, Z <
ZZ 5-min capable CTs & PTs X X
Spokane
Waste to
Energy Net
Meter
Y Y Y Y
5-min capable
with memory
upgrade
X
Plummer
Saw Mill Y Y Y N, Z <
ZZ
5-min capable
with memory
upgrade
PTs X X
Upriver
Net Meter Y Y Y N, Z <
ZZ
5-min capable
with memory
upgrade
PTs X X
Clearwater
Net Meter
1
Y Y Y Y Not 5-min
capable X X
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 24 of 34
Generator
Meter
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-
program
Meter
Replace Meter
or Upgrade
Memory
Compe
nsate to
hi-side
Clearwater
Net Meter
2
Y Y Y Y Not 5-min
capable X X
Clearwater
Gross
Meter 1
Relay
class <
Metering
class
Unk
Relay
class <
Metering
class
Unk Not 5-min
capable
Test CTs
and PTs X X
Clearwater
Gross
Meter 2
Relay
class <
Metering
class
Unk
Relay
class <
Metering
class
Unk Not 5-min
capable
Test CTs
and PTs X X
Fighting
Creek Y Y Y Unk
5-min capable
with memory
upgrade
PTs
nameplate
burden
PTs X X
Colstrip N/A, 5-minute average of instantaneous MW telemetry sufficient, see section 2.2.5 for details
Mid-C
CHPD N/A, 5-minute average of instantaneous MW telemetry sufficient, see section 2.2.5 for details
Mid-C
DOPD N/A, 5-minute average of instantaneous MW telemetry sufficient, see section 2.2.5 for details
Mid-C
GCPD N/A, 5-minute average of instantaneous MW telemetry sufficient, see section 2.2.5 for details
Saddle
Mountain
Wind
Future
N/A, future installation will be EIM compliant based on Avista standards
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 25 of 34
Generator
Meter
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-
program
Meter
Replace Meter
or Upgrade
Memory
Compe
nsate to
hi-side
Rattlesnak
e Wind
Future
N/A, future installation will be EIM compliant based on Avista standards
Box
Canyon Out of scope, POPD expected to exit Avista BAA prior to EIM entrance, see section 3.4 for details
Unk = Unknown

3.3 Interchange, Avista-Owned
Some points of interchange have two meters, a primary and backup. However, the attributes of both metering sets are identical across Avista-
owned interchange meter equipment, so each set is listed as one row for conciseness in the table below.
Table 4: Interchange Metering Status, Avista-Owned
Point of
Interchange
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-program
Meter
Replace Meter
or Upgrade
Memory
BPAT @ Colbert Y Y Y N, Z <
ZZ 5-min capable PTs X
BPAT @ DeerPark
12F1 Y Y Y N, Z <
ZZ 5-min capable PTs X
BPAT @ DeerPark
12F2 Y Y Y N, Z <
ZZ 5-min capable PTs X
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 26 of 34
Point of
Interchange
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-program
Meter
Replace Meter
or Upgrade
Memory
BPAT @ Kettle
Falls A621 Y Unk Y Y 5-min capable CTs X
BPAT @ Loon Lake Y Y Y N, Z <
ZZ 5-min capable PTs X
BPAT @ Mead Y Y Y N, Z <
ZZ 5-min capable PTs X
BPAT @ North
Lewiston Y Unk Y Unk 5-min capable CTs & PTs X
BPAT @ Noxon
13kV Construction
Sub
Y N, 0.5
< 1.8 Y N, Z <
ZZ 5-min capable CTs & PTs X
BPAT @ Noxon
R316 (Libby Line) Y Unk Y Y 5-min capable CTs X
BPAT @ Noxon
R336 Lancaster
Line)
Y Unk Y Y 5-min capable CTs X
BPAT @ Noxon
R337 (Hot Springs
Line)
Y Unk Y Y 5-min capable CTs X
BPAT @ Orofino Y
Y,
pendin
g
verifica
tion
Y Unk 5-min capable Verify CT
Accuracy PTs X
BPAT @ Priest
River Y N, 0.5
< 1.8 Y N, Y <
ZZ 5-min capable CTs & PTs X
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 27 of 34
Point of
Interchange
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-program
Meter
Replace Meter
or Upgrade
Memory
BPAT @ Sagle Y N, 0.9
< 1.8 Y N, Y <
ZZ 5-min capable CTs & PTs X
BPAT @ Spirit Y Y Y N, Z <
ZZ 5-min capable PTs X
BPAT @ Westside
(R380) Y Unk Y Unk 5-min capable N/A, future installation will replace existing equipment
and be EIM compliant based on Avista standards
BPAT @ Westside
(R382) Y Unk Y Unk 5-min capable N/A, future installation will replace existing equipment
and be EIM compliant based on Avista standards
BPAT @ Wilbur Y Unk Y Unk 5-min capable CTs & PTs X
BPAT @Milan Y N, 0.5
< 1.8 Y N, Z <
ZZ 5-min capable CTs & PTs X
GCPD @ Stratford Y N, 1.0
< 1.8 Y Y Insufficient
memory CTs X X
GCPD @ Warden
A254 Y Unk Y Unk Insufficient
memory CTs & PTs X X
GCPD @ Warden
A310 Y Unk Y Unk Insufficient
memory CTs & PTs X X
IPCO @ Lolo Y Unk Y Unk Insufficient
memory CTs & PTs X X
NWMT @ Burke Y Unk Y N, Z <
ZZ
Insufficient
memory CTs & PTs X X
PACW @ Dry Creek Y Unk Y Y Insufficient
memory CTs X X
PACW @ Dry Gulch Y Unk Y Y Insufficient
memory
N/A, future installation will replace existing equipment
and be EIM compliant based on Avista standards
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 28 of 34
Point of
Interchange
EIM Compliance Status Proposed Next Steps and Solutions
CT
Accuracy
CT
Burden
PT
Accuracy
PT
Burden Meter Determine
Unknown
Determine
Connected
Burden
Re-program
Meter
Replace Meter
or Upgrade
Memory
BPAT @
Opportunity
(Valley tap) Future
N/A, future installation will be EIM compliant based on Avista standards
GCPD @ Wanapum
- Saddle Mt backup
Future
N/A, future installation will be EIM compliant based on Avista standards
PACW @ Saddle
Mountain Sub
Future
N/A, future installation will be EIM compliant based on Avista standards
Unk = Unknown

3.4 Interchange, 3rd Party-Owned
The proposed solution for all 3rd Party-owned interchange metering is to utilize 5-minute averaged instantaneous telemetry MW reads,
validated with hourly check-out meter values, as described in section 2.2.4. Once validated, the equipment ratings of 3rd Party-owned
interchange metering are acceptable for EIM participation, since the equipment owner utilizes it for revenue purposes. BPA typically nets the
interchange metering at each substation to a combined SCADA value, so these combined points of interchange are listed as a single row.
The Seattle City Light (SCL) points of interchange at Main Canal and Summer Falls should be discussed in further detail with SCL to determine a
consistent modeling of these points of interchange. In light of SCL’s planned EIM participation and the current setup with SCL dividing the
interchange in half between its BAA and the Tacoma Power BAA, while Avista only interchanges with SCL, Avista and SCL should coordinate to
ensure consistent EIM modeling and metering of interchange at these points to mitigate any adverse EIM operational or settlement impacts.
Pend Oreille Public Utility District (POPD) is currently in the Avista BAA, with several meters measuring the interchange between Avista and BPA
in the POPD service territory. However, POPD has communicated its intent to exit the Avista BAA in October 2020, prior to Avista’s EIM entrance.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 29 of 34
With the planned exit of POPD from the Avista, a new point of interchange would be metered at Pine Street substation. Therefore, Avista is not
including these current interchange meters in its EIM metering scope, noted in the table below, and will include the future Pine Street
interchange metering in its EIM metering scope. Avista should track the POPD planned BAA exit and adjust the list of interchange and generation
meters in scope for EIM participation if the POPD BAA exit changes in schedule or scope.
Table 5 : Interchange Metering Staus, 3rd Party-Owned
Point of Interchange
EIM Compliance Status Proposed Next Steps and Solutions
Equipment Validated Determine Unknowns Calculate 5-minute MW Averages
BPAT @ Addy Y X
BPAT @ Bell Y X
BPAT @ Benton Y X
BPAT @ Hatwai Y X
BPAT @ Hot Springs Y X
BPAT @ Kaiser-Trentwood
Load Y X
BPAT @ Lancaster –
Boulder Y X
BPAT @ Lancaster –
Rathdrum Y X
BPAT @ Sandcreek Y X
BPAT @ Usk Y X
CHPD @ Chelan Y X
NWMT @ Hot Springs Y X
SCL @ Main Canal N X X
SCL @ Summer Falls N X X
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 30 of 34
Point of Interchange
EIM Compliance Status Proposed Next Steps and Solutions
Equipment Validated Determine Unknowns Calculate 5-minute MW Averages
BPAT @ Coyote Springs
Pseudo-Tie See section 3.2 regarding Coyote Springs, utilize generation metering for EIM interchange metering
BPAT @ Lancaster Gen See section 3.2 regarding Lancaster, utilize generation metering for EIM interchange metering
CHPD @ Mid-C Pseudo-Tie See section 3.2 regarding CHPD Mid-C, utilize generation metering for EIM interchange metering
DOPD @ Mid-C Pseudo-Tie See section 3.2 regarding DOPD Mid-C, utilize generation metering for EIM interchange metering
GCPD @ Mid-C Pseudo-Tie See section 3.2 regarding GCPD Mid-C, utilize generation metering for EIM interchange metering
NWMT @ Colstrip Pseudo-
Tie See section 3.2 regarding Colstrip, utilize generation metering for EIM interchange metering
GCPD @ Wanapum Future N/A, future installation that will be owned by GCPD
BPAT @ Pine Street Future N/A, future installation for POPD BAA exit that will be owned by BPA
BPAT @ Box Canyon Out of scope, POPD expected to exit Avista BAA prior to EIM entrance
BPAT @ Diamond Lake Out of scope, POPD expected to exit Avista BAA prior to EIM entrance
BPAT @ Metaline Falls Out of scope, POPD expected to exit Avista BAA prior to EIM entrance
BPAT @ Newport Out of scope, POPD expected to exit Avista BAA prior to EIM entrance
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 31 of 34
4 Estimated Costs
This section provides high-level descriptions and cost estimates for the proposed metering projects,
generation controls projects, meter-related network projects, and meter head-end solution.
4.1 Avista Participating Resources
The following table summarizes the proposed generation controls and metering projects. Merged rows
in the high side metering column indicate a shared GSU between multiple generator units with a
common proposed high-side metering set. The projects are listed in priority order, with the latter
projects subject to further discussion or testing of existing metering equipment prior to proceeding with
a project.
Table 6: Generation Controls and Metering Project Cost Estimates
Generation PLC
(in $,000)
Low Side
Metering
(in $,000)
High Side
Metering
(in $,000)
Total Metering by
Site (in $,000)
Noxon $200
$750
- Noxon Unit 1 $30 $200 - Noxon Unit 2 $30
- Noxon Unit 3 $30 $200 - Noxon Unit 4 $30
- Noxon Unit 5 $30 $200
Cabinet $200
$520
- Cabinet Unit 1 $200 - Cabinet Unit 2
- Cabinet Unit 3 $60 $200 - Cabinet Unit 4 $60
Coyote Springs $200 $200
Long Lake $200
$140
- Long Lake Unit 1 $35 Utilize existing
SS project to
install high-
side metering
- Long Lake Unit 2 $35
- Long Lake Unit 3 $35
- Long Lake Unit 4 $35
Little Falls $200 $0
Rathdrum $200
$400 - Rathdrum Unit 1 $200
- Rathdrum Unit 2 $200
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 32 of 34
Generation PLC
(in $,000)
Low Side
Metering
(in $,000)
High Side
Metering
(in $,000)
Total Metering by
Site (in $,000)
Lancaster $150 $100 $100
Kettle Falls $200 $200
Boulder Park $160 $200 $360
Nine Mile
$520
- Nine Mile Unit 1 $200 - Nine Mile Unit 2
- Nine Mile Unit 3 $60 $200 - Nine Mile Unit 4 $60
Monroe Street $100 $200 $300
Upper Falls $100 $200 $300
Total $1,150 $3,790
Low Estimate, rounded
(+0% PLC, -20% Metering) $1,200 $3,000
High Estimate, rounded
(+20% PLC & Metering) $1,400 $4,500
PLC = Programmable Logic Controller
4.2 Other Metering & Network Costs
In addition to the costs summarized in Section 4.1, this report mentions costs and effort associated with
some additional items which were include in the overall project cost estimates and described in greater
detail in the Technology Assessment Summary Report.
 Transmission Meters – Costs for transmission meter swaps are included in Line 15.
 Meter Data Collection and Processing – License costs for MV90 work and hardware to collect
meter data reads, costs and effort for Oracle MDM setup, and costs for non-fiber meter data
acquisition are included in Line 15.
 Network Improvements – Cost and effort to create T1 connections, including High Voltage
Protection (HVP), are included in Line 16.
Table 7: Summary Budgetary Cost Estimate for EIM Technology Projects
Line Cost Estimate Category
Project & Procurement
Solutions & Services
(in $,000)
Project & Procurement
Avista Internal Labor
(in Hours)
15 Transmission Meters & Data Collection $340 5,200
16 Network Improvements for Metering $210 - $2,000 2,600

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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 33 of 34
Note that costs are not estimated for the proposed meter memory upgrades at the following generation
sites due to a lack of available cost estimates and preliminary scopes of work at the time of this
assessment:
 Palouse Wind (2 meters)
 Spokane Waste to Energy Net Meter
 Plummer Saw Mill
 Upriver Net Meter
 Clearwater Net Meter 1
 Clearwater Net Meter 2
 Clearwater Gross Meter 1
 Clearwater Gross Meter 2
 Fighting Creek
See section 2.1.7 for detail on meter memory requirements and recommended next steps.

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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 5, Page 34 of 34
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 1 of 21
Program Name: Energy Imbalance Market
Program Manager: Kelly Dengel
Business Case Name: Energy Imbalance Market
Expenditure Request (ER): 7141 – Energy Imbalance Market
Submit Date: 05/17/2019
1 Key Roles & Program Information
Program Sponsor(s): Scott Kinney/
Mike Magruder
Business Case
Owner(s): Kelly Dengel
Business Program
Manager: Kelly Dengel Executive Steering
Committee Members:
Jason Thackston, Heather
Rosentrater, Jim Kensok,
Ryan Krasselt, Kevin
Christie
Director Steering
Committee Members:
Scott Kinney, Andy
Vickers, Josh DiLuciano,
Mike Magruder, Jim
Corder, Hossein Nikdel,
Adam Munson, Pat
Ehrbar, Todd Colton
Other Stakeholders:
James Dykes, Robert Follini,
Annette Brandon, Jacob
Reidt, Kit Parker, Bob
Weisbeck, Tom Dempsey,
Alexis Alexander, Kristina
Newhouse, Glen Farmer,
Jeff Schlect, Brad Calbick,
Craig Figart, Garth
Brandon, Rip Divis, Rich
Hydzik, Kenny Dillon, Jeff
Schlect, Mike Andrea,
Glenn Madden, Randy
Spacek, Calvin Howard,
Sheena Byerly, Ethan
Jelinek, Elizabeth Arnold,
Jason Pegg, Shanna
Pagniano, Tim Davey,
Nolan Steiner
2 Program Overview
2.1 Business Need
As of 2014, Avista has progressively monitored the formation and expansion of the Western Energy Imbalance
Market (EIM) administered by the California Independent System Operator (CAISO). The Western EIM, a real-time
energy market producing substantial cost savings for renewable integration and system optimization, has grown
to include over 75% of the load in the Western Interconnection. As western states promote and mandate
increasing renewable portfolio standards and de-carbonization of the electric grid, Balancing Authorities Areas
(BAA) will require interconnection-wide assimilation of available resources to maintain reliability and manage
renewable integration costs. Avista has made substantial commitments to decarbonize its generation fleet, and
along with recent Washington State de-carbonization legislation, will require new approaches to maintain its
current optimization objectives, while containing the rising integration costs of renewable resources. On April 25,
2019, Avista signed the EIM Implementation Agreement with the CAISO and will officially join the market in April
of 2022 in an effort to support its leadership as a low cost, customer-focused, energy service provider.
The Western EIM is an in-hour economic based regional resource dispatch program that allows participants to lower
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Exhibit No. 8
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Schedule 6, Page 1 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 2 of 21
energy costs by either dispatching less expensive resources to meet load obligations, or increase revenue through
the bidding of excess energy into the market. The EIM dispatches the most economic resource across its entire
market footprint based on bid prices to balance in-hour load and generation, resulting in lower overall dispatch cost
for each individual participant. The EIM also lowers the amount of on-line regulation that each utility holds in excess
every hour to make up the error between the forecasted load and resource plans, and what actually occurs during
the operating hour. The reduced regulation can then be monetized creating additional revenue.
Several northwest utilities, (PacifiCorp, Portland General Electric, Puget Sound Energy, Idaho Power,
Northwestern, and Seattle City Light) along with other western utilities, have either already joined the CAISO EIM
or announced they will join in the near future. The Bonneville Power Administration (BPA) is conducting a
customer stakeholder process and is expected to issue a formal Record of Decision in September of 2019 with the
intention to join the Western EIM in April, 2022. If BPA joins the Western EIM over 75 percent of the load in the
Western Interconnection will be participating in the market. This shift in market participation will impact daily
market liquidity by reducing the number of available bi-lateral trading partners to conduct near term daily energy
transactions. The risk of limited trading partners could drive daily market prices higher and/or cause reliability
issues for Avista if energy can’t be procured from the bi-lateral market during stressed conditions such as the loss
of an Avista generating facility.
The factors influencing Avista’s decision to join the Western EIM
include a reduction in bi-lateral market liquidity, increased integration
of third-party renewable resources and likely changes within state
legislation that would drive additional renewable resources to be built
within Avista’s BAA. The EIM will allow Avista to reduce costs
associated with integrating renewable resources, while maintaining the
flexibility and optimization of its hydro generation, and ensuring Avista
continues to serves its customers with reliable and cost-effective
energy. In April of 2019, Avista announced its own clean energy goals
that will transition resource mix to 100 percent clean by 2045.
Renewable generation requires additional regulation and load
following to back up the intermittency of the resource. There is a
tipping point where Avista’s existing hydro flexibility can’t sufficiently
or economically supply the required load following for the amount of
renewable resources integrated into the Avista BAA. Any additional
renewable resource integrated in Avista’s service territory results in a
reduction of hydro flexibility to follow these variable resources, and
the EIM is the most efficient and cost effective way to provide the
required flexible ramping capability.
Currently Avista has only a single 100 MW wind facility and limited solar
facilities within its BAA so there is adequate hydro flexibility to follow
these plants. However, there are several third-party independent power
producers that are in the Avista transmission interconnection queue
that are exploring integration. In addition, Avista initiated a Request for Proposal for 150 MW of renewable
resources in June of 2018 and if pricing is favorable, Avista may sign a 20-year power purchase agreement for up to
150 MW of renewable resources starting in 2020. Future Washington State emissions legislation could drive
additional renewable resources to be built in our BAA. Finally, Avista continuously receives requests from smaller
solar and wind resources that are seeking Public Utility Regulatory Policies Act contracts. Any additional renewable
resource integrated in Avista’s service territory may result in a reduction of hydro flexibility to follow the resource.
Utilities typically announce their formal decision to join the Western EIM two or three years prior to entry, and
use that time to comply with CAISO and FERC requirements. The CAISO has historically allowed two utilities to join
the market in April of each year. After a formal agreement is signed between Avista and the CAISO, a CAISO
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Schedule 6, Page 2 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 3 of 21
provided project schedule with milestones and financial obligations will be finalized and followed. In order to
prepare Avista for entry by April 1 of 2022, there is a substantial body of technical work, physical construction
work and business process design for Avista to complete for the implementation. The implementation effort
includes multiple new software applications, upgrades to existing software, generation metering and control
upgrades, interconnection metering upgrades at substations and network infrastructure upgrades.
2.2 Who Benefits?
Joining the Western EIM would allow Avista to reduce costs associated with integrating renewable resources,
while maintaining the flexibility and optimization of its hydro generation, and ensuring Avista continues to serve
its customers with reliable and cost-effective energy. Once Avista is an active Western EIM participant, Avista
intends for the costs and benefits of participation to be treated in a similar manner as other Avista Power Supply
revenues and expenses. This includes some level of EIM costs and benefits included in the authorized Power
Supply (once more financials are known), and the tracking of actual to authorized costs through the existing Idaho
Power Cost Adjustment (PCA) mechanism in Idaho and the Washington Energy Recovery Mechanism (ERM) in
Washington.1
2.3 Strategic Focus Area
Avista aims to tie everything we do back to our corporate Vision, Mission, Values and Areas of Focus. The EIM
program focuses on the strategic areas of Our Customer, Our People, Perform and Invent.
Our Customers – We must hold our customers’ interests at the forefront of all our decisions, operating our
business by showing that we are transparent, genuinely care, and are easy to do business with. Joining the
Western EIM will allow Avista to reduce costs associated with integrating renewable resources, while maintaining
the flexibility and optimization of its hydro generation, and ensuring Avista continues to serve its customers with
reliable and cost-effective energy.
Our People – Our employees are essential: Through them we deliver value to our customers and the communities
we serve. Joining the Western EIM has a tremendous impact on the employees at Avista with day-to-day
operational changes and the re-engineering of business processes to conform with market standards.
Perform – Our focus on performance today is critical to serving our customers well and unlocking pathways to
growth. In order to join the Western EIM, Avista has to commit to three solid years of planning and delivery of
generation, substation and technology projects, and continue to prioritize the effort in order for on-time market
entry.
Invent – The activities that yielded yesterday’s successes will not be sufficient to meet the challenges of
tomorrow. The way Avista has historically operated in a bi-lateral market won’t be sufficient for cost-effective
operations in the future – joining the Western EIM will help Avista balance renewable energy integration, while
providing reliable and cost-effective energy.
Areas of Focus:
Our Customers X
Our People X
Perform X
Invent X
1 For initial setup costs incurred prior to the go-live date in 2022, it is Avista’s intention that capital costs would be recovered in
general rate proceedings, just like all other utility capital additions. If allowed in Idaho, any incremental expense related to initial EIM
setup may be included in the PCA (Avista has requested such treatment in the 2019 Idaho General Rate Case). The treatment for
incremental setup expense in Washington is under evaluation by Avista.
Page 3 of 21
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Schedule 6, Page 3 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 4 of 21
2.4 Program Tracks
The following outlines the planned tracks for this Program. In keeping with the CAISO’s project management
expectations, the Program will be structured through various tracks, with multiple efforts/projects under each
track. Progress reporting to the CAISO will be in terms of these tracks. The CAISO track schedule will be in place
about 18-22 months prior to go-live initiation. Between Q1 2019 and that time, Avista will prepare for the EIM
entry with program planning, design, requirements gathering, the selection of a third party organized market
System Integrator and the procurement of EIM-related software. See Appendix A for the CAISO Track Timeline.
Avista Track 0 – Avista EIM Program Preparation: This track represents the body of work Avista must
complete to be ready to join the CAISO schedule. It includes program planning, requirements gathering and
design, System Integrator selection and software procurement.
CAISO Track 1 – Planning and Project Management: This track will ensure project management and oversite
coordination between CAISO and Avista. It includes developing planning documents, project schedule, status
reports, issue and risk tracking, overall readiness checklists and any other planning and controlling
documents, process and activities to support a successful implementation of the program.
CAISO Track 2 – Policy, Legal and Support Track: This track will ensure Avista reviews and signs the
appropriate CAISO entity agreements – a combination of EIM Entity (Transmission System Operations) and
EIM Participating Resource (Merchant) – based on a joint Avista-CAISO schedule. Changes to Avista’s Open
Access Transmission Tariff (OATT) will be accommodated within this track.
CAISO Track 3 – Modeling of Transmission and Generation Assets: This track ensures Avista’s transmission
and generation assets are integrated with several CAISO systems, specifically Avista’s Transmission Full
Network Model with the CAISO’s Energy Management System (EMS) and the Master File. The Master File
specifies many generation and intertie resources for the purposes of scheduling, bidding and settlements.
CAISO Track 4 – System Integration and Testing: This track ensures the required Avista’s EIM-related
software integrates with the CAISO systems and are functioning as designed to ensure the EIM runs
successfully for existing and new participants. Prior to, and concurrent to this track, Avista will need to
implement the various EIM-related software solutions, enhance in-house applications and build
integrations. This currently includes implementing several new software solutions that impact Enterprise
Technology, Generation Production and Substation Support, Transmission System Operations, Power Supply
and Resource Accounting.
CAISO Track 5 – Metering and Settlements: This track ensures various Avista metering activities are
successful in the EIM for physical metering and meter data accuracy. Physical metering, associated with a
market resource like a generation facility or an interconnection point, and the identification and
classification of relevant metering components must meet existing CAISO metering standards and accuracy
ratings. Meter data accuracy speaks to the validation of market resource configurations and related
metering components in alignment with the market resources’ physical characteristics and participation
level within EIM.
CAISO Track 6 – Operations Training and Readiness: This track provides a series for training events
throughout the EIM implementation time. This includes computer-based training, in-person training, EIM
workshops, trainer visits to the CAISO and training support for phased steps to production: Day in the Life,
Parallel Operations and Go-Live initiation.
2.4.1 Program Requirements by Track
Track Scope
Track 0 Avista EIM Program Preparation Avista program structure, leadership, documentation, change
management plan, internal project schedule, software procurement
and contracting
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Exhibit No. 8
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Schedule 6, Page 4 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 5 of 21
Track 1 Planning & Project Management Joint Avista-CAISO project plan and schedule
Joint impact assessment document
Avista go-live support plan document
Joint checkpoint, next step, progress evaluation meetings, etc.
Joint monthly project leadership meetings
Joint quarterly executive meetings
Track 2 Policy, Legal, Support EIM Entity Implementation Agreement
EIM Entity Agreement
EIM Entity Scheduling Coordinator (EESC) Agreement
EIM Participating Resource Scheduling Coordinator (PRSC)
Agreement
EIM Participating Resource Agreement
Avista Open Access Transmission Tariff (OATT)
Track 3 Transmission & Generation Modeling Transmission Full Network Model (FNM) creation & maintenance
Master File creation
EIM Transmission System Operations desk & remodel
Track 4 System Integration & Testing Acquire & configure Generation Outage Management software
Acquire & configure Transmission Outage Management software
Acquire & configure Participating Resource Scheduling Coordinator
(PRSC) bidding & scheduling software (merchant)
Acquire & configure EIM Entity Scheduling Coordinator (EESC)
scheduling software (transmission)
Acquire & configure PRSC settlement software (merchant)
Acquire & configure EESC settlement software (transmission)
Acquire & configure reporting software
Enhance Avista Decision Support System (ADSS) functionality
Enhance Nucleus functionality
Integrate EIM software systems
Integrate EIM software with CAISO systems
Integrate Avista Energy Management System (EMS) to CAISO EMS
Pre-production testing with CAISO – Day in the Life phase
Pre-production testing with CAISO – Market Simulation phase
Pre-production testing with CAISO – Parallel Operations phase
Track 5 Metering & Settlements Low-Side Metering (LSM) /unit level metering at some generation
plants
High-Side Metering (HSM) installation at some generation plants
Current Transformer (CT) / Potential Transformer (PT) testing and
applicable upgrades
Installation of a Schweitzer Engineering Laboratories SEL-735
revenue quality meter at generation and substation/interconnection
locations
Interconnection meter upgrades at some substations
Network and communications installations/upgrades
Install new instance of Itron’s MV90 xi for meter data collection
Generation plant Programmable Logic Control (PLC) upgrades
Modify Oracle Meter Data Management system for EIM meters
Submission & approval of Settlement Quality Meter Data (SQMD)
plans and metering portfolio to CAISO
Track 6 Operations Readiness & Training Create internal EIM training plan
Complete CAISO EIM computer-based training modules
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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 5 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 6 of 21
CAISO conducts hands-on training for Avista
Develop internal operational EIM procedures
File internal operational EIM procedures with CAISO
Complete CAISO market readiness criteria worksheet
CAISO provides planned go-live operations procedure documents
Avista files market readiness certificate with FERC prior to go-live
CAISO files market readiness certificate with FERC prior to go-live
Develop & implement EIM operations & support model
2.4.2 Generation Production & Substation Support Requirements
In accordance with CAISO Track 5 Metering and Settlements, there are various High Side Metering (HSM) and Low
Side Metering (LSM) metering improvements, PLC installations or upgrades, and accuracy testing of CTs/PTs that
Avista must perform. This also requires the installation and upgrade of network communications. How Avista
decided to register their generation plants with the CAISO will influence what metering and controls work is
actually performed. There are various resource registration options, but the most common represent registering
at the unit level or at the aggregate plant level. Avista will progressively work through resource registration
decisions as market knowledge and generation asset details are known. In addition, a discussion with the CAISO
about Avista’s current metering and generation portfolio will also influence the resource registration and bidding
strategy. Based on current plant capabilities and EIM understanding, the following body of work is planned for the
Energy Production business line, specifically Generation Production and Substation Support (GPSS), with support
from Enterprise Technology and Energy Delivery. The following sites are Electric Allocated North jurisdiction.
High Side Meters Projects EIM PLC Projects
Low Side Meters Projects CT/PT Testing Expense
2.4.3 Substation Interconnection & Third-Party Generation Requirements
In accordance with CAISO Track 5 Metering and Settlements, the upgrade to revenue-quality metering with the
installation of an SEL-735 meter and the associated network communications is required. Based on the current
capabilities at these sites and Avista’s EIM understanding, the following sites are planned for the Energy Delivery
business line, with support from Enterprise Technology and Energy Production. The following sites are Electric
Allocated North jurisdiction.
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Exhibit No. 8
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Schedule 6, Page 6 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 7 of 21
Substation Interconnection Sites Third-Party Generation Sites
Burke Fighting Creek
Colbert Spokane Waste-to-Energy
Dry Creek Clearwater Paper Company
Deer Park Plummer Saw Mill
Dry Gulch Upriver
Kettle Falls Palouse Wind (Thorton)
Lolo Solar Select (Lind)
Loon Lake
Mead
Milan
North Lewiston
Noxon 13kV
Noxon Switch
Opportunity
Orofino
Priest River
Sagle
Spirit
Stratford
Warden
Westside
Wilbur
2.5 Where will assets or technology be deployed?
The EIM Program has a range of physical assets that will be installed and a variety of technology applications that
will be deployed. Physical assets, such as meters, and technology assets, such as networking and communications
equipment, will be deployed at various locations, including Avista generation plants, third-party generation
locations and substation facilities. Technology application assets will primarily be deployed at Mission campus,
Avista’s disaster recovery center in San Jose, CA, and through various cloud-based providers utilizing the Software
as a Service or SaaS model.
3 EIM Program Milestones
The below milestones represent internal dates Avista must meet to coincide with the CAISO-driven milestone
schedule in Section 4. All installation and development work must be complete in production by September 2021 in
order to start a multiple phase 6-month testing obligation with the CAISO. Individual project schedules will be
created and managed to drive internal and external resources to meet the September 2021 date.
Description Target date for completion/approval





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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 7 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 8 of 21
EIM software installations
ADSS & Nucleus enhancements
EIM software integrations
GPSS meter installations
Substation meter installations
Network communication installations
GPSS generation controls installations
SCADA upgrades
09/2021
09/2021
09/2021
09/2021
09/2021
09/2021
09/2021
09/2021
System Integration & Testing with CAISO 09/2021 to 03/2022
All EIM Systems Go-Live with CAISO 04/2022
All EIM Technology Systems Warranty 07/2022
Program Closing
Program level Lessons Learned
Program Level Approval to Close
09/2022
10/2022
3.1.1 CAISO Project Milestones
The below schedule represents the CAISO driven project schedule for EIM entry by April 2022. The milestones
listed reflect payment to the CAISO of $50k per milestone, for a total, one-time fee of $300k to join the EIM
market. In order to meet these milestone dates, Avista must perform the work listed in the Section 2.5.
CAISO-Avista Project Scope and Milestones Project Delivery Dates
supporting April, 2022
Detailed Project Management Plan
The Parties will develop and initiate a final project management plan that
describes specific project tasks each Party must perform, delivery dates,
project team members, meeting requirements, and a process for approving
changes to support completion of the Project. This phase will include a
detailed IT system review to assist Avista in development of a detailed
metering plan, bid-to-bill system and coordination with Avista EMS. Work
will be initiated on the Avista staff training program using the foundational
and detailed system computer-based training module, as well as on the
resource data templates needed during Milestone 2.
March 2019-
December 2019
Milestone 1 – This milestone is completed when the Agreement has
been made effective in accordance with Section 1 of the Agreement.April 2020
Full Network Model Expansion
Full Network Model expansion for Avista and EMS/SCADA including: proof of
concept of export/import of EMS data, complete model into the CAISO test
environment, complete validation for all SCADA points from Avista, testing of
the new market model and validation of the Outage and State Estimator
applications.
November 2020
Milestone 2 – This milestone is completed upon modeling Avista into
the CAISO Full Network Model through the EMS which will be
July 2021
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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 8 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 9 of 21
deployed into a non-production test environment using the CAISO's
network and resource modeling process.
System Implementation and Connectivity Testing
System requirements and software design, the execution of necessary
software vendor contracts, development of Market network model including
Avista, allow Avista to connect to a non-production test system.
August 2021
Milestone 3
CAISO to promote market network model including Avista area to non-
production system, and allow Avista to connect and exchange data in
advance of Market Simulation.
September 2021
Construction, Testing and Training in Preparation for Market Simulation -
This task includes IT infrastructure upgrades, security testing, training, Day-in-
life simulation and functional testing.
September 2021
Milestone 4a
Start of Joint Integration Testing with CAISO, Interface testing with
minimum data requirements and functional integration testing. CAISO
will make the test environment available for Avista connectivity testing
prior to the delivery date assuming Avista has provided all prerequisite
data and non-production system availability does not conflict with
CAISO production system Spring Release schedule.
September 2021
Milestone 4b – Begin ‘Day in the Life’ scenario testing November 2021
Milestone 4c – Begin Structured Market simulation
(Milestone 4 payment due at this point)December 2021
Activate Parallel Operations
During January 2022, the CAISO will activate a parallel operation
environment to practice production grade systems integration as well as
market processes and operating procedures in anticipation of the impending
Avista activation as an EIM Entity and to confirm compliance with the EIM
readiness criteria set forth in the CAISO tariff.
January 2022
Milestone 5 – Start of parallel operations February 2022
System Deployment and Go Live
Implementing the Project and going live will include resource registration,
operating procedures and updates, execution of service agreements,
completion of the Avista tariff process, applicable board approvals, the filing
March 2022
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 9 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 10 of 21
and acceptance of service agreements and tariff changes with FERC, and
completion and filing of a readiness criteria certification in accordance with
the CAISO tariff.
Milestone 6 – This milestone is complete upon the first production
Avista EIM trade date.April 1, 2022
4 Assumptions, Risks, Constraints & Dependencies
4.1 Assumptions
The following assumptions have been made:
a)All Avista required program/project resources will be available for the duration of the program.
b)All the necessary funding to complete the program will be available.
c)All Avista business users will be available for application and system User Acceptance Testing (UAT).
d)Avista will hire a third-party System Integrator to provide EIM subject matter expertise.
e)For EIM systems that must integrate directly with the CAISO systems, Avista will select software
solutions under a SaaS model. It’s anticipated Avista will chose on premise solutions for Itron’s MV90 xi
software for metering and General Electric software needed for the Full Network Model. Under the SaaS
model, Avista will pay for vendor services, but not purchase software application licenses.
f)The technology system selection and procurement process will have priority within the Supply Chain and
Legal departments.
g)The Avista Decision Support System (ADSS) will be enhanced for EIM functions.
h)The Nucleus application will have minor modifications for EIM functions.
i)The existing customer Oracle Meter Data Management (MDM) application will be enhanced for EIM
meters and functions.
j)A new instance of MV-90 xi will be installed for EIM meters, with the intent that a consolidation effort
will be conducted in three to five years to transfer non-Advanced Metering Infrastructure (AMI) meters
from the existing MV-90 instance to the new EIM MV-90 instance.
k)The MDM EIM-related enhancements and the proposed Oracle Customer Care and Billing (CCB)/MDM
upgrade should not present priority or development conflicts with EIM.
l)After Avista has signed the CAISO implementation agreement, a discussion with the CAISO will occur
about the state of Avista’s generation/interchange metering portfolio. It’s assumed this meeting will
occur within two months of signing the agreement and the some level of negotiation will occur
regarding metering upgrades prior to go-live.
m)For EIM purposes and funding, if Avista registers generation facilities at the aggregate level, each facility
will either have HSM or LSM improvement work, but not both funded by EIM. Directionally speaking,
and for the purpose of GPSS outlined work, the metering approach assumes aggregate resource
registration.
n)Avista will receive the needed permissions from various third-party generation and metering entities to
perform EIM-related upgrades. Avista will fund EIM-related upgrades at various third-party sites.
o)Avista will procure an Energy Management System (EMS) plug-in for EIM market dispatch integration,
but a complete EMS upgrade will not be required.
p)Avista has plans to fund a 24-hour operations center within the next three-five years, and house various
operational business units, including Transmission System Operations. As such, the construction effort
and costs for the EIM transmission operations desk at Mission campus and the Backup Control Center
(BuCC) should be kept minimal.
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 10 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 11 of 21
q)The in-flight GPSS funded Human Machine Interface (HMI) project and the EIM-related PLC projects,
have independent scope. The HMI project’s goal is to standardize plant control screen display for plant
operators, and the EIM PLC projects will capitalize on that standardization to display EIM data. If the
HMI project is complete at the site where an EIM PLC project is needed, the new HMI screens will be
updated to incorporate EIM data. If the HMI project has not begun at a site where an EIM PLC project is
needed, the existing HMI screens will be updated with EIM data until the HMI project is available to
update that site.
r)The Outage Management software projects for transmission and generation will start Q1 2020 and
finish in Q3 2020, as the features/software is used and useful in today’s business environment
regardless of EIM participation.
4.2 Risks
Program level risks will be managed through a spreadsheet and posted to a common work space accessible by
EIM project team members. Program risk will be discussed at steering committee meetings for mitigation
recommendations and decisions. A Risk Management plan will be documented as necessary to identify mitigation
plans the Director and Executive Steering Committee members may take action on. The following are potential
risks for this program:
a)Interdependencies and integrations between EIM software projects will add complexity and may delay
completion.
b)Competing priorities amongst other Avista programs/projects may constrain funds and resource
availability. Resource areas that are likely to be constrained include network engineers, substation
engineering and design, and generation engineers.
c)This program requires multiple, concurrent projects to be in flight at the same time, while competing for
the same business resources and possibly technology resources.
d)The CCB/MDM application upgrade is scheduled to begin in 2019 and will likely take 14 months to
complete. The complexity and timing of the upgrade may adversely affect EIM-related enhancements.
e)Avista may not be able to meet all the meter upgrades across all generation facilities by the given April
2022 go-live date.
f)If all the software Request for Proposal documents aren’t issued by Q4 2019, the software
implementation timeline will be at risk.
g)If resources across multiple business units aren’t available for EIM planning and implementation, the
April 2022 date will be a risk.
h)Delays in business processes re-engineering based on EIM requirements and complexities will impact
the program/project schedule.
i)Joining the Western EIM presents a large amount of organizational business change that will require an
Organizational Change Management (OCM) plan. Avista doesn’t have a dedicated OCM champion and
this role is critical to the program’s success and employee adoption of the EIM practices.
j)Third-party generation sites don’t have clear business ownership – a business owner must be identified
to ensure these projects are completed.
k)It’s unknown as to who will perform EIM-related work at third-party generation sites – Avista
contracted, external contract or the generation owner.
l)The in-flight HMI project utilizes the same ET resources needed for EIM-related projects that could cause
delays in completing work.
4.3 Constraints
The program schedule is the hard constraint. Avista has signed the CAISO implementation agreement with an EIM
entry date of April 1, 2022. As such, we will conform to the CAISO implementation schedule and dates. In order to
meet that date, Avista will chose to adjust scope and budget as necessary.
Given a fixed schedule, we will choose a scope and adjust resources as necessary.
Place one “X” in each column (one per row) to provide a visual queue as to this project’s Flexibility Matrix.
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 11 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 12 of 21
Flexibility Matrix Low Flexibility Medium Flexibility High Flexibility
Scope X
Schedule X
Budget X
o Note: Quality is always expected to be high
4.4 Dependencies
Given the vast business impact of the EIM program, there are multiple and concurrent projects that rely on other
portions of a project being complete, or must be satisfied in order for EIM work to be completed.
4.4.1 GPSS Dependencies
a)The EIM dispatch of Little Falls depends on Long Lake EIM dispatch, however does not depend on Long Lake
for HSM or PLC projects.
b)The Long Lake LSM, HSM and PLC projects all depend on the Long Lake Overhaul project. The schedule for
this project is TBD.
c)The Cabinet Gorge LSM, HSH and PLC projects all depend on the Cabinet Gorge Automation Project for Unit
2, 3 and 4.
d)Network assessments are required for LSM projects at Cabinet, Coyote Sprints, Lancaster, Boulder Park,
Northeast, Post Falls, Nine Mile and Upper Falls.
e)All LSM, HSM and PLC projects have some level of dependency on each other across the plants
f)Both LSM and HSM projects will require outages.
g)The CT/PT accuracy testing efforts will require outages and must be started by Q3 2019.
h)The needed transformer repairs must be complete at Coyote Sprints 2 before HSM can be started.
i)Coyote Springs 2 and Lancaster both rely on third-party PTs and will Avista will need permission prior to
performing EIM-related work.
j)The completion of HSM projects will require completion of the PLC and network projects.
4.4.2 Network Dependencies
a)Wide Area Network (WAN) Performance Improvement Project – improve routing integration of Avista
Private Transport network and Carrier Transport network. This project is not within the EIM Program.
b)SIP Project– Session Initiation Protocol – increase network bandwidth to Backup Control Center (BUCC). This
project is not within the EIM Program.
4.4.3 Transmission System Operations/SCADA Dependencies
a)The Avista management and operation of the Transmission Full Network Model (FNM) should be complete
and operational prior to deployment of Transmission Outage Management software
4.4.4 Substation Dependencies
a)The substation metering site projects must be conducted in the following sequence – integration design,
substation design, circuit delivered to site and construction.
b)All substation project scheduling is dependent on the network team delivering Internet Provider (IP) circuits.
c)The Colbert substation Critical Infrastructure Protection (CIP) project must be complete before EIM-related
work can begin.
5 Compliance and Controls
Each individual project under the EIM Program will conform to the Avista compliance and control standards.
Area Required (Y/N)
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 12 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 13 of 21
Compliance Impact Assessment (contact: James McDougall) Y
Business Continuity Plan (contact: Erin Swearingen) Y
Reliability Compliance (NERC) (contact: Erin McClatchey) Y
SOX Business Controls Impact Assessment (contact: Stacey Wenz) Y
SOX Computer Controls Impact Assessment (contact: Matt Williams) Y
PCI (Payment Card Industry) Compliance Assessment (contact: Matt Williams) Y
6 Program Financial Structure & Cost Estimates
6.1 Program Financial Structure
The EIM Program will follow one Expenditure Request (ER), with multiple Budget Items (BI) grouped by business
area and vice president. The Expenditure Request (ER) organization E55 is Power Supply. Multiple projects will be
established under each Budget Item (BI). For financial tracking, each EIM project will reference the Parent Project
ID of EIM422.
Energy Imbalance Market / Parent Project ID – EIM422
ER ER 7141 – Energy Imbalance Market / ER Sponsor ORG E55
VP Heather
Rosentrater
Jim
Kensok
Heather
Rosentrater
Jason
Thackston
BI Transmission
Substation
Engineering
System Ops
SCADA
Upgrades
Transmission
High Side
Metering Network
Hardware/
Software
Transmission
Remodel
Low Side
Metering
High Side
Metering
Generation
Controls
BI XS907/M08 YS908/D56 XS909/M08
19N09 /
N09
20N09 /
N09 19N07/H07 AG19/A07 AG020/A07 AG021/A07
6.2 Total Program Cost Estimates
The EIM Program costs have been estimated and refined with input from engineers, developers and subject
matter experts from Generation Production and Substation Support, Transmission Substation Engineering,
Enterprise Technology, Transmission System Operations and Power Supply. In addition, our estimates have been
refined with input from Utilicast, a third-party EIM System Implementer Avista has engaged with. The estimating
effort resulted in a range, and the numbers below represent the low side of the range with a 25% contingency
assigned.
6.3 Program Cost Estimates by Business Area
The below estimates represent EIM cost estimates by business area and excludes contingency.
EIM Program Estimates Implementation Contingency Totals Annual O&M Expense
Capital $18,129,000 $4,532,250 $22,661,250
Expense $2,380,000 $595,000 $2,975,000 $3,534,000
Pre-Paid Expense $840,000 $210,000 $1,050,000
Total Costs $21,349,000 $5,337,250 $26,686,250 $3,534,000
Business Area Implementation
Capital
Pre-Paid
Expense*
Implementation
Expense
Annual O&M
Expense
ET Applications $4,640,000 $840,000 $593,000
Application Procurement $1,180,000
ET Network $2,465,000 $271,000
GPSS $5,164,000
Transmission & Substation $1,760,000 $420,000
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 13 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 14 of 21
*The desired EIM software solutions will be purchased under a SaaS model, with the exception of the Itron’s MV90 xi software
for metering and the General Electric software needed for the Full Network Model. Under the SaaS model, Avista will pay for
vendor services, but not purchase software application licenses. The Pre-Paid Expense estimate was based on 40% of the
estimated software licensing costs of $2.1M.
**The above chart estimates 11-13 additional Avista FTEs amongst Power Supply, Transmission System Operations, Resource
Accounting, Risk, Compliance and Enterprise Technology. These estimates, along with additional departmental impacts, are not
final and will be reevaluated throughout the program.
7 Roles and Responsibilities
7.1 Program Organization Chart
The below program organization chart represents information known at the time of document submission. The
organization chart will be a living document with updates and additions throughout the duration of the program.
The organization chart(s) will be made available on an internal common work space.
7.2 Executive Sponsor(s)
EIM Program $4,100,000 $780,000 $120,000
New Avista FTEs** $2,550,000
Total Costs $18,129,000 $840,000 $2,380,000 $3,534,000
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 14 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 15 of 21
The Executive Sponsors are ultimately accountable for the success of the EIM Program, but have delegated
accountability for day to day activities to Program Sponsors. The Executive Sponsors will finalize fundamental
program philosophies, provide a platform for decision making for the program, as required, and facilitate
communication with executive leadership, as necessary. In accordance with the CAISO implementation plan,
Avista executives will meet with CAISO executives about program schedule and performance on a monthly to
quarterly basis throughout the implementation period. The Executive Sponsors for this program are Jason
Thackston and Heather Rosentrater.
7.3 Program Sponsor(s)
The Program Sponsors have been designated as an accountable resource for the EIM Program. The Sponsors will
provide support related to fundamental program philosophies, monitor overall progress of the program, provide
guidance to the program manager, and facilitate communication with senior leadership and project sponsors. The
Program Sponsors for this program are Scott Kinney and Mike Magruder.
The Program Sponsors have the following responsibilities:
Championing the project and raising awareness at the senior level
Approving strategies, implementation plan, project scope and milestones
Approving key organization/business decisions for the program
Resolving certain issues, policies, and change management
Driving and managing change throughout the organization
Meet regularly with CAISO management to ensure project is proceeding on schedule
Manage the contract with the System Integrator
7.4 EIM System Integrator
To ensure a successful implementation, Avista must establish a detailed integration plan to implement the
software, hardware, processes and strategies required to participate in the market. To support this effort, Avista
sought a CAISO EIM knowledgeable third party System Integrator to assist with the End-to-End Program
Implementation including Program Management, overseeing all aspects of the six CAISO integration tracks,
software selection and integration for all business units, business process and strategy development and training.
Avista has chosen Utilicast as their Western EIM System Integrator. They will provide the professional services
required to evaluate, design, implement and integrate EIM-related Commercial Off the Shelf (COTS) systems with
current Avista systems. In addition, they will assist with evaluating business processes and providing
recommended modifications to maximize efficiencies necessary to compile, analyze and deliver the necessary
information effectively. Utilicast will provide Subject Matter Experts related to the CAISO tracks to work with
Avista personnel.
Avista intends to sign two separate statements of work (SOW) with Utilicast for the EIM integration effort. The first
SOW will cover EIM planning and project design initiatives in 2019 that will further determine and define actual
integration efforts in 2020 through go-live in April of 2022. The 2019 focus will be on metering and generation
control requirements and design, generation bidding strategies, development of technology application Request
For Proposal (RFP) documents and selection of application vendors. After completion of the first SOW, Avista
intends to sign a second SOW with Utilicast for actual EIM implementation efforts, which would include a 3-6 month
warranty period. If Utilicast doesn’t adequately perform and meet the System Integrator requirements in 2019,
then Avista will have an opportunity to re-evaluate its relationship with Utilicast and potentially hire a new
consultant to perform EIM integration efforts starting in 2020.
In terms of vendor management, performance and expectations, Utilicast be managed by Scott Kinney, EIM
Program Sponsor.
7.5 Program Manager
The Program Manager (PgM) is responsible for managing the overall progress of the EIM Program and ensuring
Avista adheres to the CAISO-set project schedule. The Program Manager will work with the program sponsors and
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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 15 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 16 of 21
cross-department stakeholders to create a Program schedule that conforms with the CAISO schedule. The
Program Manager works with the various business unit project managers to maintain project schedule and
provide support, as needed, for the duration of the program. The PgM will make budget and scope decisions that
will not impact fundamental EIM Program philosophies or the EIM business case. The Program manager is
accountable to the EIM Program Sponsors and to both the Director and Executive Steering Committee. The
Program Manager for this program is Kelly Dengel.
The Program Manager is responsible for:
Championing the program and raising awareness at the senior level
Driving and managing change throughout the organization
Ensuring program priority is established and resources are allocated to the various projects.
Ensuring the timely and effective cooperation of all departments in providing information, and other
required assistance, to the project teams
Helping to remove obstacles and solve problems that are beyond the control of the Project Managers
Ensuring the various project are delivered on time within the CAISO project management plan
7.6 Lead Subject Matter Expert
The Lead Subject Matter Expert (SME) is responsible for learning EIM business requirements and processes, and
relating them to their various business areas to assess impact and influence change management. The SME should
have an overarching view of processes and functionality within their given business area, and know where to
incorporate EIM impacts. They will represent their given business area’s interests at EIM meetings, communicate
EIM changes within their organization, be the main contact for the PgM, and help facilitate and develop EIM
processes and business change for their areas.
7.7 Project Managers
The primary responsibility of the Project Manager (PM) is the complete and satisfactory execution of projects
within the EIM program for their business units. The Project Manager works closely with all stakeholders to
ensure risk is mitigated and contingency plans are created and delivered. The Project Manager will report
monthly, and on an as-needed basis, to the Program Manager on all-project related activities such as schedule,
scope, budget and risks. The Project Managers are accountable to their Departments and to the Program
Manager. All stakeholders can identify a risk and offer a solution(s) for mitigation, with meetings held by the
Project Manager to discuss recommendations. Delivery of risk assessment and contingency planning within the
project is a responsibility of the PM, with input from the Delivery Managers and the Program Manager. Based on
the severity of the risk, the contingency plan can be approved by the PM or the Program Manager, with ultimate
approval, if needed, from the Director Steering Committee. The Project Manager has the following
responsibilities:
Project planning and execution
Facilitate issue resolution
Resolve scheduling issues
Provide written plans and schedules templates
Define, track and maintain project schedule and budget
Ensure project follows project management principles
Manage communication between stakeholders
Ensure project is delivered to schedule and budget (report on deviations)
Manage project execution
Coordinate resource requirements
8 Steering Committee(s)
8.1.1 Executive Steering Committee
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Exhibit No. 8
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Schedule 6, Page 16 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 17 of 21
The primary function of the Executive Steering Committee is to ensure the EIM Program is given adequate
priority throughout the organization to ensure the success of Avista joining the Western EIM by the scheduled
April 1, 2022 date. The Executive Steering Committee will meet on a quarterly basis internally, and on an as-
needed basis. In accordance with the CAISO implementation plan, Avista executives will meet with CAISO
executives about program schedule and Avista performance on a monthly to quarterly basis throughout the
implementation period. The Executive Steering Committee is responsible for taking recommendations from the
Director Steering Committee and ultimately making Program level decisions for use of contingency funding. In
the unforeseen event that the EIM Program schedule is at risk, the Executive Steering Committee has the right
to review and adjust the EIM go-live date. The Executive Steering Committee would be responsible for this
decision. Members of the Executive Steering Committee and the Program Sponsors would be responsible for
this re-negotiation with CAISO.
8.1.2 Director Steering Committee
The primary function of the Director Steering Committee is to provide guidance and approval on key program
issues such as program objectives, budgetary control, resource allocation, cross business unit decisions and
decisions involving large expenditures. The Director Steering Committee will monitor and review the program
status, as well as provide oversight of the program deliverable rollout. The Director Steering Committee will
meet monthly.
The Director Steering Committee ensures program concepts and guidelines are established and maintained with
a holistic view. They ensure business objectives are being adequately addressed and the program remains under
control. In practice these responsibilities are carried out by performing the following functions:
Monitoring and review of the project at regular Steering Committee meetings
Providing assistance to the project when required
Controlling project scope as issues force changes to be considered, ensuring that scope aligns with the
agreed business requirements of project sponsor and key stakeholder groups
Resolving project priorities and conflicts; reconciling differences of opinion and approach
Address cross-functional issues
Formal acceptance of project deliverables
8.1.3 Director Steering Committee Approval Responsibilities
The Director Steering committee members will be informed on Program and project level decisions, and will
provide approval on Program documents. They are responsible for approving major program elements such as:
Prioritization of Program objectives and outcomes as identified in the EIM Program Business Case;
Deliverables as identified in the Program Charter
Budget, ensuring that effort, expenditures and changes are appropriate to stakeholder expectations;
Schedule adherence;
Risk management strategies, ensuring that strategies to address potential threats to the project's success
have been identified, estimated and approved, and that the threats are regularly re-assessed;
Project management and quality assurance practices.
9 Program Governance and Reporting
9.1 Reporting
The purpose of these procedures is to provide effective mechanisms to control the scope of the program, manage
issues and risks and monitor progress. Program level management of decisions and documents will be managed
through Clarity Project and Portfolio Management System. Enterprise Technology projects, and their associated
processes, will be managed within Clarity. Generation, transmission operations and substation projects will be
managed through their established project management processes and procedures. Each project artifact will
reference the EIM program with narrative related to EIM scope, CAISO track, requirements, and the financial
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 17 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 18 of 21
structure with the EIM Parent Project ID of EIM422 and the associated Expenditure Request (ER) and Budget Item
(BI).
9.2 Financial Control
Financial Controls will be managed at the program level with monthly financial reporting through Oracle reports,
with assistance from Financial Planning and Analysis team. The Program finances and forecasted spend will be
reviewed monthly with the Director Steering Committee and quarterly with the Executive Steering Committee.
The Capital Planning Group will also be kept informed of the Program Finances. The monthly financial reporting
documents will be posted to Clarity.
9.3 Change Control / Approval Authority
Program level authority sits with the EIM Director Steering Committee, and the Executive Steering Committee.
Ultimate approval authority sits with the Executive Steering Committee. The Executive Steering Committee is
responsible for taking recommendations from the Director Steering Committee and ultimately making Program
level decisions for use of contingency funding. In the unforeseen event that the EIM Program schedule is at risk,
the Executive Steering Committee has the right to review and adjust the EIM go-live date. The Executive Steering
Committee would be responsible for this decision. Members of the Executive Steering Committee and the
Program Sponsors would be responsible for this re-negotiation of the EIM Implementation Agreement with the
CAISO.
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 18 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 19 of 21
Approval Signatures
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Scott Kinney - 05.21.19.msg
________________________________________________
Scott Kinney, Director of Power Supply
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Andy Vickers 05.17.19.msg
_______________________________________________
Andy Vickers, Director of Generation Production and Substation Support
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Josh DiLuciano 06.03.19.msg
______________________________________________
Josh DiLuciano, Director of Electrical Engineering
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Mike Magruder - 05.29.19.msg
______________________________________________
Mike Magruder, Director of Transmission Operations and System Planning
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Jim Corder - 05.23.19.msg
______________________________________________
Jim Corder, Director of Information Technology and Secruity
RE EIM Program Charter Approval - Due May 22 - UPDATE - Hossein Nikdel - 05.22.19.msg
______________________________________________
Hossein Nikdel, Director of Applications and System Planning
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Adam Munson - 05.29.19.msg
______________________________________________
Adam Munson, Director of Accounting
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Pat Ehrbar - 05.22.19.msg
______________________________________________
Pat Ehrbar, Director of Regulatory Affairs
RE EIM Program Charter Approval - Due May 22 - UPDATE - Todd Colton - 05.29.19.msg
______________________________________________
Todd Colton, Senior Legal Counsel
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Heather Rosentrater - 05.29.19.msg
______________________________________________
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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 19 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 20 of 21
Heather Rosentrater, VP of Energy Delivery
Approve EIM Program Charter Approval - Due May 22 - UPDATE - Jason Thackston - 05.29.19.msg
______________________________________________
Jason Thackston, Senior VP of Energy Resoruces
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Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 20 of 21
Program Initiation Charter
Program Initiation Charter Avista Confidential Page 21 of 21
Appendix A
The following CAISO provided timeline provides a generic overview of track activity between July 2020 through April 2022. In the legend, Avista is the
Entity and CAISO is the Independent System Operator (ISO).
Document is no longer concidered confidential
Exhibit No. 8
Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 6, Page 21 of 21
Program Scope Summary
Program Scope Summary Avista Confidential Page 1 of 47
Program Name: Energy Imbalance Market
Program Manager: Kelly Dengel
Business Case Name: Energy Imbalance Market
Expenditure Request (ER): 7141 – Energy Imbalance Market
Submit Date: TBD
1 Key Roles & Program Information
Program Sponsor(s): Scott Kinney/
Mike Magruder
Business Case
Owner(s): Kelly Dengel
Business Program
Manager: Kelly Dengel Executive Steering
Committee Members:
Jason Thackston, Heather
Rosentrater, Jim Kensok,
Ryan Krasselt, Kevin
Christie
Director Steering
Committee Members:
Scott Kinney, Andy
Vickers, Mike Magruder,
Jim Corder, Hossein
Nikdel, Adam Munson, Pat
Ehrbar, Todd Colton
Other Stakeholders:
James Dykes, Robert Follini,
Annette Brandon, Jacob
Reidt, Kit Parker, Bob
Weisbeck, Tom Dempsey,
Alexis Alexander, Kristina
Newhouse, Glen Farmer,
Brad Calbick, Craig Figart,
Rip Divis, Kenny Dillon,
Mike Andrea, Glenn
Madden, Randy Spacek,
Lamont Miles, Brian
Hoerner, Xin Shane, Jason
Pegg, Carolyn Groome
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 1 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 2 of 47
2 Contents
1 KEY ROLES & PROGRAM INFORMATION ................................................................................................................................... 1
3 EXECUTIVE SUMMARY .............................................................................................................................................................. 3
4 PROGRAM CHARTER VS. SCOPE FINANCIAL ESTIMATES ............................................................................................................ 3
5 CAISO & AVISTA PROGRAM SCOPE OVERVIEW ......................................................................................................................... 3
6 AVISTA SCOPE BY CAISO EIM TRACK ......................................................................................................................................... 6
6.1 TRACK 0/TRACK 1 – AVISTA EIM PROGRAM / PLANNING & PROJECT MANAGEMENT SYSTEM INTEGRATOR – UTILICAST .................................. 6
6.2 TRACK 2 – POLICY, LEGAL, SUPPORT ................................................................................................................................................. 8
6.3 TRACK 3 – TRANSMISSION & GENERATION MODELING ......................................................................................................................... 9
6.4 TRACK 4 – SYSTEM INTEGRATION & TESTING ENTERPRISE TECHNOLOGY SOFTWARE SELECTION.................................................................. 11
6.5 TRACK 5 – METERING & SETTLEMENTS GENERATION PRODUCTION & SUBSTATION SUPPORT, INTERCHANGE & NETWORK INFRASTRUCTURE ..... 19
6.6 TRACK 6 – OPERATIONS READINESS & TRAINING ............................................................................................................................... 28
6.7 WHERE WILL ASSETS OR TECHNOLOGY BE DEPLOYED? ......................................................................................................................... 33
7 EIM PROGRAM MILESTONES ................................................................................................................................................... 33
8 PROGRAM ASSUMPTIONS, RISKS, CONSTRAINTS & DEPENDENCIES ....................................................................................... 36
8.1 ASSUMPTIONS ............................................................................................................................................................................ 36
8.2 RISKS ........................................................................................................................................................................................ 37
8.3 CONSTRAINTS ............................................................................................................................................................................. 38
8.4 DEPENDENCIES ........................................................................................................................................................................... 38
9 PROGRAM COSTS .................................................................................................................................................................... 39
9.1 ACTUAL COSTS AS OF AUGUST 2020 .............................................................................................................................................. 39
9.2 FORECASTED PROGRAM COST ESTIMATES AS OF AUGUST 2020 ........................................................................................................... 40
9.3 FORECASTED PROGRAM COST ESTIMATES BY BUSINESS AREA .............................................................................................................. 41
9.4 INCREMENTAL COST GUIDANCE & ESTIMATES ................................................................................................................................... 41
10 COST BENEFIT ANALYSIS ......................................................................................................................................................... 43
10.1 ANALYSIS BASED ON THE CHARTER ESTIMATES .................................................................................................................................. 43
10.2 ANALYSIS BASED ON SCOPE ESTIMATES ........................................................................................................................................... 43
11 ROLES AND RESPONSIBILITIES ................................................................................................................................................. 44
11.1 PROGRAM ORGANIZATION CHART .................................................................................................................................................. 44
12 PROGRAM GOVERNANCE AND REPORTING ............................................................................................................................ 44
12.1 REPORTING ................................................................................................................................................................................ 44
12.2 FINANCIAL CONTROL .................................................................................................................................................................... 44
12.3 CHANGE CONTROL / APPROVAL AUTHORITY ..................................................................................................................................... 45
13 DIRECTOR APPROVALS ............................................................................................................................................................ 46
14 EXECUTIVE APPROVALS........................................................................................................................................................... 47
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Program Scope Summary
Program Scope Summary Avista Confidential Page 3 of 47
3 Executive Summary
In May 2019, Avista leadership approved the EIM Program Charter outlining the total estimated costs associated with
joining the Western Energy Imbalance Market (EIM) operated by the California Independent System Operator (CAISO).
The Charter estimated $26.6 million in integration costs and $3.5-$4 million in on-going annual expense, and were
considered preliminary.
The Charter costs estimates drew from the 2018 Utilicast assessment results for technology and the metering/controls
upgrades, and provided an initial picture of the work required by Avista to integrate into the market, along with
estimates for on-going operations. For the remainder of 2019, Avista focused on high-level scope decisions, an initial
integrated project schedule and completing the Request for Proposal (RFP) phase for EIM software. In October 2019,
Avista also selected their System Integrator, Utilicast, and signed an Implementation Agreement for 2020-2022.
Throughout 2019 and into 2020, Avista continually acquired more market operations knowledge and gained a better
understanding of how Avista can meet market requirements, while balancing operational needs and financial
constraints.
After a year into the EIM integration effort and acquiring a better understanding of the market operation support needs,
Avista created a preferred employee resource plan (EIM Human Resource Plan) and the EIM Program Scope document.
Together, the documents represent updates to Avista’s EIM Program, incorporating updated software, metering and
network project designs and schedules, the resources needed for integration and operations, and the overall cost
estimates based on actual spend through August 2020 and remaining integration work. The updated EIM integration
cost estimate is $32.1 million, and the on-going annual cost estimate is $3.9 million. Based on this information, an
annual revenue of $7.8 million is needed to break even after 10 years of market operations. This annual revenue
estimate is within the range of benefits determined by analysis performed by Energy and Environmental Economics (E3)
in 2017. If Avista’s actual EIM system benefits are closer to the potential upper bound of the $12 million as determined
by E3 and experienced by other similarly situated EIM entities, then Avista customers will see positive revenue in a much
shorter time period.
4 Program Charter vs. Scope Financial Estimates
When Avista created its Charter estimates, an attempt was made to provide a total cost of ownership to join the EIM.
This included cost estimates for capital projects, expense for implementing the Program, including existing and
incremental labor, non-labor and on-going incremental costs associated with new hires and software maintenance. The
Charter estimates provided costs associated with a particular effort in multiple line items, rather than a single line item,
representing a total anticipated cost. The Scope document presents the estimates for the particular effort, as a single
line item, inclusive of all known costs. Where possible, a comparison of costs from the Charter to the Scope document
have been made with references to the Charter line item estimates. In some cases, cost estimates have been re-assigned
from one cost area to another, and a direct comparison is not available.
In terms of implementation, the effort to join the EIM requires both capital and expense activities. Specific to expense,
the Charter estimates identified expense deliverables and provided a cost estimate by assuming a number of man hours
needed to perform the task and multiplied it by $100 labor rate. It was primarily assumed these expense deliverables
would be completed by existing employees across multiple business units. As of July 1, 2019, Avista began charging
specific EIM expense projects across six business units. However, Avista did not create an individual expense project for
each expense deliverable. Although Avista has worked on many expense efforts, such as completing the CAISO
implementation agreements or documenting plant operation details for the Resource Data Template, the level of
expense reporting by individual item (deliverable) is not tracked to this level of detail within Company financial records.
5 CAISO & Avista Program Scope Overview
The CAISO has developed an implementation structure for market participants that includes six program tracks. A
description and the associated requirements of each of these six tracks is provided below along with an Avista
preparation track shown as track zero.
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
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Program Scope Summary
Program Scope Summary Avista Confidential Page 4 of 47
CAISO EIM Track Avista Scope
Track 0 Avista EIM Program Preparation
This track represents the body of work Avista
must complete to be ready to join the CAISO
schedule. It includes program planning,
requirements gathering and design, System
Integrator selection and software
procurement.
Avista program structure, leadership, documentation, change
management plan, internal project schedule, software procurement
and contracting
Select System Integrator
Track 1 Planning & Project Management
This track will ensure project management
and oversite coordination between CAISO
and Avista. It includes developing planning
documents, project schedule, status reports,
issue and risk tracking, overall readiness
checklists and any other planning and
controlling documents, process and activities
to support a successful implementation of
the program.
Joint Avista-CAISO project plan and schedule
Joint impact assessment document
Avista go-live support plan document
Joint checkpoint, next step, progress evaluation meetings, etc.
Joint monthly project leadership meetings
Joint quarterly executive meetings
Track 2 Policy, Legal, Support
This track will ensure Avista reviews and signs
the appropriate CAISO entity agreements –
a combination of EIM Entity (Transmission
System Operations) and EIM Participating
Resource (Merchant) – based on a joint
Avista-CAISO schedule. Changes to Avista’s
Open Access Transmission Tariff (OATT) will
be accommodated within this track.
EIM Entity Implementation Agreement
EIM Entity Agreement
EIM Entity Scheduling Coordinator (EESC) Agreement
EIM Participating Resource Scheduling Coordinator (PRSC) Agreement
EIM Participating Resource Agreement
Department of Market Monitor Filings
Market Base Rate Study
CAISO Implementation Milestone Payments
CASIO Grid Management Charge
Avista Open Access Transmission Tariff (OATT)
Track 3 Transmission & Generation
Modeling
This track ensures Avista’s transmission and
generation assets are integrated with several
CAISO systems, specifically Avista’s
Transmission Full Network Model with the
CAISO’s Energy Management System (EMS)
and the Master File. The Master File specifies
many generation and intertie resources for
the purposes of scheduling, bidding and
settlements.
Transmission Full Network Model (FNM) creation & maintenance
Integrate Avista Energy Management System (EMS) to CAISO EMS
Master File / Generation Participation & Cost Modeling
Major Maintenance Adders & Default Energy Bid logic
Energy Transfer System Resource (ETSRs)
Track 4 System Integration & Testing
Acquire & configure Generation Outage Management software
Acquire & configure Transmission Outage Management software
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Schedule 7, Page 4 of 48
Program Scope Summary

Program Scope Summary Avista Confidential Page 5 of 47
This track ensures the required Avista’s EIM-
related software integrates with the CAISO
systems and are functioning as designed to
ensure the EIM runs successfully for existing
and new participants. Prior to, and
concurrent to this track, Avista will need to
implement the various EIM-related software
solutions, enhance in-house applications and
build integrations. This currently includes
implementing several new software solutions
that impact Enterprise Technology,
Generation Production and Substation
Support, Transmission System Operations,
Power Supply and Resource Accounting.

Acquire & configure Participating Resource Scheduling Coordinator
(PRSC) bidding & scheduling software (merchant)
Acquire & configure EIM Entity Scheduling Coordinator (EESC)
scheduling software (transmission)
Acquire & configure PRSC settlement software (merchant)
Acquire & configure EESC settlement software (transmission)
Acquire & configure reporting & analytics software
Enhance & integrate Avista Decision Support System (ADSS)
Acquire & configure Energy Accounting software
Acquire & configure a E-Tagging solution
Enhance Nucleus functionality
Integrate EIM software systems
Integrate EIM software with CAISO systems
Pre-production testing with CAISO – Day in the Life phase
Pre-production testing with CAISO – Market Simulation phase
Pre-production testing with CAISO – Parallel Operations phase
Track 5 Metering & Settlements

This track ensures various Avista metering
activities are successful in the EIM for
physical metering and meter data accuracy.
Physical metering, associated with a market
resource like a generation facility or an
interconnection point, and the identification
and classification of relevant metering
components must meet existing CAISO
metering standards and accuracy ratings.
Meter data accuracy speaks to the validation
of market resource configurations and
related metering components in alignment
with the market resources’ physical
characteristics and participation level within
EIM.

Low-Side Metering (LSM) /unit level metering at generation plants
High-Side Metering (HSM) installation at generation plants
Current Transformer (CT) / Potential Transformer (PT) testing and
applicable upgrades
Installation of a Schweitzer Engineering Laboratories SEL-735 revenue
quality meter at generation and substation/interconnection locations
Interconnection meter upgrades at some substations
Network and communications installations/upgrades
Install new instance of Itron’s MV90 xi for meter data collection
Generation plant Programmable Logic Control (PLC) upgrades
Creation, submission & approval of Settlement Quality Meter Data
(SQMD) plans and metering portfolio to CAISO
Track 6 Operations Readiness & Training

This track provides a series for training events
throughout the EIM implementation time.
This includes computer-based training, in-
person training, EIM workshops, trainer visits
to the CAISO and training support for phased
steps to production: Day in the Life, Parallel
Operations and Go-Live initiation.
Create internal EIM training plan
Complete CAISO EIM computer-based training modules
CAISO conducts hands-on training for Avista
Develop internal operational EIM procedures
File internal operational EIM procedures with CAISO
Complete CAISO market readiness criteria worksheet
CAISO provides planned go-live operations procedure documents
Avista files market readiness certificate with FERC prior to go-live
CAISO files market readiness certificate with FERC prior to go-live
Develop & implement EIM operations & support model
EIM Human Resource Plan
EIM Transmission System Operations desk & remodel at BuCC
EIM Transmission System Operations desk & remodel at Mission
Noxon 230kV Switchyard CIP Compliance

Document is no longer concidered confidential
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 5 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 6 of 47
6 Avista Scope by CAISO EIM Track
6.1 Track 0/Track 1 – Avista EIM Program / Planning & Project Management
System Integrator – Utilicast
6.1.1 EIM Program & Project Management Establishment
After announcing EIM entry and signing the Implementation Agreement, Avista began to organize the Program
integration team across the impacted business units and established core team members who would be charged with
implementing and managing the work. In February 2019, Avista hired the EIM Program Manager to establish the
program structure and governance, gather financial estimates and identify work streams across the impacted business
units. This also included identifying leadership roles, subject matter experts, project managers and engineers. The
Program was also tasked with educating Avista teams about the organized market structure and what requirements
Avista would need to fulfil in order to participate.
The Program Manager began communication with the CAISO project management office to aligning internal Avista
milestones with CAISO-driven milestone dates. Monthly track calls have been established with the appropriate CAISO,
Utilicast and Avista Subject Matter Expert representatives to understand deliverables and milestones, which have been
progressively discussed and incorporated into Avista’s overall Program schedule.
The Director Steering Committee began meeting in March of 2019, and the Executive Steering Committee met quarterly
in 2019 and moved to monthly meetings in 2020. In December 2019, the first joint Avista/CAISO Executive meeting was
held and are subsequently planned for quarterly updates through go-live. See Section 12 for information on the project
governance structure.
6.1.2 Utilicast – System Integrator
Avista engaged with Utilicast in three phases, with the intent to progressively evaluate performance and value before
signing additional EIM integration support agreements. Phase 1 in 2018 focused on the technology, metering and
network model assessment, helping Avista understand the CAISO requirements and processes, and identifying the gaps
to be filled. After soliciting responses for a System Integrator via a Request for Information (RFI) proposal, Avista agreed
to a sole sourcing engagement with Utilicast in an effort to continue the partnership as their System Integrator. This led
to a phase two agreement in 2019 that focused on metering and generation control requirements and design,
generation bidding strategies, development of technology application requirements and RFPs and the
evaluation/selection of EIM software vendors. The phase three engagement was signed in December 2019 and focused
on the program implementation efforts through go-live of 2022.
Under this program implementation agreement, Utilicast will provide Subject Matter Experts to evaluate, design,
implement and integrate EIM-related Commercial Off the Shelf (COTS) systems with current Avista systems. In addition,
they will assist with evaluating business processes and providing recommended modifications to maximize efficiencies
necessary to compile, analyze and deliver the necessary information effectively. Utilicast will also engage in all aspects of
the EIM Program, provide project management expertise and are uniquely positioned to assist Avista with a successful
market entry.
6.1.2.1 Utilicast Financial Summary Estimate
The 2018 Utilicast Assessments were completed in 2018 and were not included in the Program Charter estimates. The
2019 Technology RFP was reflected under Charter Line Item 10 “System Selection & Procurement” with a $500k expense
estimate for Utlicast and $680k for Avista labor. Utilicast actuals for the Technology RFP are listed in Table 1 and Table 9.
Estimates for Avista labor are listed in Table 9. The Utilicast agreement was signed with a do not exceed amount of
$600k and we completed the SOW with an actual spend of $508k.
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Schedule 7, Page 6 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 7 of 47
The 2020-22 Utlicast Implementation Agreement costs were included under Charter Line Item 9 “Program Leadership,
Management & SMEs” at $3.2 million in capital. After further evaluation of market integration requirements, project
management support, and subject matter expertise, the final Utilicast Implementation Agreement included estimated
contract costs of $3.7 million capital and $1.6 million Operations and Maintenance (O&M) expense to support market
integration efforts. Some of the increased Utilicast costs offset internal Avista labor.
Table 1 – Utilicast Agreements
When the 2020-22 Implementation agreement with Utilicast was signed, each deliverable was assigned an expense or
capital indicator, which allowed for an estimate of annual expense and capital charges by year. These estimates were
not known at the writing of the Program Charter, as the Implementation Agreement was not signed until October 2019.
In September 2020, the expense forecast associated with the Implementation Agreement was reduced by $450k based
on the 2020 actual spend and a review of scheduled deliverables. The primary drivers for the Utlicast expense are
associated with training, business process design and generation/interchange modeling.
6.1.2.2 Utilicast Implementation Agreement 2020-2022
At the time of the Charter, Avista estimated $3.2M of Utilicast capital labor to support the EIM implementation under
the Charter capital Line Item 9 “Program Leadership, Management & SMEs.” This line also contained $700k in Avista
labor for capital efforts that have been included in the EIM software estimates. This Utilicast estimate did not include an
estimate for O&M expense. The assignment of deliverables also corresponded with a CASIO project track and an Avista
business unit. By grouping these deliverables, an estimate of capital spend by business unit and a total estimate of
expense was projected. Although the Utilicast expense items may align with a specific business unit, the expense costs
will be charged to the Power Supply business unit. The Charter estimates did not assign Utilicast labor to individual
business unit estimates. In addition, Utilicast labor to support Avista’s Decision Support System (ADSS) enhancements
was included in the total Utilicast Implementation Agreement costs, but not be included in the EIM Program totals, as
ADSS EIM enhancements were planned for funding under a different business case.
Table 2 – Utilicast 2020-2022 Implementation Agreement Estimates by Business Unit
Agreement Year Capital Expense Capital Expense
Technology RFP (Line 10)2019 $ - $ 500,000 $ - $ 508,435
Implementation (Line 9)2020-22 $ 3,200,000 $ - $ 3,700,000 $ 1,150,000
$ 3,200,000 $ 500,000 $ 3,700,000 $ 1,658,435
Actuals
Scope Estimates (as of 08/2020)Utilicast Charter Estimates (as of 05/2019)
Totals
Business Units CAISO Track Capital Expense Capital Expense
ET Applications Track 4 $ 2,986,181 $ 2,986,181
ET Network Track 4 & 5 $ 67,060 $ 67,060
GPSS Track 5 $ 67,060 $ 67,060
Substation Track 5 $ 67,060 $ 67,060
Transmission Track 4 $ 40,000 $ 40,000
Facilities Track 6 $ - $ -
ADSS Track 4 $ 472,639 $ 472,639
EIM Program All $ - $ 1,600,000 $ - $ 1,150,000
Utilicast Totals $ 3,700,000 $ 1,600,000 $ 3,700,000 $ 1,150,000
Utilicast Implementation Agreement
(signed 10/2019)
Implementation Agreement
(as of 10/2019)
Scope Estimates
(as of 08/2020)
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
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Program Scope Summary
Program Scope Summary Avista Confidential Page 8 of 47
6.2 Track 2 – Policy, Legal, Support
This track ensures Avista reviews and signs the appropriate CAISO entity agreements – a combination of EIM Entity
(Transmission System Operations) and EIM Participating Resource (Merchant/Power Supply), conducts changes to the
OATT, and completes the necessary studies and filings for market participation.
6.2.1 Summary
EIM Agreements: In order to transact in the market, Avista needs to sign various CAISO Agreements to conduct
operations as a Merchant Scheduling Coordinator and Entity Scheduling Coordinator. These agreements allow
the Merchant and the Entity to transact in the market, while preventing the inappropriate sharing of
information and adhering to FERC Standards of Conduct. This agreement submission also includes items such as
financial forms, certifications, risk policies, and user and contact lists. A joint Avista-CAISO schedule for
completing the agreements has been made. These items were planned under the Charter implementation
Charter Line Item 13 “OATT, MBR & ISO Agreements” at $130k as Avista labor expense.
Open Access Transmission Tariff (OATT): Avista must make significant changes to its OATT to accommodate
transmission utilization in the EIM, change ancillary service charges and incorporate EIM financial settlement
obligations due to operating in the EIM. These OATT changes are also affected by the need to conduct a new
Market Base Rate analysis and submit the study findings to FERC for approval. These items were forecasted in
Charter Line Item 13 “OATT, MBR & ISO Agreements” at $130k as expense.
Market Base Rate Study: Market Based Rate (MBR) Authority represents permission granted by FERC to allow
power to be sold at market rates, as opposed to a traditional cost of service rate (aka cost-plus). Sellers seeking
market-based rate authority must prove to FERC that they have no ability to set market prices, or that there are
proper mitigations in place if there is an opportunity to set the price. A new MBR study is required to be
conducted and approved by FERC as part of the EIM registration process to ensure Avista doesn’t have the
ability to set the market price within the EIM. These items were planned under the Charter implementation
Charter Line Item 13 “OATT, MBR & ISO Agreements” at $130k as Avista labor expense.
Professional Services: The Program Charter provided an estimate for outside services to conduct the MBR study
and legal review of OATT changes. These items were planned under the Charter implementation Charter Line
Item 13 “OATT, MBR & ISO Agreements” at $105k of expense under the Solutions & Services column.
Department of Market Monitoring Filings: Although the business logic and collection of operational inputs
required to complete these documents are in Track 3 – Generation and Transmission Modeling, the negotiation
and filing of the documentation is under Track 2. Avista will submit filings for Major Maintenance Adders
(MMAs) and Default Energy Bids (DEB) by generation resource. The MMAs are one of the cost components in
the CAISO’s proxy cost calculation for start-up and minimum run hour load costs. The negotiated DEB is CAISO’s
process to mirror competitive market outcomes in the event that Avista is found to have an ability to
unjustifiably increase electricity prices during certain time frames at certain locations. The Program Charter did
not provide an estimate for this work, but it’s assumed the filing procedures can be included in the estimates for
the EIM Agreements, OATT, and MBR activities.
CAISO Milestone Payments: As part of the EIM Implementation Agreement, CAISO outlined six milestone
payments that align with CAISO’s set implementation schedule. Each payment is $50k and payable upon
meeting the milestone, for a one-time total implementation fee of $300k. Details of the milestone descriptions
can be found in Section 7. This item was planned as implementation expense in the Charter under expense Line
Item 18 “EIM Membership & Ongoing Fees” at $300k.
CAISO Grid Management Charge: The CAISO charges EIM participants a Grid Management charge based on the
amount of MWh transacted in the market. This estimate ($120k) was mislabeled in the Charter as CAISO Annual
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Fee. This item was planned as expense in the Charter under on-going, annual expense Line Item 18 “EIM
Membership & Ongoing Fees” at $120k.
6.2.2 Track 2 Policy, Legal, Support Financial Estimate Summary
With the exception of payment to CAISO for the filing of the scheduling coordinator agreements, a majority of the items
estimated in the Program Charter have not changed. Although the Charter did not provide an estimate for the ISO
Department of Market Monitoring filings, it’s assumed these filings can be accommodated under the expense estimates
for the EIM Agreements, OATT, and MBR activities. With the exception of the CAISO Grid Management Fee, the items
represented as expense are a one-time O&M charge. Although there isn’t a specific expense estimate for Utilicast under
this track, the support effort is represented in the EIM Program line in cost estimate tables.
Table 3 – Policy, Legal, Support Financial Estimates
6.3 Track 3 – Transmission & Generation Modeling
6.3.1 Existing State Prior to EIM
A vital step in every EIM implementation, is the integration the entity’s detailed electrical system model into CAISO’s
region-wide model; this electric system model is called the Full Network Model (FNM). It’s accompanied by the
development of the Resource Data Templates (RDT). This information is critical, as it allows the market to accurately
optimize resource dispatch, while respecting transmission reliability and contractual limits. It is each entity’s
responsibility to maintain a detailed model of their own system, and to provide timely updates to CAISO, including
planned construction and outage activities. Failure to provide and maintain an accurate representation of Avista’s
electrical system within CAISO’s model will lead to non-optimal market dispatches, which negatively impact market
settlements.
Prior to EIM entry, Avista used off-line models and hosted third-party solutions to perform the necessary analysis for
real-time operation of the electrical system. This was reasonable at the time, as maintenance of these real-time models
was very labor and time intensive. Modern systems now enable entities to more easily exchange model information,
thus reducing the labor and time required to manage the model. Avista will add the additional staffing and tools
necessary to build, manage, and maintain its own network model for real-time operations.
6.3.2 Transmission & Generation Modeling Scope Summary
6.3.2.1 Transmission Full Network Model Scope
During the EIM Program planning stages, Avista was in the process of transitioning providers for the Reliability
Coordinator (RC) function from Peak Reliability to RC West, operated by the CAISO. Avista began operations
under RC West on November 1, 2019. While operating under Peak Reliability, Avista contracted with Peak to
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
EIM Agreements (Line 13) $ - $ - $ - $ -
OATT (Line 13) $ - $ - $ - $ -
MBR (Line 13) $ - $ - $ - $ -
DMM Filings $ - $ - $ - $ - $ -
Professional Services (Line 13) $ - $ 105,000 $ - $ - $ 105,000 $ -
CAISO Payments (Line 18) $ - $ 300,000 $ - $ - $ 300,000 $ -
CAISO Grid Management Fee (Line 18) $ - $ - $ 120,000 $ - $ - $ 120,000
Totals $ - $ 535,000 $ 120,000 $ - $ 535,000 $ 120,000
Utilicast $ - $ - $ - $ - $ - $ -
Grand Totals $ - $ 535,000 $ 120,000 $ - $ 535,000 $ 120,000
Track 2 - Policy & Legal
$ 130,000
Scope Estimates (as of 08/2020)Charter Estimates (as of 05/2019)
$ 130,000
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
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Program Scope Summary Avista Confidential Page 10 of 47
provide hosted service and maintenance of the transmission network model, real-time state estimation, and
real-time contingency analysis. Under RC West, the same services have been provided.
During this RC transition period, Avista started a project to bring these crucial reliability functions in-house –
not only for RC purposes, but also for EIM. The development and integration of these tools into Avista’s
Supervisory Control and Data Acquisition Energy Management System (SCADA/EMS) is in flight and funded by
the SCADA/SOO/BuCC BC. The Program Charter provided a capital estimate for Utilicast support of the FNM
implementation under the Line Item 11 “Full Network Model for EIM” at $40k, which is still planned. Line Item
11 also had Avista FNM capital labor at $80k. The on-going labor expense associated with Line 11 is for a
portion of a new FTE to support the FNM at $50k (the other funding is from SCADA). The new FTE planned to
support the FNM implementation, and the associated on-going labor expense costs, are represented in Table 4
and also in Table 17.
6.3.2.2 Integration with CAISO Automated Dispatch System
In the Program Charter, costs were estimated for integration of Avista’s EMS SCADA with CAISO’s Automated
Dispatch System (ADS). The ADS provides the market Dispatch Operating Targets (DOTs) which the EIM entity
uses to control its generation plants. In order to accommodate this, Avista will procure an add-in dispatch
module from its SCADA software provider. This dispatch module will retrieve the dispatch targets in real-time
from CAISO, and present them to the Avista EIM operator. Generation resources which are on full EIM control,
will automatically be sent these operating targets. Plant control systems will follow the dispatch targets to
achieve the targeted energy output. The dispatch module implementation estimate was included in Charter
Line Item 1 “Vendor EIM Software Solution” with a capital estimate of $156k. This has been transferred to the
Track 3, Table 4 financial estimates with an updated estimate of $160k.
6.3.2.3 Master File / Generation Participation & Cost Modeling
In the Charter, Avista provided estimates for an item labeled “Generation Participation & Cost Modeling,”
which included estimates for multiple items. One of these critical items is the RDT, which are inputs into the
CAISO Master File (MF) for both generation and interconnection resources. The RDTs for generation describe
to the market all the base physical and operational properties of each generation resource, which the market
then uses for optimization and constraints. The RDTs for interconnection resources represent interchange
schedules and market dispatch limits between Balancing Authorities Areas – for those in the EIM and those not
participating. Separate RDTs must be prepared for PRs (Participating Resources) and NPRs (Non-Participating
Resources). The decisions on what to include in the RDT will have impacts on the market solution. Some of the
choices will be made based on tradeoffs, or with a plan about how manual dispatches or outages will be used
to manage some condition that cannot be expressed in the RDT. The RDT also functions as an interface to the
CAISO Master File, which then supplies the data to the market system. The other two items involved the
collection of information and business logic to inform the DEB and MMA. These items need to be coordinated
and aligned with the FNM and the engineering teams conducting the metering upgrades. This collective work
was labeled under the Charter under Line Item 12 “Generation Participation & Cost Modeling” at $200k in
capital. As there is no asset planned for installation, this work has been reclassified as expense.
6.3.2.4 Energy Transfer System Resource (ETSR)
An Energy Transfer System Resource (ETSR) is the representation of how the market facilitates the transfer of
energy from one EIM Balancing Authority (BA) to another EIM BA for the purposes of tracking, tagging and
settlements. As part of the implementation, Avista must define the physical location of the ETSR and negotiate
ETSR limits with neighboring EIM Entities. Although the ETSR values will be configured in the EIM software, the
business process definition and discussion are considered expense. The Charter did not include estimates for
this work; however it’s believed the effort will be accommodated within the existing expense estimate.
6.3.3 Track 3 Financial Estimate Summary
The estimates below include the following updates and additional costs:
The Charter provided a capital estimate for Utilicast support of the FNM implementation under the Line Item 11
“Full Network Model for EIM” at $40k and a portion of the Avista FNM capital labor at $80k. The portion of the
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 10 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 11 of 47
on-going labor expense at $50k associated with Line 11 is for a new the FTE to support the FNM. The new FTE
planned to support the FNM implementation, and the associated on-going labor expense costs, are represented
in Table 4 and also in Track 6.
The dispatch module implementation estimate was included in Charter Line Item 1 “Vendor EIM Software
Solution” with a capital estimate of $120k. This has been transferred to the Track 3 financial estimates with an
updated estimate of $160k.
The Charter Line Item 12 “Generation Participation & Cost Modeling” had estimates for the creation of the
Master File through RDT collection, the MMA and the DEB, and was planned as capital ($200k). As there is no
asset planned for installation, so this work has been reassigned as one-time expense cost.
With the exception of the Utilicast support for the FNM, there isn’t a specific expense estimate for Utilicast
under this track, as the support effort is represented in the EIM Program line in cost estimate tables.
Table 4 – Transmission & Generation Modeling Estimates
6.4 Track 4 – System Integration & Testing
Enterprise Technology Software Selection
6.4.1 Existing State Prior to EIM
Avista has primarily relied on Nucleus, an in-house application, to perform a myriad of business functions that are
typically satisfied with multiple, independent systems supporting Risk, Gas Supply, Power Supply, Resource Accounting
and System Operations. At one point, Nucleus was a commercial application and Avista purchased the source code –
thus customizing the application over many years to meet different business needs. Although Nucleus was briefly
considered for EIM use, the plan quickly shifted to understanding what functions would be impacted or duplicated in the
new systems needed for EIM operations. Where possible, Avista intended to avoid further integration with Nucleus and
allow the application to support existing operations.
In terms of outage management for generation and transmission, Avista knew their existing internally developed
Generation Outage Coordinator (GOC) application and manual submission processes would not be acceptable for
market use. Avista planned to implement an Outage Management System (OMS) that would satisfy both the
Transmission and Generation outage management processes internally for Avista and externally for EIM.
Avista has developed an internal generation optimization application called Avista Decision Support System (ADSS) and
believe it will be integral for EIM operations, as there isn’t a commercial application that specializes in hydro
optimization. Avista chose to enhance the ADSS application for EIM use and integrate with the purchased OMS and
Scheduling applications.
In June 2017, Avista implemented a Power Costs, Inc. (PCI) application for participation in CAISO’s Market Redesign and
Technology Upgrade (MRTU). The MRTU is a market operated by the CAISO, with governance provided by the California
Public Utilities Commission (PCUC). The market’s intent is to improve energy efficiency, transparency, reliability and
prevent market manipulation within CAISO. Avista used the application to submit market bids and perform settlements
calculations at the CAISO tie lines – locations that intersect Avista’s contracted transmission path with CAISO
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
FNM Creation* $ - $ - $ - $ - $ - $ -
FNM EIM Support (Line 11) $ 80,000 $ - $ 50,000 $ 80,000 $ - $ 50,000
EIM Dispatch Module (Line 1) $ 156,000 $ - $ - $ 160,000 $ - $ -
Master File / Gen Cost Modeling (Line 12) $ 200,000 $ - $ - $ - $ 200,000 $ -
Totals $ 436,000 $ - $ 50,000 $ 240,000 $ 200,000 $ 50,000
Utilicast $ 40,000 $ - $ - $ 40,000 $ - $ -
Grand Totals $ 476,000 $ - $ 50,000 $ 280,000 $ 200,000 $ 50,000
Track 3 - Transmission & Generation
Modeling
* Funded by SCADA business case
Scope Estimates (as of 08/2020)Charter Estimates (as of 05/2019)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 11 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 12 of 47
transmission grid. This was a limited installation of PCI’s GenManager application, as prior to EIM, Avista did not have a
business need for an extensive scheduling, bidding or settlement application.
6.4.1.1 EIM Software – RFP & Selection
In June of 2019, Avista engaged with Utilicast to define the system requirements for various EIM software applications,
while assuming some internal applications would be modified for EIM. During requirements gathering, it was
determined that Avista’s Oracle Meter Data Management (MDM) application for residential meters would not be
suitable for EIM metering activity. The assumption in the original charter assumed the MDM could be used for this
functionality. Avista issued two technology-based RFPs. The first RFP was issued in August 2019 for a Generation and
Transmission Outage Management System. The second RFP was issued October 2019 for the Bid to Bill EIM suite,
including the PRSC and EESC for scheduling, the PRSC and EESC for settlements, Energy Accounting and an
Analytics/Reporting application. A common scoring matrix and logic was used for both RFPs. The scoring matrix was
based on a combination of the vendors scoring themselves and Avista’s scoring. The vendors provided a self-score based
on their ability to meet the functional and non-functional requirements. During the product demonstrations, Avista
reviewed and adjusted the vendor provided score based on the product performance. Avista also scored on the areas of
industry expertise, references, demonstration scenarios and customer service. A total score of 100 was achievable. The
evaluation of software costs were not included in the scoring matrix, but were considered in the overall evaluation
process, as some vendors provided pricing for standalone systems, while others provided bundled suite pricing. The
primary drivers for software selection were centered on functionality and vendor relationships, as Avista knew the
financial aspect would be influenced by software bundling options and contract negotiations.
The OMS RFP was issued to, and responses received from, Sunnet, Open Access Technologies, Inc. (OATI), PCI and MCG
Energy Solutions. On-site demonstrations of each OMS product were held in mid-September 2019 with a cross-section
of business and technology users, as well as Utilicast members. Excluding the Sunnet product, which focuses primarily
on transmission outages, the OMS scoring was competitive. Knowing there was a desire to select a vendor who could
fulfill multiple software needs, Avista delayed their OMS decision in favor of selection after the Bid to Bill software
evaluation process. Table 5 below provides the scoring for each vendor.
Table 5 – OMS Vendor Scoring
MCG Energy 87.7
PCI 87.1
OATI 83.3
SUNNET 74.0
The Bid to Bill Suite was issued to OATI, PCI, Power Settlements and MCG Energy Solutions. Although MCG Energy
provides organized energy market solutions, their EIM Market-share representation is minimal and Avista did not
believe their product would meet EIM needs. The on-site software demonstrations were held in the month of November
2019 with representation from PCI, OATI and Power Settlements. PCI and OATI bid the entire suite, while Power
Settlements did not bid for Energy Accounting and did not have a fully developed scheduling solution (PRSC & EESC).
Although a common scoring matrix was used, a different group of business users were engaged in the evaluation
process. Each of the solutions within the Bid to Bill suite was scored individually, with a roll up score for each vendor
listed in Table 6 below.
Table 6 – Bid to Bill Vendor Scoring
PCI 77.3
OATI 71.1
Power Settlements 70.0
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 12 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 13 of 47
After all scores were collected, meetings were held with all the evaluation team members to discuss the merits of
choosing a single vendor versus integrating a “best of breed” model with various multiple vendors. Trade-offs would be
present as no single vendor could fully excel in each functional requirement area across eight software solutions. The
evaluation team made a recommendation to choose PCI for PRSC/EESC scheduling, Energy Accounting, Transmission
OMS and Generation OMS, and Power Settlements for PRSC/EESC settlements and Reporting/Analytics. Even though
Power Settlements had a lower overall score for Bid to Bill because of not having a mature scheduling solution, the
evaluation team felt they had a superior settlement and reporting/analytics solution.
After the EIM Director Steering Committee approved the recommendation in November 2019, the recommendation was
reviewed and approved by the Executive Steering Committee in December 2019. Although the cost estimates presented
to the leadership team exceeded the original Program Charter estimates, they reflected a baseline negotiation point and
Avista believed additional savings could be negotiated with PCI and Power Settlements.
6.4.1.2 EIM Software – Negotiated Contract Costs
After the Executive Steering Committee approval, Avista engaged with PCI and Power Settlements to negotiate the
terms and conditions of the agreements, as well as the implementation costs (capital) and on-going operating expense
(expense), for the following EIM systems:
Power Costs, Inc.
o Asset Operations
Generation Outage Management System (GOMS) – Performs functions to submit planned and
unplanned outages to CAISO for the generation units.
Transmission Outage Management System (TOMS) – Performs functions to submit planned and
unplanned outages to CAISO for the transmission lines.
o GenManager Front Office
PRSC Bidding & Scheduling System – Performs Merchant functions to submit bids and base
schedules to CAISO for participating resources.
EESC Scheduling System – Performs Entity (Balancing Authority) functions to submit base
schedules for both participating resources and non-participating resources.
o Energy Accounting
Energy Accounting System – Performs meter verification, estimation and editing (VEE) for
generation and interchange metering to produce and share Settlement Quality Meter Data
(SQMD) with CAISO.
Power Settlements
o SettleCore
PRSC Settlement System – Performs Merchant settlement functions for the participating
resources and activities.
EESC Settlement System – Performs Entity settlement functions for non-participating resources
and transmission resources.
o Visual Analytics
Performance & Analytics System– Performs a near real-time market analytic functions in a visual
display.
In March 2020, Avista concluded the negotiations with PCI and executed an amendment to the existing Master Service
Agreement (MSA). In May 2020, Avista concluded the negotiations with Power Settlements. The slide below, shown at
the May 2020 Director and Executive Steering Committee meetings, summarizes the initial vendor costs presented in
December 2019 and the vendor costs after negotiations, which resulted in a savings of $300k in implementation capital
costs and annual average savings of $53k in expense costs over the five-year contracted agreement compared to the
original vendor costs. These savings were attributed to Avista choosing an on premise deployment of Power
Settlements, thus removing the hosting services.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 13 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 14 of 47
Slide 1 – Negotiated Software Costs
6.4.1.3 EIM Software – Vendor Financial Estimate Summary
The Charter estimates for the software vendor costs were considered preliminary and included a financial range for each
EIM system, and the estimates assumed the low range of the costs. They included software license costs, professional
services and travel expenses for vendors. They were reflected under Charter Line Items 1 and 1a “Vendor EIM Software
Solutions” at $1.26 million in capital, $840k in working expense and $500k in re-occurring annual maintenance expense.
The capital and working expense estimates should have been combined into one capital estimate at $2.1 million. The
Charter estimates assumed a hosted SaaS solution for all EIM applications, with internal Avista labor estimates for
Oracle MDM customizations and reporting.
The Scope estimates in Table 7 include the following changes and combined allocations of funds:
When the decision was made to purchase a COTS solution for Energy Accounting, instead of enhancing Avista’s
existing MDD application, the funds were reallocated. Charter Line Item 5 “Other Avista Software Enhancements
– MDM” at $800k was reassigned with $400k allocated to software licensing and $400k allocated to Avista labor
for software projects.
The removal of the SaaS hosting costs for the PRSC/EESC Settlement system.
The EMS Dispatch Module estimates at $120k under the Charter Line Items 1 and 1a “Vendor EIM Software
Solutions” reassigned to Track 3, Table 4.
The Charter estimates did not account for software hosting and maintenance fees that could be capitalized
during project delivery, which lead to an additional $454k in capital.
Avista signed agreements with PCI and PS to implement the software and five years of application support after market
entry. The Scope expense estimates in Table 7 include a capital cost assignment by EIM application, implementation
expense for vendor software training and an on-going annual expense estimate over a five-year term. The Charter
estimates did not specifically include an assumption for the software support term.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 14 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 15 of 47
Table 7 – EIM Vendor Software & Licensing Estimates
6.4.1.4 EIM Software – Avista Labor Summary
The Charter estimates detailed various technology labor items to support the EIM software implementations. Table 8
outlines the Charter estimates by line item and presents a total Avista labor allocation that was applied to the EIM
software projects. These estimates also include half of Charter Line Item 5 “Other Avista Software Enhancements –
MDM” at $400k for Avista software project labor. This estimate assumed existing labor for project delivery and did not
include estimated costs associated with the new EIM FTEs contributing to the capital software projects.
Table 8 – EIM Software Internal Labor
6.4.1.5 EIM Software – Total Project Financial Estimate Summary
The Program Charter estimates included the vendor estimates, estimates for internal labor, and professional services
associated with a System Integrator. However, they were shown in different line items and not consolidated. The
updated total project capital estimates in Table 9 represented total estimated costs for the EIM software
implementation, with the following details:
Avista’s RFP software selection and procurement effort with Utlicast and internal Avista labor. The 2019
Technology RFP with Utilicast was reflected under Charter Line Item 10 “System Selection & Procurement” with
a $500k expense estimate for Utilicast and $680k for Avista labor. Utilicast actuals for the Technology RFP are
listed in Table 1 and Table 9.
Summarized vendor software allocation from Table 7
Summarized internal labor allocation from Table 8
The OMS project separated into two phases – Phase 1 for pre-EIM entry and Phase 2 for EIM go-live
Utilicast labor allocated based on deliverables included in 2020-2022 Implementation Agreement (Table 2)
The removal of SaaS hosting costs for the PRSC/EESC Settlement system
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Vendor EIM Software Solutions (Line 1)1,260,000$ -$ -$ -$ -$
Vendor EIM Software Solutions (Line 1a)840,000$ -$ -$ -$ -$
Software Enhancements MDM (Line 5)400,000$ -$ -$ -$ -$ -$
EMS Dispatch Model to Track 3 (Line 1)(120,000)$ -$ -$ -$ -$ -$
EIM Software Vendor Allocation 2,380,000$ -$ 500,000$ -$ -$ -$
PCI EESC Scheduling -$ -$ -$ 355,297$ 10,152$ 100,395$
PCI PRSC Bidding & Scheduling -$ -$ -$ 355,297$ 10,152$ 100,395$
PCI OMS (Gen / Trans) Phase 1 & 2 -$ -$ -$ 513,307$ 13,699$ 84,961$
PCI Energy Accounting -$ -$ -$ 322,380$ 8,122$ 100,395$
PS PRSC & EESC Settlement -$ -$ -$ 725,500$ 22,500$ 64,637$
PCI Hosting & Maintenance -$ -$ -$ 444,117$ -$ -$
PS Maintenance -$ -$ -$ 10,000$ -$ -$
Totals 2,380,000$ -$ 500,000$ 2,725,898$ 64,625$ 450,783$
Vendor
500,000$
Track 4 -
EIM Vendor Software
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Vendor EIM Software Solutions (Line 1)900,000$ -$ -$ -$ -$ -$
Internal Integration Effort (Line 3)820,000$ -$ -$ -$ -$ -$
Custom Reporting Allowance (Line 4)200,000$ -$ -$ -$ -$ -$
Avista Software Enhancements MDM (Line 5) 400,000$ -$ -$ -$ -$ -$
Dedicate Security & Architecture (Line 6)330,000$ -$ -$ -$ -$ -$
PgM Leadership Labor (Line 9)350,000$ -$ -$ -$ -$ -$
EMS Dispatch Model to Track 3 (Line 1)(36,000)$ -$ -$ -$ -$ -$
EIM Software Internal Labor -$ -$ -$ 2,964,000$ -$ -$
Totals 2,964,000$ -$ -$ 2,964,000$ -$ -$
Track 4 -
EIM Software Internal Labor
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 15 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 16 of 47
The addition of hardware costs associated with the on premise deployment of the EESC & PRSC Settlement
system at $77k.
Nucleus enhancements estimates for EA and Settlements
The PRSC Settlements & EESC Settlements applications combined into a single project, with the inclusion of the
Advanced Analytics module.
The addition of training expense as provided by the EIM software vendor.
Table 9 – EIM Software Projects Costs
Table 9 provides an estimate of software costs without Utilicast costs assigned to individual projects.
Table 10 provides an estimate of software costs by project with Utilicast costs included.
Table 10 – EIM Software Projects Costs with Utilicast*
*Excludes System & Software Selection Utilicast implementation costs
6.4.1.6 EIM Software – Miscellaneous
EIM MV90: Beyond the EIM Bid to Bill software provided by PCI and PS, Avista also needed a meter head-end
system to collect interval meter data for market submission. Avista had a choice to use an existing MV90
installation used for commercial customers or install a new MV90 specifically for EIM meter collection. Avista
decided to install a new instance of MV90, as the existing installation is out of maintenance and support
warranty and the existing meters are on a long-term transition to another enterprise customer billing system.
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
System Selection & Procurement $ - $ 680,000 $ - -$ $ 680,000 $ -
EIM Software Vendor Alloc. (Table 7)2,380,000$ $ 500,000 -$ $ - $ -
EIM Software Internal Labor (Table 8) $ 2,964,000 $ - $ - -$ $ - $ -
PCI EESC Scheduling $ - $ - $ - 973,816$ 10,152$ $ 100,395
PCI PRSC Bidding & Scheduling $ - $ - $ - 1,105,816$ 10,152$ $ 100,395
PCI OMS (Gen / Trans)880,774$
PCI OMS (Gen / Trans) Phase 2 234,094$
PCI Energy Accounting -$ -$ -$ 1,212,899$ $ 8,122 $ 100,395
PS PRSC & EESC Settlement -$ -$ -$
PS Visual Analytics -$ -$ -$
Totals $ 5,344,000 $ 680,000 $ 500,000 $ 6,067,799 $ 744,625 $ 450,783
Utilicast -$ 500,000$ -$ 2,986,181$ 508,435$ -$
Grand Totals 5,344,000$ 1,180,000$ 500,000$ 9,053,980$ 1,253,060$ 450,783$
1,660,400$
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
-$ $ 84,961
$ 64,637 $ 22,500
$ 13,699
Vendor
-$ -$
Track 4 - Software Projects Total
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
PCI EESC Scheduling $ - $ - $ - 1,599,004$ 10,152$ $ 100,395
PCI PRSC Bidding & Scheduling $ - $ - $ - 1,731,003$ 10,152$ $ 100,395
PCI OMS (Gen / Trans)1,421,499$
PCI OMS (Gen / Trans) Phase 2 459,591$
PCI Energy Accounting -$ -$ -$ 1,586,342$ 8,122$ $ 100,395
PS PRSC & EESC Settlement -$ -$ -$
PS Visual Analytics -$ -$ -$
Totals $ - $ - $ - $ 9,053,980 $ 64,625 $ 450,783
Utilicast -$ -$ -$ -$ 508,435$ -$
Grand Totals -$ -$ -$ 9,053,980$ 573,060$ 450,783$
Vendor
2,256,541$ 22,500$ $ 64,637
-$ -$ -$ $ 13,699
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)Track 4 - Software Projects Total
with Utilicast
$ 84,961
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 16 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 17 of 47
Any meters that can’t be transitioned to the enterprise billing system, will be migrated to the new instance of
MV90 and the existing installation will be retired.
The project to install the EIM MV90 xi application offered by Itron started in Q2 2019 and the project completed
in Q1 2020. As revenue quality SEL-735 meters are installed or reconfigured to support market entry, they’ll
send daily meter data to this collection system. The Charter did not include a single line item for the MV90
project, but instead provided estimates for bodies of work associated with network improvements, continuation
of third-party meter data access, and hardware and software licensing costs. These estimates were presented in
various line items in the Charter, which were later consolidated or reassigned to the EIM MV90 project. The EIM
MV90 project had a total spend of $438,166, with on-going O&M expense estimated at $20k.
o Miscellaneous Hardware and Software: Although the Charter planned for a SaaS EIM solution, not all
EIM-related applications would follow this deployment method. This estimate accommodated hardware
and software costs for associated EIM applications that would be on premise at Avista, such as the
MV90 meter headend application. The estimate in Charter Line Item 7 “Miscellaneous Software &
Hardware Costs” at $330k for capital and $25k of on-going annual maintenance expense were assigned
to the MV90 project.
o MV90 Network: As a component of the EIM MV90 installation project, the Charter provided a financial
estimate to route MV90 data securely through the SCADA network, and allow secure third-party
interchange access to the meter data. The estimate in Charter Line Item 23 “Network – MV90 (2, 7)” at
$55k for capital was originally labeled as a service, but should have been labeled as Avista labor. These
labor estimates were assigned to the MV90 project.
o MV90 / Migrate BPA Meters: At 12 interconnection locations, BPA requires Avista provide MV90 access
for energy scheduling and accounting purposes. The meters are accessed both through Avista’s MV90
and BPA’s MV90. With the decision to replace interchange meters at these locations and the NERC
Critical Infrastructure Protection (CIP-003) requirement to provide secure communications, a secure
Virtual Private Network (VPN) connection was established for BPA’s MV90. The scope to develop the
BPA to Avista VPN connection has been accommodated under the interchange substation projects, and
the scope to commission the individual communications to each meter will be included in each project.
The estimates in Charter Line Item 25 “Stand Up MV90 & Migrate Existing BPA Meters” at $215k for
capital and $18k of on-going services expense were reallocated to Avista’s EIM MV90 project.
Table 11 – MV90 Project
Variable Energy Resources (VER) Forecast: In order to adequately forecast Variable Energy Resources (VER)
generation output, Avista needs to acquire a single VER forecast solution that will provide a five-minute
generation forecast based on weather conditions for all VER facilities in Avista’s BA. Avista currently has two
(Meteologica and Vaisala) forecast providers that provide hourly values. Avista needs a singular forecast to
integrate into EIM software and a service that can expand as additional VER resources are brought online in the
BA. Avista intends to operate a pilot trial period with forecast providers before selecting and implementing the
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Misc. Hardware / Software (Line7)330,000$ -$ 25,000$ -$ -$ -$
MV90 Network (Line 23)55,000$ -$ -$ -$ -$ -$
MV90 / Migrate BPA Meters (Line 25)215,000$ -$ 18,000$ -$ -$ -$
MV90 EIM Project 438,166$ -$ 20,000$
Total 600,000$ -$ 43,000$ 438,166$ -$ 20,000$
Track 4 - MV90
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 17 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 18 of 47
service for EIM. These costs were not planned in the Charter. A capital estimate ($200k) and on-going expense
estimate ($15k) have been updated.
Current Transformer (CT) Analyzer: In order to support the transformer accuracy testing efforts at substation
and generation locations, Avista purchased software called “CT Analyzer” offer by Omicron. These costs were
not planned in the Charter, but the application was required to test the accuracy of CTs to verify they met CAISO
market requirements. If the CT accuracy did not meet the CAISO standard then they were either replaced, or a
correction factor was calculated which may result in market penalties. These costs were not planned in the
Charter and the actual cost was $11k.
OATI Tag Forwarding: In order to adequately support the EESC Settlement solution, tag data is to accurately
analyze the billing determinates provided by CAISO. Additionally, the tag data is required for the EESC
Scheduling solution. Avista originally planned to leverage OATI’s webData solution to provide the tag data to the
EESC Scheduling solution. However, during the planning phase of the project, it was determined that the
software vendors preferred methodology was to receive the tag data via OATI’s Tag Forwarding service. This
service is required to meet the tag data requirements for both the EESC Settlement and EESC Scheduling
solutions. These costs were not planned in the Charter and the capital estimate ($27k) and on-going expense
estimate ($27k) have been updated.
PCI E-Tag Forwarding: In order to adequately support the EESC Settlement solution and the EESC Scheduling
solution, tag data is required (see above). Given the fact that the tag data is needed for two EIM systems, and
OATI’s Tag Forwarding service can only provide tag data to one system, a “pass through” tag data solution was
devised. PCI’s E-Tag Forwarding solution was surfaced for this “pass through” and Avista will pursue this
solution. These costs were not planned in the Charter and the capital estimate ($30k) and on-going expense
estimate ($19k) have been updated.
Avista Decision Support System (ADSS) Enhancements: When Avista conducted the EIM software RFP, it was
planned that Avista’s internal optimization application – ADSS – would perform EIM bid calculation and other
EIM requirements. Avista estimated $1 million in internal Avista labor to perform the ADSS enhancements, but
that estimate did not include estimates for professional services related to development or implementing the
functionality, or full data integration with other EIM applications because the specific interfaces were not known
at the time the original estimate was created. The estimated $1 million was not included in the EIM Program BC
or Charter, but rather in the 2020 ADSS enhancement BC under productivity funding.
The ADSS EIM enhancement effort began in Q1 2020 and has led to greater understanding of the business
functions needed to support EIM operations and integration with the EIM software. Enhancements for EIM
include bidding configuration, changes to the scratch pad feature, a market dashboard and the creation of an
economic balancing stack of Avista’s resources. Integration of these features is planned for PCI’s Outage
Management software and the PRSC/EESC software. The new estimate to complete the ADSS enhancements
was increased by $2.0 million to $3.46 million total including Utilicast support.
The updated ADSS forecast of $3.46 million is inclusive of updated labor estimates, professional services,
Utilicast costs and full integration costs. Avista’s Project Accounting Department recommended that all ADSS
EIM enhancement costs be moved to the EIM project and removed from productivity funding based on the new
scope and performed work. In July 2020, the Executive EIM Steering Committee approved the transfer of the
EIM ADSS effort to the EIM BC, with funding covered by the Program contingency. The labor estimate below
includes Avista and contract labor (non-labor), while the professional services estimate includes support from
Sixth Man for user experience design and Abermod for bidding calculation logic.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 18 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 19 of 47
Table 12 – ADSS EIM Estimates
6.4.1.7 EIM Software – Miscellaneous Software Financial Summary
The Charter did not include a single line item for the EIM MV90 project, but instead provided estimates for bodies of
work associated with network improvements, continuation of third-party meter data access, and hardware and software
licensing costs. These have been summarized in the below chart. In addition, the Charter estimates did not include
funding for ADSS EIM enhancements and integration, a new VER forecast provider or the purchase of CT testing
software. The Utilicast charges reflected below are only associated with the ADSS EIM effort. The software maintenance
expense estimates below include an on-going annual estimated amount.
Table 13 – Miscellaneous Software Estimate Update
6.4.1.8 EIM Software – Annual Upgrades & Enhancements
Avista has forecasted costs to implement the solutions and on-going vendor costs associated with maintenance and
licensing. Avista also recognizes the need to forecast costs for future annual upgrades and enhancements to expand
capabilities and increase efficiencies. Additionally, the CAISO releases annual market enhancements which affect EIM
software and may cause subsequent internal integration changes. Avista has forecasted $500k annually for EIM
upgrades and enhancements to support operations. These estimates are preliminary and will be refined as Avista gains
operational market experience.
6.5 Track 5 – Metering & Settlements
Generation Production & Substation Support, Interchange & Network Infrastructure
6.5.1 Existing State Prior to EIM
Within the Metering & Settlements Track, Avista grouped upgrades for generation and substation interchange metering,
generation controls and network infrastructure. In order to appreciate why Avista pursued a specific scope path, it’s
important to understand Avista’s existing state prior to EIM. Across a majority of the generation and substation sites,
Avista has relied on non-revenue quality meters with no ability to securely retrieve 5-minute revenue quality interval
meter data required for market participation. The most extreme unsuitable EIM meter is at the Post Falls Hydro Electric
Dam, which has antiquated electro-mechanical meters with a manual hourly meter collection process. Most of Avista’s
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
MV90 (Table 11)600,000$ -$ 43,000$ $ 438,166 $ - $ 20,000
VER Forecast -$ -$ -$ $ 200,000 $ - $ 15,000
CT Analyzer -$ -$ -$ $ 11,004 $ - $ -
OATi Tag Forwarding -$ -$ -$ $ 27,600 $ - $ 27,600
PCI eTag Forwarding -$ -$ -$ $ 29,850 $ - $ 18,750
ADSS Enhancements -$ -$ -$ 2,987,494$ $ - $ -
Totals 600,000$ -$ 43,000$ 3,694,114$ -$ 81,350$
Utilicast -$ -$ -$ 472,639$ -$ -$
Grand Totals 600,000$ -$ 43,000$ 4,166,753$ -$ 81,350$
Track 4 -
Miscellaneous Software
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
2020 2021 2022 Total
Labor 1,332,312$ 1,174,795$ 315,421$ 2,822,528$
Professional Services 128,966$ 36,000$ -$ 164,966$
Utilicast 163,484$ 154,117$ 155,035$ 472,636$
Totals 1,624,762$ 1,364,912$ 470,456$ 3,460,130$
Scope Capital Estimates (as of 08/2020) Track 4 - ADSS EIM
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 19 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 20 of 47
generation sites did not have revenue class Current Transformers (CTs) or Potential Transformers (PTs) that allow for
accurately measuring generation output. Avista also has very limited Automated Generation Control (AGC) systems and
associated Programmable Logic Control (PLC) at its generation plants – both of which are required for a resource to
receive and follow a Market dispatch signal. Although there is a network presence at most of these generation sites, not
all generation meters are capable of connecting to the network for retrieval of 5-minute interval data. However, the
current state of Avista’s meters, generation controls and associated network connectivity was acceptable, as Avista
traditionally operated in a bi-lateral hourly market.
Throughout the substation interconnection sites, Avista does meet the revenue quality meter requirement with JEMStar
meters and accurate CTs/PTs. Although Avista considered reprograming these meters to collect 5-minute interval data
with an associated memory upgrade, these meters are at least 12 years old, require dial up communications to retrieve
this interval data and are unable to connect via Internet Protocol (IP) communications. Considering the age of the
meters and the fact that Avista should not rely on dial up communications alone, the decision was made to replace the
meters with a SEL-735 meter capable of 5-minute interval data and multiple connectivity options.
Due to limited field support of dial up communications and lack of monitoring capabilities, Avista decided to replace dial
up communications in favor of IP communications installations wherever cellular installations are feasible – this aligns
with Avista’s preferred communication protocol and long-term operational plan. For the purposes of EIM, the IP
communications migration will be limited to MV-90, engineering access, and metering communications, but eventually
could include migration of SCADA as part of a future project if the new IP communications circuits are deemed reliable.
Migration to IP communications for SCADA and metering has been a long-term evolution for Avista, and one without a
strong business need prior to EIM.
Avista does collect hourly interchange meter data, but it’s done at most substations by non-revenue meters with varying
capabilities, with various network protocols, manual processes and supplemented with information from PI (Plant
Information) and SCADA averages. This process and the associated data are not scalable or reliable for accurate 5-
minute interval EIM metering and settlements.
6.5.2 Generation Production & Substation Support – Scope Summary
In 2018, Utilicast and Avista partnered to conduct a site by site metering assessment to document Avista’s
metering and controls infrastructure, highlighting where existing assets were insufficient for EIM entry. Sites
were divided into two categories: market dispatch and non-dispatch. Initially, it was determined that all market
dispatch resources would need to be equipped to bid at the unit-resource and at the plant aggregate-resource
levels. Components at dispatch plant sites would be revenue grade, and all controls would need to be upgraded
to accommodate both Avista internal dispatch and market dispatch requests. While non-dispatch sites would
also adhere to CAISO requirements, flexibility, redundancy, and accuracy were of lesser priority for resources
that would not be bid into the market. Avista intended to retain existing CTs and PTs at non-dispatch sites. These
sites were planned for correction factors, thereby minimizing project scope and cost. With these general
guidelines in mind, the Metering Assessment Summary Report was developed, project scope was identified for
each site, and costs were assigned at a very rough order of magnitude.
In the first quarter of 2019, Generation Production & Substation Support (GPSS) was asked to review and refine
estimated EIM metering and controls costs. Because Avista was still gathering participation requirements and
market strategy information, scope was not yet highly defined. Thus, project cost refinements conducted in
early 2019 were considered preliminary and assigned plus or minus 50% accuracy, per the standards of the
Association for the Advancement of Cost Engineering (AACE). As a starting point, each market dispatch location
was assigned new high-side meters (HSM) and EIM PLC. In order to provide an initial HSM cost assessment, the
Noxon Rapids, Cabinet Gorge, Coyote Springs 2, and Little Falls locations were individually assessed. Then,
Rathdrum, Lancaster, Boulder Park, Kettle Falls, and Long Lake HSM projects were assigned HSM cost estimates
based on which assessed location they most resembled. A single EIM PLC project cost was estimated and applied
to all dispatch locations. At non-dispatch locations, the goal was to achieve CAISO metering requirements while
minimizing project costs. Low-side generation meters (LSM) needed to be compliant SEL-375s, but CTs and PTs
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 20 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 21 of 47
did not need to be revenue grade. Instead, an estimated cost for transformer accuracy testing was applied to all
CTs and PTs in order to account for the cost of accuracy measurements and correction factor calculations. In
March of 2019, teams completed new estimates for HSM and PLC dispatch sites, and LSM and CT/PT
measurement costs for non-dispatchable sites.
Since March 2019, Avista’s market understanding and participation strategy for each site has matured. Pilot
HSM, LSM and PLC projects began at Noxon Rapids in the summer of 2019. In January of 2020, GPSS conducted
Resource Participation Strategy Workshops by plant to finalize detailed project scope at each generation site.
Avista leaned on Utilicast’s expertise, interdepartmental meetings, and economic studies to further understand
the best strategy for preparing Avista’s assets for EIM entry. Because of these additional learnings, scope
changed and project costs increased beyond the estimates developed in March 2019. Scope changes included
transferring third-party generation metering and control upgrades to Substation projects, changing some
locations from dispatch to non-dispatch or high-side metering to low-side metering based on the detailed field
assessments and additional design work. Many of the planned dispatch sites no longer required PLC projects and
most non-dispatch projects ultimately required new transformers. Contractors were hired to support project
management, electrical design, and drafting services. All deviations from preliminary estimates have been
governed by the Advisory Committee and the Director Steering Committee for approvals, and changes have
been documented, approved and filed for record.
6.5.2.1 High Side Meter Scope
High-side meter (HSM) projects planned to install SEL-735 meters on the substation-side of the Generation
Step-up Units (GSU) in accordance with Avista’s most current SEL-735 Combined (interchange and generation)
Meter Setting Standard. These meters validate market resource configurations, and related metering
components in alignment with the physical characteristics and EIM participation level with all generation
resources feeding the metered GSU (for example, multiple units and station service). When a HSM is installed
at a participating resource, revenue class CTs/PTs are often installed as part of the project. HSM projects
involve SCADA and network communication improvements, as well as MV-90 configuration.
6.5.2.2 Low Side Meter Scope
Low-side meter (LSM) projects planned to install SEL-735 meters at plant-side of the GSU in accordance with
Avista’s most current SEL-735 Combined Meter Setting Standard. One LSM meter validates market resource
configurations and related metering components in alignment with the physical characteristics and the EIM
participation level within one generating unit or station service. When a LSM is installed, revenue class CTs/PTs
are added or existing non-revenue class CTs/PTs are utilized with an appropriate compensation factor applied.
LSM projects involve SCADA and network communication improvements, as well as MV-90 configuration.
6.5.2.3 Programmable Logic Control Scope
EIM Programmable Logic Control projects (PLC) planned to install a PLC system to act as an interface point
between Avista’s Supervisory Control and Data Acquisition (SCADA) system, plant high-side meters, low-side
meters and plant unit controllers. The PLC receives plant MW set points from SCADA, from Avista operators or
the market, and delivers the unit MW set point to the unit PLC. It also receives HSM, unit, and station service
metering MW signal inputs, as well as meter position switch inputs. It blocks unit rough zone and non-
compliant emission operating set points and connects to the plant Human Machine Interface (HMI), which
allows plant operations to start and stop units. Finally, the EIM PLC possess a switch input for EIM participation
and non-EIM participation modes.
6.5.2.4 Low Side Meter Reconfiguration Scope
At some generation sites, the unit and/or station service meters were already upgraded to SEL-735 meters as
part of a previous project. These meters required reconfiguration in accordance with Avista’s most current SEL-
735 Combined Meter Setting Standard. These new settings integrate with MV-90 billing recorders and contain
EIM information in the SCADA and Generation Distributed Network Protocol (DNP) Maps. The transformer
compensation is applied to meter settings so SCADA has a backup MV-90 signal to create redundancies with
the new HSMs. No new assets are planned for installation; therefore this work is classified as expense.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 21 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 22 of 47
6.5.2.5 Metering & Transformer Research Scope
The CAISO Metering Business Process Manual outlines acceptable equipment ratings such as transformer
accuracy and burden ratings needed for EIM participation. This scope includes researching meter details, and
conducting field tests where the accuracy of the equipment burden rating was unknown and correction factors
would be applied. EIM entities can use equipment which does not meet the ratings requirements and apply a
correction factor, which reduces the observed readings to ensure that the metered output is not overstated –
it doesn’t increase accuracy. With field test data, Avista can calculate the appropriate correction factor to
adjust for deficiencies in CT and PT accuracy. No new assets are planned for installation; therefore this work is
classified as expense.
6.5.3 GPSS Financial Estimate Summary
The Charter estimates were considered preliminary and assigned a plus or minus 50% accuracy, per AACE standards. In
the Charter, they were represented as capital only items in the Solutions & Services column, but should have be
represented in the Avista Labor column under the following:
Charter Line Item 19 “Generation Metering from GPSS – Low Side” at $764k
Charter Line Item 20 “Generation Metering from GPSS – High Side” at $2.3 million
Charter Line Item 21 “Generation Metering from GPSS – EIM PLC” at $2.1 million
The estimates in the Charter did not include a potential 50% increase in costs and assumed internal engineering design
for all aspects of the projects and internal field labor. The original estimates included labor, materials, and travel time,
but failed to include drafting labor (internal or contracted), project management labor (contracted), labor for planning
costs, professional services for engineering (Northwest Power Engineering), Utilicast, AFUDC and overheads. The
updated estimates below include these additions. They also reflect:
Elimination of EIM PLC projects at six generation locations
o Rathdrum, Lancaster, Boulder Park, Kettle Falls, Long Lake and Little Falls
Transfer of Lancaster efforts to Substation for management and execution for the installation of Automated
Generation Control (AGC) at the plant and HSM configuration at the BPA-owned Lancaster interchange.
Transfer of Coyote Springs HSM efforts to ET Network, as there is a BPA-owned interchange and revenue quality
meter that can be leveraged
Transfer of costs at two locations to Substation based on project accounting rules, while the management and
execution of the work stayed with GPSS.
o Noxon 230 kV, Northeast CT
Scope change as strategies changed from high-side to low-side metering, dispatch to non-dispatch, and the use of
correction factors to control costs. This was the case at Boulder Park, which switched from a HSM to a LSM project.
The decision to make Long Lake a non-dispatchable resource resulted in a scope from a HSM to a LSM project.
Change of scope and/or accounting clarification of scope resulted in a transfer of capital to expense costs
o Monroe, Kettle Falls and Little Falls
Discovery of open-delta transformer complications at two locations
o Post Falls (LMS to HSM) and Long Lake
Non-Participating Resource (NPR) metering research conducted by Northwest Power Engineering to support meter
settings and configuration
Utilicast metering and controls support labor estimated for GPSS projects open as of August 2020.
The O&M expense estimates represent a single time charge.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 22 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 23 of 47
Table 14 – GPSS Financial Estimate Updates
6.5.4 Substation Interconnection & Third-Party Generation – Scope Summary
As outlined in the 2018 Utilicast metering assessment, Avista and Utilicast provided an initial assessment of
what substation interconnection and third-party generation locations would need metering upgrades, which led
to the initial cost estimate in the Charter. Since that time, the forecasted scope of work for substation
interchange and third party generation metering is nearly equivalent to what was originally estimated, with
some differences:
The original scope of work assumed meter replacement at all sites, but further research determined that
three sites required meter reconfiguration because a SEL-735 meter had been installed under a previous
substation project.
o Substation Interchange Locations: Deer Park, Orofino and Colbert
o Third-Party Generation Locations: Lind Solar
Six sites were removed from this body of work because planned substation projects already addressed
EIM needs, were scheduled to complete prior to the EIM deadline and funded through other business
cases.
o Substation Interchange Locations: Spirit, North Lewiston, Westside, Dry Gulch, Opportunity
o Third-Party Generation Locations: Clearwater Paper Company
The metering and controls work at the Lancaster generation site was originally included in the GPSS
upgrade work and has been transferred to third-party generation work because Avista does not own the
plant. The controls work to install Automated Generation Control (AGC) at Lancaster, and the associated
communication upgrades, are planned to be funded by Avista but installed by Tyr, the plan owner. The
substation interconnection meter reconfiguration, which will serve as a high-side meter for Lancaster
generation, will be funded by Bonneville Power Administration (BPA).
The original substation estimates did not include project costs for meter upgrades at Saddle Mountain
interchange or the Rattlesnake Flats third-party wind generation site and are not reflected in the updated
estimates. Those locations will accommodate EIM metering standards and MV90 configuration under existing
substation projects and are funded through other business cases.
Pend Oreille Public Utility District: At the time of the Charter estimates, Avista assumed metering
upgrades for Pend Oreille Public Utility District (POPUD), would not be funded by Avista. Although Avista
owns these interchange and generation meters, the upgrade costs would be funded by POPUD and
updated prior to EIM entry per the existing Metering Agreement between the entities.
o POPUD Substation Interchange Locations: Newport, Diamond Lake, Metaline Falls, Pine Street,
Box Canyon.
o POPUD Generation: Box Canyon
Based on current discussions with POPUD leadership and Avista, Avista may need to fund the upgrades
as POPUD does not have the resources to complete the work within the timeframe required to meet
CAISO milestones. The upgrades are estimated at $200k for design and installation.
Track 5 - GPSS
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
HSM (Line 20) $ 2,336,696 $ - $ - $ 2,137,536 $ - $ -
PLC (Line 21) $ 2,131,353 $ - $ - $ 1,594,331 $ - $ -
LSM (Line 19) $ 607,615 $ - $ - $ 663,490 $ - $ -
LSM Reconfiguration $ - $ - $ - $ - $ 222,326 $ -
Metering Research $ - $ - $ - $ - $ 62,250 $ -
Totals $ 5,075,664 $ - $ - $ 4,395,356 $ 284,576 $ -
Utilicast $ - $ - $ - $ 67,060 $ - $ -
Grand Totals $ 5,075,664 $ - $ - $ 4,462,416 $ 284,576 $ -
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 23 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 24 of 47
6.5.4.1 Meter Replacement Scope
At some interconnection locations, a meter replacement project was planned to install one or more SEL-735
meters in accordance with Avista’s most current SEL-735 Combined Meter Setting Standard. These new
settings integrate with MV-90 billing recorders and contain EIM information in the SCADA and Generation
Distributed Network Protocol (DNP) Maps. In some cases, accompanying integration equipment was also
planned for installation, such as a Remote Terminal Unit (RTU), GPS clock, SEL-3620 or SEL-3622 security
appliance, and/or RuggedCom Ethernet switch.
6.5.4.2 Meter Reconfiguration Scope
At some interconnection locations, one or more SEL-735 meters had been installed as part of a previous
project. These meters required reconfiguration in accordance with Avista’s most current SEL-735 Combined
Meter Setting Standard. These new settings integrate with MV-90 billing recorders and contain EIM
information in the SCADA and Generation Distributed Network Protocol (DNP) Maps. No new assets are
planned for installation, therefore this work is classified as expense.
6.5.5 Substation & Third-Party Financial Estimate Summary
The Charter estimates for substation and third-party generator work assumed internal engineering design for all
aspects of the projects and field labor. This work was represented under Charter Line Item 15 “Transmission
Meters & Data Collection – SS & 3rd Party” at $852k for capital, without any expense estimates. They were
represented as capital only items in the Solutions & Services column, but should have been represented in the
Avista Labor column. The original estimates included some internal labor, materials, and travel time, but failed to
include drafting labor (internal and external), project management labor, labor for planning costs, AFUDC,
overheads, professional services for engineering design (POWER Engineers) and Utilicast. The updated estimates
below include these additions. They also reflect:
Change in the scope at three locations from meter replacement to meter reconfiguration.
The removal of costs associated with six locations where other substation projects will address EIM
needs.
Inclusion of Lancaster efforts for the installation of Automated Generation Control (AGC) and HSM
configuration at the BPA-owned Lancaster interchange.
Inclusion of two generation projects that were managed by the GPSS business unit, but the project
accounting details were recorded under the substation business unit based on FERC accounting rules.
o Noxon 230 kV, Northeast CT
Inclusion of POPUD meter replacements
Utilicast metering support labor estimated for all substation and third-party generation meter projects
open as of July 2020.
The O&M expense estimates represent a single one-time charge.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 24 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 25 of 47
Table 15 – Substation & Third-Party Generation Financial Estimate Updates
6.5.6 Network Infrastructure Support – Scope Summary
At the time of Program Charter estimates, every controls and meter upgrade project assumed a parallel network
communications capital project to support asset implementation. The network scope was divided into “packages” as
detailed below and each site was assigned a package. With the exception of Package 6, each package assumed on-going
expense estimates for maintenance and support. The Charter financial estimates assumed Avista would remove existing
dial-up communications and install secure third-party Internet Provider (IP) communications via a reliable wired circuit
at many, if not all, locations. Internet Protocol communications can either be physical wires, such as Ethernet or a T1 line
that provides high-speed data transport services, or wireless options such as private microwave or commercial cellular.
Avista has a mixture of communication options in production, including a mixture of contracted carrier services and
Avista-owned private services.
As the metering or controls projects began, network site surveys were conducted to evaluate communication options
with the goal of implementing an economic, reliable and secure network path. Sometimes, this meant retaining existing
dial-up communications at a location or changing the body of work from capital to expense. Throughout the middle of
2019 and into 2020, these site surveys led to an updated scope of work for network infrastructure as reflected in the
following changes:
At eight substation interconnection locations, the original scope assumed delivery of wired T1 communications
with High Voltage Protection outlined in Package 2, but upon conducting site surveys that scope has been
reduced to one location – Burke.
o Three sites were removed because planned network projects already addressed IP
communication needs, were scheduled to complete prior to the EIM deadline and funded
through other business cases: Orofino, Sagle & Colbert
o Three sites originally planned for wired IP communications will now deliver a wireless option:
Cellular Wireless: Milan & Priest River under Package 5
Microwave: Kettle Falls under a modified Package 2
o One site planned for wired IP communications will retain dial-up communications: Spirit
Two substation interconnection locations identified to receive IP communications under Package 1 were already
delivered under a previous project: Lolo & Dry Creek
Four substation interconnection locations were planned for IP communications under Package 3, but will deliver
a wireless cellular option under Package 5: Noxon 13kV, Deer Park, Wilbur & Loon Lake
At the Northeast CT generation site, it was determined that no network hardware was needed based on the
GPSS design.
At two generation sites, it was determined that network hardware would be delivered and funded through
other business cases:
o Boulder Park & Rathdrum
At three generation sites, the meters had already been upgraded and only needed network reconfiguration.
These sites have been transferred to Package 6 scope as expense:
Track 5 - Substation
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Substation Interchange
Meter Replace (Line 15) $ 610,200 $ - $ - $ 1,312,291 $ - $ -
Meter Reconfiguration $ - $ - $ - $ - $ 18,720 $ -
Third-Party Gen
Meter Replace (Line 15) $ 242,000 $ - $ - $ 315,515 $ - $ -
Meter Reconfiguration $ - $ - $ - $ - $ 36,100 $ -
AGC $ - $ - $ - $ 157,724 $ - $ -
Totals $ 852,200 $ - $ - $ 1,785,530 $ 54,820 $ -
Utilicast $ - $ - $ - $ 67,060 $ - $ -
Grand Totals $ 852,200 $ - $ - $ 1,852,590 $ 54,820 $ -
Charter Estimates (as of 2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 25 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 26 of 47
o Monroe Street, Little Falls & Kettle Falls
6.5.6.1 Package 1 – Standard Substation Communication Package Scope
Some locations do not have IP communications delivered to the site. Those locations were planned to receive
IP communication services from a Network Service Provider. The Standard Substation Communication Package
includes contracting IP services from a third-party Local Exchange Carrier (LEC) and the installation of
communication hardware: Cisco Connected Grid Router 2010 (CGR2010), a Cisco Industrial Ethernet 4010
Switch (IE4010), and a NetGuardian Remote Terminal Unit (RTU) for monitoring the communications system
and physical elements of the substation. Fiber-optic transceivers, fiber jumpers and other cabling equipment
were also included.
6.5.6.2 Package 2 – Standard Substation Communication Package + High Voltage Protection Scope
This scope assumed the base installation of Package 1 and equipment to protect against Ground Potential Rise.
At some locations, a LEC wired communication service was required to protect from Ground Potential Rise – a
phenomenon that occurs when large amounts of electricity enter the ground and have a high potential to
harm people or equipment. To provide this High Voltage Protection (HVP), fiber-optic cabling is used between
the substation panel house and the Copper-Fiber Junction box (CFJ) where services from the provider are
transferred to Avista. The distance between these two points is determined by the LEC and provides protection
for the LEC if an electrical disturbance were to happen in the substation.
6.5.6.3 Package 3 – Standard Substation Communication Package + Modified High Voltage Protection Scope
This scope assumed the installation of Packages 1 & 2, with a modification for the CFJ. At some locations, a
power over fiber (PoF) solution was installed, which provides electrical isolation between the device and the
power supply. This eliminates the need to supply power to the CFJ outside of the substation, however that PoF
solution will not support T1/Ethernet services required for IP communications. Therefore, a power source and
enclosure were required at the CFJ.
6.5.6.4 Package 4 – Network Capacity Increase and Extension Package Scope
At some locations, IP communications were already available, but required an extension of the Local Area
Network (LAN) to provide connectivity to new meters. This package was identified for the generation facilities
due to the location of the meters and distance from the existing network cabinet. It also included additional
metering connectivity that could be required to support low and high side metering, along with small industrial
Ethernet switches currently, fiber-optic transceivers, and cabling.
6.5.6.5 Package 5 – Commercial Cellular Communications Scope
At some locations, IP communications could be attained via a wireless cellular option leveraging the standard
IP package of a Cisco Connected Grid Router 2010 (CGR2010), a Cisco Industrial Ethernet 4010 Switch (IE4010),
and a NetGuardian RTU for monitoring the communications system and physical elements of the substation
plus an LTE interface module in the Connected Grid Router.
6.5.6.6 Package 6 – Network Communications Expense Scope
At some generation or substation sites, IP communications already existed, but network configurations were
required to support metering work. This configuration could include opening a network port or updating an
existing drawing. No new assets were planned for installation; therefore this work is classified as a one-time
expense.
6.5.7 Network Infrastructure Financial Estimate Summary
The Charter estimates for network infrastructure assumed internal engineering design and field labor for all aspects of
the metering and control projects. They were represented under Charter Line Item 16 “Network Improvements for
Metering (1)” at $1.719 million in capital, $15k in re-occurring annual expense. Charter Line Item 26 “Network
Maintenance” at $256k represented a summary of on-going network expense, with the components of $215k for the
network packages and $39k for the dedicated network connections.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 26 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 27 of 47
Charter Line Item 24 “Network PM” reflected estimates for project management of the network projects, as the package
estimates did not include project management labor. The project management costs have been incorporated in the
Scope capital estimates for the projects. The original estimates failed to include labor for planning costs, AFUDC,
overheads and professional services (Utilicast). The updated estimates below include these additions. New estimates
also include scope changes for 13 substation locations and the elimination of six generation projects as listed in Section
5.5.6. With the exception of Package 6, all other expense estimates in the Scope column represent on-going O&M costs.
Table 16 – Network Financial Estimates Updates
6.5.8 Network – Miscellaneous Improvements
Beyond the network upgrades identified for the various generation and substation integration sites, Avista also
identified the potential need for network upgrades associated with EIM software, connection to CAISO’s Automated
Dispatch System (ADS) and meter access for BPA. These two items were represented under Charter Line Item 8
“Network for Vendor & CAISO” at $60k in capital, while the on-going expense was represented under Charter Line Item
26 “Network Maintenance” at $39k as a component of the total $256k.
Dedicated CAISO Connection: At the time of Program Charter estimates, Avista assumed a dedicated
communications network between CAISO and Avista would be needed to support dispatch operational targets
(DOTs) from CAISO’s ADS system. It was Avista’s preference to integrate with CAISO via a private leased solution
instead of a VPN connection over the Internet. Since that time, Avista has determined that a private leased
connection to CAISO is not required and this scope has been removed. This was represented under Charter Line
Item 8 “Network for Vendor & CAISO” with capital estimate was $35k, while on-going operations and
maintenance support expense was not included.
Dedicated SaaS Connection: At the time of Program Charter estimates, Avista assumed approximately seven
software solutions would be purchased with a SaaS deployment. It was unknown what Cloud Service Provider
(CSP) network would be used, but one of the three major CSP networks was assumed: Amazon AWS, Microsoft
Azure or Google Cloud. Avista’s preference was to utilize a leased private connection between Avista premises
and the CSP, with AT&T MPLS serving as the preferred conduit. Since that time, Avista has determined a leased
private connection to the CSP is not required and this scope has been removed. This was represented under
Charter Line Item 8 “Network for Vendor & CAISO” with capital estimate was $14k, while on-going operations
and maintenance support expense was not included.
6.5.9 Network Miscellaneous Financial Estimate Summary
The planned dedicated network connections have been removed from the Program scope and reflected below.
Track 5 - Network
Project Type Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Package 1 (Line 16) $ 270,000 $ - $ 91,000 $ - $ - $ 1,000
Package 2 (Line 16) $ 1,016,000 $ - $ 72,800 $ 457,200 $ - $ 18,200
Package 3 (Line 16) $ 208,000 $ - $ 36,400 $ - $ - $ -
Package 4 (Line 16) $ 225,000 $ - $ 15,000 $ 323,255 $ - $ 15,100
Package 5 $ - $ - $ - $ 751,796 $ - $ 35,200
Package 6 $ - $ - $ - $ - $ 10,000 $ -
Network PM (Line 24) $ 416,000 $ - $ - $ - $ - $ -
Totals $ 2,135,000 $ - $ 215,200 $ 1,532,251 $ 10,000 $ 69,500
Utilicast $ - $ - $ - $ 67,060 $ - $ -
Grand Totals $ 2,135,000 $ - $ 215,200 $ 1,599,311 $ 10,000 $ 69,500
Charter Estimates (as of 2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 27 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 28 of 47
Table 17 – Miscellaneous Network Financial Estimate Updates
6.6 Track 6 – Operations Readiness & Training
In order to prepare Avista for the EIM, there is a significant body of work for market training and understanding,
adopting software and navigating organizational change management. Joining the EIM has far-reaching effects across
System Operations, Power Supply, Generation, Substation, SCADA, and Technology, with each business unit gaining
understanding of how the market changes their day-to-day operations. This track accommodates training, items Avista
needs to prepare to accommodate new personnel and or compliance with joining the market, and the hiring of new FTEs
to support EIM market operations.
6.6.1 Operations Readiness & Training Scope Summary
6.6.1.1 Training
The CASIO provides computer-based training, in-person training, EIM workshops, train-the-trainer workshops
and training support for phased testing: Day in the Life, Market Simulation, Parallel Operations and Go-Live
initiation. In addition, Avista will need to develop their training plan, with specific emphasis given to
developing the internal operations readiness criteria for those operating in the market and training new FTEs
hired to support market settlements and analysis. This effort was represented under Charter Line Item 14
“Training & OCM” at $480k in Avista labor expense. This estimate provided for hiring a temporary
Organizational Change Management Specialist for the EIM Program and labor associated with training.
6.6.1.2 EIM Human Resource Plan
At the time of the Charter, Avista assumed additional temporary resources would be needed for the Program
implementation and incremental resources would be needed to support on-going EIM operations. Avista
planned for two additional resources to support the Program implementation – the EIM Program Manager and
the Organization Change Management Specialist. Costs associated with the EIM Program Manager were
primarily captured in Charter Line Item 9 “Program Leadership, Management & SMEs” at $700k.
Avista assumed 11-13 incremental FTEs would be needed to support EIM post go-live, with the positions hired
9-18 months prior to market entry and approximately one third of their time would be allocated to the EIM
project for market education and software training. Throughout Q1/Q2 2020, in partnership with Utilicast and
input from other EIM Entities, Avista conducted further analysis of what resources would be needed to
prepare for market entry during the implementation phase, and those that would be needed for effective and
efficient market operations. In June 2020, the EIM Human Resource Plan was signed by the Executive Steering
Committee members, approving 17 incremental EIM FTE hires throughout 2020-2021 in preparation for
market operations, however each individual position would be further evaluated prior to hiring to ensure need
and timing. In August 2020, hiring date revisions were made and are reflected in Table 18.
The need for the additional 5 FTEs (17 vs. 12), was determined through staffing conversations with other EIM
Entities, who indicated lean staffing levels at the time of market entry have hindered operational performance.
Avista believes the 17 FTEs represents a mature workforce needed to fully support EIM operations at market
entry. There were two primary areas that drove the FTE increase and associated costs – System Operations
and Settlements. Although System Operations planned for a team of five EIM Operators, they identified an
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Dedicated CAISO Connection (Line 8) $ 35,000 $ - $ 25,000 -$ $ - $ -
Dedicated SAS Connection (Line 8) $ 25,000 $ - $ 14,000 -$ $ - $ -
Totals 60,000$ -$ 39,000$ -$ -$ -$
Utilicast -$ -$ -$ -$ -$
Grand Totals 60,000$ -$ 39,000$ -$ -$ -$
Track 5 -
Miscellaneous Network
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 28 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 29 of 47
additional relief operator and adjusted the timing of each hire to allow for NERC certification. It was originally
assumed the existing accounting team could accommodate EIM settlements, with the addition of a Settlement
Analyst and Data Management Operator for meter data submission to the CAISO. After discussions with
Utilicast and other EIM entities, the need for a separate Settlements team was identified with a staff of up to
five.
EIM Operators: Within System Operations, a common approach to EIM operations includes adjusting
existing desk processes/responsibilities and adding an EIM Operator desk to focus solely on pre-operating
hour EIM operations. Through discussions with Utilicast, Avista identified which tasks would reside with
the Merchant and which tasks would reside with the Entity (Balancing Authority). The results included
shared generation management tasks between the Merchant and Reliability Operators, new EIM tasks for
the Reliability & Transmission Operators, and a full set of EIM tasks for the new EIM Operator role.
In order to provide continuity amongst all the operators and an environment for cross-functional desk/role
qualifications, the EIM Operator role will need to be NERC certified. This assumption requires all System
Operators to obtain NERC certification and qualify on their respective desks, with the Reliability Operators
and EIM Operators qualified for both desks. This would allow greater flexibility for covering shifts during
emergency conditions, training, vacations and unexpected absences. The NERC certification process will
require the EIM Operators to be hired at least 12-16 months in advance to allow for NERC certification and
learning the EIM job functions.
Settlements Team: When the original EIM FTE estimates were identified, Avista assumed the existing
MRTU settlements process would be similar to EIM settlements and assumed two additional FTEs would
cover Avista’s needs. In MRTU settlements, a member of Power Supply reconciles the charges for accuracy
and a member of the Resource Accounting team ensures CAISO payment and financial recording to the
financial system. As conversations with Utilicast and other EIM Entities, occurred, the complexity of the
EIM settlements and the need for dedicated team became clear. At the time of market entry, some Entities
underestimated settlement complexity and staff needed to perform the daily settlements processes and
have added staff to ensure adequate support. Avista plans to avoid this risk by proposing a settlement
team of up to five at the time of market entry, with imbedded analysts in the Merchant and Entity to
coordinate with the Settlements team and conduct deeper market analysis. While the Merchant Analyst
was included in the original FTE proposal, the Entity Analyst is an addition. The Entity Analyst role is vital to
understanding what impact the EIM BA Operator’s actions have on Avista’s overall performance and
financial position in the market.
The centralized Settlements team will support Merchant and Entity settlements, promotes expansion of
settlement specific skill sets and ensures the timely analysis and appropriate priority is given to
settlements. The team will have visibility to the financial results for both the Merchant and Entity, so cost
benefit studies and overall market performance will be more easily evaluated and assembled.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 29 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 30 of 47
Table 18 – EIM Human Resource FTE Comparison
In the EIM HR Plan document, a financial estimate during the implementation and post-implementation phases
was established. Each FTE was assigned an estimated hire date, an annual salary (assumed 78.05% loaded rate)
and a breakout of efforts between capital and O&M. These resources were further assigned an estimated annual
3% annual merit increase, and where applicable, incremental step increases based on achieving certain
experience levels. This framework provided an estimate of annual capital and O&M FTE costs across 2020-2023,
with 2022 representing a shift to primarily O&M expenses based on a market go-live date of March 2022 and
2023 representing a fully burdened O&M year. With the increased incremental FTE count needed to support
market operations, a better understanding of when the new FTE needs to be hired and a robust financial
estimating framework, the Program saw an increase of capital, implementation expense and on-going O&M
costs. Of the Charter’s $3.5-$4 million annual estimated on-going expense impact, $2.5 million was estimated
for labor (assumed 60% loading rate). The revised estimate of 17 EIM FTEs increased the annual labor estimate
to $3.2 million (system loaded).
As shown in Table 19, an estimate for the EIM incremental FTEs was accommodated under Charter Line 17 and
17a “Incremental Permanent Avista FTEs”: $550k in capital, $185k in implementation expense and $2.5 million
in on-going annual expense. The original new employee estimate included only four months of labor costs to
support parallel testing and employee training. The Charter estimate significantly underestimated the
Quantity Hire Date Quantity Org. Hire Date
(as of 06/2020)
Rev. Hire Date
(as of 08/2020)
Implementation Resources
EIM Program Manager 1 Jan-19 1 Jan-19
Org. Change Management Specialist 1 1 Sep-20
Substation Engineer 1 Jan-20
Total 2 3
Incremental EIM FTEs
Power Supply Analyst 1 Oct-20 1 Jul-21 Sep-21
Network Model Tech 1 Oct-20 1 Jun-20
SCADA Tech 1 Oct-20 0
EIM BA Desk 1 Jul-21 1 Feb-20
EIM BA Desk 1 Jul-21 1 Sep-20 Oct-20
EIM BA Desk 1 Jul-21 1 Sep-20 Oct-20
EIM BA Desk 1 Jul-21 1 Jan-21
EIM BA Desk 1 Jul-21 1 Jan-21
EIM BA Desk 0 1 Mar-21 Mar-22
Training Admin 0 1 Mar-22
EIM BA Analyst 0 1 Jul-21 Sep-21
Settlements Manager 0 1 Sep-20 Oct-20
Data Management Operator 1 Oct-20 1 Apr-21
Settlement Analyst 1 Apr-21 1 Apr-21
Settlement Analyst 0 1 Jul-21 Jun-21
Settlement Analyst 0 1 Jul-21 Aug-22
Compliance 0 or 1 Apr-21 0
IT Analyst 1 or 2 Oct-20 1 Jun-20 Oct-20
IT Analyst 0 1 Jun-20 Jan-21
Total 11 to 13 17
Scope Estimates (as of 08/2020)Charter Estimates (as of 05/2019)
EIM FTE Estimates
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 30 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 31 of 47
incremental integration labor. In addition to the specific incremental labor in Charter Line Item 17, other
incremental labor estimates included in the Charter. In order to provide a net incremental estimate based on
the EIM HR Plan, Table 19 identifies other Charter incremental labor estimates and removes them from the EIM
HR Plan estimates. In August 2020, prior to incorporating the updated EIM FTE incremental costs in the Scope
forecast, the EIM FTE cost estimates were reviewed and further reductions were made to reflect 2020 hiring
delays and the postponement of two positions – the Training Admin and one of the Settlement Analysts. These
positions will be hired approximately six months after market go-live. Those August reductions are presented in
the August 2020 HR Plan Reductions line in Table. 19.
Table 19 – EIM Human Resource FTE Estimates
6.6.1.3 Go-live Procedures and Support Model
In partnership with the CAISO, Avista will determine the planned go-live procedures that must be followed
across all business units to ensure a smooth transition into the market. In order to support market operations
post go-live, Avista has been discussing options for a 24-hour technology support model with a combination of
vendor and internal labor support. This level of technology support is not present in current operations, and
the limited availability of support is not scalable. Avista will continue discussions to ensure the appropriate
support model is in place at the time of market entry. Avista has planned for two technology resources
dedicated to EIM software operations. Details and cost estimates can be found in the EIM Human Resource
Plan.
6.6.1.4 Transmission System Operations EIM Desk Scope – Mission
To prepare for EIM entry, Transmission System Operations needs to hire additional personnel to staff a 24x7
EIM Operator desk/workstation. The existing System Operations area has the Reliability System Operator desk,
the Training/Storm Recovery desk and the Transmission System Operator desk. The original scope planned to
modify the System Operations area to accommodate an additional workstation to perform the necessary EIM
activities, while maintaining sight lines to necessary displays/monitors and not hindering the necessary
activities and functions performed by the existing desks. This scope planned to deliver two new computers, a
phone console, new monitors, ergonomic chairs and a projector and screen for the Mission Campus. This was
represented under Charter Line Item 22 “Transmission Desk” at $233k in capital, while no expense was
estimated.
6.6.1.5 Transmission System Operations EIM Desk Scope – BuCC
The establishment of an EIM BA desk/workstation at the Backup Control Center (BuCC) was not planned under
the EIM Program Charter. The establishment of a secondary control center is mandated by NERC and the EIM
BA workstation needs to be operational by market entry. After reviewing the available space at the BuCC, the
Program will deliver a modified workstation with two new computers, new monitors and a new phone console.
This project was not planned in the Program Charter and must be complete prior to market go-live in
accordance with FERC standards that require a functional back up control center where all functions of the BA
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Incremental Avista FTEs (Line 17, 17a) $ 550,000 $ 185,000 $ 2,500,000 $ - $ - $ -
EIM Human Resource Plan $ - $ - $ - $ 2,878,954 $ 2,285,070 $ 3,227,467
Program Leadership & SMEs (Line 9) $ - $ - $ - $ (350,000) $ - $ -
Full Network Model (Line 11) $ - $ - $ - $ (80,000) $ - $ (50,000)
Training & OCM (Line 14) $ - $ - $ - $ - $ (480,000) $ -
System Selection (Line 10) @ 25% $ - $ - $ - $ - $ (170,000) $ -
August 2020 HR Plan Reductions $ - $ - $ - $ (193,735) $ (601,500) $ -
Totals $ 550,000 $ 185,000 $ 2,500,000 $ 2,255,219 $ 1,033,570 $ 3,177,467
Utilicast $ - $ - $ - $ - $ - $ -
Grand Totals $ 550,000 $ 185,000 $ 2,500,000 $ 2,255,219 $ 1,033,570 $ 3,177,467
Track 6 - EIM HR FTEs
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 31 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 32 of 47
and Transmission Operators can be performed and meet all compliance standards. The capital estimate for this
project is $86k.
6.6.1.6 Noxon 230kV Switchyard CIP PSP Project
As part of the metering and network upgrade projects at the Noxon Hydro Eclectic Dam (HED) and the Noxon
230kV Switchyard, external routable communications have been introduced, thus classifying the Noxon 230kV
Switchyard as a Medium Impact BES Cyber System. Due to this new classification, additional requirements
must be met to remain compliant with all relevant Critical Infrastructure Protection (CIP) requirements. This
project will implement new processes, cyber security and physical security infrastructure at the Noxon 230kV
Switchyard. The CIP standards that will be addressed in this project include:
o CIP-004-6 Cyber Security – Personnel & Training
o CIP-005-5 Cyber Security – Electronic Security Perimeters
o CIP-006-6 Cyber Security – Physical Security of BES Cyber Systems w/ (ERC)
o CIP-007-6 Cyber Security – System Security Management
o CIP-008-5 Cyber Security – Incident Reporting and Response Planning
o CIP-009-6 Cyber Security – Recovery Plans for BES Systems
o CIP-010-2 Cyber Security – Configuration Change Management & Vulnerability
o CIP-011-2 Cyber Security – Information Protection
This project was not planned in the Program Charter and must be complete in order to implement the metering
and control projects at Noxon HED. The capital estimate for this project is $95k and $25k for implementation
expense.
6.6.2 Track 6 Financial Summary
The primary cost driver in Track 6 is the EIM HR Resource Plan, documenting the incremental FTEs needed for market
operations. The Charter estimates did not sufficiently account for the capital and expense costs associated with the EIM
FTEs during project implementation. Updates have been made to remove duplicate incremental labor costs represented
in other areas of the Charter (Table 19) and represent the net additional costs to the Program. The estimates also
include the following:
An updated FTE capital allocation across 2019-2022 and an updated annual O&M expense estimate (including
the August 2020 revisions).
A capital estimate for the additional EIM desk at the BuCC
A capital and expense estimate for the Noxon 230kV Switchyard CIP compliance project.
Table 20 – Operations Readiness & Training Financial Updates
Capital Implementation
Expense
Ongoing
Expense Capital Implementation
Expense
Ongoing
Expense
Training & OCM (Line 14) $ - $ 480,000 $ - $ - $ 480,000 $ -
EIM Human Resource Plan (Line 17, 17a) $ 550,000 $ 185,000 $ 2,500,000 $ 2,255,219 $ 1,033,570 $ 3,177,467
EIM System Ops Desk - Mission (Line 22) $ 233,000 $ - $ 225,071 $ - $ 4,000
EIM System Ops Desk - BuCC $ - $ - $ 86,000 $ - $ 4,000
Noxon 230kV CIP PSP $ - $ - $ 110,624 $ 10,000 $ -
Totals $ 783,000 $ 665,000 $ 2,500,000 $ 2,676,914 $ 1,523,570 $ 3,185,467
Utilicast $ - $ - $ - $ - $ - $ -
Grand Totals $ 783,000 $ 665,000 $ 2,500,000 $ 2,676,914 $ 1,523,570 $ 3,185,467
Charter Estimates (as of 05/2019)Scope Estimates (as of 08/2020)Track 6 - Operation Readiness &
Training
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 32 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 33 of 47
6.7 Where will assets or technology be deployed?
The EIM Program has a range of physical assets that will be installed and a variety of technology applications that
will be deployed. Physical assets such as meters and control systems and network and communications
equipment, will be deployed at generation plants, third-party generation locations and substation
interconnection facilities. EIM technology application assets for Power Costs, Inc. will be deployed in the Amazon
Web Services (AWS) cloud environment, while the Power Settlements EIM application will be deployed at Mission
Campus and Avista’s disaster recovery center in San Jose, CA.
7 EIM Program Milestones
Avista originally signed the EIM Implementation Agreement with an April 1, 2022 entry date. Since that time, other
entities have announced entry for the 2022 class: BPA, Tacoma Power, Tucson Electric and Xcel Energy (parent company
of Public Service Company of Colorado). Due to BPA operational and environmental requirements, they were able to
negotiate a March entry date. In early 2020, BPA leadership approached Tacoma and Avista EIM leadership about
changing their entry date to March 2, 2022. This request was driven by a desire to align testing cycles and operational
data, as there are numerous transmission interconnection points BPA shares with Tacoma and Avista. Discussions with
BPA, Tacoma and CAISO leadership, and internal review amongst the Avista EIM Program team and Steering
Committees, occurred in Q1/Q2 2020. After seeking approval from the Director and Executive EIM Steering Committees
in July 2020, Avista formally changed their market entry date to March 2, 2022.
In order the meet the March entry date, the internal Avista schedule needed to align with the adjusted March-driven
CAISO milestones. In addition, Avista set an internal deadline date of June 2021 for the completion of all metering,
controls and software projects for a successful entry into the testing phases. The below table reflects the adjusted
milestone schedule.
Major Milestone Descriptions
Target Completion Dates (MM/YY)
Planned Date Revised Date


















Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 33 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 34 of 47
Connectivity & Integration
Day-in-the-Life
Market Simulation
Parallel Operations
NA 08/2021
NA 09/2021
NA 11/2021
NA 02/2022
All EIM Systems Go-Live with CAISO 03/2022 03/2022
All EIM Technology Systems Warranty 07/2022 06/2022
Program Closing
Program Level Approval to Close 12/2022 12/2022
7.1.1 CAISO Project Milestones
The below schedule represents the CAISO driven project schedule for EIM entry on March 2, 2022. The
milestones listed reflect payment to the CAISO of $50k per milestone, for a total, implementation fee of $300k
to join the EIM market. Unless otherwise stated, the milestone dates below represent a month-end deadline.
Activity Project Delivery Dates
supporting
March 2, 2022 Go-Live
Detailed Project Management Plan
The Parties will develop and initiate a final project management plan that
describes specific project tasks each Party must perform, including delivery
dates, project team members, meeting requirements, and a process for
approving changes to support completion of the Project. This phase will
include a detailed IT system review to assist Avista in development of a
detailed metering plan, bid-to-bill system and coordination with Avista EMS.
Work will be initiated on the Avista staff training program using the
foundational and detailed system computer-based training module, as well
as on the resource data templates needed during Milestone 2.
March 2019-
December 2019
Milestone 1 – This milestone is completed when the Agreement has
been made effective in accordance with Section 1 of the Agreement.April 2020
Full Network Model Expansion
Full Network Model expansion for Avista and EMS/SCADA including: proof of
concept of export/import of EMS data, complete model into the CAISO test
environment, complete validation for all SCADA points from Avista, testing of
the new market model and validation of the Outage and State Estimator
applications.
November 2020
Milestone 2 – This milestone is completed upon modeling Avista into
the CAISO Full Network Model through the EMS which will be
deployed into a non-production test environment using the CAISO's
network and resource modeling process.
June 30, 2021
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 34 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 35 of 47
System Implementation and Connectivity Testing
System requirements and software design, the execution of necessary
software vendor contracts, development of Market network model including
Avista, allow Avista to connect to a non-production test system.
August 2021
Milestone 3
CAISO to promote market network model including Avista area to non-
production system, and allow Avista to connect and exchange data in
advance of Market Simulation.
July 15, 2021
Construction, Testing and Training in Preparation for Market Simulation -
This task includes IT infrastructure upgrades, security testing, training, Day-in-
life simulation and functional testing.
July 15, 2021
Milestone 4a
Start of Joint Integration Testing with CAISO, Interface testing with
minimum data requirements and functional integration testing. CAISO
will make the test environment available for Avista connectivity testing
prior to the delivery date assuming Avista has provided all prerequisite
data and non-production system availability does not conflict with
CAISO production system Spring Release schedule.
Mid-July 2021
Milestone 4b – Begin ‘Day in the Life’ scenario testing September 2021
Milestone 4c – Begin Structured Market simulation
(Milestone 4 payment due at this point)October 1, 2021
Activate Parallel Operations
During December 2021, the CAISO will activate a parallel operation
environment to practice production grade systems integration as well as
market processes and operating procedures in anticipation of the impending
Avista activation as an EIM Entity and to confirm compliance with the EIM
readiness criteria set forth in the CAISO tariff.
December 2021
Milestone 5 – Start of parallel operations December 2021
System Deployment and Go Live
Implementing the Project and going live will include resource registration,
operating procedures and updates, execution of service agreements,
completion of the Avista tariff process, applicable board approvals, the filing
and acceptance of service agreements and tariff changes with FERC, and
March 2, 2022
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 35 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 36 of 47
completion and filing of a readiness criteria certification in accordance with
the CAISO tariff.
Milestone 6 – This milestone is complete upon the first production
Avista EIM trade date.
March 2, 2022
8 Program Assumptions, Risks, Constraints & Dependencies
This section has been updated to reflect changes at the Program level since the time of the Charter. Items resolved or no
longer applicable have been removed, while open items or new additions have been listed below.
8.1 Assumptions
The following assumptions have been made:
a)All Avista required program/project resources will be available for the duration of the program.
b)All the necessary funding to complete the program will be available.
c)All Avista business users will be available for all application and system testing phases within the
independent projects and the program as a whole.
d)The in-house Avista Decision Support System (ADSS) application will be enhanced for EIM functions.
e)The in-house Nucleus application will have minor modifications for EIM functions.
f)Avista will receive the needed permissions from various third-party generation and metering entities to
perform EIM-related upgrades. Avista will fund EIM-related upgrades at various third-party sites.
g)Avista will procure an Energy Management System (EMS) plug-in for EIM market dispatch integration.
h)Avista plans to conduct an EMS upgrade prior to market entry funded by the SCADA BC. Although the
upgrade is planned to be complete in March of 2021, prior to the internal Avista deadline of June 2021,
any delays for this project would significantly impact Avista’s ability to conduct the CAISO testing phases
and market go-live as planned.
i)Avista has plans to fund a 24-hour operations center within the next three-five years, to house various
operational business units, including Transmission System Operations. As such, the construction effort
and costs for the EIM transmission operations desk at Mission campus and the Backup Control Center
(BuCC) should be kept minimal.
j)The in-flight GPSS funded Human Machine Interface (HMI) project and the EIM-related PLC projects,
have independent scope. The HMI project’s goal is to standardize plant control screen display for plant
operators, and the EIM PLC projects will capitalize on that standardization to display EIM data. If the
HMI project is complete at the site where an EIM PLC project is needed, the new HMI screens will be
updated to incorporate EIM data. If the HMI project has not begun at a site where an EIM PLC project is
needed, the existing HMI screens will be updated with EIM data until the HMI project is available to
update that site.
k)The Long Lake EIM LSM project will be completed independent of a future-planned Long Lake Overhaul
project.
l)Although an integration with the settlement software to Avista’s Oracle E-Business Suite (EBS) financial
system is desirable, it is not necessary for market entry. The project team will consider integration
options, but be prepared to create a manual process for recording EIM financial data in the financial
system. Costs associated with full integration between the settlement software and EBS are not included
in the Scope program estimates.
m)As part of the PCI Asset Operations software suite, Avista purchased licenses for the PCI Journal module
–a feature that supports operator logging. The Program costs include the purchase of the licenses and
initial scoping with PCI for transmission and generation use, but the implementation of the module will
be funded outside the EIM Program.
n)Joining the Western EIM presents a large amount of organizational business change that will require an
Organizational Change Management (OCM) plan. An OCM specialist will start in September 2020 and
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 36 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 37 of 47
will be a dedicated advocate for the Program’s success and employee adoption of the EIM practices
through go-live.
o)The installation of revenue quality meters in substation will not preclude existing third-party meter data
access. The new meters will continue to collect hourly data, and supplement with the collection of five-
minute internal data for EIM.
p)If Avista fails to meet the March 2, 2022 market entry date with BPA and Tacoma, the CAISO will allow
us to join April 1 with the rest of the 2022 class. This will present additional testing and operational
challenges.
8.2 Risks
Program level risks will be managed through a spreadsheet and posted to a common work-space accessible by
EIM project team members. Program risk will be discussed at steering committee meetings for mitigation
recommendations and decisions, and decisions will be documented. The following are potential risks for the
Program:
a)Interdependencies and integrations between EIM software projects will add complexity and may delay
project completion.
b)Interdependencies among the control/meter upgrade projects and the network projects may delay
project completion.
c)Competing priorities amongst other Avista programs/projects may constrain funds and resource
availability. Resource areas that are likely to be constrained include network engineers, substation
engineering and design, protection engineers and generation engineers.
d)This program requires multiple, concurrent projects to be in flight at the same time, while competing for
the same business, engineering and technology resources.
e)Although an integration with the Settlement software to Avista’s Oracle E-Business Suite financial
system is desirable, the financial application upgrade timeline may not align with the EIM
implementation timeline. If an integration were to be pursued on an unsupported platform, it could
cause technical complications or require rework after the application is upgraded. The project team will
pursue integration efforts, but will also create a manual process for recording EIM financial data in the
financial system.
f)Delays in business processes re-engineering based on EIM requirements and complexities will impact
the program/project schedule.
g)The in-flight HMI project utilizes the same ET resources needed for EIM-related projects that could cause
delays in completing work.
h)Delays in the POPUD interconnection and generation meter upgrades will hinder Avista’s ability to
submit five-minute meter data granularity.
i)Market entry requires Avista to follow CAISO’s time for FNM updates, including updates independent of
Avista and those related to market entities interconnected with Avista. This timeline will impact field
construction schedules and data submission deadlines. Although failure to meet these deadlines doesn’t
limit Avista’s ability participate in the market, it does negatively impact neighboring interconnected
entities and Avista’s EIM settlements.
j)Avista plans to conduct an EMS upgrade prior to market entry funded by the SCADA BC. Although the
upgrade is planned to be complete in March of 2021, prior to the internal Avista deadline of June 2021,
any delays for this project would significantly impact Avista’s ability to conduct the CAISO testing phases
and market go-live as planned.
k)The completion of the Burke substation network upgrades may be at risk due to potential
environmental compliance. The Burke substation is located on a Superfund site, which requires a long-
term response to clean up hazardous material contaminations. Additionally, the site’s climate incurs
inclement weather regularly which could impact construction at the site, both for third party and Avista
construction.
l)The COVID-19 pandemic has forced a majority of the Avista workforce to work remotely for an extended
period of time. At the time of this writing, the overall Program schedule hasn’t been impacted by this
shift, though individual projects have been delayed due to crew’s ability to work on site or the
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 37 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 38 of 47
constraints of conducting application design sessions remotely. It is unknown how long this pandemic
may impact Avista’s work plans, which may likely be a significant risk to meeting the Program schedule
for market go-live.
8.3 Constraints
The program schedule is the hard constraint. Although Avista originally signed the CAISO implementation agreement
with an EIM entry date of April 1, 2022, Avista plans to formally change their entry date to March 2, 2022 to align with
BPA and Tacoma Power. In order to meet that date, Avista will chose to adjust scope and budget as necessary.
Given a fixed schedule, we will choose a scope and adjust resources as necessary.
Place one “X” in each column (one per row) to provide a visual queue as to this project’s Flexibility Matrix.
Flexibility Matrix Low Flexibility Medium Flexibility High Flexibility
o Note: Quality is always expected to be high
8.4 Dependencies
Given the vast business impact of the EIM program, there are multiple projects that rely on other portions of a project
being complete – both inside the EIM BC and in other business cases – for EIM work to be completed.
8.4.1 GPSS Dependencies
a)The introduction of external routable communications at the Noxon 230kV interconnection substation due
to EIM metering upgrades, has required the location to be classified as a Medium Impact Bulk Electric
System (BES) Cyber System location. Medium Impact BES locations must comply with various Critical
Infrastructure Protection (CIP) standards regulated by NERC. The Noxon 230kV CIP project must be complete
prior to the Noxon 230kV metering upgrade project and the Noxon HSM, LSM and PLC projects conducting
their integrated configurations and testing for production use.
b)The Cabinet Gorge HSM, PLC and LSM (not funded by EIM Program BC) projects all depend on the Cabinet
Gorge Automation Project for Unit 2, 3 and 4 (not funded by EIM BC).
c)All LSM, HSM and PLC projects have some level of dependency on each other at the plants
d)Coyote Springs 2 and Lancaster both rely on PTs and high side meters at BPA substation interconnection
sites. Avista will partner with BPA to perform the EIM-related work at those locations.
e)The completion of HSM projects will require completion of the PLC and network projects.
8.4.2 Network Dependencies
a)Conducting EIM operations from the Backup Control Center (BuCC) will be required. The EIM Program has
planned to install an EIM BA workstation at the BuCC. The ability for EIM work to be quickly executed will be
aided by the Session Initiation Protocol (SIP) project. This project will increase network bandwidth to Backup
Control Center (BuCC) and is not funded by the EIM Program BC. The completion of the EIM BA workstation
at the BuCC is not dependent on completion of the SIP project at the BuCC, but conducting work from the
BuCC would be improved.
8.4.3 Transmission System Operations/SCADA Dependencies
a)None known at the time of the document submission.
8.4.4 Substation Dependencies
a)The EIM meter replacement at the Westside interconnection substation is not part of the EIM Program BC.
The meter replacement scope will be funded under a multi-phase substation rebuild at Westside. The
completion of the rebuild is dependent on the timing of another project – the Downtown Transmission
Cable Replacement project. These dependencies impact the timeline of when the EIM work can be
completed at Westside. The current schedule calls for the Westside rebuild to be completed by the end of
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 38 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 39 of 47
May 2021, which is close to the June 2021 EIM internal deadline for project completion. If the work cannot
be completed within the EIM timeline, Avista may seek a metering exception for Westside with CAISO.
9 Program Costs
9.1 Actual Costs as of August 2020
The EIM Program formally began in March 2019 and the tracking of EIM project costs began in June 2019. The EIM
software RFP process (expense) was conducted in 2019, and Avista began capital projects focusing on network, metering
and control upgrades. As of August 2020, Avista has formally transferred to plant or put into production, seven projects:
ET Applications: EIM MV90 head-end meter system, the CT Analyzer for transformer testing.
ET Network: Nine Mile LSM Network, Post Falls LSM Network, the Noxon PLC Network
Generation: Noxon HSM
Substation: Noxon HSM Substation 230kV
The following details are reflected in the actual Program charges between June 2019 and August 2020:
Avista began recording EIM expense labor as of June 1, 2019 with project accounts in the given business areas.
The expense charges in Table 21 reflect totals and do not include a reduction associated with the Idaho
Commission’s deferral order.
As described in the EIM Human Resource Plan, Avista planned to hire three temporary FTEs to support the
Program implementation and 17 incremental FTEs to support on-going EIM operations. As of August 2020,
Avista has hired two of the Program implementation FTEs (Program Manager and Substation Engineer) and two
incremental FTEs for on-going support (EIM BA Operator and EMS Modeling Engineer).
The Utilicast capital costs reflect charges under the 2020-2022 Implementation Agreement for support of
metering, controls and network upgrades, and software application projects.
The Utilicast expense costs are associated with the 2019 Utilicast Technology RFP and the 2020-2022
Implementation Agreement. The 2018 Utilicast Assessments expense costs were are not included. Although the
Utilicast expense items may align with support of a specific business unit, the costs have been centralized under
the EIM Program line and charged to the Power Supply business unit.
The Substation business unit is inclusive of capital costs for the Transmission FNM support, the EIM Dispatch
Module, the Noxon 230kV CIP project, the Noxon 230 kV project and the Northeast CT project.
In terms of Implementation Expense, the EIM Program line represents the business units that charge labor
expense to the Program, including Power Supply, Supply Chain, Legal, Rates and Technology Applications.
Table 21 – EIM Program Implementation Costs as of August 2020
Avista Utilicast Avista Utilicast
ET Applications $ 855,024 477,231$ -$
ET Network $ 636,214 46,399$ 8,593$
GPSS $ 1,946,138 43,309$ 206,822$
Substation $ 624,687 20,256$ 54,374$
Transmission $ - -$ 314,002$
Facilities $ 34,072 -$ -$
ADSS $ 603,126 70,281$ -$
EIM Program $ - -$ 569,983$ $ 684,795
Totals 4,699,261$ 657,476$ 1,153,774$ 684,795$
Grand Totals
Actual Program Costs
by Business Unit
(as of 08/2020)
Actual Program Costs (as of 08/2020)
Capital
$ 5,356,737 1,838,569$
Implementation Expense
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 39 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 40 of 47
9.2 Forecasted Program Cost Estimates as of August 2020
The Charter estimates from May 2019 outlined the total integration costs for joining the EIM (Table 22). After a year into
the EIM integration effort and acquiring a better understanding of the market operation support needs, the Program
Scope Document reflects the updated estimated costs for market integration. The total project estimates from the
original Charter to the Scope Document are provided in Table 22 (Charter) and Table 23 (Scope) for comparison.
Table 22 – Charter Program Estimates as of May 2019
Table 23 – Scope Program Estimate as of August 2020*
*Pre-paid expense estimates reclassified to capital
Implementation Capital – this estimate includes all known updated project costs for EIM software
integration, EIM resource plan, and metering and controls upgrades.
Implementation Expense – this estimate includes all known expense costs associated with market
integration prior to market entry, including existing Avista labor, new Avista labor (incremental) associated
with the EIM HR Plan for market operations, and non-labor expense items such as the CAISO milestone
payments and Utilicast.
Contignecy – this estimate for capital and expense represents funds to cover unknown costs or increased
costs above expected spend. This is consisent with Avista project estimating practices. Considering most
phyiscal infrastructure projects have completed the 60% design phase and the hiring of new employees is
set based on the EIM Human Resource plan, the contignecy estimate is lower than the Charter estimate.
Annual O&M Expenses – this estimate includes all known updated costs associated market operations post
go-live, including the incremental Avista labor to support EIM operations (EIM HR Plan), CAISO grid
management fees, software maintenance and liscencing fees, and network maintenance.
Annual Capital Estimate – this prelimary estimate represents anticipated capital costs for software
enhancements and upgrades. Avista will have a better estimate after gaining operational experience and
understanding the impact CASIO annual updates have on system integration. These estimates were not
included in the cost benefit anaylsis.
EIM Program Charter Estimates
(as of 05/2019)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 18,129,000 $ 4,532,250 $ 22,661,250 $ - $ -
Expense $ 2,380,000 $ 595,000 $ 2,975,000 $ 3,534,000 $ -
Pre-Paid Expense $ 840,000 $ 210,000 $ 1,050,000 $ - $ -
Total Costs $ 21,349,000 $ 5,337,250 $ 26,686,250 $ 3,534,000 $ -
EIM Program Scope Estimates
(as of 08/2020)Implementation Contingency Totals Annual O&M
Expenses Annual Capital
Capital $ 24,091,964 $ 2,600,000 $ 26,691,964 $ - $ 500,000
Expense $ 5,011,026 $ 400,000 $ 5,411,026 $ 3,907,100 $ -
Total Costs $ 29,102,990 $ 3,000,000 $ 32,102,990 $ 3,907,100 $ 500,000
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 40 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 41 of 47
9.3 Forecasted Program Cost Estimates by Business Area
The estimates in Table 24 (Charter) represent the Charter costs by business area, excluding the contingency. For
comparison, Table 25 (Scope), excluding contingency, has been provided.
Table 24 – Charter Program Costs by Business Unit as of May 2019
*Capital labor associated with the New Avista FTEs was included in the Transmission & Substation estimate
Table 25 – Scope Program Costs by Business Unit as of August 2020
9.4 Incremental Cost Guidance & Estimates
9.4.1 IPUC EIM Expense Deferral & Approval
On March 23, 2020, the Idaho Public Utilities Commission (IPUC) issued Order No. 34606 approving Avista’s application
to defer incremental O&M costs (without a carrying charge), associated with joining the EIM operated by the
CAISO. Commission Staff comments, filed on March 4, 2020 expressed support of Avista’s request to defer its EIM
incremental expenses, noting they believe the Company demonstrated it is reasonable for it to join the EIM. Per Order
No. 34606, the Company is to cease deferring the incremental implementation costs at the go-live date, and is to file a
report after one year of participation, describing the costs and benefits of participation, any other relevant information,
Business Area
(as of 05/2019)
Implementation
Capital
Pre-Paid
Expense
Implemention
Expense
Annual O&M
Expense
ET Applications $ 4,640,000 $ 840,000 -$ 593,000$
Application Procurement $ - $ - 1,180,000$ -$
ET Network $ 2,465,000 $ - -$ 271,000$
GPSS $ 5,164,000 $ - -$ -$
Transmission & Substation $ 1,760,000 $ - 420,000$ -$
EIM Program $ 4,100,000 $ - 780,000$ 120,000$
New Avista FTEs $ - $ - -$ 2,550,000$
Grand Totals $ 18,129,000 $ 840,000 $ 2,380,000 $ 3,534,000
Business Area
(as of 08/2020)
Implementation
Capital
Pre-Paid
Expense
Implemention
Expense
Annual O&M
Expense
ET Applications $ 9,760,600 $ - -$ 532,133$
ADSS $ 3,460,133 $ - -$ -$
Application Procurement $ - $ - 1,251,671$ -$
ET Network $ 1,599,311 $ - 10,000$ 77,500$
GPSS $ 4,462,416 $ - 284,576$ -$
Substation $ 1,963,214 $ - 264,820$ -$
Transmission $ 280,000 $ - -$ -$
Facilities $ 311,071 $ - -$ -$
EIM Program $ - $ - 1,685,000$ 120,000$
New Avista FTEs $ 2,255,219 $ - 1,513,570$ 3,177,467$
Grand Totals $ 24,091,964 $ - $ 5,009,637 $ 3,907,100
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 41 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 42 of 47
including but not limited to the CAISO’s quarterly Western EIM Benefits Report. Recovery of any operational cost
associated with membership in the EIM after the Company's go-live date would be determined in a future proceeding.
At that time, a prudency review would be conducted to determine the reasonableness of recovering the deferrals from
Idaho customers.1
At the time of the filing, the Company expected the annual O&M expense after joining the market to be approximately
$3.5 - $4.0 million per year on a system basis, mostly associated with adding 11-13 new employees to facilitate market
operations and settlements, including a five-person 24x7 hour EIM operating desk. Idaho’s share of these costs is
approximately 35% or $1.2 - $1.4 million annually. Staff noted the Company’s estimated costs appear reasonable and
that it is Avista’s responsibility to demonstrate these costs are prudent prior to recovery. Staff noted some concern over
expected labor costs, when comparing Avista’s estimated costs to that of similar utilities, but recognize current cost
estimates may change and will be reviewed in detail in future general rate cases.
9.4.2 Avista’s Incremental EIM FTE Guidance
After the approval by IPUC of the Company’s accounting petition to defer incremental operating expenses associated
with the implementation of EIM, the following guidance will be used to determine what expenditures are incremental.
EIM incremental guidance determination:
New positions* which are added specifically for EIM will be considered incremental if they meet one of the
following criteria:
o A new employee is hired into an EIM position.
o An existing employee is hired into an EIM position and their previous position is backfilled.
* Avista will not account for partial positions (i.e. an employee is working on EIM and non-EIM work) as incremental
unless there is a significant impact to the business and there is a determinable way to recognize and document the
specific incremental portion of actual work.
Labor Loadings (primarily medical and retirement benefits) for incremental employees are tracked as “non-
labor” within the Company’s financial system. Loadings are determined monthly by the Company’s internal
Corporate Accounting team and represented as a percent which is applied to the account where the direct labor
is charged. In order to appropriately represent the net cost of these incremental employees, the company will
apply the loading rate to the incremental labor cost for each new employee.
Based on Avista’s incremental guidance, the Table 26 represents incremental expense during implementation and the
anticipated on-going expense.
Table 26 – Scope Incremental Cost Estimates
_____________________________________________________________________________________________
1 Avista intends to include Washington’s share of all incremental EIM capital expenses in future Washington General Rate Cases.
EIM Program Scope Estimates
(as of 08/2019)Implementation Contingency Totals Annual O&M
Expenses
Capital $ 24,091,964 $ 2,600,000 $ 26,691,964 $ -
Incremental Expense $ 3,608,880 $ 400,000 $ 4,008,880 $ 3,907,100
Total Costs $ 27,700,844 $ 3,000,000 $ 30,700,844 $ 3,907,100
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 42 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 43 of 47
10 Cost Benefit Analysis
Prior to signing the CAISO EIM Implementation agreement in April 2019, Avista hired Energy and Environmental
Economics (E3) to conduct an EIM benefit assessment in the fall of 2017. E3 conducted similar benefit assessments for
several other utilities to help understand the potential value of EIM participation. The E3 assessment estimated that
Avista could see a range of annual benefits from $2 to $12 million from EIM participation. There were four main study
assumptions that drove the wide range of potential EIM benefits: the amount of flexible hydro Avista bids into the
market, the amount of transmission made available for market transactions, the amount of renewable generation that is
integrated into the Avista BAA, and the assumed EIM price volatility. E3 stated in the Avista’s Benefit Analysis report in
the Overview section on page 3, “actual benefits to Avista will depend primarily on the availability of its hydropower
resources to participate in the EIM, the transmission capacity that is available for use by the EIM, expansion of wind and
solar resources within the Avista balancing area, and EIM market conditions.” These are the primary drivers for EIM
benefits and will be different for each EIM participating utility.
Using Avista’s best estimates for these critical study assumptions, Avista anticipates EIM annual benefits to be close to $6
million, with potential for benefits to move closer to the upper end of the study range depending upon observed market
price volatility. Recent market price volatility experienced in 2018 significantly increased the benefits of current market
participants. Both the Idaho Power Company (IPC) and Portland General Electric (PGE) achieved EIM benefits in 2018 that
were over five times their anticipated benefits calculated by E3. Avista’s resource mix and transmission connection to
other EIM participants most closely matches IPC and PGE. Therefore Avista may achieve similar elevated EIM benefits
during times of high market price volatility.
10.1 Analysis Based on the Charter Estimates
Avista performed an initial economic analysis to determine the system annual benefits required to breakeven over a
ten-year operating period based on initial estimated EIM implementation and on-going costs based on two scenarios.
The first scenario assumed integration costs of $21.4 million and on-going costs of $3.5 million (original expected system
project costs) and the second scenario assumed integration costs of $26.7 million and on-going costs of $4.0 million
(expected system with contingency).
In order to break even in 10 years, assuming integration costs of $21.4 million, Avista would need to achieve system
annual benefits of approximately $5.0 million. Assuming integration costs of $26.7 million, Avista would need to achieve
annual system benefits of approximately $6.0 million. As previously discussed, based on the E3 benefit analysis, Avista
estimated conservative annual EIM benefits of $5.8 million (system). Therefore, Avista initially anticipated positive
revenue from EIM participation in less than 10 years and could achieve breakeven much sooner if observed market
benefits are closer to what IPC and PGE have experienced in 2018 and 2019.
10.2 Analysis Based on Scope Estimates
Avista performed an additional economic analysis based on the updated costs estimates. Based on the new integration
cost of $32.1 million and on-going costs of $3.9 million, an annual revenue of $7.8 million is needed to break even after
10 years of market operations. This is still well within the range of estimated benefits determined by E3 and quite a bit
less than CAISO reported benefits for IPC and PGE in 2018 and 2019. If Avista’s actual EIM system benefits are closer to
or exceed the potential upper bound of $12 million, as determined by E3 and experienced by other similar situated EIM
participating utilities, then Avista customers will see positive revenue in a much shorter time period. The economic
analysis did not consider other EIM benefits such as reduced flexible ramping requirements, reliability and system
visibility enhancements, and reductions in greenhouse gases.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 43 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 44 of 47
11 Roles and Responsibilities
11.1 Program Organization Chart
The below program organization chart represents information known at the time of document submission. The
organization chart will be a living document with updates and additions throughout the duration of the program. The
organization chart(s) are posted on the EIM SharePoint site.
12 Program Governance and Reporting
12.1 Reporting
The purpose of these procedures and documents is to provide effective mechanisms to record and control the scope of
the program, manage issues and risks and monitor progress. Program level management of decisions and documents
will be discussed at the EIM Director and Executive Steering Committees and posted to the EIM SharePoint site.
Enterprise Technology projects, and their associated processes, will be managed within Clarity. Generation, transmission
operations and substation projects will be managed through their established project management processes and
procedures, and final documentation posted to the EIM SharePoint site. Each project artifact will reference the EIM
program with narrative related to EIM scope, CAISO track, requirements, and the financial structure with the EIM Parent
Project ID of EIM422 and the associated Expenditure Request (ER) and Budget Item (BI). The request to open EIM
projects will be reviewed by the EIM Program Manager and approved by the Business Case Sponsor.
12.2 Financial Control
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Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 44 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 45 of 47
Financial controls at the program level will managed with monthly financial reporting through Oracle reports, with
assistance from the Financial Planning and Analysis team and project managers from the impacted business units. The
Program finances and forecasted spend will be reviewed monthly with the Director and Executive Steering Committees.
The Capital Planning Group (CPG) will also be kept informed of the Program Finances through existing CPG processes.
12.3 Change Control / Approval Authority
12.3.1.1 Advisory Committee
The Advisory Committees consist of the subject matter experts in the various business units who can direct the
technical work, make engineering decisions and deliver the technical solution that meets the business need. The
Advisory Committee is supplemented with input and knowledge from Stakeholders amongst neighboring
business units. As needed, members of the Director Program Steering Committee will participate in the Advisory
Committee meetings for input and decisions. The EIM Program manager will be invited to all Advisory Committee
meetings and serve as a consistent conduit from the Advisory Committees to the EIM Program Steering
Committee. Communication of project schedule risks, scope issues and financial impacts will be provided by the
various project managers at the Advisory Committee and, where appropriate, reported to the EIM Director or
Executive Steering Committee. The Advisory Committee does not have the authority to independently approve
change requests, but must seek approval from the EIM Director Steering Committee.
12.3.1.2 EIM Director and Executive Steering Committee
Program level authority resides with the EIM Director and Executive Steering Committees. Ultimate approval
authority resides with the Executive Steering Committee. The Executive Steering Committee is responsible for
taking recommendations from the Director Steering Committee and ultimately making Program level decisions
for use of contingency funding. In the unforeseen event that the EIM Program schedule is at risk, the Executive
Steering Committee has the right to review and adjust the EIM go-live date. Members of the Executive Steering
Committee and the Program Sponsors would then be responsible for re-negotiation of the EIM Implementation
Agreement with the CAISO.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 45 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 46 of 47
13 Director Approvals
________________________________________________
Scott Kinney, Director of Power Supply
_______________________________________________
Andy Vickers, Director of Generation Production and Substation Support
______________________________________________
Mike Magruder, Director of System Operations and Planning
______________________________________________
Jim Corder, Director of Information Technology and Security
______________________________________________
Hossein Nikdel, Director of Applications and System Planning
______________________________________________
Adam Munson, Director of Accounting
______________________________________________
Pat Ehrbar, Director of Regulatory Affairs
______________________________________________
Todd Colton, Senior Legal Counsel
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 46 of 48
Program Scope Summary
Program Scope Summary Avista Confidential Page 47 of 47
14 Executive Approvals
______________________________________________
Heather Rosentrater, Sr. VP of Energy Delivery
______________________________________________
Jason Thackston, Sr. VP of Energy Resources
_____________________________________________
Kevin Christie, Sr. VP of External Affairs
_____________________________________________
Jim Kensok, VP Chief Information & Security Officer
_____________________________________________
Ryan Krasselt, VP and Controller
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 7, Page 47 of 48
documents; nor shall such action be deemed as recognition of any claimed contractual
right or obligation affecting or relating to such service or rate; and such acceptance is
without prejudice to any findings or orders which have been or may hereafter be made by
the Commission in any proceeding now pending or hereafter instituted by or against
CAISO.
This action is taken pursuant to the authority delegated to the Director, Division of
Electric Power Regulation - West, under 18 C.F.R. § 375.307. This order constitutes
final agency action. Requests for rehearing by the Commission may be filed within 30
days of the date of issuance of this order, pursuant to 18 C.F.R § 385.713.
Issued by: Steven T. Wellner, Director, Division of Electric Power Regulation - West
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Entire Document is CONFIDENTIAL
Cost Estimate Associated with the Human Resource Plan
Pages 1 through 2
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Program Name: Energy Imbalance Market
Program Manager: Kelly Dengel
Business Case Name: Energy Imbalance Market
Expenditure Request (ER): 7141 – Energy Imbalance Market
Submit Date: 06.17.2020
Key Roles & Program Information
Program Sponsor(s): Scott Kinney/
Mike Magruder
Business Case
Owner(s): Kelly Dengel
Business Program
Manager: Kelly Dengel Executive Steering
Committee Members:
Jason Thackston, Heather
Rosentrater, Jim Kensok,
Ryan Krasselt, Kevin
Christie
Director Steering
Committee Members:
Scott Kinney, Andy
Vickers, Mike Magruder,
Jim Corder, Hossein
Nikdel, Adam Munson, Pat
Ehrbar, Todd Colton
Other Stakeholders:
James Dykes, Robert Follini,
Annette Brandon, Jacob
Reidt, Kit Parker, Bob
Weisbeck, Tom Dempsey,
Alexis Alexander, Kristina
Newhouse, Glen Farmer,
Jeff Schlect, Brad Calbick,
Craig Figart, Rip Divis,
Kenny Dillon, Mike Andrea,
Glenn Madden, Randy
Spacek, Lamont Miles, Xin
Shane, Brian Hoerner,
Jason Pegg
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Contents
1 KEY ROLES & PROGRAM INFORMATION ................................................................................................................................... 1
2 CONTENTS ................................................................................................................................................................................. 2
3 EXECUTIVE SUMMARY .............................................................................................................................................................. 3
4 BACKGROUND ........................................................................................................................................................................... 3
5 IMPLEMENTATION RESOURCES ................................................................................................................................................. 4
5.1 INCREMENTAL FTE SUMMARY ......................................................................................................................................................... 4
6 POST IMPLEMENTATION RESOURCES – ORIGINAL ESTIMATES .................................................................................................. 6
6.1 ESTIMATED INCREMENTAL FTE SUMMARY ......................................................................................................................................... 6
6.2 DISCOVERY & ANALYSIS .................................................................................................................................................................. 6
7 POST IMPLEMENTATION RESOURCES – UPDATED ESTIMATES ................................................................................................ 10
7.1 PROPOSED INCREMENTAL FTE SUMMARY (17 FTES) ......................................................................................................................... 10
7.2 DEPARTMENT: POWER SUPPLY OPERATIONS (1 FTE) ......................................................................................................................... 10
7.3 DEPARTMENT: TRANSMISSION SYSTEM OPERATIONS (9 FTE) .............................................................................................................. 11
7.4 DEPARTMENT: FINANCE (5 FTE) .................................................................................................................................................... 16
7.5 DEPARTMENT: ENTERPRISE TECHNOLOGY (2 FTE) ............................................................................................................................. 19
8 IDAHO PUBLIC UTILITIES COMMISSION – EIM INCREMENTAL EXPENSE DEFERRAL .................................................................. 21
8.1 EIM DEFERRAL REQUEST & APPROVAL ........................................................................................................................................... 21
8.2 AVISTA’S EIM INCREMENTAL FTE GUIDANCE ................................................................................................................................... 21
9 IMPLEMENTATION & POST-IMPLEMENTATION RESOURCES – ESTIMATED FINANCIALS .......................................................... 21
9.1 INCREMENTAL FTE SUMMARY ....................................................................................................................................................... 21
9.2 FTE CAPITAL & OPERATING EXPENSE ESTIMATES .............................................................................................................................. 23
10 RECOMMENDATION & APPROVALS ........................................................................................................................................ 24
10.1 DIRECTOR STEERING COMMITTEE REVIEW ........................................................................................................................................ 24
10.2 EXECUTIVE STEERING COMMITTEE REVIEW ....................................................................................................................................... 24
10.3 DIRECTOR APPROVALS .................................................................................................................................................................. 24
10.4 EXECUTIVE APPROVALS ................................................................................................................................................................. 25
11 APPENDIX ............................................................................................................................................................................... 26
12 APPENDIX A – SETTLEMENT, BILL & ANALYTICS ROLES ............................................................................................................ 27
13 APPENDIX B – RT OPERATOR FUNCTIONAL ROLE EVALUATION ............................................................................................... 37
14 APPENDIX C – FTE CAPITAL & OPERATING EXPENSE ESTIMATES ............................................................................................. 52
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Executive Summary
In preparation for Avista to enter the Western Energy Imbalance Market (EIM), it’s imperative to discuss the needed
roles and teams required for a successful market entry and on-going operations. This document reflects the resources
identified for the program implementation and the post-implementation phases, with a proposal for 17 incremental full-
time employees (FTE). It includes justification for each position, an explanation of job functions as they relate to EIM and
associated risks if the position isn’t approved for hire. After reviewing the program implementation schedule, and
accommodating a timeline for resources to participate in the software implementation phases, a preferred hire date was
developed. This preferred hire date, along with an estimation of time allocated to EIM capital activities and expense
activities, provided input for a 2020-2023 annual financial estimate, with 2023 representing a full-year of operations and
maintenance (O&M) expense activities. In 2018, Avista originally estimated annual O&M expense at $3.5 - $4.0 million,
with $2.5 million attributed to the original labor estimate of 11-13 incremental EIM FTEs. The revised estimate of 17 EIM
FTEs increases the annual labor estimate to $3.2 million (system loaded). The need for the additional 4 FTEs (17 vs. 13),
was determined through staffing conversations with other EIM entities, who indicated lean staffing levels at the time of
market entry have hindered operational performance. Avista believes the 17 FTEs represents a mature workforce
needed to fully support EIM operations at market entry. Any additional EIM roles Avista may need will be assessed after
Avista has gained experience operating in the market.
This document represents Avista’s desired human resource plan based on all information currently available. Elements
of the plan will be progressively reviewed, and approved or denied, as new and additional information is presented and
business conditions are assessed throughout the 2020-2021 time frame. Although this document calls for a formal
approval with associated financials by the Director and Executive Steering Committees, it will not substitute for the
individual review and approval of each position prior to job posting. At the timing of this document’s approval, future
positions will be reviewed and approved at the Director and Executive Steering Committee meetings to ensure the
position, timing of the hire and associated financials are acceptable. Where possible, Avista leadership will review new
EIM roles and responsibilities in light of existing employees that can assume additional duties, without backfilling the
original position. In order for Avista to have trained personnel that are ready to engage in the mandated EIM testing
phases six months prior to market entry, all EIM FTEs must be onboarded by September 2021.
Background
In 2018, Avista developed its initial Western EIM costs estimates in partnership with Utilicast, taking into consideration
what resources would be needed to prepare for market entry, and including those needed to operate effectively and
efficiently in the market. This included an estimate of resources needed to establish an EIM Program during the
implementation phase and an estimate of new EIM-related employees needed post-implementation, with associated
costs. This also included estimates for when the new positions should be hired within the implementation phase to
support software projects, learn the market design and prepare Avista for EIM operations as the Company transitioned
to market go-live in April 2022.
Throughout most of the evaluation, it was assumed existing Avista resources would be adequate to perform various
meter and control upgrades, software implementations and learn market requirements during the implementation
phase. However, some additional roles were identified for program implementation, including an EIM Program
Manager, Organization Change Management Specialist and a temporary Substation Engineer. These temporary roles
were planned for the implementation phase, without an expectation of transitioning to an EIM-related (FTE) role post
market entry.
As Avista considered new EIM-related employees after committing to join the market in April 2019, the Company sought
input from other EIM participating utilities, including Portland General Electric, Idaho Power Company, Arizona Public
Service and PacifiCorp. Avista met with these utilities to discuss the roles and responsibilities needed to successfully
operate in the market post go-live. These utilities indicated that a separate EIM specific operating desk was required to
interact with the CAISO and ensure reliable market operations. The utilities also shared that they hired new employees
to support settlement activities, data collection and review, network model maintenance, system operations support,
resource bidding strategies, and new application technology support. After collecting this information, Avista consulted
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with Utilicast regarding the new job responsibilities and functions to get input based on their knowledge and experience
with CAISO EIM requirements and integrating other EIM participating utilities.
Avista didn’t anticipate eliminating any current positions based on new EIM requirements, and remains open to
repurposing employees, if existing work processes can be supported and maintained. The estimated resource plan was
developed based on expected new market operational work requirements. It may be possible to spread some new
expected work across existing employees, but only if it supplements current job responsibilities and doesn’t introduce
additional burden beyond employee capacity.
Implementation Resources
5.1 Incremental FTE Summary
These temporary roles were planned for the EIM Program implementation phase to establish the program and address
gaps that existed based on existing resources and Avista priorities outside the EIM Program. It was assumed the
substation engineer and change management specialist roles would terminate near the market entry timeframe, while
the program manager role would transition to an operations stabilization role through the end of 2022.
Chart 1 – Implementation Temporary FTE Summary
Role* Department Position Quantity EIM Process
1 Power Supply EIM Program Manager 1 Overall program/project management
2 Power Supply Organizational Change
Management Specialist
1 Lead Avista through operational
changes due to EIM entry
3 Substation Engineering Substation Engineer 1 Metering upgrades for interchange
locations, third-party generation sites
Original Estimated Totals 3
*See Appendix C for Role designation.
5.1.1 Role: EIM Program Manager (1 FTE)
This was the first role hired for Avista’s EIM Program with the intent to lead the development and implementation of the
program from inception to completion – managing the scope, schedule and cost. This role was planned to work closely
with business partners in Power Supply, System Operations, Generation and Substation Support, Substation Engineering
and Enterprise Technology to develop the strategy, business case objectives and project plans to support a successful
implementation. The EIM Program manager was responsible for establishing a program/project structure, establishing a
project document governance plan and creating a communication plan to stakeholders. Ultimately, this role is
responsible for delivering the EIM project implementation on time.
5.1.1.1 Key Attributes
•Required Timing: Q1 2019
•Reporting Structure: Director of Power Supply
•Other Considerations: Must possess the ability to learn organized market design and Avista’s resource operating
characteristics.
•Essential Functions:
o Responsible for overall coordination, status reporting and stability of the EIM integration project
including; scope, scheduling, resource requirements, staffing, budgeting and customer satisfaction
o Communicates with all areas of the company that impact scope, budget, risk and resources of the
assigned project(s). Manages communication activities to ensure consistency with company guidelines,
policies and procedures.
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o Manages and facilitates understanding of budget issues within business units. Ensures that internal
controls are adequate and documented. Directs the analysis and reporting of performance indicators
that best support management decision making.
o Tracks key milestones and adjusts project plans and/or resources to meet the needs of the involved
business units. Provides timely and accurate information and status updates to project sponsors, end
users and management.
o Responsible for program level documentation creation and approval, and provides guidance on all
project-level documentation and approval levels.
o Responsible for management and interaction with the implementation consultant, Utilicast.
5.1.2 Role: Organization Change Management Specialist (1 FTE)
Joining an organized market brings significant change to an organization and the Organizational Change Management
(OCM) Specialist is a key role in helping the EIM Program meet business and schedule objectives. Avista’s OCM Specialist
will have an emphasis on the people side of change – including changes to business processes, systems and technology,
job roles and organizational structure across all impacted business units. A primary focus of the OCM Specialist will be to
create and implement change management plans that minimize employee resistance and maximize employee
engagement. The OCM Specialist will work to drive faster adoption, greater utilization of EIM systems and higher
proficiency on the changes impacting employees in the organization such that business results are achieved.
5.1.2.1 Key Attributes
•Required Timing: Q3 2020
•Reporting Structure: EIM Program Manager
•Other Considerations: Prior OCM experience on a large-scale program is desired.
•Essential Functions:
o Responsible for creating and implementing complete Change Management Plans for change initiatives,
incorporating communication and training plans that minimize employee resistance and maximize
employee engagement.
o Work with project stakeholders to identify potential risks and anticipated points of resistance and
develop specific plans to mitigate.
o Develop and implement a set of actionable and targeted change management plans which include:
communication, sponsor roadmap, coaching plan, training plan and resistance management plan.
o Be an active and visible coach to executive leaders who are change sponsors, members of the project
team and end-users to encourage adoption of new operations/processes.
o Work with project manager to integrate change and management activities into the overall project plan.
o Coordinate with training development personnel in the formulation and delivery of training plans and
activities in support of project implementation.
5.1.3 Substation Engineer (1 FTE)
In order to perform metering upgrades at various Avista substation interchange locations and third-party generation
sites, Avista needed a Senior Electrical Engineering to design metering solutions to meet EIM requirements. This role will
be responsible for creating new designs or making modifications to existing electrical distribution and transmission
substations interchanges designs, including the physical, electrical and control designs. They will also assists in the
development, evaluation and selection of station layout options, and be responsible for the all drawings and
specifications used for construction, including drawings that must be submitted to CAISO for Settlement Quality Meter
Data plans. In April 2020, this role was converted from a temporary position to full time employee. It’s anticipated that
EIM metering upgrades will be the primary focus for the position through the end of 2020, with 2021 representing an
estimated time allocation of 30% on EIM projects and 70% other substation engineering projects.
5.1.3.1 Key Attributes
•Required Timing: Q1 2020
•Reporting Structure: Substation Engineering Manager
•Other Considerations:
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o Approximately 8 years of experience in Substation Engineering, using engineering principles to produce
drawings for substation engineering construction. Professional Engineer’s License is preferred.
o Able to demonstrate proficiency in all analytical tools specific to Substation Engineering.
o Must have a positive level of recognition within the engineering community regarding their work ethic,
expertise and interpersonal skills, and recognition of their expertise by outside groups is an added
attribute.
o Experience working in teams and the ability to collaborate with a wide group of stakeholders is
essential.
Post Implementation Resources – Original Estimates
6.1 Estimated Incremental FTE Summary
These EIM-related FTE resources were part of the original program estimates in 2018. Of the original $3.5-$4M annual
estimated O&M impact, $2.5M was estimated (assumed 60% loading rate) for 11-13 incremental FTEs.
Table 2 – Original Avista FTE Estimates
Department Position Quantity EIM Process
Power Supply Analyst 1 Market bids analysis, settlement analysis
System Operations Network Model Tech 1 Support network model operations
System Operations SCADA Tech 1 Support SCADA operations
System Operations EIM BA Desk 5 EIM BA operations
TBD Settlement Analyst 1 EIM settlements
TBD Data Management Operator 1 EIM meter data submittal to CAISO
TBD Compliance 0 or 1 FERC EQR or greenhouse gas reporting
Enterprise Technology IT Analyst 1 or 2 EIM Applications support
Original Estimated Totals 11 to 13
6.2 Discovery & Analysis
In order to determine an appropriate and successful EIM operational course, Utilicast led Avista through conversations
regarding the structure and components of the EIM Settlements team and the EIM Balancing Authority (BA) Desk. These
discussions were supplemented by conversations with other EIM utilities on topics including: team responsibilities,
management expectations, and integration of EIM functions with existing teams and business processes. The current
EIM utilities shared that they have modified their structure, focus and number of employees to support settlement
activities after gaining operating experience in the market. The result of these conversations led to the creation of two
Key Decision Documents to outline the roles, responsibilities and the advantages/disadvantages of how to approach a
particular model. A summarized highlight of these Key Decision Documents are listed below, with the full documents
provided in the appendix.
6.2.1 EIM Settlements Team Evaluation & Recommendation
The management and understanding of EIM settlements is a key component of identifying and analyzing business and
technical decisions for conformance to market design principles and market operations to ensure maximum
performance in the market. Avista recommends pursuing a hybrid structure with both centralized and distributed
components – a centralized Settlements Team that handles shadow settlements for both the Merchant and the
Balancing Authority, also known as the EIM Entity (Entity), with a separate analyst role embedded in the Merchant and
Entity that coordinate with the Settlements Team and conducts deeper market analysis. This centralized Settlements
Team supports Merchant and Entity settlements, promotes expansion of settlement specific skill sets and ensures the
timely analysis and appropriate priority is given to settlements. This centralized team will have visibility to the financial
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results for both the Merchant and Entity, so cost benefit studies and overall market performance can be more easily
evaluated and assembled.
The primary functions of the Settlements Team include: daily generation and interchange meter validation and
processing, daily settlement processing, sub allocation of transmission customer charges, market analytics, financial
reporting, and cost benefit analysis. The distributed analyst roles in the Merchant and Entity, along with the Settlements
Team, will analyze both individual business unit performance and Avista’s overall market performance. This hybrid
structure will facilitate deep analytical capabilities through direct links with the Merchant and Entity analysts, while also
supporting the myriad of daily shadow settlement processing tasks.
To best support EIM functions, Avista recommends a Settlements Team of five total individuals – four analysts with
shared responsibilities and a Settlement Manager. The Settlement Manager will also perform analytic activities. This
team will report to the Director of Accounting.
Table 3 - Summary of Settlement Staffing Requirements
Role / Allocation Reports to: Resides within:
Settlements Team
Settlement Manager / 1 FTE Director of Accounting Accounting
Meter Processing
Meter Analyst / 1 FTE Settlement Manager Accounting
Shadow Settlement
Settlement Analyst / 1 FTE Settlement Manager Accounting
Settlement Analyst / 1 FTE Settlement Manager Accounting
Settlement Analyst / 1 FTE Settlement Manager Accounting
Market Analytics
Market Analyst / 1 FTE Manager Preschedule & Real Time Power Supply/Merchant
Market Analyst / 1 FTE Director of System Ops & Planning BA Entity
Within the settlement functions, it is possible some of the duties may be performed by existing employees without the
need to backfill roles. Avista leadership will conduct further evaluation to assess the resource need as the EIM Program
progresses and business processes are refined.
For details on the settlement structure see Appendix A - “EIM Key Decision – Settlement, Bill & Analytics Roles”
Chart 1 – EIM Settlements Team Structure
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6.2.2 EIM Real Time Operator Roles Evaluation & Recommendation
Transmission System Operations currently has two 24x7 desks – the Reliability Desk and the Transmission System
Operator Desk. The below chart explains how System Operations is currently organized pre-EIM entry.
Chart 2 – Transmission System Operations Pre EIM
The organizational structure required to perform all existing functions and accommodate new EIM functions can take
several forms. A common approach to EIM functions includes adjusting existing desk processes/responsibilities and
adding an EIM Desk to focus solely on pre-operating hour EIM operations. Through discussions with Utilicast, Avista
identified which tasks would reside with the Merchant and which tasks would reside with the Entity. The results
included: shared generation management tasks between the Merchant and Reliability Operators, new EIM tasks for the
Reliability & Transmission Desks, and a full set of tasks for the new EIM Desk.
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In order to provide continuity amongst all the operators and an environment for cross-functional desk qualifications,
Avista recommends NERC certification for the EIM Desk operators. This would entail all of the System Operators
obtaining NERC certification and qualifying on their respective desks with the Reliability Operators and EIM Operators
being qualified on both desks. This will allow greater flexibility for covering shifts during emergency conditions, training,
vacations and unexpected absences. NERC certification will require the EIM Operators to be hired at least 12-16 months
in advance to allow time to become NERC certified and learn the job function. Future plans include training the
operators to be qualified to work all three desks in System Operations.
Following input from Utilicast and other EIM entities, Avista recommends adding a third 24x7 desk focusing on EIM
operations with five operators, and one relief operator to manage EIM real-time operations and a training administrator
to help with additional operator training requirements.
Chart 3 – Transmission System Operations Post EIM
For details on the EIM BA operator role see the Appendix B - “EIM Key Decision – RT Operator Functional Role
Evaluation”
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Post Implementation Resources – Updated Estimates
7.1 Proposed Incremental FTE Summary (17 FTEs)
After evaluation and review amongst stakeholders, directors and executives, Avista recommends the following
incremental full-time employees to support Avista EIM operations. Through conversations with Utilicast and other EIM
entities, it’s common for utilities to re-evaluate their EIM structure and resource allocation post-EIM entry and make
changes in terms of reporting structure or number of employees supporting EIM operations. Avista will evaluate the
operating structure and implement adjustments as necessary to ensure successful EIM operations.
Table 4 – Incremental FTE Summary
Role* Department Position Original Proposed EIM Process
4 Power Supply Analyst 1 1 Market bids & settlement analysis
5 System Operations Analyst 0 1 BA EIM operations analysis
6 System Operations EMS Modeling Engineer 1 1 Support network model operations
System Operations SCADA Tech 1 0 Support SCADA operations
7 System Operations EIM BA Desk Operator 5 6 EIM BA operations
8 System Operations Training Administrator 0 1 Support NERC Training Coordinator
9 Accounting Settlement Manager 0 1 EIM settlements & analysis
10 Accounting Settlement Analyst 1 3 EIM settlements & analysis
11 Accounting Meter Analyst 1 1 EIM meter data submittal to CAISO
TBD Compliance 0 or 1 0 FERC EQR/Green House Gas Reporting
12 Enterprise Tech Technical System Analyst 1 or 2 1 EIM applications operations support
13 Enterprise Tech Ops Technical Lead 0 1 EIM applications operations support
Totals 11 to 13 17
*See Appendix C for Role designation.
7.2 Department: Power Supply Operations (1 FTE)
7.2.1 Role: Power Supply Analyst (1 FTE)
The EIM is a complex market design requiring comprehensive, precise and timely analysis of processes along with
operational and settlement data to ensure business decisions are achieving the desired results. In the EIM the merchant
is the Participating Resource Scheduling Coordinator (PRSC). Avista’s PRSC manages all of the base schedule and bid
curve submittals for all of the participating generation resources. These resources are dispatched by the Market
Operator (CAISO) based off of submitted bid curves and the market solution’s Locational Marginal Prices (LMP’s). The
market solutions have reliability and economic affects that are substantial. It is incumbent upon every EIM PRSC to have
a detailed knowledge of the market design and evaluate their business decisions, operational performance, settlement
and analytical implications and results made from bidding in participating resources. The analyst will need to inform and
create ongoing bid strategy and assist in the development of the EIM benefits summary.
The EIM Power Supply Analyst position will report to the Manager of Preschedule and Real Time and work closely with
the Preschedule, Real Time, Generation Production Substation and Support, Enterprise Technology and the Settlements
Team. This position will require a deep knowledge of organized market designs, knowledge of the western Bulk Electric
System, generation resource characteristics and operations, and a thorough knowledge and use of data and visual
analytical tools. This position will require excellent communication and collaboration skills to reach across business units
to push and pull information and data informing and recommending business strategies for optimal market
participation.
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The position is also expected to monitor market stakeholder initiatives and track implementation of future EIM
enhancements such as EIM Day Ahead Market (EDAM) and enhancements to the existing Day Ahead Market.
7.2.1.1 Risk Considerations
As noted above, it is of the utmost importance that business decisions and market interaction strategies conform to
Avista’s specific resource characteristics, technology integrations and human performance. It is incumbent on Avista to
carefully analyze the business decisions and market interactions to ensure maximum market benefits. If this position is
not filled, Avista will be exposed to market settlements that could be detrimental to Avista’s monetary benefit in the
EIM, with little to no feedback loop on performance to the merchant group. This type of analytical neglect could lead to
long periods of time with unsatisfactory market strategy submissions before errors or faulty business logic are rectified.
7.2.1.2 Key Attributes
•Required Timing: Q3 2021
•Reporting Structure: Manager of Preschedule & Real Time
•Other Considerations: In depth knowledge of data analytics and the ability to learn organized market design and
resource operating characteristics. This position should be posted internal and external.
•Essential Functions:
o Evaluate bid strategy performance
o Evaluate bid cost recovery performance
o Evaluate the cost of Variable Energy Resource (VER) integration
o Evaluate generation availability and performance
o Evaluate EIM vs. bilateral market profitability
o Help determine EIM benefits calculations logic and counter-factual calculations
o Manage Generation Resource Data Template (GRDT) inputs and Masterfile information
o Evaluate market design impacts to the business
o Work with the Settlements Team to ensure accurate settlement data and overall market performance
7.3 Department: Transmission System Operations (9 FTE)
7.3.1 Role: EIM BA Analyst (1 FTE)
The EIM is a complex market design requiring comprehensive, precise and timely analysis of processes along with
operational and settlement data to ensure business decisions are achieving the expected results. In the EIM, the BA is
the EIM Entity Scheduling Coordinator (EESC). As a complement to the Power Supply Analyst and EIM Settlements Team
who will commit to robust economic analysis, the Entity BA also needs to commit to understanding the BA’s financial
impact on market performance and the settlement impacts to its third party transmission service customers. In the EIM,
the System Operator’s actions can have a significant impact on Avista’s overall performance and financial benefit in the
market. These Operators are responsible for the final resource balancing process each hour, self-scheduling non-
participating resources, entering manual dispatches, ensuring the BA is meeting its performance standards, and ensuring
both physical and scheduling constraints are maintained by the market dispatch. The operators will also review the
dispatch instructions and start-up instructions received from CAISO and ensure the plants perform to those instructions.
It is important for the System Operators, whose primary objective is to maintain the reliability of the Avista transmission
system, to also understand the financial consequences of market transactions where reliability may not be a primary
driver.
The BA Analyst will review Avista’s market performance and evaluate impacts to system reliability and transmission
service. This analysis will help drive overall System Operator process improvements and decision making consistency
across the various System Operator functions. In addition, the BA Analyst will review the load, interchange transactions
and third-party resource settlements which will be part of the overall EIM benefits and impacts summaries. The position
is also expected to monitor market stakeholder initiatives and track implementation of future EIM enhancements such
as EIM Day Ahead Market (EDAM) and enhancements to the existing Day Ahead Market.
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The EIM BA Analyst position will report to the Director of Planning and System Operations, and work closely with the
Chief System Operator, System Operators, the Enterprise Technology department, the Settlements Team. This position
will require a deep knowledge of organized market designs, knowledge of the western Bulk Electric System, transmission
service administration, scheduling, transmission constraints and a thorough knowledge and use of data and visual
analytical tools. This position will require excellent communication and collaboration skills to reach across business units
to push and pull data and make process improvement recommendations to System Operations for optimal market
participation.
7.3.1.1 Risk Considerations
If this position isn’t filled, market feedback to the EIM Operator about the effectiveness of their decisions will be delayed
and it will be difficult to research and identify the financial impacts of operator decisions. There will also be reduced
financial analysis of the third-party settlements, load and interchange transactions which are a part of the EIM Entity
Scheduling Coordinator settlement (EESC) process. Without this role, the Chief System Operator and other support
personnel, will need to identify operation process improvement recommendations and training needs in addition to
their existing operational job tasks. The Avista EIM BA Operator needs to be proficient and consistent in their actions,
while understanding the financial impact of their action. The existing Operator roles are also affected by this new
paradigm of operation under EIM. Timely feedback for improvements will be important. This role serves this need, and
provides market insight and influence for developing System Operations’ training and data materials.
7.3.1.2 Key Attributes
•Required Timing: Q3 2021
•Reporting Structure: Director of Transmission System Operations & Planning
•Other Considerations: In depth knowledge of data analytics and the ability to learn organized market design and
Avista’s resource operating characteristics. This position should be posted internal and external.
•Essential Functions:
o Evaluate sufficiency test performance
o Analyze manual dispatch and load bias impacts to price volatility and infeasibilities
o Evaluate resource performance to Dispatch Operating Targets (DOTS)
o Evaluate market impacts to Critical Performance Standards (CPS) and NERC Balancing Authority Ace
Limit (BAAL) standards for compliance
o Analyze impacts of third-party changes to generation or interchange schedules
o Analyze EIM Transfer System Resource (ETSR) and intertie constraint strategies
o Help determine EIM benefits calculations and counter-factual calculations logic
o Update intertie resource configurations in the EIM Entity Scheduling Coordinator (EESC) application
o Manage Intertie Resource Data Template definitions (IRDT) and Masterfile information
o Evaluate market design impacts to system operations
o Work with the Settlements Team to ensure accurate settlement data and overall market performance
7.3.2 Role: EMS Modeling Engineer – SCADA (1 FTE)
This position will work under the technical guidance of the SCADA/EMS Manager and will be responsible for supporting
ongoing maintenance of the Avista’s electrical transmission network model. The network model is an integral part of the
reliability monitoring of Avista’s electrical transmission system, and is crucial to Avista’s participation in the Western
EIM. The responsibilities of this position include the maintenance of an Energy Management System (EMS) Network,
SCADA and Alarm models, the real-time ICCP measurements, and the EMS displays used to provide an accurate
representation of the state of the Avista’s portion of the Bulk Electric System (BES). This position will be responsible for
exchanging accurate network model with neighboring utilities, the Reliability Coordinator (RC West), and the Western
EIM. This position will be assisting with all technical details of the network modeling effort in formats and exports for
planning, EMS, and network applications purposes. This position includes a close working relationship with other
SCADA/EMS engineers, Avista engineering and operations personnel, vendors, and neighboring utilities. Since this
position supports the network model for both RC West requirements and the EIM, it is anticipated that fifty percent of
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 12 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 13 of 52
this positions time will be allocated to each function. The allocation of work time will be adjusted after market
experience is gained.
7.3.2.1 Risk Considerations
Management of a real-time network model of Avista’s electrical system is an entirely new body of work for Avista. Prior
to EIM entry, it was sufficient to let the Reliability Coordinator (Peak Reliability) manage the real-time model of Avista’s
electrical network. When errors or inconsistencies were present, System Operations engineers resolved them in real
time and there was little reliability or financial risk.
With the change of Reliability Coordinator responsibilities shifting to the RC West, pending EIM entry and recent
changes to NERC reliability standards, it is crucial that Avista take responsibility for managing its own network
model. Avista has learned from other EIM participants that incorrect modeling of the electrical network will result in the
EIM market algorithm non-optimally dispatching resources, and even dispatching units out of the market. CAISO
considers the accuracy of the model to be Avista’s responsibility. Any EIM dispatch risk due to modeling errors will be
Avista’s obligation to manage.
Management and maintenance of the real-time network model is required, regardless of whether this position is
approved. Should this position not be filled, Avista will need to contract external resources for ongoing management of
the model.
7.3.2.2 Key Attributes
•Required Timing: Q2 2020.
•Reporting Structure: Manager of SCADA/EMS
•Essential Functions
o Implement, enhance and resolve issues of modeling the Western Interconnection, including, but not
limited to, updating the Avista EMS Network, SCADA, Alarm, and ICCP models.
o Implement, enhance, and resolve issues associated with EMS overview and substation displays which
are used by the Avista System Operators to maintain real-time situational awareness.
o Work closely with Balancing Authority, Transmission Operations, and Energy Imbalance Market teams,
vendors, and support personnel to resolve issues.
o Work closely with Transmission Operations Engineers and the SCADA/EMS engineering team to provide
support pertaining to the maintenance and enhancement of the EMS models to better meet the needs
and functionality of Avista’s reliability functions.
o Recommend creative and innovative information systems solutions to various business or technical
problems. Ensure work is technically sound and in compliance with established standards, codes, and
regulations.
o Be involved in the modification, integration and migration of EMS systems to new software versions.
o Plan and coordinate database and display changes to reflect the true and ever-changing configuration of
the transmission system to correct problems and to meet user needs, requests, and schedules.
o Exchanging accurate network model information with neighboring utilities, the Reliability Coordinator
(RC West), and the CAISO Western EIM.
7.3.3 Role: EIM BA Operator (6 FTE: 5 EIM Operators and 1 Relief Operator)
The EIM BA Desk operators will staff a new 24x7 hour operating desk in Transmission System Operations. The five new
EIM operators will conduct the final balancing process and data checks for market base schedule submission prior to
each operating hour. As part of the overall base schedule process, the EIM BA Operator will also be responsible for
providing generator information to the CAISO for any non-participating generation resources not managed by the
Merchant, including any third-party resources within the Balancing Authority Area (BAA). The EIM BA Operator will have
oversight of the automated processes in the EESC application that determine the intertie resource base schedules and
real-time values being submitted to CAISO to ensure they align with the BAA scheduled interchange. The EIM Operator
will also oversee ETSR and Intertie Constraint (ITC) limits, overriding limits if necessary or locking EIM transfer capacity.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 13 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 14 of 52
The EIM BA Operator will cross-train for certification as a Reliability Operator as well. The Reliability Operator is
responsible for many of the transmission service management and scheduling activities, ensuring the BA performance
criteria are met, generation adjustments for transmission reliability issues, implementing schedule curtailments when
necessary, approving and submitting outages to the Reliability Coordinator, updating outages on OASIS and initiating or
responding to NWPP reserve sharing events. Operating under EIM will also bring more real-time activities to this role
including the review of generation dispatch and start-up instructions, manual dispatch process and load bias processes.
System Operators have the primary responsibility of maintaining the reliability of the Avista transmission system. They
will also have significant real-time interaction with the Market Systems and Market Operator for things that are not
necessarily reliability related. Their actions will have economic impacts to the overall performance of Avista in the EIM.
It will be important for the System Operators to understand the EIM market design, how it impacts and can improve
reliability and also understand the financial consequences of market constraints if they are not managed properly.
7.3.3.1 Risk Considerations
If the EIM BA Operator team is not approved, these new EIM functions would be added to the Reliability Operator role
causing an unmanageable workload and priority conflict. Risk would include an inability to adequately and consistently
pass hourly market requirements, failure to perform additional intra-hour tasks and ultimately cause a degradation in
maintaining reliability. During contingency events, conflicting obligations between reliability and EIM priorities could
cause Avista to reduce market effectiveness and cause potential reliability issues. Reliability tasks could even be missed,
resulting in non-compliance and subject to punitive regulatory action. Ultimately, if the two desks were to be combined,
there is a risk to operator retention and recruiting due to unmanageable work load and tasks.
Based on the importance of the Reliability and EIM Operators and the significant overlap of functions, there is a need to
consider hiring an additional Operator to serve as a relief position for both desks.
The current Relief Operator provides coverage at a 1:10 Operator ratio, covering both the Transmission Reliability Desks.
The addition of the EIM Desk would increase the Relief Operator’s coverage to a 1:15 ratio, with support of all three
desks. This would be a 150% increase in the number of Operators to support, in addition to staying proficient on the
existing desks, while learning additional duties and skills for the EIM Desk. Existing standards require a substantial
amount of annual training, and the additional EIM desk will significantly increase those annual training requirements,
which must be completed while maintaining adequate desk coverage.
The Relief Operator is critical for maintaining coverage for sick leave, vacations, jury duty, and unplanned absences. The
risk of inadequate coverage to support desk operations in the event an Operator has to, or elects to, suddenly leave
System Operations or the Company should also be considered. In the long term, these unplanned vacancies take a toll
on System Operations, as it takes six months for a System Operator to complete NERC certification and adequately train
on systems and procedures required to work the desk independently. Without the presence of an additional Relief
Operator, these unplanned or long-term vacancies require the existing Operators to cover shifts through overtime,
working a shift during their training week or postponing planned vacations.
Requiring an Operator to work his/her training week to cover a shift presents a risk. System Operators must complete
more than 200 hours of required training to maintain NERC certification. These training weeks are critical for the
Operators to ensure their understanding of Avista’s infrastructure and supporting systems, and to ensure job
effectiveness. Avista’s System Operators are highly experienced and have significant amounts of One Leave. The Relief
Operator allows for better planning of shift schedules. Overall, it’s not reasonable to expect one Relief Operator to
provide adequate coverage for the EIM, Reliability, and Transmission Desks.
7.3.3.2 Key Attributes
•Required Timing: Progressive hires from Q1 2020 – Q1 2021
•Reporting Structure: Chief System Operator
•Other Considerations: Experience in Power Supply and electric markets, Real-Time Transmission or Distribution
Operations, Operations Engineering or Transmission System Field work with the ability to learn organized
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 14 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 15 of 52
market design. NERC Reliability Coordinator certification will be required. This position should be posted internal
and external.
•Essential Functions:
o Create and submit third-party Non-Participating Resource (NPR) base schedules prior to T-75, T-55, T-40
operating hour
o Finalize contingency and regulating reserves for EIM prior to T-40 operating hour
o Review and respond to sufficiency test failures (Capacity, Balance, Flex Ramp) for the BAA prior to T-40
o Balance and submit all final generation resource base schedules prior to T-40 (in coordination with
Merchant)
o Submit real-time (RT) Variable Energy Resource (VER) forecasts to CAISO (automated)
o Create and submit aggregated intertie base schedules for each intertie location prior to T-75, T-55, T-40
(automated)
o Determine EIM transfer limits for each intertie to another EIM participant and submit to BAAOP
continuously (automated but with override capability)
o Provide a rolling five hour forecast or ramped interchange for each intertie at a 5-minute granularity,
refreshed every 5 minutes (automated)
o Single point of contact for CAISO RT Market Operator
o Coordinate shutdown of Avista generation (shared)
o Submit After the Fact (ATF) RT interchange schedules to CAISO (Automated)
7.3.4 Role: Training Administrator (1 FTE)
In order to have competent proficient operators that are able to understand and function in the EIM, and manage
Avista’s system in the most reliable and efficient way, they must have a training program that is robust and keeps their
skills and knowledge at the highest level.
The System Operator positions require 200 Continuing Education Hours (CEH) of training every 3 years in order maintain
their NERC credentials and to be able to perform their Reliability Related Tasks (RRT). The EIM BA Operator and the BA
System Operator will both perform some of these tasks. The training for these positions is developed, delivered and
documented in house and must be specific to the system they operate. Generic operator training does not meet
compliance standards. At present, there is one trainer that fulfills this role for the current 13 NERC certified personnel in
System Operations. With the addition of the EIM BA desk, there will be up to 19 NERC certified personnel in System
Operations. Other EIM entities have a training staff to operator ratio of between 1:6 and 1:8. Avista operates with a 1:13
ratio today. With the added EIM BA desk personnel, that ratio would increase to 1:19. After this training administrator is
added to support the training coordinator, the ratio would decrease to 1:9.5.
To accommodate this increased training demand, it is necessary to add either a second trainer or a training admin role.
The training admin position will assist the Training Coordinator with the increased administrative work caused by the
increase in NERC certified System Operators, and will aid the trainer in the documentation, scheduling and logistics
processes.
7.3.4.1 Risk Considerations
In order to support the increase operator-to-training coordinator ratio, while not decreasing training performance or
compliance obligations, Avista supports hiring a Training Administrator to assist with training goals and objectives. This
allows the Training Coordinator to embrace the market complexity and build more robust EIM training, while
maintaining current reliability training compliance objectives. If this role is not approved, the Training Coordinator may
be unable to develop new training materials to ensure operator proficiency, or identify and address operator learning
deficiencies in a timely manner. This increase in operator training will require additional documentation and
maintenance, which if not addressed will likely cause audit deficiencies and a reduction in training quality.
7.3.4.2 Key Attributes
•Required Timing: Q1 2022
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 15 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 16 of 52
•Reporting Structure: Chief System Operator
•Essential Functions:
o Prepare individual documents for required training courses.
o In conjunction with Trainer develop, update and maintain training schedule for 19 certified operators.
o Maintain all compliance required documentation using QTD, SOCCED, CATSWEB and Source Training.
o Input completed training documents into electronic format.
o Assist Trainer in developing and documenting individual training plans.
o Work with Trainer to assess effectiveness of training by evaluating completed assessments and course
evaluations.
o Assist Trainer with budget and keep accounting records for training budget.
o Assist Trainer in maintaining simulator updates by tracking system changes.
o Administer operator competency assessments and compile data to help identify training deficiencies.
o Complete other administrative work as directed by Chief and Trainer.
7.4 Department: Finance (5 FTE)
7.4.1 Role: Settlement Manager (1 FTE)
In Avista’s proposed Settlement Team structure, the Settlement Manager would lead a group of four analysts by
monitoring, guiding and directly supporting meter data verification and submittal, statement and invoice processing,
shadow verification, sub allocation, and troubleshooting of daily activity corresponding to Trade Dates in the T+3B,
T+12B and T+55B CAISO settlement timeline, which may span up to 8 or more cycles and as many as 36 months of
history. Other matrixed analysts (2) embedded within the Merchant and BA organizations will collaborate closely with
and use software tools of the Settlement Team to perform deep-end financial and strategic analyses. The Settlement
Manager is also expected to participate in and contribute to weekly BA performance reviews with CAISO staff, monitor
market stakeholder initiatives and track implementation of future EIM enhancements such as EIM Day Ahead Market
(eDAM) and enhancements to the existing Day Ahead Market.
7.4.1.1 Risk Considerations
A less-than-fully-staffed settlement team would generally be deficient in its capability to identify:
•Settlement calculations errors due to mishandling of input data on CAISO’s part,
•Data submission problems related to Avista software or processes
•Operational behavior patterns resulting in suboptimal settlement and financial results
•Capture benefits through dispute resolution or educating others on the settlement consequences of operational
decisions.
The Settlement Manager will prioritize the processing and analytical activities of the group to focus on those which will
provide the most value. He or she will also provide the leadership necessary to properly anticipate market
enhancements, voice Avista’s position in proposed CAISO rule changes and manage evolution of the EIM Entity
commercial model.
7.4.1.2 Key Attributes
•Required Timing: Q3 2020
•Reporting Structure: Director of Accounting
•Other Considerations: Well qualified candidates should possess a working knowledge of Avista’s metering
portfolio and generation operational characteristics, familiarity with MV-90, PI and Nucleus and their
integrations with the Energy Accounting system, intimate understanding of the CAISO meter submittal timeline
and a basic awareness of EIM settlement calculations and market operations, as well as the ability to handle and
analyze large data sets.
•Essential Functions:
o Troubleshoot interruptions in acquisition of data from upstream system
o Acknowledge, analyze and respond appropriately to validation messages generated by the Energy
Accounting system
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 16 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 17 of 52
o Validate calculations in the Energy Accounting system to aggregate, net, profile or prorate raw metering
to achieve CAISO resource ID net high-side data submittals
o Verify timely submission to the CAISO Market Results Interface – Settlements (MRI-S) application
o Reconcile submittals against downloads from CAISO
o Support analysis of unit performance related to Uninstructed Imbalance Energy
o Manage Energy Accounting system configuration for modeling and metering changes
o Support the annual Self-Audit Attestation and biannual Audit & Testing of Metered Facilities required of
EIM Bas
o Ensure Merchant and EIM Entity analysts have adequate information to evaluate market performance
7.4.2 Role: Meter Analyst (1 FTE)
Responsibility of the EIM Meter Data Analyst starts after generation and interchange meter data that has been collected
by MV-90, PI or Nucleus and interfaced to the new EIM application called Energy Accounting. Validation, Estimation and
Editing (VEE) occurs within the system as raw data is transformed to resource identification level, with net high-side
meter values submitted to CAISO. Submittals are expected by eight business days after the trade or operating date with
provision for a true-up by 48 days following the trade date. This processing is entirely subject to the availability and
quality of data from upstream systems and requires the analyst monitor it continuously for omissions and warning flags.
The Avista meter model for EIM is not static – modifications of physical equipment and inclusion of additional resources
will require updates to software and processes. The Meter Analyst is expected to work with other groups to ensure
adaptation of these changes is well anticipated and seamlessly executed.
7.4.2.1 Risk Considerations
Without dedicating a stand-alone resource to the task of processing and analyzing metering, which is eventually
submitted to CAISO for EIM settlement calculations, the job would have to be shared among others either in the
settlements group or prior to settlements, among staff primarily focused on physical metering or the MV-90 system. As
one of only two or three principle billing determinants over which Avista will actually have control, metering collection
and verification represents an extremely important input to settlement calculations. Ensuring submitted values start
with complete and accurate raw data, are validated for known anomalies and are properly transformed through
algorithms performing aggregation, netting, proration or profiling to the CAISO resource identification level is required.
Timely data submission has a high impact on successful settlement results and will help prevent unnecessary work.
Analysts in the settlement group are tasked with interpreting CAISO calculations and results, so transitioning between
metering and settlement concerns would surely diminish the effectiveness of their efforts. Likewise, to expect that staff
previously obligated to manage installation, testing and maintenance of all metering devices or responsible for
troubleshooting data collection from all equipment in the field on a daily basis, would not provide sufficient attention to
the VEE processes and data submittal functions.
7.4.2.2 Key Attributes
•Required Timing: Q2 2021
•Reporting Structure: Settlement Manager
•Other Considerations: Well qualified candidates should possess a working knowledge of Avista’s metering
portfolio and generation operational characteristics, familiarity with MV-90, PI and Nucleus and their
integrations with the Energy Accounting system, intimate understanding of the CAISO meter submittal timeline
and a basic awareness of EIM settlement calculations as well as the ability to handle and analyze large data sets.
•Essential Functions:
o Troubleshoot interruptions in acquisition of data from upstream systems
o Acknowledge, analyze and respond appropriately to validation messages generated by the Energy
Accounting system
o Validate calculations in the Energy Accounting system to aggregate, net, profile or prorate raw metering
to achieve CAISO resource ID net high-side submittals
o Verify timely submission to CAISO MRI-S
o Reconcile submittals against downloads from CAISO
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 17 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 18 of 52
o Support analysis of unit performance related to Uninstructed Imbalance Energy
o Manage Energy Accounting system configuration for modeling / metering changes
o Support the annual Self-Audit Attestation and biannual Audit & Testing of Metered Facilities required of
EIM BAs
o Assist field personnel with meter data collection issues
7.4.3 Role: Settlement Analyst (3 FTE)
Under the direction of the Settlement Manager, Settlement Analysts will oversee the processing of daily settlement
statements to ensure accuracy of the results, agreement with shadow calculations, isolate the root cause of any
variances and communicate issues with operational groups or create CAISO disputes when necessary as well as reconcile
weekly CAISO invoices with daily settlement results.
7.4.3.1 Risk Considerations
While dispute resolution may be infrequent, the potential financial impact when extrapolated over 288 intervals per
Trade Date and 75-100 resource locations is significant. Unfortunately, there is no way for a Settlement Analyst to
predict exactly when or where the settlement may produce a favorable financial outcome. Only heightened software
business intelligence tools and diligent review of their indications will yield consistent results. It is a job that has to be
done thoroughly for each Trade Date and every subsequent settlement update from CAISO. While it certainly is possible
to simply accept CAISO results, a slim settlement team will miss the opportunity to reclaim, through dispute resolution,
routinely large financial sums due to:
•Settlement calculations errors due to mishandling of input data on CAISO’s part
•Data submission problems related to Avista software or processes
•Operational behavior patterns resulting in suboptimal settlement results
Additionally, Avista will send bills to its Transmission Customers representing the suballocation of EIM Entity settlement
with CAISO. The process is highly automated, but may require some additional communication with the recipients –
particularly with those not already participating in another EIM BA – to understand their content and meaning. Of
course every utility wants to be perceived as providing superior customer service, but this does not happen
automatically. A settlement team taxed with simply processing its own settlement artifacts from CAISO will undoubtedly
sacrifice the customer service it could perhaps otherwise provide its own Transmission Customers.
7.4.3.2 Key Attributes
•Required Timing: Q2 – Q3 2021
•Reporting Structure: Settlement Manager
•Other Considerations: Candidates should demonstrate a basic understanding of EIM economic and operational
concepts, knowledge/understanding of CAISO charge code calculations, Open Access Transmission Tariff (OATT)
provisions and the ability to work with settlement software to manage processing of settlement information in
an effective and timely manner.
•Essential Functions:
o Awareness of the status of daily trade date processing corresponding to the current calendar day and
week while maintaining synchronicity with the CAISO settlement timeline
o Ability to detect processing disruptions and “kick start” the system manually (i.e. reacquire quantities or
prices from upstream systems) when required
o Ability to compare daily CAISO settlement results with:
▪those from a previous iteration of the settlement cycle
▪those calculated within the shadow system using statement inputs
▪those calculated within the shadow system using first principle inputs
… and address variances appropriately
o Validate CAISO invoices and generate AR/AP for transmittal to the financial system upon approval by
authorized personnel in the financial system of record.
o EESC – perform daily suballocation calculations and reconcile with CAISO Entity Charge Code amounts
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 18 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 19 of 52
▪Transmission Customer’s suballocation statements are made available daily, while validated
invoices are prepared weekly for approval and publication by authorized personnel in Resource
Accounting. Accounts Receivable/Accounts Payable are generated as suballocation invoices are
validated and made ready for transmittal to the financial system upon approval by authorized
Resource Accounting personnel
o PRSC – perform analysis of key performance indicators which may illuminate suboptimal financial
positions, flawed bidding strategy for Participating Resources (PRs) or poor generation dispatch
following for PRs
o EESC – perform trending analysis of Entity settlement amounts which may reveal Transmission
Operation problems, flawed bidding strategy for PRs or poor generation dispatch following for PRs and
NPRs
7.5 Department: Enterprise Technology (2 FTE)
7.5.1 EIM Technology Summary
To successfully support the technical aspects of the EIM software application platform and meet the business
expectations outlined below, Avista recommends two additional FTEs be hired to join the EIM Program in early 2020.
Both FTEs are expected to integrate with the project team to ensure non-functional requirements and automated
platform support are delivered, and gain a deep understanding of business workflows and processes. Upon project
completion, they will become the primary application support personnel for all aspects of EIM software, MV90, ADSS
and Nucleus. They will also be part of the larger EIM support organization as dedicated operations resources.
Avista’s proposed support model for EIM is informed by learnings from Avista’s Automated Meter Infrastructure (AMI)
support model. This model assumes matrix organization accountability, with both dedicated and shared resources from
IT and business areas working as a team to provide a holistic EIM support approach. The EIM platform will bring five new
hosted applications, three new “hybrid-on-premise” applications, along with heavily integrated on-premise systems
(ADSS, MV90). Although some applications are hosted solutions, the EIM applications will have many integration points
that will need both traditional and enhanced levels of IT support. Support expectations are near real-time response
expectations with quick resolution and 24x7 availability. Operations support for Nucleus and ADSS, primary energy
resources software applications, will also be supported by this team.
The two new technology FTEs will provide onsite business hours support alongside of the larger EIM support
organization. For after-hours support needs, the Network Operations Center (NOC) analysts will be trained on specific
support tasks that can be performed without guidance. For items that the NOC analysts are not trained to support, an
on-call schedule will be in place to allow escalation when timely resolutions are needed. Based on conversations with
other utilities, two dedicated support team members have been sufficient based on their volume and needs.
7.5.2 EIM Operations Technical Lead (1 FTE)
The first FTE to be hired will be the EIM Operational Technical Lead (OTL). This individual will be considered the Subject
Matter Expert on the EIM platform and its accompanying systems.
7.5.2.1 Risk Considerations
Hiring the EIM Operational Technical Lead in the specified timeline allows the individual to participate in project
decisions, and have a thorough understanding of why decisions were made. Delaying the start would create knowledge
gap, transfer risk and potentially add unnecessary documentation burden. The Operations teams would lack the
technical expertise to effectively and efficiently address complex system issues, which could lead to delivery resources
being on-call and performing operations work. Additional risks associated with not hiring a dedicated EIM OTL include:
•During the lifecycle of the product(s), critical EIM project resources may be reprioritized to work high level
system outages and failure
•Projected O&M costs would still remain, but would be performed by Delivery resources
•Delivery resources would need to be on-call, resulting in risk to project deadlines
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 19 of 52
EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 20 of 52
7.5.2.2 Key Attributes
•Required Timing: Q2 2020
•Reporting Structure: Matrix reporting with a solid line to IT Operations Manager and dotted lines to the EIM
support organization’s manager or business manager.
•Other Considerations
o The OTL role requires not only an understanding of how Avista systems are meant to work, but also a
sufficient skillset to adjust when they don’t function as designed. This individual will partner with
Avista’s application development teams and business partners, to build, deploy, and support a reliable,
resilient, and high performing user and customer experience.
o The OTL is expected to provide proactive leadership regarding implementation of non-functional
requirements and take the technical lead on operational availability, performance and optimization for
their respective platforms.
•Essential Functions:
o Work closely with business partners in a matrix organizational structure
o Work closely with software development teams and architects to ensure the operational success of
production applications and roadmap compliance
o Lead task forces, comprised of cross-functional disciplines, to troubleshoot resolve complex issues with
follow-thru to resolution
o Identify and develop the automation and software changes needed to address operational issues to
reduce manual effort, reduce outages, and enhance scalability and resiliency
o Resolve production issues, identify root causes, and iterate on improving both production and pre-
production environments.
o Create and maintain operational documentation and runbooks
o Design, automate, and implement monitoring, metric collection and alerting
7.5.3 EIM Technical Systems Analyst (1 FTE)
The second FTE to be hired will be the Technical Systems Analyst. This individual will primarily focus on user and system
support, service order resolution, break-fix, routine maintenance, configuration and utilization of tools to send proactive
alerts, creation of error messages that provide actionable information to end users, creation of system design and
configuration documentation, development of step-by-step support task documentation for ancillary support groups,
and other activities designed to streamline day-to-day operational support.
7.5.3.1 Risk Considerations
Hiring the EIM Technical Systems Analyst in the specified timeline allows the individual to participate in project
decisions, and have a thorough understanding of why decisions were made. Delaying the start would create knowledge
gap, transfer risk and potentially add unnecessary documentation burden. The Operations teams would lack the
technical expertise to effectively and efficiently address complex system issues, which could lead to delivery resources
being on-call and performing operations work.
7.5.3.2 Key Attributes
•Required Timing: Q2 2020
•Reporting Structure: Matrix reporting with a solid line to IT Operations Manager and dotted lines to the EIM
support organization’s manager or business manager.
•Other Considerations:
o Tier 1 and 2 application support of the EIM platform will be required along with strong
communication and analytical skills.
•Essential Functions
o Holds domain and working knowledge of production system(s)
o Serves as front line of support for customers and users
o Monitors for state and health of production assets/systems and addresses all assigned work within
appropriate KPI priorities
Document is no longer concidered confidential
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EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 21 of 52
o Actively participates in system projects, change planning and execution and executes routine
maintenance for EIM technologies
o Documents procedures and maintains knowledge base
Idaho Public Utilities Commission – EIM Incremental Expense Deferral
8.1 EIM Deferral Request & Approval
On March 23, 2020, the Idaho Public Utilities Commission (IPUC) issued Order No. 34606 approving Avista’s application
to defer incremental O&M costs (without a carrying charge), associated with joining the California Independent System
Operator's (CAISO) Western Energy Imbalance Market (EIM). Commission Staff comments, filed on March 4, 2020
expressed support of Avista’s request to defer its EIM incremental expenses, noting they believe the Company
demonstrated it is reasonable for it to join the EIM. Per Order No. 34606, the Company is to cease deferring the
incremental implementation costs at the go-live date, and is to file a report after one year of participation, describing
the costs and benefits of participation, any other relevant information, including but not limited to the CAISO’s quarterly
Western EIM Benefits Report. Recovery of any operational cost associated with membership in the EIM after the
Company's go-live date would be determined in a future proceeding. At that time, a prudency review would be
conducted to determine the reasonableness of recovering the deferrals from Idaho customers.1
At the time of the filing, the Company expected the annual O&M expense to be approximately $3.5 - $4.0 million per
year on a system basis, mostly associated with adding 11-13 new employees to facilitate market operations and
settlements, and a five-person 24x7 hour EIM operating desk. Idaho’s share of these costs is approximately 35% or $1.2 -
$1.4 million annually. Staff noted the Company’s estimated costs appear reasonable and that it is Avista’s responsibility
to demonstrate these costs are prudent prior to recovery. Staff noted some concern over expected labor costs, when
comparing Avista’s estimated costs to that of similar utilities, but recognize current cost estimates may change and will
be reviewed in detail in future general rate cases.
8.2 Avista’s EIM Incremental FTE Guidance
Due to the approval by the IPUC of the Company’s accounting petition to defer incremental operating expenses
associated with the implementation of EIM, the following guidance will be used to determine what expenditures are
incremental. EIM incremental guidance determination:
•All non-labor, including contracted labor, charged to EIM will be considered incremental.
•New positions* which are added specifically for EIM will be considered incremental if they meet one of the
following criteria:
o A new employee is hired into an EIM position.
o An existing employee is hired into an EIM position and their previous position is backfilled.
* Avista will not account for partial positions (i.e. an employee is working on EIM and non-EIM work) as incremental
unless there is a significant impact to the business and there is a determinable way to recognize and document the
specific incremental portion of actual work.
Implementation & Post-Implementation Resources – Estimated Financials
9.1 Incremental FTE Summary
In order to estimate the financial requirements both during the implementation phase and post-implementation phase,
each resource previously discussed was assigned an estimated hire date, annual salary (assumed 78.05% loaded rate)
and a breakout of efforts between capital and O&M. These resources were further assigned an estimated annual 3%
annual merit increase, and where applicable, incremental step increases based on achieving certain experience levels.
____________________________________________________________________________________
1 Avista intends to include Washington’s share of all incremental EIM capital expenses in future Washington General Rate Cases.
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EIM Human Resource Plan
EIM Human Resource Plan Avista Confidential Page 22 of 52
This framework provided an estimate of annual capital and O&M FTE costs across 2020-2023, with 2022 representing a
shift to primarily O&M expenses based on a market go-live date of April 2020. The anticipated annual O&M expense,
based on a staggered hiring of the 17 EIM employees, is provided below. This baseline will be updated after FTEs are
hired.
Chart 4 – FTE O&M Labor Estimates (in Millions) Including Idaho Commission Deferral
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EIM Human Resource Plan Avista Confidential Page 23 of 52
9.2 FTE Capital & Operating Expense Estimates
Chart 5 – FTE Capital & O&M Expense Estimates (in Millions)
This Excel file is not imbedded in the PDF document, but available as a separate file titled “Confidential – EIM HR Plan
Financials – Final 05.20.2020”
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Recommendation & Approvals
10.1 Director Steering Committee Review
At the March 2020 EIM director steering committee meeting, the proposal of 17 FTE roles was
discussed, with emphasis on the Settlement team and EIM BA desk. The directors were in support of
proposed Settlement team structure (see Chart 1) and a recommendation was made for the team to
report to the Director of Accounting. They also supported a Settlement team of five FTEs, with
corresponding analysis outside the Settlement Team within Power Supply and System Operations. A
draft version of the document was sent for review and feedback was incorporated.
10.2 Executive Steering Committee Review
At the April 2020 EIM executive steering committee meeting, the proposal of 17 FTE roles was
discussed, with emphasis on the Settlement team and EIM BA desk. The executives were in support of
proposed Settlement team structure (see Chart 1) and approved the team to report to the Director of
Accounting. They also supported a Settlement team of five FTEs, with corresponding analysis outside the
Settlement Team within Power Supply and System Operations. A draft version of the document was sent
for review and feedback was incorporated.
10.3 Director Approvals
Approve EIM HR Plan Document - Approval Needed by May 29 - Scott Kinney - 06.01.2020.msg
________________________________________________
Scott Kinney, Director of Power Supply
Approve EIM HR Plan Document - Approval Needed by May 29 - Andy Vickers - 05.20.2020.msg
____________________________________________
Andy Vickers, Director of Generation Production and Substation Support
Approve EIM HR Plan Document - Approval Needed by May 29 - Mike Magruder - 05.29.2020.msg
______________________________________________
Mike Magruder, Director of Transmission Operations and System Planning
Approve EIM HR Plan Document - Approval Needed by May 29 - Jim Corder - 06.08.2020.msg
______________________________________________
Jim Corder, Director of Information Technology and Secruity
Approve EIM HR Plan Document - Approval Needed by May 29 - Hossein Nikdel - 05.28.2020.msg
______________________________________________
Hossein Nikdel, Director of Applications and System Planning
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Avista Utilities Key Decisions Document
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Approve EIM HR Plan Document - Approval Needed by May 29 - Adam Munson - 06.09.2020.msg
______________________________________________
Adam Munson, Director of Accounting
RE EIM HR Plan Document - Approval Needed by May 29 - Pat Ehrbar - 05.28.2020.msg
______________________________________________
Pat Ehrbar, Director of Regulatory Affairs
10.4 Executive Approvals
Approve Final EIM HR Plan Document - Approval Needed by June 19 - Jason Thackson - 06.12.2020.msg
______________________________________________
Jason Thackston, Senior VP of Energy Resoruces
Approve Final EIM HR Plan Document - Approval Needed by June 19 - Heather Rosentrater - 06.15.2020.msg
_____________________________________________
Heather Rosentrater, VP of Energy Delivery
Approve Final EIM HR Plan Document - Approval Needed by June 19 - Kevin Christie - 06.12.2020.msg
_____________________________________________
Kevin Christie, Sr. VP of External Affairs
Approve Final EIM HR Plan Document - Approval Needed by June 19 - Jim Kensok - 06.11.2020.msg
_____________________________________________
Jim Kensok, VP Chief Information & Secruity Officer
Approve Final EIM HR Plan Document - Approval Needed by June 19 - Ryan Krasselt - 06.17.2020.msg
_____________________________________________
Ryan Krasselt, VP and Controller
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Appendix
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Appendix A – Settlement, Bill & Analytics Roles
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EIM Key Decision
Settlement, Billing & Analytics Roles
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Table of Contents
1 Recommendation ................................................................................................................................ 30
2 Background ......................................................................................................................................... 31
3 Analysis ............................................................................................................................................... 32
4 Options & Peer Evaluation .................................................................................................................. 35
4.1 Centralized Organization................................................................................................................. 35
4.1.1 Advantages .................................................................................................................................. 35
4.1.2 Disadvantages ............................................................................................................................. 35
4.2 Distributed Organization ................................................................................................................. 35
4.2.1 Advantages .................................................................................................................................. 35
4.2.2 Disadvantages ............................................................................................................................. 35
5 Approvals ............................................................................................................................................ 36
Revision History Date Author
0.0 – First Draft 2/5/2020 kdonald
0.1 – Removing content related to ATF RTIS submittal / verification
–responsibility of the RT desk and incorporating kdengel feedback 2/6/2020 kdonald
0.2 – Updating with decision from 2/28/2020 meeting 2/28/2020 kdonald
0.3 – Updated with director edits and comments 04/20/2020 kdengel
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Key Decision Topic: EIM Settlements, Billing & Analytics Roles Decision: Approved ☒
Date: 04/30/2020 Not Approved ☐
Author(s): Ken Donald - Utilicast
Decision Makers: EIM Director Steering Committee
Decision Support: Kelly Dengel, Robert Follini, Xin Shane, Kenny Dillon, Carolyn Groome, Ian McLelland, Lauren
Pendergraft
Recommendation
A hybrid of centralized and distributed organizational models is proposed to support on-going EIM
market operations. This structure will facilitate deep analytical capabilities through matrixed
relationships to resources within the Merchant and BA groups, while also supporting flexibility in the
application of resources to cover the myriad of daily settlement processing tasks. Because settlement
represents such an integral part of successful EIM participation, a strong sense of accountability within
this team and among operational groups to this team is necessary. The group is directly tied to
leadership at a director position in order to enhance escalation of issues to an appropriate level. To best
support EIM functions, the settlement function should be comprised of a centralized Settlement group
reporting to the Director of Accounting with indirect ties to analysts in Power Supply and System
Operations (Entity/BA) as shown in Table 1 below:
Table 1 - Summary of Settlement Staffing Requirements
Role / Allocation Reports to: Resides within:
Settlement Manager / 1 FTE Director of Accounting Accounting
Meter Processing (T+8B & T+48B)
Meter Analyst / 1 FTE Settlement Manager Accounting
Shadow Settlement (T+3B, T+12B & T+55B Trade dates - at a minimum)
Settlement Analyst / 1 FTE Settlement Manager Accounting
Settlement Analyst / 1 FTE Settlement Manager Accounting
Settlement Analyst / 1 FTE Settlement Manager Accounting
Market Analytics (T+3B, T+12B & T+55B Trade dates)
Market Analyst / 1 FTE (some portion
of this FTE is dedicated to other non-
settlement Merchant Operations
analysis tasks)
Manager Real Time & Day Ahead Power
Supply/Merchant
Market Analyst / 1 FTE (some portion
of this FTE is dedicated to other non-
settlement Transmission Operations
analysis tasks)
Director of System Ops & Planning BA Entity
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Background
There is no cookie-cutter template for building an organizational structure to support EIM functions. A
recent survey of existing EIM BAs reveals varying approaches dependent on, in no certain order, the size
and diversity of the BA footprint, utility culture, experience of existing staff with EIM software products
and maturity of pre-EIM functions such as meter data management.
At the root of the problem is the need to answer questions such as: “Should I pay my CAISO bill without
any verification of its accuracy?” An only partly facetious answer might be “Sure, CAISO is usually
correct.” As a theoretical baseline, it is entirely valid to consider that there is absolutely no requirement
for a BA to shadow its settlement artifacts, modify Transmission Customer billing procedures or commit
to robust economic analyses in order to join the EIM. However, the effort and expense involved in
procuring sophisticated software systems is a good indication that Avista wishes to join as an informed
participant.
What is meant for a settlement organization to be an “informed participant” in EIM is that on a daily
basis settlement data is analyzed to ensure that charges and credits are:
•Technically Correct – CAISO has accurate data and performs settlement math appropriately
•Practically Correct – Result amounts represent reality
•Reasonable – Results are consistent with expectations
Whereas settlement results from bidding at the CAISO interties in the normal daily and hourly market
(Market Redesign and Technology Upgrade or MRTU) are more directly traceable to discreet
transactions, the number of moving variables in EIM are increased exponentially and more difficult to
understand. It is essential that the analyses consider approximately 100 price points in all 288 intervals
of each Trade Date. The value these efforts provide to Avista, in terms of its ability to operate
successfully in the EIM, ranges from very concrete near-term effects to more distant and strategic goals.
•Identification of CAISO data handling or calculation errors and disputing unfavorable settlement
amounts
o CAISO is not infallible – notable examples from other EIM Entities where an incorrect
price was applied range from hundreds to approaching a million dollars per occurrence
•Isolation of internal system failures which prevent timely and accurate flow of data necessary to
ensure economic dispatch by CAISO
o Most often this occurs with generation Base Schedule and interchange snapshot
submittals, but could include outage information, bid data, etc. By performing shadow
calculations against First Principle inputs from Avista’s own systems, settlements can
determine where CAISO did not have the data necessary to produce the correct result.
Often this is the fault of the EIM Entity and not able to be remedied by settlement
dispute, but communication with EIM groups upstream of settlements can prevent
continued failures.
•Recognition of market power flow patterns and situational awareness of related financial data
o By combining operational characteristics such as Energy Transfer System Resource
(ETSR) flow, application of load bias and CAISO unit commitments with settlement
results, patterns will begin to evolve which could be used to guide future bidding
behavior. The settlement system acts as a manifold for the universe of market data
while “Business Rules” filter it for specific scenarios:
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▪Are CAISO committed resources being run at minimum and therefore not
setting price?
▪Is CAISO dispatch respecting modeled limits?
▪Are significant number of Avista resources being displaced by cheaper
generation from the EIM?
▪Does limitation of flow into and out of Avista through ETSR dispatch produce
repeatable and predictable impacts on Energy, Congestion and Loss Offset
Charge Codes?
•EIM Benefits / counterfactuals
o The question of whether the decision to participate in EIM was a good one, or how good
it was, is inevitable and requires collection and processing of atomic level data well in
advance of the question being proposed
o CAISO will publish EIM benefits quarterly, but these results are no less fallible than the
daily settlement artifacts. Robust EIM participation will involve independent verification
of the quarterly benefits
o Not only should the informed EIM BA shadow the CAISO calculations, but may also want
to develop and execute its own metrics
In the analysis below the steps required to answer: “Should I pay my CAISO bill?” and other important
considerations are categorized; details of the specialized tasks and skills involved in doing so are
presented in Table 2.
Analysis
Broadly, the key settlement functions can be classified into these groups.
•Meter processing – both physical data and software accuracy. Under EIM, the need to
troubleshoot issues and anticipate regular model or equipment changes is underscored by daily
acquisition, validation and submission of 5-minute interval data.
•Daily settlement processing – in acquiring First Principle inputs from Avista’s own internal
systems the reconciliation of EIM Charge Code amounts involves much more than checking that
CAISO’s math is correct. The Merchant and Entity sides perform shadow validation and invoice
roll-up calculations independently. The CAISO settlement timeline folds into a business-day
calendar and iterates for a single Trade Date at least 3 and possibly up to 8 times as much as 3-
years beyond the Trade Date. As a consequence, settlement analysts need to be capable of
processing a more than a handful of Trade Dates each day.
•Transmission Customer sub-allocation – Third Party Load, Non-Participating Generation and
Interchange Transactions share in the amounts directly charged or credited by CAISO to the EIM
Entity. The tools and methods are far less standard than those associated with shadow
settlement.
•Market Analytics – Starting with “simple” tasks involved in identifying variances due to input
data problems or calculation errors and building up to complex comparison of generation and
transmission operational characteristics ensuring consistent modeling and market solutions.
•Financial Reporting and Cost Benefits – Identifying how market results impact overall costs.
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•Market Initiatives – Keeping pace with the constant current of market enhancements proposed
in CAISO stakeholder forums. Anticipating the changes and managing the necessary software
modifications is a key to success in the EIM.
The table below contains some of the key tasks for EIM which fall into the groups identified above.
Detail of the specific systems and processes required will be refined during the EIM Implementation
with input from vendor functional designs.
Table 2 - Major EIM Settlement Tasks
Task System
Estimated
hours per
day
Meter Processing (T+8B & T+48B)
Obtain/VEE Generation and Interchange Meter Data Energy Accounting 1 hour
Identify/rectify communication failures from
upstream systems Energy Accounting 1 hour
Process/Submit Generation and Interchange Meter
Data (possibly at T+1 for interchange as well) Energy Accounting 1 hour
Troubleshoot/Calculate/Submit ELAP Load Meter
Data Energy Accounting 1 hour
Obtain/VEE 3rd party load data Energy Accounting 0.5 hour
Prepare for meter configuration changes related to
new resources or equipment changes* Energy Accounting 0.5 hour
Analysis & Reporting (T+48B only) Energy Accounting 0.5 hour
Shadow Settlement (T+3B, T+12B & T+55B Trade dates - at a minimum)
Process PRSC Market Results and EIM Settlement
Statements, identify issues with upstream data,
isolate result variances, create disputes
Settlements – Merchant 4 hours
Process EESC Market Results and EIM Settlement
Statements, identify issues with upstream data, isolate
result variances, create disputes
Settlements - Entity 3 hours
Process sub-allocation statements invoices from other
EIM BAs Settlements – Merchant 0.5 hours
Sub-allocation of Entity settlements to Transmission
Customers, Receive/Analyze/Process TC disputes and
post disputes to OASIS
Settlements - Entity 2 hours
Reconcile PRSC Invoices – convey AR/AP to FSO**
(weekly) Settlements – Merchant 0.25 hours
Reconcile EESC Invoices – convey AR/AP to FSO**
(weekly) Settlements – Entity 0.25 hours
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Task System
Estimated
hours per
day
Create, verify & transmit sub-allocation invoices**
(weekly or monthly) Settlements – Entity 0.25 hours
Create EQR reflecting EIM Transactions, combine with
bilateral EQR and upload to FERC Settlements – Merchant 0.25 hours
Process GHG Obligations and Open Positions / Mark to
Market Settlements – Merchant 0.25 hours
Market Analytics (T+3B, T+12B & T+55B Trade dates)
Merchant P&L analysis (UIE, LMP, BCR, Limit violations
etc.) Visual Analytics - Merchant 4 hours
Entity BA analysis (VERs, UFE, ACE, ETSRs, BCR uplift,
Offsets, Load Bias etc.) Visual Analytics - Entity 2 hours
EIM Benefits / Counterfactual analysis Visual Analytics - Entity 0.5 hours
Strategic Initiatives (Not tied to Trade dates)
Review Daily CAISO Market Reports to identify issues N/A 2 hours
Prepare for and attend CAISO “week in review”
meetings covering the impacts of congestion, ETSR
flow, transmission constraints etc.
N/A 1 hours
Track progression of market enhancements such as
eDAM & DAME N/A 0.5 hours
Contribute to & attend CAISO stakeholder events N/A 0.5 hours
*Requires significant collaboration with resources upstream working with field equipment and systems
(i.e. MV-90)
**Manage AR/AP & credit not included in settlement tasks
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Options & Peer Evaluation
Based on previous EIM Entity Implementations, settlement groups have evolved into two distinct
patterns with software systems that commonly support both structures – either centralized or
decentralized teams. In order to understand the options, Avista spoke with settlement team
members at Puget Sound Energy, Portland General Electric, Idaho Power, NV Energy, and Arizona
Public Service. Through these conversations, Avista learned it was common for early EIM Entities to
take a decentralized team approach, while more recent entrants took the centralized approach.
Each Entities’ settlement team was structured a little differently within each model, but they all
stressed the importance of understanding settlements as a whole and avoiding a model where
analysis is separated into work groups which creates several challenges to fully understand overall
market performance. They also stressed the importance of strong, cross-functional
communications amongst all impacted departments for settlement discrepancy resolution,
determining operational impact and making operational decisions to improve performance. This
resolution and performance improvement is also aided by the presence of strong analysts in the
Merchant and Entity groups that can compare operational decisions against the financial
settlements to determine if the group is making sound economical choices for Avista. Based on
their feedback, and information shared by Utilicast, Avista recommends pursuing the centralized
team structure, with indirect ties to analysists in Power Supply and System Operations (Entity/BA).
4.1 Centralized Organization
Characterized by a common group of co-located staff members working strictly with the
confines of settlement functions but spanning both Merchant and Entity interaction with CAISO.
4.1.1 Advantages
•Facilitates job sharing between Merchant and Entity activities
•Promotes expansion of settlement specific skills and knowledge within the
group
•Settlements tend to be given more timely focus and appropriate priority
•With vision over financial results from both groups, cost benefit studies are
more easily assembled
4.1.2 Disadvantages
•A settlement “silo” may not have immediate awareness of operational
consideration which manifest in financial results
•Possible Standards of Conduct concerns
4.2 Distributed Organization
Characterized by dedication of certain individuals physically and organizationally within the
Merchant and Entity groups to settlement functions separately.
4.2.1 Advantages
•“Shallow” and “Deep end of the pool” analyses reside with the same individuals
•Operational conditions more easily considered in settlement analysis
4.2.2 Disadvantages
•Diminished opportunity to “crossover” with partial FTEs
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EIM Human Resource Plan Avista Confidential Page 36 of 52
•Potential of falling behind on daily settlement tasks when local concerns take
precedence
•Challenging to see complete financial picture for both Merchant and Entity
Approvals
EIM Director Steering Committee Approvals:
Scott Kinney Date: 04/28/2020
Approve EIM - Settlements Document Approval Due April 30 - Scott Kinney - 4.28.2020.msg
Mike Magruder Date: 04/30/2020
Approve EIM - Settlements Document Approval Due April 30 - Mike Magruder - 04.30.2020.msg
Hossein Nikdel Date: 04/23/2020
Approve EIM - Settlements Document Approval Due April 30 - Hossein Nikdel - 04.23.2020.msg
Jim Corder Date: 04/30/2020
Approve EIM - Settlements Document Approval Due April 30 - Jim Corder - 04.30.2020.msg
Adam Munson Date: 04/30/2020
Approve EIM - Settlements Document Approval Due April 30 - Adam Munson - 04.30.2020.msg
Pat Ehrbar Date: 04/23/2020
Approve EIM - Settlements Document Approval Due April 30 - Pat Ehrbar - 04.23.2020.msg
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Appendix B – RT Operator Functional Role Evaluation
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EIM Key Decision
Real Time Operator Functional Role
Evaluation under EIM
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Table of Contents
1 Background ......................................................................................................................................... 40
2 Discussion ............................................................................................................................................ 43
2.1 Permissions to CAISO Applications ............................................................................................. 44
2.2 Dispatch in the Market ............................................................................................................... 44
2.3 Economics and Reliability ........................................................................................................... 45
3 Proposal to Incorporate EIM tasks at Avista ....................................................................................... 48
4 Approvals ............................................................................................................................................ 51
AUTHORS:
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Key Decision Topic: RT Operator Functional Role Decision: Approved ☒
Date: 04/22/2020 Not Approved ☐
Author(s): Jarrett Friddle / Brian Holmes - Utilicast
Decision Makers: Rip Divis, Mike Magruder, Scott Kinney, Robert Follini
Decision Support: Kelly Dengel, Robert Follini, Rip Divis, Mike Magruder, Scott Kinney
Background
Joining the Western EIM will require many new tasks to be performed. This summary focuses only on
the Real-Time Merchant and Transmission Operations functions. For successful participation, the new
tasks and responsibilities need to be aligned in a logical way, supported by the software, workable
within CAISO roles and restrictions, and defined in sufficient detail in business processes.
The purpose of this document is to:
1.Document the key Real-Time roles and tasks associated with EIM
2.Provide a framework for the distribution of those tasks to specific Real-Time Desks at Avista
3.Provide a concrete framework for discussing pros, cons and tradeoffs
4.Document the final decision of Avista on the functional tasks of each RT Operator Group
Table 3 lists some of the major Real-Time roles and responsibilities in traditional utility operations which
will continue in EIM. They are grouped into major similar categories and may not be grouped the same
way that Avista currently accomplishes these tasks. Additional tasks can be added.
Table 4 lists some of the major Real-Time roles and responsibilities in EIM operations. They are grouped
into major similar categories and may not be grouped the same way that Avista will accomplish these
tasks. Additional tasks can be added.
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Avista Utilities Key Decisions Document
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Table 3 – Major Traditional Real-Time Roles & Responsibilities
Energy Supply and Trading RT Generation/BAA Management Transmission Provider Transmission Operations
•Determine optimal unit
commitment and Adjust
forward Generation Plan
•Determine Long / Short
Position and purchase or sell
energy and capacity bilaterally
•Determine optimal
Contingency / Regulating
reserve placement
•Determine and schedule
available energy from hydro
resources
•Tag purchases and sales
•System and/or BA Load
Forecasting
•Hourly VER Forecasting
•Monitor and control
Generation to manage ACE /
BAAL and follow load intra-
hour (Regulation)
•Monitor and Maintain
Contingency Reserve Levels
•Enter Generator Forced
Outages into OMS
•Ensure Contingency Reserves
are responding to events to
meet required response times
•Activate Reserve Sharing
Processes
•Adjust generation to manage
transmission system overloads
•Where applicable, manage
Hydro flow / elevation
constraints in Real-Time
•Adjust Generation to respond
to schedule curtailments
•Review and approve e-tags for
the BA/TP
•Review and approve short-
term transmission service
•Check out Scheduled
Interchange with neighboring
BAs.
•Calculate operational NSI for
AGC
•Curtail tags for reliability / to
manage transmission system
overloads
•Transmission Switching and tag
out management
•Create or Review and Approve
Switching Orders
•Enter Forced Transmission
Outages into OMS
•Perform Contingency Analysis
studies
•Review Gen Plan for Reliability
Impacts
•Coordinate with generation
management to address
transmission system overloads
through generation and/or
transmission switching.
•RAS scheme arming and
implementation
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 41 of 52
Avista Utilities Key Decisions Document
EIM Human Resource Plan Avista Confidential Page 42 of 52
Table 4 – Major EIM Operational Roles & Responsibilities
PRSC EIM Bidding/Base
Scheduling
EIM Entity Base Scheduling EIM Generation/BAA
Management
EIM Scheduling
Management
EIM Transmission
Management
•Create and Submit
Avista Participating
Resource Base
Schedules prior to T-75
and T-55
•Designate Contingency
and Regulating
Reserves for EIM prior
to T-75 and T-55
•Create and Submit 4-
Part Economic Bids to
drive Market outcomes
•Review / Respond to
Sufficiency Test
Failures (Capacity,
Balance, Flex Ramp) for
the PRSC prior to T-55
•Manage Market De-
Rates to Resource
Availability
•Monitor CAISO
Dispatches in Real-
Time in ADS
•Submit Hourly VER
Forecasts as part of
Base Schedules
•Create and Submit Non-
Participating Resource
Base Schedules,
including 3rd Party
•Review / Respond to
Sufficiency Test Failures
(Capacity, Balance, Flex
Ramp) for the BAA by T-
40
•Modify and Submit all
final Generation
Resource Base
Schedules prior to T-40
•Finalize Contingency
Reserves and
Regulating Reserves for
EIM Entity Area prior to
T-40
•Submit RT VER
Forecasts
•Review / approve /
block generation
dispatches in BAAOP
•Activate Contingency
Events in BAAOP
•Initiate Reserve Sharing
with NWPP
•Manage EIM through
load conformance
process (especially
during contingency
events) in BAAOP
•Perform manual
dispatch as needed
through EIM processes
in BAAOP, including
shutdowns
•SPOC for CAISO for all
Generation Outages /
Availability, including
3rd Party
•Coordinate Market
Generation Following /
Independent Dispatch
with plants and RTMO
•Create and Submit
aggregated Intertie
Base Schedules for each
Intertie Location prior
to T-75, T-55, T-40
•Determine EIM Transfer
limits for each Intertie
to another EIM
participant and submit
to BAAOP continuously
•Provide a rolling five
hour forecast or
ramped interchange for
each Intertie at a 5-
minute granularity,
refreshed every 5
minutes to BAAOP
•Perform ATF
interchange checkout
for tags and EIM
Transfers, update EIM
Dynamic ETSR Tags
•Submit ATF RTIS
•Review / Respond to
Sufficiency Test Failures
(Congestion)
•Troubleshoot topology
errors in BAAOP
•SPOC for CAISO all
Transmission Outages /
Availability
•Manage EIM binding
constraints (physical)
and perform
transmission
conformance as needed
in BAAOP
•Verify and confirm
transmission outage
information
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 42 of 52
EIM Human Resource Plan Avista Confidential Page 43 of 52
The organizational structure design to perform all existing and the new functions specifically arising
from being a participant in EIM can take several forms. A common approach to the general process flow
under EIM tends to follow current processes with some adjustments plus the addition of an EIM Desk in
Transmission Operations. However, to the extent the Merchant organization is more engaged with RT
Generation Management, there has generally been a little more responsibility shift to or sharing with
the Transmission Operations side.
Typically, the Merchant will account for the Hydro Resource Plan, Variable Energy Resource forecasts,
Load Forecast and Generation Outages to build the DA Plan. Prior to the hour, the input information will
be tuned to reflect latest conditions and observations and the Merchant will optimize the remaining
fleet along with bilateral trading to meet the expected BAA or net load and to market excess available
energy.
Transmission Operations will normally review the plan for reliability impacts and communicate if
adjustments need to be made. That process continues up until roughly 60 minutes from the start of
each operating hour and then bilateral trading ceases around T-60. All Intertie Resource (Interchange)
and Generation Base Schedules are expected to be submitted as final and balanced to the Market
Operator by T-55. So it is the functions from T-60 through the end of the operating hour that generally
needs some adjustment in most utilities that join EIM.
Discussion
Below is a table of the existing setup of Avista and which Real-time functions are performed by each RT
Desk.
Table 5: Existing Avista RT Operator Functions
RT Merchant Operators Reliability Operators Transmission Operations
•Determine Long / Short
Position and purchase or
sell energy and capacity
bilaterally
•Determine optimal unit
commitment (in
coordination with
Transmission Operations to
meet reliability targets)
•Determine optimal
Contingency / Regulating
reserve placement (in
coordination with
Transmission Operations to
meet reliability targets)
•Monitor and control
Generation to manage ACE
/ BAAL and follow load
intra-hour
•Monitor and Maintain
Contingency Reserve Levels
•Review and approve e-tags
for the BA/TP
•Review and approve short-
term transmission service
•Check out Scheduled
Interchange with
neighboring BAs.
•Calculate operational NSI for
AGC
•Curtail tags for reliability / to
manage transmission system
overloads
•Notify RC of Forced Gen and
Transmission Outages
•Ensure Contingency
Reserves are responding to
events to meet required
response times
•Activate Reserve Sharing
Processes
•Transmission Switching and
tag out management
•Create or Review and
Approve Switching Orders
•Enter Forced Transmission
Outages into OMS
•Perform Contingency
Analysis studies
•Coordinate with generation
management to address
transmission system
overloads through
generation and/or
transmission switching.
•RAS scheme arming and
implementation
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 43 of 52
EIM Human Resource Plan Avista Confidential Page 44 of 52
•Enter Generator Forced
Outages into OMS
•Where applicable, manage
Hydro flow / elevation
constraints in Real-Time
•Adjust Generation to
respond to schedule
curtailments
•Determine and schedule
available energy from
hydro resources
•Tag purchases and sales
•Adjust generation to
manage transmission system
overloads
Here are a few things to consider when determining where some of the RT functions land while
operating under EIM.
2.1 Permissions to CAISO Applications
CAISO’s access policies to ensure SOC compliance present restrictions to the Merchant employees that
would prevent them from performing many of the interactions with the Market system in Real-time.
•The Balancing Authority Area Base Schedule Coordinator role is the only role allowed to update
Base Schedules after T-55 for the final binding Sufficiency Tests of the EIM Entity at T-40. This
role is not allowed to be assigned to a Merchant Function Employee or system certificate.
•The majority of interaction with the Market Operator and its systems after T-55 is strictly
allowed only by the Balancing Authority Operator and is not permitted by Market Function
Employees. Most systematic communication of changes in Real-time to the Market Operator is
via the CAISO Balancing Authority Area Operations Portal (BAAOP) which is restricted to non-
MFE personnel only due to non-public transmission information and 3rd Party generation
information that is also available.
2.2 Dispatch in the Market
There should be less interaction from Avista in terms of managing generation to meet load and manage
the ACE and congestion in real time. Start Up and Shut Down activities will likely still require
communications to the Plants, but the market will also have a big hand in determining those starts and
stops beyond the units that are already base scheduled to be online through the Base Schedules.
•Barring intervention by the BAA, the following things will be true from the Market dispatch.
o Self-Committed resources designated in the Base Schedule will be dispatched to start by
the Market and expected to be on-line for those hours.
o Within EIM, the generation commitment outside of hours with non-zero base schedules
is a function of the Merchant determined 4-part Bids for Participating Resources (locked
in at T-75) and the resource’s availability submitted for the market clearing process (via
OMS).
o For all non-VER PRs, the real-time dispatch for all committed hours will be determined
by the incremental energy bid curves and the resource’s availability submitted for the
market clearing process (via OMS)
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 44 of 52
EIM Human Resource Plan Avista Confidential Page 45 of 52
o VERs without Bids will be “dispatched” to their forecasts. If a VER is participating, then
it could be dispatched down economically from its forecast based on the bid curve
submitted by the Merchant.
o All other Non-participating Resources and Participating Resources with no bid-curve will
be dispatched to their hourly base schedule, including ramp impacts across the hour
boundary (except when deployed for Available Balancing Capacity based on BAA
infeasibility and the Default Energy Bid defined for that NPR).
o The market dispatch will target dispatching the generation and EIM Transfers to
optimally meet the net demand forecast and scheduled interchange every 5 minutes.
•Managing the dispatch, under the context of EIM, takes on a slightly different form from today’s
operation. To obtain the most benefits from the market, the dispatch should be determined as
much as possible through the Market Operator’s Security Constrained Economic Dispatch (i.e.
by following the Bids).
2.3 Economics and Reliability
Although the load following and balancing needs are generally met through the Market process, there
can be significant interaction between the Market Operator and the EIM Entity. There are legitimate
reasons to modify the known input parameters for the resources when the physical or economic
circumstances have changed since T-55 or even T-40.
Historically, AVA has had the Merchant function manage most generation decisions in real time.
Changes in base points, responses to contingencies, managing plant/unit unavailability issues and other
things where economics of the units is the primary driver are under the Merchant’s purview. There are
two areas where the Transmission System Operators are involved in the generation movement; 1)
ensuring there are resources on AGC control for ACE/BAAL excursions and 2) unit re-dispatch for
transmission system reliability.
Given the access restrictions above, however, the System Operators in the Transmission Function side of
the house will need to be involved in helping to manage the real-time generation when necessary. All
those decisions and actions will have financial implications for Avista. So, it is important that the
Transmission side System Operators, who have traditionally been concerned strictly with maintaining
reliability, can understand and evaluate the financial consequences when making adjustments in the
market. Reliability issues will still trump economics if they are present, but many of actions taken in the
market will not be in response to a reliability risk.
There will certainly be times when the reliability indicators are all acceptable, but AVA is being
economically harmed by how the resources are performing. The System Operators need to be able to
recognize these situations and be part of the solution to ensure all Reliability and Economic goals are
achieved as a part of the Energy Imbalance Market. There will need to be coordination and a sharing of
responsibilities between the Transmission System Operators and the Real-time Traders to manage
manual generation changes while operating in the EIM.
Below is a list of items to consider and activities that have both reliability and economic impacts where
the Transmission System Operator will be involved.
•There are not only financial consequences for intentionally moving a unit away from its market
dispatch target, but also reliability consequences (and unless done in conjunction with a Load
Bias, may not have the intended effect). The market will be assuming the entity to follow its
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 45 of 52
EIM Human Resource Plan Avista Confidential Page 46 of 52
generation and EIM Transfer dispatch instructions. The EIM Transfer will typically be fully
automated and integrated into the scheduled interchange component of the ACE equation.
Units not following their DOTs will result in Area Control Error increasing, posing a risk to
Control Performance Standards or being outside BAAL requirements unless other units or
regulating units are also moving in conjunction, which then puts them off their economically
based DOTs.
•Communication of intent to deviate from the submitted bids, availability and base schedules
supplied by T-40 is extremely important so that the SCED reflects these modifications and you
are not fighting with the CAISO dispatch within the BA.
•The following items that affect the Real-time Market Dispatch are submitted via BAAOP, again
only available to the Transmission System Operators
o Manual Dispatch of an NPR away from its Generator Base Schedule
▪To supply identified contingency reserves during an event
▪Physical Problem at the plant
▪Hydro flow management
▪Correction of localized constraints that cannot be unloaded effectively by re-
dispatch of PRs.
▪Generation Testing
o Manual Dispatch of a PR to a fixed MW quantity (ignores bid curve)
▪To supply identified contingency reserves during an event
▪Physical Problem at the plant
▪Hydro flow management if Market-based dispatch modifies elevations to an
unacceptable level.
o Manual Dispatch change of Pmin and/or Pmax of a PR not reflected through Rerates or
Derates in outage records.
▪Physical Problem at the plant
▪Hydro flow management if Market-based Dispatch modifies elevations to an
unacceptable level.
o Submit Load Bias due to a Reserve Sharing activation or to arrest ACE excursions which
could be due to the following reasons
▪True Load or VER Forecast Error
▪Resources not following DOTs
▪Mismatches in Scheduled Interchange representations between Avista
Scheduling System and that submitted to CAISO as Intertie Resource Schedules
▪The best response to ACE deviations is either:
•If there are no input data errors, load or VER forecast issues,
contingency events, or generation problems, wait until the next market
solution.
•If one of the above is true, use Load Conformance in BAAOP to adjust
the market solution target. Adjusting individual generation via manual
dispatch will not have an effect, as the market will just dispatch another
unit, import or export in the equal and opposite manner to compensate.
o The ability to block or modify a Dispatch instruction or block a Start-up/Shutdown notice
is only available in BAAOP. Although Starts and Stops are available to the Merchant via
the ADS instructions, the ability to block them has already passed by the time the
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 46 of 52
EIM Human Resource Plan Avista Confidential Page 47 of 52
instructions are issued. The time available to block or modify a Dispatch instruction or
block a Start-up/Shutdown notice is about 30-90 seconds.
o Changes in Import and Export limits for EIM Transfers are generally managed
automatically in the systems once the rules are defined, but manual intervention for
these items or locking the ETSRs, which will also have an impact on the RT Dispatch, are
also changed in BAAOP.
o Although Avista appears to have limited internal physical transmission constraints, if
those need to be activated or have limits adjusted, that activity is only available in
BAAOP.
•The exception allowed for direct communication of input data changes to the Market Operator
by the Merchant function after T-55 would be for any Generator Availability modifications
submitted via the Avista OMS system or for Participating Resources directly in CAISO WebOMS.
These are updated continuously.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 47 of 52
Program Scope
EIM Human Resource Plan Avista Confidential Page 48 of 52
Proposal to Incorporate EIM tasks at Avista
The table below describes the proposed distribution of tasks including all new EIM related items across the three
existing RT Operators plus the new EIM desk. The result is some Shared Generation Management tasks between the
Merchant and the Reliability Operator and some EIM tasks added to Reliability and Transmission along with a full set of
primarily pre-hour activities for the new EIM Operator.
Table 6: New EIM Desk with Shared Generation Management and some EIM tasks added to Reliability and
Transmission
RT Merchant Operator New EIM Operator Reliability Operator Transmission Operator
•Determine Long /
Short Position and
purchase or sell
energy and capacity
bilaterally
•Determine and
schedule available
energy from hydro
resources
•Submit Hourly VER
Forecasts as part of
Base Schedules
•Determine optimal
unit commitment,
Basepoint and
Reserve Allocations
for all Avista
Resources
•Submit Base
Schedules to EIM by
T-75, T-55
•Enter Generator
Planned/Forced
Outages into OMS
(ahead of Real-time)
•Tag purchases and
sales
•Create and Submit 4-
Part Economic Bids
prior to T-75 to drive
Market outcomes
•Review / Respond to
Sufficiency Test
Failures (Capacity,
Balance, Flex Ramp)
for the PRSC prior to
T-55
•Manage Hydro flow /
elevation constraints
in Real-Time in
•Create and Submit
3rd Party Non-
Participating
Resource Base
Schedules prior to T-
75, T-55, T-40
•Finalize Contingency
and Regulating
Reserves for EIM
prior to T-40
•Review / Respond to
Sufficiency Test
Failures (Capacity,
Balance, Flex Ramp)
for the BAA prior to
T-40
•Balance and Submit
all final Generation
Resource Base
Schedules prior to T-
40 (in coordination
with Merchant)
•Submit RT VER
Forecasts
•Create and Submit
aggregated Intertie
Base Schedules for
each Intertie
Location prior to T-
75, T-55, T-40
•Determine EIM
Transfer limits for
each Intertie to
another EIM
participant and
submit to BAAOP
continuously
•Provide a rolling five
hour forecast or
ramped interchange
for each Intertie at a
•Review and approve e-tags
for the BA/TP
•Review and approve short-
term transmission service
•Calculate operational NSI
for AGC
•Curtail tags for reliability /
to manage transmission
system overloads
•Approve Gen and
Transmission Outages and
forward to RC/Market
•Update Outages on OASIS
•Activate Contingency
Events in BAAOP
•Initiate Reserve Sharing
with NWPP
•Manage EIM through load
conformance process
(especially during
contingency events) in
BAAOP
•Ensure Contingency
Reserves are responding to
events to meet required
response times using
BAAOP Manual Dispatches
•Adjust generation to
manage transmission
system overloads
•Perform manual dispatch
as needed through EIM
processes in BAAOP (in
coordination with
Merchant/Plants/RTMO)
and EMS generation
dispatch mode
•Review / approve / block
generation dispatches in
BAAOP
•Transmission
Switching and tag out
management
•Create or Review and
Approve Switching
Orders
•Enter Transmission
Outages into OMS
•Perform Contingency
Analysis studies
•Coordinate with
generation
management to
address transmission
system overloads
through generation
and/or transmission
switching.
•RAS scheme arming
and implementation
•Review / Respond to
Sufficiency Test
Failures (Congestion)
•Troubleshoot topology
errors in BAAOP
•Manage EIM binding
constraints (physical)
and perform
transmission
conformance as
needed in BAAOP
•Verify and confirm
transmission outage
information in BAAOP
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 48 of 52
Program Scope
EIM Human Resource Plan Avista Confidential Page 49 of 52
coordination with
Reliability (shared)
•Manage Market De-
Rates for Resource
Availability
•Monitor CAISO
Commitments &
Dispatches in Real-
Time in ADS
•Coordinate shutdown
of Avista Generation
(shared)
5-minute
granularity,
refreshed every 5
minutes
•SPOC for CAISO for
all RT Market
Operator
•Coordinate
shutdown of Avista
Generation (shared)
•Monitor and manage ACE /
BAAL
•Monitor and Maintain
Contingency Reserve Levels
(shared)
•Manage Hydro flow /
elevation constraints in
Real-Time in Coordination
with Merchant (shared)
•Monitor Performance to
Dispatch Instructions
•Check out Scheduled
Interchange with
neighboring BAs, including
updating tags for Dynamic
ETSR Transfers.
•Submit ATF RTIS
Legend:
Black: Existing Functions
Red: Existing Function Transferred or Shared responsibility
Blue: EIM Specific
Brown: Existing Function Impacted by EIM
Transitioned Functions: The Reliability Operator will have the responsibility for monitoring and managing ACE and any
Balancing Authority ACE Limit (BAAL) issues. As mentioned above, the CAISO Dispatch is designed to achieve a set of
DOTs with each dispatch that will zero an EIM Entity Area’s ACE every five minutes if followed. This is not always
perfect, however. Several factors can lead to ACE reaching levels where action will need to be taken to remain in
compliance with Reliability Standards. Although probably not the first option to address this scenario under EIM, if it is
necessary to manually move a Resource, the Reliability Operator will coordinate with the Merchant which resource(s) to
move.
Shared Functions between Merchant and Reliability: RT Generation Movement within the operating hour make up the
areas where there is a sharing between the Reliability Operator and the RT Trader, who has historically managed real-
time generation movement. Several possible reasons for Manual Dispatch were listed in the discussion of Section 2.
Any of these reasons for Manual Dispatch of Resources should be coordinated with the RT Trader unless necessary for
local Transmission Reliability. (Contingency Reserve Dispatch, Availability Issues, Contingency Reserve Recovery, Hydro
Level Management, Shutdown, etc.)
Existing Functions Affected by EIM: Curtailing Tags for Reliability at the instruction of the RC or for management of local
transmission issues will continue to occur, however, occurrences may be decreased if the constraint is actively
monitored and can be managed effectively through the re-dispatch of the Energy Imbalance Market. Any physical
constraint should be activated within the Market unless the constraint is only impacted by output of one or two
resources. The Outage Management role the Reliability Operator has will be modified slightly with the use of the new
AVA Outage Management System, but the RO will be required to actively review and perform the submission to CAISO
for most outages.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 49 of 52
Program Scope
EIM Human Resource Plan Avista Confidential Page 50 of 52
The assignment of responsibilities across the Merchant, EIM Operator, Reliability Operator and the Transmission
Operator is based on what information is known and understood at the time of the document approval. After Avista has
joined the market and has gained operational experience, these responsibilities will be evaluated and re-assigned as
needed to meet the business objectives and maintain operational excellence.
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 50 of 52
Program Scope
EIM Human Resource Plan Avista Confidential Page 51 of 52
Approvals
Rip Divis, Chief System Operator Date 04.22.2020
Approve EIM RT Operator Functional Roles Doc Approval - Rip Divis - 04.22.2020.msg
Robert Follini, Manager of Real Time & Day Ahead Date 03.03.2020
Approve EIM RT Operator Functional Roles Doc Approval - Robert Follini - 03.03.2020.msg
Mike Magruder, Director of Trans Planning & System Operations Date 03.31.2020
Approve EIM RT Operator Functional Roles Doc Approval - Mike Magruder - 03.31.2020.msg
Scott Kinney, Director of Power Supply Date 03.03.2020
Approve EIM RT Operator Functional Roles Doc Approval - Scott Kinney - 03.03.2020.msg
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 51 of 52
Program Scope
EIM Human Resource Plan Avista Confidential Page 52 of 52
Appendix C – FTE Capital & Operating Expense Estimates
This Excel file is not imbedded in the PDF document, but available as a separate file
titled “Confidential – EIM HR Plan Financials – Final 05.20.2020”
Confidential – EIM
HR Plan Financials – Final 05.20.2020.xlsx
Document is no longer concidered confidential
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 52 of 52
Entire Document is CONFIDENTIAL
Updated Cost Estimate associated with the Human Resource Plan
Pages 1 through 2
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 10(R), Page 1 of 1
Avista Energy Imbalance Market
Benefits Assessment
October 11, 2017
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 1 of 16
Table of Contents
Overview ................................................................................................................................................. 3
1.EIM Benefits and Costs..................................................................................................................... 4
2.Avista Benefits Assessment .............................................................................................................. 5
Data Sources ................................................................................................................................................ 5
Benchmarking Analysis Methods and Results ............................................................................................ 7
Statistical Analysis ...................................................................................................................................... 10
Seasonal Considerations for EIM Entry ..................................................................................................... 14
3.Summary and Conclusions ............................................................................................................. 15
References ............................................................................................................................................ 16
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 2 of 16

Overview

Since its creation in 2014 through September 2017, the Western Energy Imbalance Market (EIM) has
expanded to include four participating EIM entities (which are each balancing authority areas, or BAAs)
and the California Independent System Operator (CAISO). Portland General Electric (PGE) entered the
EIM in October 2017, and six additional EIM entities are expected to enter between 2018 and 2020.1
Before deciding whether to enter the EIM, prospective participants have undertaken studies to assess
the EIM’s value proposition for their customers, to weigh the potential benefits against the costs of
participation.
This report estimates potential benefits to Avista Utilities from participating in the Western EIM, based
on benchmarking and statistical analyses that draw on nine publicly-available EIM potential benefit
studies and the CAISO’s quarterly Western EIM Benefits Reports. With this approach, the report provides
reasonable estimates of the range of expected benefits from EIM participation for Avista, without the
need to undertake a detailed modeling study.
Based on this approach, the study estimates that EIM gross benefits to Avista in 2023 would range from
$2 million to $13 million per year (all values in 2017$). Actual benefits to Avista will depend primarily on
the availability of its hydropower resources to participate in the EIM, the transmission capacity that is
available for use by the EIM, expansion of wind and solar resources within the Avista balancing area, and
EIM market conditions.
This report is organized into three sections:
 Section 1 provides a general overview of the kinds of potential benefits and costs for EIM
participants, as background;
 Section 2 describes methods and results from the benchmarking and statistical analyses; and
 Section 3 summarizes key conclusions from the analyses.

1 Entities that are currently committed to join include Idaho Power Company (IPC) and Powerex, which are
scheduled to go online in 2018, Seattle City Light (SCL), Sacramento Municipal Utility District (SMUD) and Los
Angeles Department of Water and Power (LADWP) in 2019, and Salt River Project (SRP) in 2020.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 3 of 16
1. EIM Benefits and Costs
Quantitative benefit projections in EIM studies have largely focused on the value of interregional
dispatch savings and, to a lesser extent, reduced flexibility reserve needs. The CAISO’s Western EIM
Benefits Reports include ex-post estimates of actual interregional dispatch savings (in dollars), reduced
flexibility reserve needs (in MW and percent reduction), reduced wind and solar energy curtailment (in
GWh), and reduced greenhouse gas (GHG) emissions (in metric tons of CO2). Table 1 describes five
categories of expected benefits for participating entities in the Western EIM.
Table 1. Descriptions of EIM benefit categories
Cost savings from more efficient real-time dispatch of
generation across the EIM footprint including access to excess
renewable energy from other participating EIM entities.
Cost savings from lower flexibility or “load following” reserve
requirements to balance within-hour changes in load, wind
generation, and solar generation
Fuel cost savings, and avoided loss of renewable energy credits
and tax credits where applicable, from reduced curtailment of
wind and solar generation
Reductions in GHG emissions from more efficient dispatch of
thermal generation and reduced wind and solar curtailment
Reduced risk of reliability violations, through greater regional
visibility and situational awareness of system conditions and
contingencies, automated security-constrained response to
congestion, and mitigation of delays in manually finding
generation to replace operating reserves

The scope of this report on EIM benefits is limited to interregional dispatch savings. This focus on
dispatch savings is not because it is necessarily the largest benefit, but rather because it is the most
straightforward to quantify and is the only metric that has been quantified across all EIM studies. To the
extent that other benefit categories are also applicable to Avista, those benefits would represent
additional upside potential from EIM participation.
Incremental costs to EIM participants have included the initial, upfront cost of software and system
integration, estimated at $10-20 million, and annual operating costs, estimated at $1-3 million per year.2
The wide range of estimated up-front costs are a result of EIM entities treating internal costs, such as
meter upgrades, differently and starting at different integration points. Recent experience shows that
improvements made by the CAISO and application vendors should result in integration costs towards
the lower end of this range. Of this amount, the CAISO-related costs are estimated to be $400,000 up-
front and $250,000 annually. The sum of upfront costs and the present value of annual costs can be
compared against the present value of annual EIM benefits over a specified time horizon, to assess the
cost-effectiveness of EIM entry.
2 See, for instance, cost estimates in the APS and NV Energy EIM benefit studies, available at
https://www.westerneim.com/Pages/About/default.aspx.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 4 of 16

2. Avista Benefits Assessment
This study uses two approaches to estimate EIM benefits to Avista: (1) a benchmarking analysis, and (2)
a statistical (regression) analysis. This section describes the data sources, methods, and results for both
approaches.
Data Sources
Both the benchmarking and regression analyses draw on publicly-available EIM potential benefit
studies3 and the CAISO’s quarterly Western EIM Benefits Report4 series. Table 2Table 1 lists 50 total
modeled scenarios, based on study-specific assumptions about a range of sensitivity variables including
transmission availability, hydropower generation levels, and natural gas prices. CAISO and the eight
utilities in Table 2 are referred to as ‘EIM entities’ in the remainder of this report.
Table 2. EIM benefit studies and CAISO reports used in this analysis
CAISO CAISO 6 Q4 2014 - Q2 2017
PacifiCorp PAC 6 Q4 2014 - Q2 2017
NV Energy NVE 4 Q4 2015 - Q2 2017
Puget Sound Energy PSE 2 Q4 2016 - Q2 2017
Arizona Public Service APS 13 Q4 2016 - Q2 2017
Portland General Electric PGE 4 n/a
Idaho Power Company IPC 4 n/a
Seattle City Light SCL 8 n/a
Chelan County Public Utility District CHPD 3 n/a

The 50 benefit potential scenarios and CAISO quarterly benefit reports create a wide range of projected
and reported benefits (dispatch savings) to EIM entities, shown in Figure 1.
For comparability among EIM entities, this study normalized the benefits in Figure 1 to each entity’s load
for the historical year or projected study year. An exception is that the CHPD’s benefits, which are
normalized by generation rather than load, because of the large amount of hydropower in its balancing
area relative to the size of its load. If normalized to load, the upper end of CHPD’s benefit range would
be higher than that of SCL. This study extrapolated partial year benefits for APS and PSE in 2016 and for
all participating entities in 2017.
3 See reference section for list of published benefit studies. CAISO and PacifiCorp benefits were studied jointly.
CHPD results based on information described in Clearing Up, 1783, January 20, 2017 (Source: Energy News Data).
4 See references section.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 5 of 16
Figure 1. Range of annual load normalized benefits ($/MWh) to EIM entities, based on EIM studies
and CAISO reports (“Actual”)

The range of projected benefits in EIM potential studies (columns in Figure 1) is driven by scenario
assumptions, while the range of CAISO-reported benefits (diamonds in Figure 1) is driven by actual
market, weather and other operational conditions. Differences between projected benefits and actual
benefits (as reported by CAISO) are driven both by differences between study assumptions and actual
conditions and by the fact that modeling studies tend to underestimate the value of automated,
centralized real-time dispatch relative to (non-EIM) business as usual operations.
CAISO-reported actual benefits for EIM entities have typically been higher than the estimated benefits in
potential studies. PSE actual benefits for the first 3 quarters of EIM participation have thus far been
lower than studied amounts, though CAISO staff indicates that one factor that may contribute to the
lower actual observed savings are constraints applied by BPA on the rate of change of EIM flows across
BPA flow gates. CAISO is working with BPA to enhance when and how such rate of change constraint
limits should be applied.
A key question in this study is: How can the range of benefit estimates across EIM entities in Figure 1
be narrowed to arrive at EIM benefit estimates that are consistent with the characteristics of Avista’s
electricity system? Both the benchmark and regression analyses seek to address this question, using
different approaches.

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 6 of 16
Benchmarking Analysis Methods and Results
The benchmarking analysis involves three steps:
1) Compare Avista with other EIM entities using five key metrics;
2) Narrow the range of load normalized benefits from Figure 1, based on the results of (1);
3) Estimate benefits to Avista in 2023, by multiplying the range of load normalized benefits from
(2) by Avista’s forecasted 2023 load.
Based on our experience identifying drivers of dispatch savings in previous EIM studies, this study
selected the following five key metrics to compare Avista with other EIM entities:
1) Annual energy (load or generation);
2) Hydropower capacity as a share of generating capacity;
3) Transmission transfer capability to the rest of the EIM;
4) Solar and wind generating capacity as a share of generating capacity; and
5) Combustion turbine (CT) capacity.
The five figures that follow compare Avista to other EIM entities on the basis of these five metrics.
Figure 2. Annual load comparison:
Avista’s annual load is most comparable to SCL, IPC, and PGE

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 7 of 16

Figure 3. Hydropower share comparison:
Avista’s share of hydropower capacity as a share of total generating capacity is most comparable to
IPC, SCL, and CHPD

Figure 4. EIM transmission comparison:
Avista’s transmission transfer capability to the rest of the EIM is most comparable to SCL, PSE, and
PGE

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 8 of 16

Figure 5. Solar and wind share comparison: Avista’s wind and solar capacity as a share of total
generating capacity is most comparable to PGE and NVE

Figure 6. CT capacity comparison: Avista’s CT capacity is most comparable to IPC and PGE

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 9 of 16
Across these five metrics, Avista most closely resembles PGE, SCL, IPC, PSE, and CHPD, as summarized in
Table 3. The range of normalized benefits for these five utilities is highlighted in Figure 7, with benefits
ranging from $0.13/MWh (PGE lowest case) to $2.83/MWh (SCL highest case). To be conservative, this
study limited the maximum end of this range to $1.00/MWh, as shown in Figure 7.
Table 3. Summary of EIM Entities that Most Closely Resemble Avista for the Five Metrics
Annual load/generation SCL, IPC, PGE
Hydropower share of total generating capacity IPC, SCL, CHPD
Transmission transfer capability to EIM SCL, PSE, PGE
Solar and wind capacity share of total generating capacity PGE, NVE
CT capacity share of total generating capacity IPC, PGE

Figure 7. Range of Annual Load Normalized Benefits from Figure 1, Highlighting PGE, SCL, IPC, PSE, and
CHPD

To estimate potential EIM benefits to Avista, this study multiplies the load-normalized range of benefits
for the five utilities highlighted in Figure 7 ($0.13 to $1.00/MWh) by Avista’s projected balancing
authority area load of 12.45 terawatt-hours (TWh) for 2023. This produces an EIM benefits range for
Avista of approximately $2 million to $13 million per year.
Statistical Analysis
For the statistical analysis, this study developed a regression model that estimates annual EIM benefits
(dependent variable) as a function of key explanatory factors (independent variables). This study uses
the regression to predict annual EIM benefits to Avista in 2023. All of the regression analysis and
prediction was done using the SAS statistical software package.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 10 of 16
Table 4 shows dependent and independent variables used in the regression. This study chose
independent variables based on a combination of our experience with EIM studies and practical
considerations around data availability. For instance, hydro generating capacity share of total generation
is a proxy for hydropower capacity that is available to participate in the EIM, because data were
insufficient to distinguish EIM-available hydropower for all entities included in the regression model.
Table 4. Description of regression variables5

Annual EIM benefits Natural log Million 2017$

Benefit estimate source (1 = study, 0 = actual) None Dummy variable
Annual load Natural log TWh
Generating capacity Natural log MW
Natural gas price Natural log $/MMBtu
Transmission transfer capability to the EIM Natural log MW
Total EIM participants Natural log Number
California renewables as a share of sales (RPS) None %
Hydro share of total generation capacity None %
Wind and solar share of total generation capacity None %
CT share of total generation None %

Table 5 shows regression model coefficient and probability value results, with statistically significant
coefficient estimates highlighted in bold text and coefficients color coded on the basis of their sign.
Table 5. Regression model coefficient estimates and p-values
Annual load 0.320 0.1101
Generating capacity -0.224 0.1664
Natural gas price 0.906 0.2380
California renewables as a share of sales (RPS) 5.895 0.0769
Wind and solar share of total generation capacity 0.303 0.7544
CT share of total generation -1.013 0.3750

5 The value of most of the Table 4 variables in the regression varies for each EIM entity depending on when the
EIM study was conducted or when the applicable CAISO report was released. “California renewables as a share of
sales (RPS)” is California’s equivalent RPS at the time the EIM study was conducted or when the applicable CAISO
report was released.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 11 of 16
The coefficient signs and p-values in Table 5 suggest four statistically significant results:
1) Actual benefits tend to be higher than modeled benefits;
2) Higher transmission transfer capability between an entity and the rest of the EIM tends to
increase EIM benefits for that entity;
3) On average, incremental EIM benefits tend to decrease as the number of participants increases;
4) An EIM entity’s hydropower capacity (as a share of total generation capacity) tends to increase
EIM benefits for that entity.
This study estimates EIM benefits to Avista by applying Avista-specific inputs (Table 6) to the regression
model. This study uses low, mid, and high scenarios for Avista to capture how EIM benefits vary with
four inputs: (1) whether the EIM benefits are consistent with EIM studies (“modeled”) or CAISO reports
(“actual”); (2) the amount of Avista’s transmission transfer capability to the EIM; (3) Avista’s
hydropower capacity as a share of its total generating capacity, as a proxy for Avista’s hydropower
capacity available to participate in the EIM; and (4) Avista’s wind and solar generation capacity as a
share of its total generation capacity.
Table 6. Avista-specific regression inputs6

Annual Avista BAA load TWh 12.45
Generating capacity MW 2,366
Natural gas price $/MMBtu 3.81
Total EIM participants # 12
California renewables as a share of sales (RPS) % 40%
CT share of total generation % 11% (253 MW)

Benefit estimate source Dummy 1 - 0
Transmission transfer capability to the EIM MW 300 - 500
Hydro share of generation capacity % 13% (298 MW) 24% (578 MW) 49% (1158 MW)
Wind and solar share of generation capacity % 5% (120 MW) - 26% (620 MW)

The scenario inputs in Table 6 lead to 24 EIM benefit scenario results. Table 7shows predicted EIM
benefits to Avista (rightmost column) for each of these 24 scenarios.

6 Fixed inputs were obtained directly from Avista. Annual load is 2023 forecasted load. Generating capacity is
based on current Avista generating mix. Natural gas price is based on 2023 annual average for the Malin hub.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 12 of 16
Table 7. Predicted EIM benefits to Avista in 2023 by scenario
1 300 13% 5% 1.54
1 300 13% 26% 1.63
1 300 24% 5% 1.88
1 300 24% 26% 2.00
1 300 49% 5% 2.92
1 300 49% 26% 3.10
1 500 13% 5% 1.84
1 500 13% 26% 1.96
1 500 24% 5% 2.27
1 500 24% 26% 2.41
1 500 49% 5% 3.51
1 500 49% 26% 3.73
0 300 13% 5% 4.94
0 300 13% 26% 5.17
0 300 24% 5% 6.12
0 300 24% 26% 6.40
0 300 49% 5% 9.66
0 300 49% 26% 10.11
0 500 13% 5% 5.96
0 500 13% 26% 6.22
0 500 24% 5% 7.39
0 500 24% 26% 7.72
0 500 49% 5% 11.69
0 500 49% 26% 12.22

Because the “hydro share of generating capacity” variable is a proxy for hydropower owned or
contracted by Avista and able to participate in the EIM, the “low” scenario for this variable should be
seen as representing a situation in which Avista’s EIM-available hydropower is less than anticipated.
These scenarios provide indicative guidance on the impact of low water flow years. The 13% (298 MW),
24% (578 MW), and 48% (1,158 MW) values do not imply that Avista would have this amount of
hydropower capacity available to participate in the EIM. For SCL, for instance, the “hydro share of
generating capacity” is 100%, but less than 100% of its total hydropower capacity is available to
participate in the EIM.
The range of potential EIM benefits for Avista in Table 7 is approximately $2 million to $12 million per
year. This range is consistent with the $2 million to $13 million range of potential benefits from the
benchmark analysis, which multiplies the load-normalized range of benefits for the five utilities
highlighted in Figure 7 ($0.13 to $1.00/MWh) by Avista’s projected balancing authority area load for
2023.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 13 of 16
Seasonal Considerations for EIM Entry
As part of this analysis, this study reviewed CAISO-reported EIM benefits by quarter to determine if
there has been significant seasonal variation in benefits that might influence when a new entity would
want to join the EIM. The results, shown in Figure 8, indicate that there is no definite trend thus far in
the variation of the quarterly benefits across current entities in the EIM. Additionally, there is no definite
pattern in the quarterly share of total annual EIM benefits (for all participants), as shown in Figure 9.
Figure 8. Quarterly and annual average benefits to EIM entities

Figure 9. Quarterly share of annual total EIM benefits

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 14 of 16
3. Summary and Conclusions
This report assesses the range of potential benefits to Avista from participating in the Western EIM,
focusing on dispatch cost savings. Drawing on publicly-available data, this study used benchmarking and
statistical analyses to estimate a range of potential EIM benefits to Avista.
The benchmarking analysis compared Avista to other EIM entities using five key metrics: (1) annual load,
(2) hydropower capacity as a share of generating capacity, (3) transmission transfer capability to the rest
of the EIM, (4) solar and wind generating capacity as a share of generating capacity, and (5) CT capacity.
Through this comparison, it was determined that Avista most closely resembles Portland General
Electric, Seattle City Light, Idaho Power Company, Puget Sound Energy, and Chelan County Public Utility
District.
This study used a range of load- or generation-normalized EIM benefits to these entities ($0.13/MWh to
$1.00/MWh) to estimate EIM benefits to Avista by multiplying this range by Avista’s forecasted load for
2023. This analysis produced an estimated range of annual EIM benefits to Avista of approximately $2
million to $13 million (2017$) per year.
The statistical analysis used a regression model to predict annual EIM benefits to Avista as a function of
10 explanatory variables. The study used this model to predict annual EIM benefits to Avista in 2023,
using inputs obtained from Avista. The regression analysis produced an estimated range of annual EIM
benefits to Avista of approximately $2 million to $12 million (2017$) per year.
In both analyses, the range of projected annual EIM benefits to Avista is driven by the amount of
hydropower capacity available to participate in the EIM, transmission transfer capability available for
the EIM, expansion of wind and solar generation capacity, and actual EIM market conditions. Within
base case conditions modeled, based on Avista’s current expectation for characteristics of its system for
the test year of 2023, estimated savings could range from $3 million to $10 million (represented as the
range of savings between the regression-based scenarios 5 and 17, respectively). Avista’s realized
benefits are more likely to fall toward the upper end of this range (or possibly beyond) under conditions
with more volatile sub-hourly prices in the EIM, high availability of flexible hydropower in Avista to
respond to EIM prices, and available transmission for Avista to transact with other EIM participants at
those prices, as well as higher penetration of wind in the Avista BAA, which would increase the value of
market flexibility to Avista. A dampening of EIM price volatility, or generation or transmission conditions
that more tightly constrict Avista’s ability to respond to EIM prices could lead to benefits at the lower
end of this range.
This study also reviewed CAISO-reported quarterly EIM benefits, to determine whether seasonal
variation in benefits might influence when a prospective entity might want to join the EIM. This review
did not identify any clear patterns in quarterly benefits among individual EIM benefits or for the EIM as a
whole.
It is important to note that the potential EIM benefits quantified in this analysis are focused exclusively
on interregional dispatch savings because it is the most straightforward to quantify and is the only
metric that has been quantified across all EIM studies. To the extent that other EIM benefit categories
such as improved reliability as a result of real-time regional system awareness provided by the EIM, are
applicable to Avista, those benefits would represent additional upside potential from EIM participation.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 15 of 16
References

CAISO-reported benefits:
Quarterly Western EIM Benefits Reports, CAISO, 2015-2017. Available at:
https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx.

EIM benefit studies:
PacifiCorp-ISO EIM Benefits Assessment. Energy & Environmental Economics, 2013. Available at:
https://www.westerneim.com/Documents/PacifiCorp-ISOEnergyImbalanceMarketBenefits.pdf.
NV Energy-ISO EIM Economic Assessment. Energy & Environmental Economics, 2013. Available at:
https://www.westerneim.com/Documents/NV_Energy-ISO-
EnergyImbalanceMarketEconomicAssessment.pdf.
Benefits Analysis of Puget Sound Energy’s Participation in the ISO EIM. Energy & Environmental
Economics, 2014. Available at: https://pse.com/aboutpse/EnergySupply/Documents/PSE-
ISO_EIM_Report_wb.pdf and https://www.caiso.com/Documents/PugetSound-
ISO_EnergyImbalanceMarket-BenefitsAnalysis.pdf.
APS EIM Participation: Economic Market Assessment. Energy & Environmental Economics, 2015.
Available at: https://www.westerneim.com/Documents/ArizonaPublicService-ISO-
EnergyImbalanceMarketEconomicAssessment.pdf.
PGE EIM Comparative Study: Economic Analysis Report. Energy & Environmental Economics, 2015.
Available at: http://edocs.puc.state.or.us/efdocs/HAD/lc56had152028.pdf
Idaho Power Company Energy Imbalance Market Analysis. Energy & Environmental Economics, 2016.
Available at: http://edocs.puc.state.or.us/efdocs/HAA/haa144137.pdf.
Seattle City Light: Benefits of EIM Participation. Energy & Environmental Economics, 2016. Available at:
https://www.rtoinsider.com/wp-content/uploads/E3_SCL_EIM_Study_FinalReport_2016-05-31.pdf
(accessed on September 16, 2017).

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 11, Page 16 of 16
Exhibit No. 8, Schedule 12
Capital Investment Business Case Justification Narratives Index
Business Case Name Page Number
Energy Imbalance Market
Energy Imbalance Market 2
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 1 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 1 of 12
EXECUTIVE SUMMARY
In an effort to continue as a low cost, customer-focused energy service provider, Avista signed
an Implementation Agreement on April 25, 2019 with the California Independent System
Operator (CAISO) to join the Western Energy Imbalance Market (EIM) by April 2022. The
Western EIM is a real-time, intra-hour energy market operated by CAISO that facilitates
regional resource dispatch on a five minute basis to dispatch the lowest cost resources across
the entire market footprint, while balancing in-hour load and resource obligations. This market
allows participants to lower energy costs by either dispatching less expensive resources to meet
load obligations, or by increasing revenue through the bidding of excess energy into the
market. By the time Avista joins, more than 82% of the Western Interconnection load will be
transacting in the EIM. As such, the liquidity of the hourly bi-lateral market Avista has
traditionally transacted in will be significantly impacted because market rules require EIM
participants to determine their resource schedules well in advance of the upcoming hour. As
such, non-EIM participants will have less counterparties to transact with close to the operating
hour. In addition, as renewable portfolios are increasingly mandated, Avista will need the
market to ease the financial pressure of integrating renewable resources, while maintaining
reliability.
In July 2020, in partnership with CAISO and the Bonneville Power Administration (BPA), Avista
changed their entry date to March 2022, to align with BPA and Tacoma Power. This decision
was made in an effort to coordinate the testing phases and go-live operations amongst
northwest entities for a smoother market entry transition.
Avista will need to implement a variety of EIM software solutions, perform metering upgrades
at a majority of its generation and substation interconnection sites, and install generation
control systems. The original estimates described in the EIM Program Charter reflected $18.1M,
with $4.5M planned in contingency, for a total estimated capital spend of $22.6M. The Charter
also outlined $2.9M in implementation expense for a total Program implementation cost
estimate of $26.6M and $3.5-$4M in on-going annual expense. In October 2020, cost estimates
were updated in the Program Scope document, reflecting $24.1M with $2.6M planned in
contingency, for a total estimated capital spend of $26.7M. The Charter also outlined
implementation expense estimates at $5.4M for a total Program implementation cost estimate
of $32.1M and an on-going annual expense estimate of $3.9M.
The Program implementation effort began in 2019 and will continue through March 2022, with
warranty and closing activities through summer 2022. The CAISO allows Entities to join the
market annually in April, with a fixed CAISO-set schedule for testing phases and market go-live.
If Avista does not meet the planned go-live date, Avista will need to wait until April 2023 to join
the market. Missing the go-live date will put Avista at risk for maintaining reliable service to our
customers, providing energy services at the lowest costs, integrating renewable energy at the
lowest costs and hindering de-carbonization efforts.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 2 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 2 of 12
The work in the EIM Business Case (BC) will benefit electric customers in Washington and Idaho
while the network improvements will benefit gas and electric customers in Washington, Idaho
and Oregon.
VERSION HISTORY
Version Author Description Date Notes
1.0 Kelly Dengel Original Business Case Template 4/29/2019
2.0 Kelly Dengel Updated Business Case Template 7/31/2020 Based on Charter Document
3.0 Kelly Dengel Updated Business Case Template 12/17/2020 Based on Scope Document
GENERAL INFORMATION
1.BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista, and other utilities across the northwest, have traditionally operated in a bilateral market.
As more utilities join an organized market, market liquidity will be impacted by reducing the
number of available bi-lateral trading partners to conduct near term daily energy transactions.
This puts Avista at risk for higher market prices and reliability issues if energy can’t be procured
from the bi-lateral market during stressed conditions, such as the loss of an Avista generating
facility. Avista’s resource mix continues to change with the inclusion of additional renewable
resources to meet both internal clean energy goals and state policy requirements. As additional
renewable energy integrates into the Avista portfolio, it becomes more expensive to manage and
follow the variable nature of these resources. The EIM provides a more economic means to
manage renewable resource variability.
In monitoring this risk and bilateral market shift, Avista has progressively monitored organized
energy market activity within the west including the CAISO EIM and the possible formation of the
Requested Spend Amount $26.7M
Requested Spend Time Period 3 Years – 2019 through 2022
Requesting Organization/Department Power Supply
Business Case Owner | Sponsor Kelly Dengel | Scott Kinney & Mike Magruder
Sponsor Organization/Department Power Supply | System Operations
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 3 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 3 of 12
Mountain West Transmission Group (MWTG). In April 2018, the MWTG initiative was deferred,
and in December 2018 Avista decided to pursue entry to the Western EIM. Avista signed an EIM
Implementation Agreement with the CAISO on April 25, 2019 to join the market in April 2022. In
July 2020, in partnership with CAISO and the Bonneville Power Administration (BPA), Avista
changed their entry date to March 2022, to align with BPA and Tacoma Power. This decision was
made in an effort to coordinate the testing phases and go-live operations amongst northwest
entities for a smoother market entry transition.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The major drivers influencing Avista’s decision to join the market centered on reliability, the
integration of renewable resources and a desire to adhere to clean energy goals.
The CAISO EIM is an in-hour economic based regional resource dispatch program that allows
participants to maintain system reliability and lower energy costs by either dispatching less
expensive resources to meet load obligations, or increase revenue through the bidding of excess
energy into the market. The EIM dispatches the most economic resource across the entire market
footprint based on bid prices to balance in-hour load and generation, resulting in lower overall
dispatch cost for each individual participant. The EIM also lowers the amount of on-line
regulation that each utility holds in excess every hour to make up the error between the
forecasted load and resource plans, and what actually occurs during the operating hour. The
reduced regulation can then be monetized creating additional revenue.
Another driver for joining the EIM is the integration of additional renewable resources in the
Avista Balancing Authority Area (BAA). Renewable generation requires additional regulation and
load following to back up the intermittency of the resource. There is a tipping point where
Avista’s existing hydro flexibility can’t sufficiently or economically supply the required load
following for the amount of renewable resources integrated into the Avista BAA. The EIM allows
for the expanded integration of renewable resources by providing a cost effective, reliable
market backstop to balance intermittent resources. Currently Avista has only a single 100 MW
wind facility and a 20 MW solar facility within its BAA, so there is adequate hydro flexibility to
follow these plants. Recently Avista signed a new 20 year Power Purchase Agreement with
Clearway Energy for 145 MW of wind starting in the fall of 2020. In addition there are multiple
third-party independent power producers in the Avista transmission interconnection queue that
are exploring integration into the Avista BAA, including projects that meet the Public Utility
Regulatory Policies Act requirements to be considered as a qualifying resource.
In April of 2019, Washington State passed clean energy legislation that will drive additional
renewable resources to be built in Avista’s BAA. Finally, Avista recently announced its own clean
energy goals that will transition our resource mix to 100 percent clean by 2045. Any additional
renewable resource integrated in Avista’s service territory results in a reduction of hydro
flexibility to follow these variable resources, and the EIM is the most efficient and cost effective
way to provide the required flexible ramping capability.

Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 4 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 4 of 12
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Entities typically announce their intent to join the market at least two years prior to go-live, while
the CAISO-driven implementation schedule is 18 months for market integration. Avista has given
itself a little over 2.5 years to prepare for market entry, as there is a substantial body of technical
work, physical construction work and business process design Avista must complete. This
extended timeline allows Avista to implement five new software applications, conduct upgrades
to existing software, and perform generation metering and control upgrades, interconnection
metering upgrades at substations and associated network infrastructure upgrades. Throughout
the implementation, Avista will rely on Utilicast, their consultant system integrator, to provide
market education and expertise in preparing the company for successful market participation.

Several northwest utilities, (PacifiCorp, Portland General Electric (PGE), Puget Sound Energy,
Idaho Power Company (IPC), Northwestern, Seattle City Light and BPA) along with other western
utilities, have either already joined the CAISO EIM or announced they will join in the near future.
When BPA joins the Western EIM in March 2022, more than 80 percent of the load in the Western
Interconnection will be participating in the market. This shift in market participation will impact
daily market liquidity by reducing the number of available bi-lateral trading partners to conduct
near term daily energy transactions. The risk of limited trading partners could drive daily market
prices higher and/or cause reliability issues for Avista if energy can’t be procured from the bi -
lateral market during stressed conditions, such as the loss of an Avista generating facility.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
CAISO publishes a quarterly benefit report, which represents a calculation of each Entities’
market benefits. This report will be used in part to reflect Avista’s EIM benefits, and determine
the EIM Business Case investment payback period. Avista will also develop an internal benefit
report, which will include considerations for hydro bidding and Avista specific operational factors
that may not be adequately represented in CAISO’s benefit calculation. These two items
combined will help Avista determine the financial investment return.

Prior to signing the CAISO EIM Implementation agreement in April 2019, Avista hired Energy and
Environmental Economics (E3) to conduct an EIM benefit assessment in the fall of 2017. E3 has
conducted similar benefit assessments for several other utilities to help understand the potential
value of EIM participation. The E3 assessment estimated that Avista could see a range of annual
benefits from $2 to $12 million from EIM participation.

There are four main study assumptions that result in the wide range of potential EIM benefits:
the amount of flexible hydro Avista bids into the market, the amount of transmission made
available for market transactions, the amount of renewable generation that is integrated into the
Avista BAA, and the assumed EIM price volatility. Using Avista’s best estimates for these critical
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 5 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 5 of 12
study assumptions, Avista anticipates EIM annual benefits to be close to $6 million, with potential
for benefits to move closer to the upper end of the study range depending upon observed market
price volatility. Recent market price volatility experienced in 2018 significantly increased the
benefits of current market participants. Both IPC and PGE achieved EIM benefits in 2018 that
were over five times their anticipated benefits calculated by E3 studies. Avista’s resource mix and
transmission connection to other EIM participants most closely matches IPC and PGE. Therefore
Avista may achieve similar elevated EIM benefits during times of high market price volatility.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Additional Program detail is provided in the EIM Program Initiation Charter dated May 17, 2019
and the EIM Program Scope Document dated October, 29, 2020. Both are posted to the EIM
SharePoint site.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Across a majority of the generation and substation sites, Avista has relied on non-revenue quality
meters with no ability to securely retrieve 5-minute revenue quality interval meter data required
for market participation. Most of Avista’s generation sites did not have revenue class Current
Transformers (CTs) or Potential Transformers (PTs) that allow for accurately measuring
generation output. Avista also has very limited Automated Generation Control (AGC) systems and
associated Programmable Logic Control (PLC) at its generation plants – both of which are
required for a resource to receive and follow a market dispatch signal. Although there is a
communication network presence at most of these generation sites, not all generation meters
are capable of connecting to the network for retrieval of 5-minute interval data. However, the
current state of Avista’s meters, generation controls and associated network connectivity was
acceptable, as Avista traditionally operated in a bi-lateral hourly market. The generation meters
will be replaced with a SEL-735 meter, or a locations where the SEL-735 already exists, the meter
will be reprogrammed to collect 5-minute reads.

Throughout substation interconnection sites, Avista does meet the revenue quality meter
requirement with JEMStar meters and accurate CTs/PTs. Although Avista considered
reprograming these meters to collect 5-minute interval data with an associated memory
upgrade, these meters are at least 12 years old, require dial up communications to retrieve
interval data and are unable to connect via Internet Protocol (IP) communications. Considering
the age of the meters and the fact that Avista should not rely on dial up communications alone,
the decision was made to replace the meters with a SEL-735 meter, capable of 5-minute interval
data and multiple connectivity options.

Due to limited field support of dial up communications and lack of monitoring capabilities, Avista
decided to replace dial up communications in favor of IP communications installations wherever
cellular installations are feasible – this aligns with Avista’s preferred communication protocol and
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 6 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 6 of 12
long-term operational plan. For the purposes of EIM, the IP communications migration will be
limited to MV-90, engineering access, and metering communications, but eventually could
include migration of SCADA as part of a future project if the new IP communications circuits are
deemed reliable. Migration to IP communications for SCADA and metering has been a long-term
focus and evolution for Avista. Avista does collect hourly interchange meter data, but it’s done
at most substations by non-revenue meters with varying capabilities, with various network
protocols, manual processes and supplemented with information from PI (Plant Information) and
SCADA averages. This process and the associated data are not scalable or reliable for accurate 5-
minute interval EIM metering and settlements.

Option Capital Cost Start Complete
CAISO Western Energy Imbalance Market $26.7M 05/2019 06/2022
Do Nothing $0 N/A N/A
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Reference key points from external documentation, list any addendums, attachments etc.

Avista developed its initial EIM implementation estimate with help from Utilicast who has aided
several other Utilities prepare for market operations. Avista hired Utilicast to perform a
technology assessment, a meter and controls assessment, and develop an overall cost
assessment in 2018. Avista recognizes that the EIM project implementation cost estimate is a
working estimate and will evolve as the Company learns more about the specific CAISO EIM
requirements, determines the capability of its existing equipment, completes the preliminary
design of required upgrades and selects its market application vendors.

After the Utilicast assessments were complete, Avista used the information to reexamine the
work load and design requirements for facility upgrades including meters, generation controls,
and communication networks. Avista also develop a project schedule, project structure and
preliminary resource plan. This updated information was used to develop the EIM Program
Initiation Charter in May of 2019 and inform the EIM Business Case narrative. The Program Scope
document approved in October 2020 provided further cost estimate updates base on completing
initial project designs and installations and reevaluating employee resource needs. Avista
recognizes the cost and preparation for EIM entry is significant so it has been diligent in its
structured approach to estimate project costs and keep actual costs under control. The Company
reached out to multiple existing EIM participating entities to acquire best practices based on their
approach and experience. Avista chose to hire Utilicast to leverage its EIM operational and
integration expertise in lieu of attempting an Avista-guided implementation.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 7 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 7 of 12
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

The EIM Program is a multi-year program affecting Generation Production & Substation Support,
Power Supply, Transmission System Operations, Substation, Enterprise Technology, Accounting
and SCADA. The below tables represents the anticipated capital allocation request per year based
on the Program Scope estimates and a summary of what projects or deliverables will be
addressed.

BC Year Capital Request Projects/Deliverables
Total $26,700,000

In preparation for Avista to enter the Western EIM, the discussion of the roles and teams required
for a successful market entry and on-going operations was imperative. As described in the
executive-approved EIM Human Resource Plan of May 2020, 17 incremental full-time employees
were identified for the program implementation and the post-implementation phases. This
document includes justification for each position, an explanation of job functions as they relate
to EIM and associated risks if the position isn’t approved for hire. After reviewing the program
implementation schedule, and accommodating a timeline for resources to participate in the
software implementation phases, a preferred hire date was developed. This preferred hire date,
along with an estimation of time allocated to EIM capital activities and expense activities,
provided input for a 2020-2023 annual financial estimate, with 2023 representing a full-year of
operations and maintenance (O&M) expense activities.

In 2018, Avista originally estimated annual O&M expense at $3.5 - $4.0 million, with $2.5 million
attributed to the original labor estimate of 11-13 incremental EIM FTEs. The revised estimate of
17 EIM FTEs, as described in the EIM Human Resource Plan, increases the annual labor estimate
to $3.2 million (system loaded) and the total estimated annual expense to $3.9M. The need for
the additional 4 FTEs (17 vs. 13), was determined through staffing conversations with other EIM
entities, who indicated lean staffing levels at the time of market entry have hindered operational
performance. Avista believes the 17 FTEs represents a mature workforce needed to fully support
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 8 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 8 of 12
EIM operations at market entry. Any additional EIM roles Avista may need will be assessed after
Avista has gained experience operating in the market.

In August 2020, prior to incorporating the updated EIM Human Resource Plan cost estimates in
the Scope Document estimates, the FTE cost estimates were reviewed in light of the EIM Charter
estimates and reductions were made. Reductions were also made to reflect 2020 hiring delays
and the postponement of two positions – the Training Admin and one of the Settlement Analysts.
These positions are anticipated to be hired approximately six months after market go-live.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
By joining the Western EIM, many existing business processes will be impacted and Avista will
adopt an entirely new set of market processes to incorporate in daily operations. The primary
business groups impacted by operating in the market include Power Supply, Transmission System
Operations and Accounting/Finance. The Power Supply group will be responsible for generating
hourly market bids for generation resources, while System Operations will implement a new 24-
hour desk with EIM operators representing Avista’s Balancing Authority Area (BAA) in the market
and the Accounting/Finance group will analyze data and CAISO settlement information. These
three groups will need to communicate closely with each other and the plant operators through
phone calls and the aid of the EIM software applications. The Accounting/Finance business unit
will acquire a new Settlements team to perform market settlements and analysis of Avista’s
financial position in the market. Throughout substation and generation projects, a planning and
timing shift will need to occur to align Avista’s delivery schedules with CAISO’s scheduled
updates. If Avista does not align with CAISO’s update schedules for physical changes in the BAA,
such as new substations or transmission lines, Avista’s physical system will not be represented in
CAISO’s market design, which could result in negative financial impacts for Avista.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
As stated in Section 1.1, Avista monitored EIM expansion and development activity in the West
and as more northwest utilities joined the CAISO EIM, it was inevitable that Avista would also
need to join an in-hour market to reduce market liquidity risk and costs to integrate renewable
resources. Avista delayed a market entry decision until the financial and operational risks were
present. Once the MWTG initiative was deferred in April 2018, Avista decided to pursue entry to
the Western EIM in December 2018 since it was the only market option available.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer,
spend, and transfers to plant by year.
The EIM Program began in April 2019, and capital project progressively began in May 2019. The
bulk of the capital investments centered on the implementation of the EIM software, the upgrade
of Avista’s metering infrastructure across generation and substation to install revenue quality
meters capable of secure 5-minute reads, and the upgrade of some plant control systems in
generation. While the completion of the generation and substation projects will be progressive
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 9 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 9 of 12
throughout late 2020 and into early 2021, the EIM software applications will not be complete
until market entry in March 2022.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
In April of 2019, Avista announced its own clean energy goals that will transition our resource
mix to 100 percent clean by 2045. Also in 2019, Washington State passed clean energy legislation
that will drive additional renewable resources to be built in Avista’s BAA to meet specific emission
reduction requirements between 2030 and 2045. Any additional renewable resource integrated
in Avista’s service territory results in a reduction of hydro flexibility to follow these variable
resources, and the EIM is the most efficient and cost effective way to provide the required flexible
ramping capability.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Avista conducted a cost to benefit analysis based on the information developed from the E3
benefit study and the EIM Program Initiation Charter. Based on the estimated benefits and costs
from these assessments, Avista anticipates breaking even with its EIM investments in 7-8 years
assuming an annual revenue of $6M from market participation.

Avista performed an additional economic analysis based on the updated costs estimates provided
in the EIM Scope Document. Based on the new integration cost of $32.1 million and on-going
costs of $3.9 million, an annual revenue of $7.8 million is needed to break even after 10 years of
market operations. This is still well within the range of estimated benefits determined by E3 and
quite a bit less than CAISO reported benefits for IPC and PGE in 2018 and 2019. If Avista’s actual
EIM system benefits are closer to or exceed the potential upper bound of $12 million, as
determined by E3 and experienced by other similar situated EIM participating utilities, then
Avista customers will see positive revenue in a much shorter time period. The economic analysis
did not consider other EIM benefits such as reduced flexible ramping requirements, reliability
and system visibility enhancements, and reductions in greenhouse gases.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Avista internal stakeholders include: Power Supply, Transmission System Operations, SCADA,
Generation Production & Substation Support, Substation Engineering, Finance & Accounting,
Distribution System Operations, Risk, Network and Technology. Avista’s primary external
stakeholder is CAISO, however the EIM software vendors – Power Costs, Inc., and Power
Settlements – are also key stakeholders. The below table represents business units that will
perform capital projects under the EIM BC and the associated rate jurisdiction:
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 10 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 10 of 12

2.8.2 Identify any related Business Cases
The Energy Imbalance Market Business Case and the Resource Metering, Telemetry and Controls
Upgrade Business Case were initiated in 2017 to prepare Avista to join an organized energy
market. In 2019, the Resource Metering, Telemetry and Controls Upgrade Business case scope,
and the then allocated $2.21M (2019 and 2020 funds), were consolidated under the Energy
Imbalance Market Business Case, which at that time, and had a placeholder estimate of $9.4M.
With the help of Utilicast, Avista continues to gain a better understand of the current status and
capability of existing equipment and full pre-market integration requirements. This information
has been used to create the current Program estimate.
Market entrance is also dependent on the creation and integration of the Full Network Model
delivered under the SCADA/SOO/BuCC BC (System Operations Office and Backup Control Center).

3.1 Steering Committee or Advisory Group Information
The EIM Business Case has the following levels of program governance; the business unit
Advisory Committees, the Director Steering Committee and Executive Steering Committee.
 Advisory Committees – varies by business unit for technical subject matter expertise

 EIM Director Steering Committee – Scott Kinney, Andy Vickers, Mike Magruder, Jim
Corder, Hossein Nikdel, Pat Ehrbar, Todd Colton, Adam Munson and Clay Storey

 EIM Executive Steering Committee – Jason Thackston, Heather Rosentrater, Jim Kensok,
Ryan Krasselt and Kevin Christie
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 11 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 11 of 12
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Advisory Committees consist of the subject matter experts in the various business units who
can direct the technical work, make engineering decisions and deliver the technical solution that
meets the business need. The Advisory Committee is supplemented with input and knowledge
from Stakeholders amongst neighboring business units. As needed, members of the Director
Program Steering Committee will participate in the Advisory Committee meetings for input and
decisions. The EIM Program manager will be invited to all Advisory Committee meetings and
serve as a consistent conduit from the Advisory Committees to the EIM Program Steering
Committee. Communication of project schedule risks, scope issues and financial impacts will be
provided by the various project managers at the Advisory Committees and, where appropriate,
reported to the EIM Director or Executive Steering Committee. The Advisory Committee does not
have the authority to approve change requests, but must seek approval from the EIM Director
Steering Committee.
Program level authority sits with the EIM Director Steering Committee, and the Executive
Steering Committee. Ultimate approval authority sits with the Executive Steering Committee. The
Executive Steering Committee is responsible for taking recommendations from the Director
Steering Committee and ultimately making Program level decisions for use of contingency
funding. In the unforeseen event that the EIM Program schedule is at risk, the Executive Steering
Committee has the right to review and adjust the EIM go-live date. Members of the Executive
Steering Committee and the Program Sponsors would be responsible for this re-negotiation of
the EIM Implementation Agreement with the CAISO.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The EIM Program has implemented procedures and documentation to provide effective
mechanisms to control the scope of the program, manage issues and risks and monitor progress.
Project level change requests will be discussed at the Advisory Committees, and approvals will
be granted at the EIM Director Steering Committee. Program level management of decisions and
documents will be discussed at the EIM Director and Executive Steering Committees and posted
to the EIM SharePoint site. Enterprise Technology projects, and their associated processes, will
be managed within Clarity. Generation, transmission operations and substation projects will be
managed through their established project management processes and procedures, and final
documentation posted to the EIM SharePoint site. Each project artifact will reference the EIM
program with narrative related to EIM scope, CAISO track, requirements, and the financial
structure with the EIM Parent Project ID of EIM422 and the associated Expenditure Request (ER)
and Budget Item (BI). The request to open EIM projects will be reviewed by the EIM Program
Manager and approved by the Business Case Sponsor.
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 12 of 13
Energy Imbalance Market
Business Case Justification Narrative Page 12 of 12
The undersigned acknowledge they have reviewed the Energy Imbalance Market Business Case
and agree with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Business Case Owner

Business Case Sponsor

Business Case Sponsor

Steering/Advisory Committee Review

Template Version: 05/28/2020
12-17-2020
12-17-20
12-17-2020
Exhibit No. 8 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 12, Page 13 of 13