Nova Scotia Power Incorporated

DECISION

2022 NSUARB 93

M10366

NOVA SCOTIA UTILITY AND REVIEW BOARD

IN THE MATTER OF THE PUBLIC UTILITIES ACT

- and -

IN THE MATTER OF AN APPLICATION by NOVA SCOTIA POWER INCORPORATED

for approval of its Annual Capital Expenditure Plan for 2022

BEFORE:

Roberta J. Clarke, Q.C., Panel Chair

Steven M. Murphy, MBA, P.Eng., Member

Richard J. Melanson, LL.B., Member

APPLICANT:

INTERVENORS:

NOVA SCOTIA POWER INCORPORATED

Blake Williams, Senior Regulatory Counsel

Matthew Gorman, Regulatory Counsel

CONSUMER ADVOCATE

William L. Mahody, Q.C.

Emily Mason, Counsel

SMALL BUSINESS ADVOCATE

E.A. Nelson Blackburn, Q.C.

Melissa P. MacAdam, Counsel

INDUSTRIAL GROUP

Nancy G. Rubin, Q.C.

PORT HAWKESBURY PAPER LP

James A. MacDuff, Counsel

EFFICIENCYONE

James R. Gogan, Counsel

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PROVINCE OF NOVA SCOTIA

Nova Scotia Department of Natural Resources

and Renewables

Peter Craig

David Miller

Kendra Campbell

BOARD COUNSEL:

S. Bruce Outhouse, Q.C.

FINAL SUBMISSIONS: April 27, 2022

DECISION DATE:

DECISION:

June 9, 2022

The Board approves the 2022 ACE Plan and provides

directions to Nova Scotia Power in Paragraph 213 of this

decision.

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TABLE OF CONTENTS

1.0

2.0

3.0

INTRODUCTION.................................................................................................. 4

ISSUE................................................................................................................... 5

ANALYSIS AND FINDINGS ................................................................................. 5

3.1

Content of the 2022 ACE Plan................................................................... 5

3.1.1 Spare Autotransformer.................................................................... 7

3.1.1.1 Findings ............................................................................ 9

3.1.2 VJ1 Generator Replacement Project and Control System Upgrade

Project............................................................................................. 9

3.1.2.1 Findings .......................................................................... 12

3.1.3 Letters of Comment....................................................................... 12

Routine Capital Expenditures .................................................................. 13

3.2.1.1 Findings .......................................................................... 14

Cost Minimization .................................................................................... 14

3.3.1 NS Power’s Capital Project Cost Minimization Effectiveness,

including Capital Cost Budgeting and Project Scoping ................. 15

3.3.1.1 Findings .......................................................................... 22

3.3.2 NS Power’s Capital Project Cost Minimization and Related Project

Management Practices ................................................................. 28

3.3.2.1 Findings .......................................................................... 38

Reliability Investments ............................................................................. 43

3.4.1.1 Findings .......................................................................... 52

Economic Analysis Model........................................................................ 52

3.5.1 Replacement Energy Cost ............................................................ 53

3.5.1.1 Findings .......................................................................... 54

3.5.2 Accounting Treatment of Decommissioning Costs........................ 54

3.5.2.1 Findings .......................................................................... 57

3.5.3 Monte Carlo/Decision Analysis...................................................... 57

3.5.3.1 Findings .......................................................................... 58

Revenue Requirement............................................................................. 58

3.6.1.1 Findings .......................................................................... 60

Contingency and Contingency Guidelines ............................................... 61

3.7.1.1 Findings .......................................................................... 64

Eastern Clean Energy Initiative and Impact of Recent Provincial and

Federal legislation on Proposed Spending .............................................. 65

3.8.1.1 Findings .......................................................................... 67

Alignment with the 2020 IRP.................................................................... 68

3.9.1.1 Findings .......................................................................... 71

3.2

3.3

3.4

3.5

3.6

3.7

3.8

3.9

3.10 Total Cost of Ownership for IT Projects and Electric Vehicles................. 72

3.10.1.1 Findings .......................................................................... 76

3.11 Impact of COVID-19 on Capital Spending and Lessons Learned............ 76

3.11.1.1 Findings .......................................................................... 79

4.0

SUMMARY ......................................................................................................... 80

APPENDIX

Schedule “A” - 2022 ACE Plan Projects Approved by Board

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1.0

INTRODUCTION

Each year Nova Scotia Power Inc. files an Annual Capital Expenditure

[1]

(ACE) Plan outlining its proposed capital expenditures for the upcoming year. As a result

of an amendment to the Public Utilities Act, R.S.N.S.1989, c. 380, for a large-scale public

utility, such as NS Power, capital projects exceeding $1,000,000 must generally be

approved by the Board. Prior to the amendment, the threshold was $250,000.

[2]

NS Power’s 2022 ACE Plan sought approval for capital projects totalling

$181.1 million. This decision is about whether the Board should approve this proposed

capital spending.

[3]

Based on the evidence presented, and after considering the submissions

made by the parties participating in this proceeding, the Board has determined there is

sufficient justification for the need, and the corresponding cost estimates, for the proposed

projects. Therefore, the Board approves the 2022 ACE Plan.

[4]

In addition to considering the specific projects submitted for approval in the

ACE Plan, the Board has taken the opportunity presented by the annual filing to address

more general issues relating to capital spending and the approval process.

[5]

In this decision, the Board has commented on the following:

 Project scoping and management;

 Cost minimization;

 Reliability investments;

 The Economic Analysis Model (EAM);

 Revenue Requirement;

 Contingency and contingency guidelines;

 Eastern Clean Energy Initiative (ECEI) and Impact of Recent Provincial and

Federal Legislation;

 Alignment with the 2020 Integrated Resource Plan (IRP);

 Total cost of ownership for IT projects and electric vehicles; and

 Impact of COVID-19 on capital spending and lessons learned.

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[6]

In addition, the Board directs NS Power to take certain actions as outlined

in Paragraph 213 of this decision.

2.0

ISSUE

The Board must decide whether the ACE Plan program and spending that

[7]

NS Power asked to have approved are prudent, necessary, and justified.

3.0

ANALYSIS AND FINDINGS

[8]

Each year when NS Power files its ACE Plan application, the Board takes

the opportunity to explore issues related to the activities the utility proposes and the way

spending is budgeted and justified. The Board identifies these issues early in the

proceeding and seeks comments from the parties on the issues list before it is finalized.

[9]

The Board considers these issues important, as there have been limited

opportunities to publicly consider them. This is because there has been no general rate

application (GRA) by NS Power since 2013, partly due to Rate Stabilization Periods. The

Board observes, however, that NS Power has filed a GRA, to be heard in September,

2022. Some of the issues canvassed in this decision may be explored further in that GRA

hearing.

[10]

In this decision, the Board will first consider the 2022 ACE Plan application,

and then address the issues which emerged as important through the process.

3.1

Content of the 2022 ACE Plan

[11]

NS Power’s 2022 ACE Plan application provides a comprehensive overview

of its capital expenditure program. It includes the following:

 A description of capital projects for which NS Power is seeking approval;

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 Details regarding routine capital expenditures requiring Board approval;

 A list of capital projects to be submitted for subsequent approval;

 Lists of capital items not requiring Board approval;

 Responses to Board directives from prior ACE Plan proceedings; and

 Responses to stakeholder engagement commitments.

[12]

NS Power forecasts total capital spending of $531.6 million during 2022.

This amount is for individual capital items, including capital items under $1 million and

Point Aconi items which do not require Board approval; routine capital expenditures;

carryover spending from previous years; and items for subsequent submittal. NS Power

stated that these expenditures are “focused on customers and providing safe, reliable,

environmentally compliant, affordable and innovative electrical service.”

[13]

NS Power requested approval for spending of $181.1 million. The

requested amount includes 24 individual capital projects totalling $70.6 million. NS Power

plans to spend $33.3 million on these projects in 2022, and an additional $37.3 million in

2023, and beyond. NS Power also requested Board approval for $110.5 million for routine

capital expenditures in 2022.

[14]

The 24 individual projects NS Power asked the Board to approve include

20 projects, each with a total estimated cost between $1 million and $5 million, and four

projects with cost estimates, each exceeding $5 million. The number of individual projects

is greater than in the 2021 ACE Plan application.

[15]

NS Power provided a detailed description, justification, and cost support for

each of these capital work order applications. NS Power also provided substantial

additional information in its responses to Information Requests (IRs) submitted by

intervenors and the Board.

[16]

The Board notes that during the proceeding, other than the Consumer

Advocate (CA), no intervenor objected to any of the capital projects submitted for Board

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approval in NS Power’s 2022 ACE Plan. The CA’s consultant objected to approval of two

projects related to Victoria Junction Unit 1(VJ1), which are discussed later in this decision.

However, the Small Business Advocate (SBA) and CA submissions examined several

issues in their submissions related to NS Power’s capital spending that are also discussed

in this decision.

[17]

The Board finds that the capital projects listed in Schedule “A” are

necessary. Further, the Board is satisfied that the plan is prudent and that the spending

has been justified in accordance with the Board-approved Capital Expenditure

Justification Criteria (CEJC).

[18]

The Board approves the projects and capital expenditures set out in

Schedule “A”. Should any of them be cancelled, or deferred beyond 2022, NS Power

must resubmit them for Board approval.

3.1.1 Spare Autotransformer

[19]

In the 2021 ACE Plan application, NS Power sought approval of the

purchase of a spare autotransformer to respond to an unplanned failure. John Wilson, of

Resource Insight, the CA’s consultant, said that NS Power had done an insufficient

analysis of the alternatives. Lia MacDonald, NS Power’s Vice-President, Transmission,

Distribution and Delivery, testified at the 2021 hearing that NS Power was developing an

overall plan for the autotransformers in its system. The Board approved the purchase but

directed NS Power to report in the 2022 ACE Plan on the status of the management plan

for the autotransformer fleet.

[20]

In this application, NS Power filed Appendix G in response to the Board’s

2021 directive. The report provides a risk profile of the ten 138kV substation

autotransformers currently in service. The units vary in age, criticality, condition, and

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overall risk. NS Power indicated the year for tentative replacement of each unit, and in

several cases, noted interim mitigation strategies for identified problems.

[21]

In response to CA IR-13, NS Power stated that the earliest planned

replacement of a substation autotransformer would be in 2023. Like any other

replacement, the request for approval must be justified at the time. NS Power said that it

does not intend to run these autotransformers to failure. The company said replacement

decisions will be based on criticality and condition, rather than service life or the

probability of failure.

[22]

Mr. Wilson says that the plan filed as Appendix G provides insufficient

analysis. In his opinion, the probability of failures should be considered under the CEJC

scoring. He expected the plan to explain how future replacement decisions would be

made. Mr. Wilson thinks that NS Power should have a more aggressive plan instead of

relying on a spare autotransformer for an indefinite period. He concluded that NS Power

“seems unwilling” to plan more strategically and recommended that the Board select an

independent consultant to investigate autotransformer replacement strategies in co-

ordination with NS Power’s subject matter experts.

[23]

Both Mr. Wilson’s opening statement and the CA’s closing submissions

suggest that there is nothing newly developed as a plan for management of the

autotransformer fleet.

[24]

NS Power disagreed with Mr. Wilson’s recommendation, noting that the

Board had approved the 2021 spare autotransformer project. NS Power said that the

information in Appendix G shows the company is prudent in its asset management of

these units. Directing an independent consultant to investigate is both unnecessary and

would provide no value to ratepayers, according to NS Power. The company said the

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details are a “snapshot” of its autotransformer management plan. NS Power submitted

that it is constantly assessing and updating the plan and is not currently requesting

approval of any replacement project from the Board. Each project will be justified when

approval is sought. The company urged the Board not to accept Mr. Wilson’s

recommendation.

3.1.1.1

Findings

[25]

The Board need not, and will not, revisit its decision about the spare

autotransformer from the 2021 ACE Plan. While the Board considers that Appendix G

does not set out an explicit plan for the autotransformer fleet, the Board is satisfied that

NS Power is aware of the risk level of each unit now. The company has mitigation

strategies in place. The Board expects NS Power to continually monitor and assess the

status of the transformers. When NS Power determines there is need for a replacement,

the Board expects a fully justified application will be filed. Such applications will receive

the same rigour the Board brings to all capital expenditure requests by the company. The

Board does not consider it necessary to engage an independent consultant as suggested

by the CA.

3.1.2 VJ1 Generator Replacement Project and Control System

Upgrade Project

[26]

Only two projects in the 2022 ACE Plan were singled out by an Intervenor:

C0029693 and C0029691, a generator replacement and control system upgrade,

respectively, for the combustion turbine (CT) at VJ1. In the application, NS Power said

that the generator assembly currently at VJ1 was commissioned in 1976; the replacement

will extend the life of the unit and the equipment will be consistent with what has been

installed at other CT units. The company said the replacement is the “only technical

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feasible alternative.” NS Power claims that refurbishment will not mitigate the risk of a

forced outage or collateral damage to the rest of the unit. The company described CT

units as critical to meet firm capacity requirements. NS Power said the investment in this

unit is consistent with the 2020 Integrated Resource Plan (IRP).

[27]

As for the control system upgrade, NS Power said that portions of the

existing control system are now obsolete. Finding replacement parts, troubleshooting,

and diagnosing problems has become difficult. Without replacement of the system, this

will only continue. The company plans to replace the system during the regularly

scheduled outage. The replacement will improve service life and reduce future costs due

to the modular design.

[28]

Mr. Wilson questioned the estimated costs, including the contingency

amounts for both projects. The cost estimate classifications are Class 3, and the

contingency range is +10% to +30% for both projects according to the response to SBA

IR-26.

[29]

Mr. Wilson expressed concern about what he considered an excessive

contingency for the projects. He also considered the procurement process had not

resulted in cost minimization. Mr. Wilson’s concerns were:

 A lack of evidence of competitive bidding for both projects;

 Higher budgets than two other generator replacement projects; and

 An unreasonable 20% contingency for both projects.

[30]

NS Power confirmed in response to NSUARB IR-63 that the generator

replacement is needed to continue safe reliable operation of the unit until 2045. The

company expects continued operation of the CT fleet until at least that time for the

required fast acting generation due to intermittent renewable generation. NS Power

estimated the sustaining capital investments for the entire VJ1 unit from 2023 -2045

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exceed $7 million in 2022 dollars. In response to SBA IR-6, NS Power said that sustaining

the existing diesel CTs “is the lowest cost option to meet system capacity requirements

when evaluated against alternative resource options.”

[31]

Mr. Wilson recommended that the Board withhold approval for both projects

and, instead, require NS Power to resubmit the applications after addressing his concerns

and seeking to further minimize costs.

[32]

In its rebuttal evidence, NS Power explained that the generator project was

sole-sourced from the original equipment manufacturer (OEM) to eliminate the need for

significant modifications and retrofitting. The company said that the increased budget is

due to additional scoping learned from the other two projects, site preparation, travel, and

cost escalation since 2017 when those projects were undertaken. Part of the reason for

the contingency related to restrictions resulting from the COVID-19 pandemic. In addition,

the two units Mr. Wilson referred to were steam generators, not CT generators; NS Power

refurbishes steam generators more often and therefore, its experience suggests a lower

contingency amount for those projects.

[33]

Mr. Wilson remained concerned and questioned whether NS Power favours

OEMs in its procurements, and whether the company can provide clear justification for its

contingency amounts. As a result, the CA submitted that the Board should accept Mr.

Wilson’s recommendation on the two VJ1 projects.

[34]

NS Power maintained that it does not favour, nor always commits to, OEMs

but determines what is the best value for its customers, considering “the future life-cycle

costs” of the asset. As for the 20% contingency, NS Power said it had fully justified the

level, in accordance with its Non-Binding Contingency Guidelines, based on the COVID-

19 protocols (which had not been in effect for the two earlier generator replacements),

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potential “unknowns” when old systems are removed, the difference between steam

generator refurbishments and CTs, and its internal expert judgement. The company

urged the Board to reject Mr. Wilson’s recommendation.

3.1.2.1

Findings

[35]

The Board is satisfied that NS Power has justified both VJ1 projects in

question. The Board accepts the reasons for the 20% contingency. Further, the Board

considers the explanation for the selection of the OEM for the replacement generator to

be reasonable. As a result, the Board considers the projects prudent, and approves them,

along with the other projects listed in Schedule “A.”

3.1.3 Letters of Comment

[36]

The Board received two letters of comment from Kevin Mullen who, the

Board understands, is the CEO of a company involved in renewable energy development.

Mr. Mullen offered comments on several topics referred to in NS Power’s application,

including:

 Wind projects and the role of NS Power compared to independent power

producers;

 Conversion of coal plants to natural gas;

 Investment in New Brunswick transmission;

 Overspending on Tusket Falls and other small hydro dams;

 Project costs for the Mersey River system; and

 Use of grid scale battery storage.

[37]

The CA questioned NS Power about the indication in Mr. Mullen’s first letter

that there are 17 small hydro dams which NS Power had identified, as of 2018, being in

need of refurbishment or decommissioning. Mr. Mullen’s letter stated his company had

contacted NS Power and offered to take ownership of some of these dams, including

Tusket Falls. In an exchange with Jamie MacDonald, Vice President, Power Production,

Mr. Mahody suggested that, given the extent of potential hydro investment, such offers

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should be considered. While Mr. MacDonald said the company is always interested in

looking at offers, NS Power must comply with its continuing regulatory requirements and

guidelines. Mr. MacDonald acknowledged that these requirements and guidelines would

apply to any owner of these dams.

[38]

In response to questions from Nancy Rubin, Counsel for the Industrial

Group, NS Power filed Undertaking U-6. Ms. MacDonald confirmed that NS Power had

a discussion with Mr. Mullen’s company in 2020 and had determined that its proposal was

not viable. The Board notes that, should NS Power contemplate the sale or transfer of

its undertaking, s. 62 of the Public Utilities Act requires approval before any sale or

transfer can occur.

[39]

The Board briefly explored the other topics in Mr. Mullen’s letters with the

panel. Ms. MacDonald said she had read the letters and looked at some of the reports

cited. In her view, many of his comments relate to ECEI matters, and identify “…the very

type of questions that’ll be answered with the submissions.” While Ms. MacDonald said

there was nothing in his comments that is new to the company, she hoped that Mr. Mullen

would engage in the process when the ECEI applications are submitted.

[40]

The Board appreciates that Mr. Mullen took the time to provide comments

and information to the Board, and encourages him to engage further with NS Power, and

participate, should he wish, when the ECEI applications come before the Board.

3.2

Routine Capital Expenditures

[41]

Routine capital expenditures are recurring annual expenses incurred to

sustain NS Power’s equipment, and to allow for both system growth and addition of

customers to the system. NS Power requested approval for its Routine capital program

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in the amount of $110,533,578, exclusive of Point Aconi Routine spending of $764,158,

which does not require Board approval.

[42]

The proposed Routines budget in 2022 is approximately 17% higher than

the 2021 ACE Plan budget; however, the Board notes that it is lower than actual spending

in 2021. The increased spending in 2021 was primarily due to above-average

distribution-related work.

3.2.1.1

Findings

[43]

The Board approves NS Power’s 2022 Routine capital expenditures in the

amount of $110,533,578. The Board notes that Distribution Routine D007, in the amount

of $4,387,955, is approved at that figure on the understanding that where poles being

replaced are less than 30 years old, Bell Aliant is responsible to cover the Sacrificial Life

of the poles, as that term is defined in a joint use agreement between the parties. Any

such amount paid by, or recovered from, Bell Aliant should not be included in NS Power’s

rate base.

3.3

Cost Minimization

[44]

The issue of NS Power’s capital cost minimization efforts became an area

of focus for the Board and stakeholders during the 2019 ACE Plan proceeding. As noted

in the Board’s 2021 ACE Plan decision, the Board now considers it useful to address cost

minimization through two separate themes. These include the effectiveness of NS

Power’s cost minimization practices, including capital cost budgeting and project scoping;

and NS Power’s capital project cost minimization and related project management

practices themselves.

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3.3.1 NS Power’s Capital Project Cost Minimization Effectiveness,

including Capital Cost Budgeting and Project Scoping

[45]

The Board’s 2021 ACE Plan Order directed NS Power as follows:

3. Continue to track the information noted in Paragraph 92 of the Board's 2020 ACE Plan

decision for each completed capital project that was submitted for Board approval in

2017, 2018, 2019, 2020 and 2021 (either through or outside of the ACE Plan

proceedings, including projects submitted for subsequent approval, but excluding U&U

projects). Further the Board directs that the following additional information be included

in the related 2022 ACE Plan reporting:



NS Power is to identify all new projects that have been added to the report; and

For any capital projects that have a negative variance greater than or equal to 25%

of the Board approved capital cost estimate, NS Power shall provide an

explanation detailing the reasons for the variance.

The Board directs NS Power to continue to track this information, including information

related to projects approved by the Board after 2021, and report it in subsequent ACE

Plan applications. The Board finds the format of Appendix E of the 2021 ACE Plan

application a useful means of presenting this data. The Board, therefore, directs that

the data continue to be presented in this format in subsequent ACE Plan applications

(subject to the modifications noted in the preceding paragraph). This reporting shall

also categorize projects by function (i.e., generation, transmission, distribution, and

general plant), with "generation" projects further categorized by type of project (i.e.,

hydro, steam, gas, other renewables).

[46]

NS Power provided this information in Appendix E. Appendix E presents

an analysis comparing Board approved project budget amounts to final spending on the

completed projects. In particular, Appendix E provides the Board with information to

better assess NS Power’s capital cost minimization and capital cost budgeting

effectiveness, as well as its use of contingencies.

[47]

The Board has summarized the information in response to NSUARB IR-76,

and included, where relevant, comparative figures from the 2021 and 2020 ACE Plan

proceedings in brackets:

 There are 211 projects included in Appendix E (154 projects were

included in Appendix E of the 2021 ACE Plan Application).

 The average variance for the listed projects amounts to

approximately +9.5% (2021: +10.8%; 2020: +10.47%) of the original

submission approved project cost estimate.

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 The total variance of $20,137,705 for the listed projects is over and

above the total contingency amount of $11,791,484 included in the

total of the original submission approved cost estimates.

 The average contingency amount for the listed projects amounts to

approximately 5.9% (2021: 5.6%; 2020: 5.03%) of the original

submission approved cost estimate less the contingency amount.

 For projects approved by the Board prior to November 8, 2019 that

have an original submission approved cost estimate greater than

$250,000 but less than $5,000,000, amounting to 190 projects in

total:

a. 31% (2021: 28%; 2020: 31%) had a negative variance;

b. 69% (2021: 72%; 2020: 69%) had a positive variance; and

c. Of the projects that had a positive variance, 92% (2021: 92%;

2020: 91%), or 121 projects, did not require an ATO

submission to the Board.

 There was one project approved by the Board after November 8,

2019 that had an original submission approved cost estimate greater

than $1,000,000 but less than $5,000,000. This project had a

positive variance but did not require an ATO submission to the

Board.

 For projects that have an original submission approved cost estimate

greater than $5,000,000, amounting to 5 projects in total:

a. 0% (2021: 0%; 2020: 33%) had a negative variance;

b. 100% (2021: 100%; 2020: 67%) had a positive

variance; and

c. Of the projects that had a positive variance, none

required an ATO submission to the Board.

 For all projects that have an original submission approved cost

estimate less than $250,000, amounting to 15 projects in total, the

total sum of the individual project variances as a percentage of the

total sum of the individual project original submission approved cost

estimates is 206% (2021: 206%; 2020: 210%). Updated for their

subsequently approved greater than $250,000 submissions, the total

sum of the individual project variances as a percentage of the total

sum of the individual project original submission approved cost

estimates is 10% (2021: 10%: 2020: 9%).

 72% of the projects listed in Appendix E have a variance to the

original approved estimate that falls within the expected accuracy

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range of -20% to +30% for an AACE (Association for Advancement

of Cost Engineering) Class 3 cost estimate.

 18% of the projects listed in Appendix E have a variance to the

original approved estimate greater than +30%.

[48]

A further review by the Board of the data in Appendix E reveals the following

(the Board has provided the comparative percentages from the 2021 and 2020 ACE Plan

proceedings in brackets):

 For projects that have a negative variance, the total variance amount

is approximately $6.78 million or 3.2% (2021: 2.7%; 2020: 3.1%) of

the total of the original approved cost estimates.

 For projects that have a positive variance, the total variance amount

is approximately $26.92 million or 12.7% (2021: 13.5%; 2020:

13.6%) of the total of the original approved cost estimates.

[49]

In the 2021 ACE Plan Order, NS Power was directed to provide detailed

reasons for any negative project spending variances greater than or equal to 25% of the

Board approved capital cost estimate. NS Power neglected to include this information in

its 2022 ACE Plan Application. However, the company did provide the requested

information in response to NSUARB IR-76(l). Sixteen of the projects in Appendix E have

negative variances greater than 25%.

[50]

Mr. Wilson completed his own analysis of the data contained in Appendix

E. His analysis produced similar results to those listed above, and he stated the following

in his evidence:

In comparison to my review of the contingency data provided by NS Power in the 2021

ACE Plan Proceeding, the new data continue to show that NS Power appears, on average,

to underestimate project costs, inclusive of estimated contingency amounts. While the

2021 data showed a slight increase in this tendency, the 2022 data show a slight decrease

in this tendency. It appears that for projects placed in service through late 2019, there has

been no material improvement in the accuracy of project cost estimates.

[Exhibit N-10, p. 13]

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[51]

Mr. Wilson’s analysis of Appendix E also led him to conclude that most of

NS Power’s high overspend costs occur on steam generation plant projects. Based on

his analysis of evidence submitted in Board Matter M10197 (Tusket Main Dam

Refurbishment ATO), he also asserted that for most hydro capital projects, NS Power’s

project cost estimates are reasonably reflective of actual spending. However, he noted

that a group of high-overspend hydro capital projects indicates a significant cost

estimation problem. With regards to transmission and distribution (T&D) capital projects,

Mr. Wilson stated:

In comparison with the pattern I note above with respect to steam generation projects and

below with respect to civil hydroelectric projects, it appears that NS Power has a good track

record with cost estimates in the renewable, transmission and distribution project areas,

with high-overspend projects occurring at a lower frequency than steam generation

projects and with less dramatic financial consequences than the high-overspend civil

hydroelectric projects.

[Exhibit N-10, p. 14]

[52]

Mr. Wilson’s opinion regarding NS Power’s track record on T&D capital

project cost estimating was probed further during the hearing. The Board questioned NS

Power on the data the company provided in response to CA IR-17 and IR-18. That is the

data upon which Mr. Wilson based his T&D analysis. In response to Board questioning,

NS Power clarified some of the data provided in response to CA IR-17 and IR-18 and

provided Undertakings U-22 and U-23 to provide further clarification post-hearing. The

Board asked Mr. Wilson if the clarifications provided by NS Power would change his

conclusion. Through Undertaking U-25, Mr. Wilson re-performed his analysis based on

the clarifications provided by NS Power, and stated:

Based on this clarified analysis, I continue to conclude that NS Power has a good track

record of cost estimates for new transmission facilities or investment in the replacement of

existing transmission facilities at a substantially upgraded level of service.

…

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Based on this clarified analysis, I continue to conclude that NS Power has a good track

record of cost estimates for new distribution facilities or investment in the replacement of

existing distribution facilities at a substantially upgraded level of service.

[Exhibit N-18, p. 5, and p. 8]

[53]

As noted in response to NSUARB IR-76(k), 72% of the capital projects in

Appendix E have final spending amounts that are within the AACE Class 3 capital cost

estimate expected range of accuracy of -20% to +30% of their respective original

approved estimates (inclusive of contingency allowances). Further, 18% of the Appendix

E projects have final spending that exceeds +30% of their respective original approved

capital cost estimates. As noted during the 2021 ACE Plan proceeding, AACE Class 3

capital cost estimating expectations generally suggest that no more than 10% of capital

projects should have final spending exceeding the +30% upper accuracy limit; no more

than 10% of capital projects should have final spending less than the -20% lower accuracy

limit; and at least 80% of capital projects should incur final spending falling within these

accuracy limits. In response to CA IR-10(e), NS Power noted that while 18% of Appendix

E projects exceed the AACE upper accuracy expectation, the company has experienced

a declining trend between 2016 and 2020 in projects that are over-spent by more than

30%. NS Power also suggested a positive trend in the percentage of projects falling

within the -20% to +30% range expected for projects with Class 3 estimates. These

perceived trends were presented in the following table:

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Total # of

projects

placed in

service

Percentage of

Projects over-

spent by greater

than 30%

Percentage of

projects under-

spent by

greater than

20%

Percentage of

projects with total

spending

between

-20% and +30%

of budget

Year

2016

4

59

82

56

10

211

0.0%

11.9%

9.8%

25.0%

59.3%

72.0%

87.5%

80.0%

72.0%

75.0%

28.8%

18.3%

5.4%

2017

2018

2019

7.1%

2020

20.0%

10.0%

0.0%

All years

18.0%

[Exhibit N-4, IR-10(e)]

[54]

In its rebuttal evidence, NS Power stated that the information provided in

the 2022 ACE Plan Application and in response to IRs indicates that NS Power’s capital

project spending variances generally are within AACE guidelines. This claim was

explored further during the hearing:

Q. (Murphy) … On page 22 of your reply evidence -- it states, "Generally with

respect to Nova Scotia Power spending" I'm sorry.

Generally, with respect to Nova Scotia Power's project spending, the data

produced by Nova Scotia Power, either in the 2022 ACE Plan or in

responses to its IRs, indicates that Nova Scotia Power project variances

are within AAEC (sic) Guidelines as described in the above: (i) the project

data within Appendix “E” shows that NS Power is executing projects within

AACE guidelines;...

However, in response to CA's IR-10(e), Nova Scotia Power stated that 18 percent of the

projects listed in Appendix E of the ACE Plan Application have overspent their budgets by

more than 30 percent. So I guess my question is, really, can you reconcile those two

statements, the one from the reply evidence and the one from the response to the CA's

IR?

A. (Dandurand) Yes, I believe that I can, Mr. Murphy, and I think the starting point

for that would be the data that's included within Appendix E. And so when looking at that

data within the appendix, looking at the total cost for all of the 211 projects listed within the

appendix, relative to their approved budget amounts, the ratio of those projects that are

overspent more than 30 percent, which falls in line with the expectation for a Class 3

estimate, will be somewhere closer to about 12 percent.

…

Q. I'm not sure I follow. Did you say that based on the Appendix E data 12 percent

of the projects fall above that 30 percent threshold? But how does that reconcile -- I'm not

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sure how that reconciles with the response to the CA's IR where it says 18 percent of the

projects were above that threshold.

A. (Dandurand) I think the reason for that difference, Mr. Murphy, is that the

comparison between the final cost or, you know, the total cost for a project relative to what

it was in the ACE Plan for will differ from the final cost of the project compared to its

approved budget amount.

So I think that that's why those two numbers don't reconcile, is that one is

comparing to what the project was approved for versus what the project was entered into

the ACE Plan for.

And the reason why that is important, in terms of that distinction, is that there may

be a project that is in the ACE Plan for a particular amount but was later submitted to the

Board for the Board's approval and then the measuring -- or the baseline for measuring,

rather, then becomes what the project was approved for, not what the project was in the

ACE Plan for.

…

A. (Dandurand) Yeah. So I'm speaking to all -- all of our projects within Appendix

E, Mr. Murphy, and so there are notes within Appendix E specific to projects that may have

been in the ACE Plan for a specific amount, was then advanced for approval, for the

Board's approval, and approved at a specific amount that may differ from what it was in the

ACE Plan for, and then that's the comparison that I was making when I was speaking to

the alignment to AECE [sic] Guidelines, and that explains the difference between the two

figures that you mentioned earlier.

Q. So you're talking about projects, perhaps, that were in the ACE Plan below 250

or below a million and then ultimately crossed those thresholds and needed -- you know,

at one point, below 250 you didn't need approval and below a million you don't need

approval, but at some point perhaps those projects progressed beyond a million, beyond

250, and ultimately needed Board approval, so when you're talking about the 12 percent

number, you're talking about the -- it's called the latest approved budget number.

A. (Dandurand) We're talking about the first approved budget number in those

cases ---

…

A. (Dandurand) --- for a project that was advanced for the Board's approval.

[Transcript, pp. 317-322]

[55]

In effect, this exchange confirmed that the 18% of Appendix E projects

exceeding the AACE +30% upper accuracy limit, as referenced in response to CA IR-

10(e) and NSUARB IR-76, is based on a comparison of final project spending to original

budgets as presented in prior ACE Plans. However, when final project spending is

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compared to the original Board approved project budgets, 12% of Appendix E projects

exceed the AACE upper accuracy limit.

3.3.1.1

Findings

[56]

In its reply to closing submissions, NS Power stated that none of its

evidence pertaining to project budgeting and spending, as outlined in Section 4 of its

rebuttal evidence, was refuted in either the Wilson opening statement, nor the CA or SBA

closing submissions. In addition, the company asserted the evidence shows that its

project variances are within AACE guidelines. The CA, on the other hand, argued that

NS Power has a long history of project cost control issues.

[57]

While the Board does not fully agree with the position put forward by the

CA, the Board believes that the effectiveness of NS Power’s capital project cost

minimization practices, including capital cost budgeting and project scoping, remains in

question. This is the same view that the Board expressed in its 2021 ACE Plan decision.

[58]

As NS Power noted during the 2021 ACE Plan proceeding, the bulk of its

capital project cost estimates in its ACE Plans are at a Class 3 level, in accordance with

AACE International Recommended Practice. NS Power noted that AACE states that

typical accuracy ranges for Class 3 estimates are -20% to +30%, inclusive of contingency

allowances. Further, AACE cost estimating methodology implies that 80% the projects

listed in Appendix E should typically have a final cost that falls within this expected

accuracy range. AACE also suggests that generally 10% of the projects should have final

costs that fall below the -20% accuracy limits, and 10% should fall above the +30% limit.

[59]

Referring to the project data contained in Appendix E of the application, the

Board reviewed the data to compare original Board approved project budget amounts to

final spending on the related projects. The review took into account the “subsequently

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approved” budgets for those projects listed in Appendix E that were originally estimated

by NS Power to be below the Board capital approval threshold of $250,000 pre-November

8, 2019 and $1 million post-November 8, 2019. Based on this review, it appears that NS

Power’s total spend on the projects listed in Appendix E is, on average, 6.8% greater than

the Board approved budget amounts. This is a nominal improvement over the 7% figure

presented by NS Power during the 2021 ACE Plan proceeding. Further, while NS

Power’s average capital overspend of 6.8% on the Appendix E projects is within AACE

accuracy expectations, it still remains above the midpoint of the -20% to +30% range.

[60]

In addition, during the hearing, NS Power confirmed that approximately 12%

of the Appendix E projects incurred final spending that exceeded the Board’s original

approved budget by more than the maximum expected AACE accuracy limit of +30%.

The Board notes that this represents an improvement over the 14% figure presented by

NS Power during the 2021 ACE Plan proceeding. However, 12% of Appendix E projects

incurring overspending beyond the AACE +30% upper accuracy limit for Class 3

estimates still exceeds the 10% expectation prescribed by AACE.

[61]

In Undertaking U-25, Mr. Wilson re-performed his analysis of NS Power’s

capital cost performance on T&D projects. Based on the revised T&D project cost data

in Undertaking U-22 and U-23, Mr. Wilson again concluded that NS Power has a good

track record of completing accurate capital cost estimates for T&D capital projects.

However, the Board has reviewed Undertaking U-25 in more detail and has found

apparent discrepancies in the underlying data. In particular, the Board notes the

following:

 In Table 1, the variances for the GRA transmission projects appear to be

calculated by subtracting the “actual spend” from the “approved budget”

rather than vice versa. As a result of what appears to be a summation error,

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the total variance of $4,215,692 for the transmission projects appears to be

correct in Table 1.

 In Table 1, the average cost variance for the listed transmission projects as

a percent of the total approved budget for the projects should be +2.4% (i.e.,

$4,215,690 divided by $173,730,611) rather than +2.0% noted in Table 1.

 Table 1 has not adjusted the “actual spend” value for “CI C0031089 –

2021/2022 Trans ROW Widening” to reflect the fact that NS Power has

projected additional spending on this project. Based on data provided in

the 2022 ACE Plan proceeding, final spending on this project is expected

to be $5,284,787, resulting in a project variance of -$3,733 rather than -

$2,803,258 noted in Table 1. With this adjustment, the total cost variance

for the listed transmission projects is $7,015,215. This represents an

average variance of +4.0% of the total approved budget for the transmission

projects.

 In Table 2, the average cost variance for the listed distributions projects as

a percent of the total approved budget for the projects should be +2.7% (i.e.,

$5,217,864 divided by $191,032,031) rather than 0% noted in Table 2.

 Table 2 has not adjusted the “actual spend” value for “CI C0031083 – New

Distribution ROW Phase 6” to reflect the fact that NS Power has projected

additional spending on this project. Based on data provided in the 2022

ACE Plan proceeding, final spending on this project is expected to be

$11,533,408, resulting in a project variance of +$1,770,673 rather than -

$3,880,343 noted in Table 2. With this adjustment, the total cost variance

for the listed distribution projects is $10,868,880. This represents an

average variance of +5.7% of the total approved budget for the distribution

projects.

 Further, Table 2 has not adjusted the “actual spend” value for “CI 47124 –

Advanced Meter Infrastructure” to reflect the fact that NS Power has

projected additional spending on this project. Based on data provided in

the 2022 ACE Plan proceeding, final spending on this project is expected

to be $143,414,479, resulting in a project variance of +$10,185,527 rather

than +$7,104,567 noted in Table 2. With this adjustment, coupled with the

adjustment noted in the previous bullet, the total cost variance for the listed

distribution projects is $13,949,840. This represents an average variance

of +7.3% of the total approved budget for the distribution projects.

[62]

With these adjustments, the average cost variances for transmission and

distribution projects in Undertaking U-25 remain within AACE accuracy expectations for

Class 3 capital cost estimates. However, NS Power’s capital cost performance on T&D

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projects is not as good as Mr. Wilson suggested. In fact, the Board finds that the average

T&D cost variances are more aligned with NS Power’s overall capital project average

overspend of 6.8%. Distribution capital cost performance is perhaps more concerning,

with average overspending above the midpoint of the -20% to +30% AACE expected

accuracy range.

[63]

Based on the above, and considering the responses to NSUARB IR-76, the

Board finds that NS Power has marginally improved its capital cost overspending

performance compared to its performance noted in the 2021 ACE Plan proceeding. The

Board notes NS Power’s improvement. However, it is clear to the Board that, on average,

NS Power continues to overspend on capital projects. As such, the Board finds, as it did

in its 2021 ACE Plan decision, that NS Power’s capital cost minimization and/or

budgeting/scoping performance as it relates to AACE expectations remains less than

ideal. It also remains unclear to the Board whether this issue is related to inadequate NS

Power capital cost estimating/budgeting practices, inadequate costs minimization efforts

by NS Power, or a combination of both.

[64]

In the 2021 ACE Plan Order, NS Power was directed to include

explanations within Appendix E detailing the reasons for any negative project spending

variances greater than or equal to 25% of the Board approved capital cost estimate. In

its 2021 ACE Plan decision, the Board expressed concern that underspending of this

magnitude could suggest project over-scoping at the original cost estimate stage, or a

significant reduction or cancellation of the originally planned work scope. Just as large

positive variances can skew overall capital project spending results upward, the Board is

concerned that large negative variances can skew overall spending results downward.

Document: 295729

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[65]

NS Power provided the requested large negative variance information in

response to NSUARB IR-76(l). Sixteen of the projects in Appendix E have negative

variances greater than 25%. The total of the variances for these projects is -$3,082,511.

For the most part, the variances are a result of costs being lower than estimated,

reductions in the originally estimated work scope, and not requiring the use of contingency

funds. The total dollar amount of these variances only represents approximately 1.4% of

the total of the original Board approved budgets for the Appendix E projects. However,

these variances represent roughly 21% of the total variance from the original Board

approved budgets for all the Appendix E projects. If these variances and related approved

budgets are removed from the overall variance calculations, NS Power’s total spend on

the remaining projects listed in Appendix E would be, on average, 8.6% greater than the

approved Board budget amounts (compared to 6.8% when the large negative variances

are included). The Board does not consider this difference significant at this point.

However, the Board will continue to monitor large negative project variances in future

ACE plan proceedings to ensure that variances related to significant project scope

reduction do not skew NS Power’s capital cost performance reporting.

[66]

In response to CA IR-10(e), NS Power provided a table (at Paragraph 53

above) that the company claims shows a declining trend between 2016 and 2020 in

Appendix E projects that are over-spent by more than 30%. NS Power also suggested

that the table shows a positive trend in the percentage of projects falling within the -20%

to +30% range expected for projects with Class 3 estimates. The Board finds the table

useful. However, as presented, the table is organized by the year the Appendix E projects

were placed into service. The Board notes that the year a project is placed in service

may be long after the original project’s cost estimate is submitted for Board approval.

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Therefore, to better discern trends over time in NS Power’s capital cost estimating and

spending performance, the Board finds it would be more informative if the table were

organized by the year projects were put forward for original Board approval (as the second

column in the table). As such, the Board directs NS Power to incorporate the table

accordingly in future ACE Plan applications.

[67]

The Board directs NS Power to continue to track the information noted in

Paragraph 92 of the Board’s 2020 ACE Plan decision for each completed capital project

that was submitted for Board approval in 2017, 2018, 2019, 2020, 2021 and 2022 (either

through or outside of the ACE Plan proceedings, including projects submitted for

subsequent approval, but excluding U&U projects). Further the Board directs that the

following additional information be included in the related 2023 ACE Plan reporting:

 NS Power is to identify all new projects that have been added to the

report; and

 For any capital projects that have a negative variance greater than

or equal to 25% of the Board approved capital cost estimate, NS

Power is to provide an explanation detailing the reasons for the

variance.

[68]

The Board directs NS Power to continue to track this information, including

information related to projects approved by the Board after 2022, and report it in future

ACE Plan applications. The Board directs that the data continue to be presented in the

2022 ACE Plan application Appendix E format in future ACE Plan applications (subject to

the modifications noted in the preceding paragraph). This reporting is to also categorize

projects by function (i.e., generation, transmission, distribution, and general plant), with

“generation” projects further categorized by type of project (i.e., hydro, steam, gas, other

renewables).

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3.3.2 NS Power’s Capital Project Cost Minimization and Related

Project Management Practices

[69]

In its 2019 ACE Plan Order, the Board directed NS Power to provide, in

future ACE Plan applications, “specific examples of project execution cost minimization

efforts for the prior year, complete with a description of the cost savings accrued by these

efforts.” In its 2020 ACE Plan decision, the Board found that the cost minimization

examples provided by NS Power in its 2020 ACE Plan application were not responsive to

this direction. As a result, the Board’s 2020 ACE Plan Order extended its 2019 direction

to provide, in future ACE Plan applications, “examples of cost minimization during

execution and construction from the prior year’s projects, with specific cost minimization

being fully described.”

[70]

In its 2021 ACE Plan Order, the Board directed NS Power to continue

providing, in future ACE Plan applications, specific examples of cost minimization

practices used during execution and construction of the prior year's projects, with specific

cost minimization efforts being fully described. In particular, the Board directed NS Power

to present this information in the format used in Section 11.1.5 of the 2021 ACE Plan

application. This material was to be supplemented with additional specific project details

in the format used in Attachment 1 of NS Power's response to CA IR-1 in the 2021 ACE

Plan proceeding. NS Power complied with this directive in its 2022 ACE Plan application

by providing Appendix F in its application.

[71]

The Board’s 2021 ACE Plan Order further directed NS Power to undertake

stakeholder engagement to address the following issues as they relate to the company’s

cost minimization efforts:

 A better understanding of NS Power's cost minimization and project

management practices;

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 Development of criteria for the selection of projects to be included as

specific examples of NS Power's cost minimization efforts;

 The capital cost threshold for which NS Power will conduct internal post

project reviews;

 A framework and reporting protocols for a capital cost "lessons learned"

business practice; and

 Whether the Board's Contingency Directive should be expanded to require

data on all projects with budgets or spending over $250,000, and whether

the scope of the data request should be wider.

[72]

NS Power submitted its 2021 ACE Plan Stakeholder Engagement Report

to the Board on October 1, 2021.

[73]

In response to these directives, and as it did in its 2020 and 2021 ACE Plan

applications, NS Power stated in its application that “Cost minimization is at the forefront

of all stages of capital project development and execution.” The company went on to

reiterate that it follows cost minimization processes intended to “obtain best value for

customers at the lowest cost.” NS Power then described some of the general cost

minimization processes that it typically employs throughout the course of capital project

execution. These processes are essentially the same as those outlined by the company

in the 2019, 2020 and 2021 ACE Plan proceedings.

[74]

Section 11.1.5 of NS Power’s 2022 ACE Plan application then described

several capital cost minimization efforts undertaken by the company over the past year.

As in the 2021 ACE Plan application, these efforts were categorized as follows: design

and detailed engineering; project execution efficiencies; and procurement

process/negotiated savings. The total project cost savings NS Power assigned to these

efforts was $13.4 million, as presented in Figure 71 of the application. For each of these

categories, Appendix F of NS Power’s application described specific project cost

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minimization examples (49 in total) that were completed to help achieve these project

cost savings.

[75]

In response to NSUARB IR-77(e), NS Power stated that the $13.4 million in

cost savings noted in Appendix F represent approximately 11% of the approved costs of

the related projects. During the hearing, Paul Dandurand, Senior Manager of Asset

Management Operations and Capital Planning, confirmed that the noted savings of $13.4

million relate only to the examples in Appendix F. He further stated that the examples of

cost minimization and related savings in Appendix F are not inclusive of all the cost

minimization efforts by NS Power over the course of 2021.

[76]

The Appendix F cost minimization efforts were assessed further in Mr.

Wilson’s evidence. Mr. Wilson noted that the reported cost savings of $13.4 million in

Appendix F primarily results from NS Power’s procurement process and negotiated

savings. He further stated that while NS Power views its procurement process as the

main opportunity to achieve cost minimization, Appendix F does not provide much further

explanation. Specifically, he identified that most of the Appendix F procurement process

savings are explained as “Procurement process resulted in lower pricing,” or words to

that effect. In most of these cases, Mr. Wilson noted that the cost savings appear to

simply be the difference between the winning bid and another bid or the original budget.

He therefore recommended that NS Power:

Provide cost minimization information that is more useful for identifying lessons learned in

the 2023 ACE Plan. The Board should then identify as an issue in the 2023 ACE Plan

proceeding the determination of what cost minimization information would be useful (and

worth the effort) to compile and file, or whether it may be more efficient to consolidate the

cost minimization report with information summarized from the post-project reviews into a

single requirement.

[Exhibit N-10, p. 6]

Document: 295729

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[77]

The Appendix F examples of capital cost minimization submitted by NS

Power were explored further during the hearing:

MEMBER MURPHY: Jeff, can you call up response to Board IR-77(b), please?

That's good. Thanks, Jeff. In that IR, Nova Scotia Power is asked to explain specifically

how the company's procurement process resulted in cost savings for the eight projects that

were listed.

…

Q. So Nova Scotia Power was asked to explain how the procurement process

resulted in cost savings for eight of those projects that -- those eight projects that are noted.

For five of the projects, number (i), (ii), (iv), (vii) and (viii), Nova Scotia Power explained

that the cost savings was a result of using the company's RFP process where the selected

lowest cost vendor's cost was less than the original budget amount. Can you confirm to me

that the cost savings for those projects that were noted in Appendix F based on that

response are simply the difference between Nova Scotia Power's estimate and the price

provided by the low-cost vendor?

...

Q. So I'm looking for confirmation -- for those five projects, can you confirm to me

that the savings is the difference between what was budgeted by Nova Scotia Power for

the project and the price that was provided by the lowest cost vendor?

A. (Dandurand) That I would need for each of these individually to undertake to

confirm that for you, Mr. Murphy. I believe that to be the case, but I’m not 100 percent

certain that that's the case in all of these five examples.

Q. Okay. I don't think I'll ask for an undertaking for this, but that's the way I interpret

the response. So my question, really, was if I'm interpreting it correctly, wouldn't those

savings actually be more related to perhaps an overestimate on Nova Scotia Power's part

or perhaps the low bidder being a little more aggressive than perhaps Nova Scotia Power

thought, rather than a proactive example of cost minimization on behalf of Nova Scotia

Power?

A. (Dandurand) So I think the intention of these examples, Mr. Murphy, to

demonstrate cost minimization is the RFP process itself, and so utilizing the RFP process

to competitively source either materials, services, et cetera, resulting in cost savings for

customers through that process and then making the comparison between what the

successful bidder's cost was relative to others that were competing through that RFP

process. And the reason that we highlight that, of course, is that our procurement

resources, you know, work to negotiate the best possible price for our customers, and so

the savings then are captured as a result of that work that's done by those involved in

negotiating the best price for customers.

Q. Do you know what percentage of procured projects are procured using a tender

process or an RFP process rather than a sole source process?

…

Q. Or rather than percentage, would it be fair to say that the good majority of

projects are procured using a tender process or an RFP process?

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A. (Dandurand) I think subject to check, Mr. Murphy, I would say that I would

expect the majority of, you know, projects are competitively sourced and then in some

cases, yes, there's a requirement to sole source, but I would need to confirm that for you

in terms of a specific percentage as to what percentage of our procurements are

competitively sources versus sole sourced.

Q. Okay. And I understand what you're saying about the -- about the procurement

– the RFP procurement process and whatnot, but it almost sounds like it's fair to say that

that process is a standard process rather than a project-specific process. And I guess in

terms of cost minimization, the examples that the Board is looking for is project-specific

examples rather than general -- general examples that could be applied to the bulk of Nova

Scotia Power's projects.

A. (Dandurand) So I think -- I think, Mr. Murphy, that, you know, those examples

related to our procurement process can certainly apply to our capital, you know, projects

and procedures, so that's the reason why we've captured them as such. Specific examples

outside of the procurement process or, you know, processes that are on the front end of a

project, for example, we have captured some of those in Appendix F of the ACE Plan that

are related more to the execution phase of our capital projects. But just to not -- not include

these, you know, cost savings initiatives from a procurement, I'll say, perspective is

something that we did not want to do. We just wanted to ensure that they were included in

there as they are part of the execution of our -- of our capital projects.

[Transcript, pp. 289-295]

[78]

As it relates to the provision of cost minimization examples in future ACE

Plan applications, NS Power proposed criteria describing how such examples will be

selected. These criteria, identified in the 2021 Stakeholder Engagement Report, would

be implemented for the 2023 and subsequent ACE Plans and include:

 projects over $5 million; and

 projects between $1 million and $5 million identified as part of the post

project review selection criteria (ATO, a unique or first-time undertaking

(new technology), significant schedule under or over performance, and/or

project manager initiated for sharing or recognition).

[79]

In addition, NS Power stated in its 2021 Stakeholder Engagement Report

with respect to the selection criteria of cost minimization projects within ACE Plans: “NS

Power will monitor the process for effectiveness and solicit feedback internally and

through stakeholder engagement through the 2022 ACE Plan process and consider

updates as a continuing improvement activity.” The CA supports this proposal but

believes that a random sampling of 15% of projects under $1 million should also be

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included as examples. NS Power does not agree with the CA on this point. Instead, the

company agreed to also include specific examples of its cost minimization efforts from

projects under $1 million that meet the criteria identified in the second bullet above,

excluding the ATO criterion.

[80]

During the hearing, the CA asked NS Power to identify any “new initiatives”

the company undertook in 2021 to ensure projects costs were minimized and executed

on a least cost basis. NS Power responded that it has developed a number of continuous

improvement initiatives, but that there has not been a lot of specific new initiatives

implemented. In his closing submission, the CA stated:

Recognizing the level of attention that the Board and stakeholders have placed on cost

minimization in recent years, it is concerning that NS Power is unable to identify new

initiatives that ensure projects are executed on a least cost basis. For a company that takes

all opportunities to highlight that cost minimization is integral to how it executes its projects,

NS Power comes up remarkably emptyhanded when asked to provide the concrete

examples of how this is achieved.

[Exhibit N-21, p. 17]

[81]

For the 2023 ACE Plan, NS Power has agreed to report on any new cost

minimization techniques that it adopts.

[82]

With respect to NS Power’s cost minimization practices, the issue of capital

project management and delivery was raised during this proceeding. This was aimed at

addressing the Board’s 2021 ACE Plan directive for the company to work with

stakeholders to develop a better understanding of NS Power's cost minimization and

project management practices. In response to CA IR-9, NS Power reiterated its

commitment from the 2021 ACE Plan stakeholder engagement process to review and

update its project management guidance documentation and practices, which includes

cost minimization elements. Updates to this documentation will be incorporated into a

new NS Power Project Delivery Model (PDM), which is currently being developed by in-

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house subject matter experts. The PDM will include guidance and recommended practice

for risk management, value engineering and benchmarking, to ensure these tools are

identified and applied appropriately. The PDM will be provided as the project

management standard guidance for capital projects at NS Power. NS Power confirmed

during hearing testimony that it expects the PDM will help the company improve its capital

cost performance so that it better meets AACE accuracy expectations. NS Power also

stated that it expects the new PDM to be implemented in the second quarter of 2022.

[83]

As part of the PDM implementation, NS Power noted that training on the

use of new practices and reporting tools to capture information related to cost

minimization is planned to be completed in the first half of 2022. Cost minimization

reporting will also be a standing agenda item for regular meetings with employees leading

capital projects. Capital and project management workshops are also planned for 2022

to discuss elements of NS Power’s capital planning and execution and project

management practices. In addition to providing employees with information related to NS

Power’s processes, these workshops will also provide training on new or updated

elements. This will include topics that have been the subject of ongoing consultation with

stakeholders, including cost minimization, post-project reviews and NS Power’s

contingency guidelines.

[84]

To address the Board’s 2021 ACE Plan directive related to work with

stakeholders to develop a framework and reporting protocols for a capital cost "lessons

learned" business practice, NS Power described its proposal in its 2021 Stakeholder

Engagement Report. The company stated that it will implement changes to formalize its

capital project planning process to ensure learnings are institutionalized. NS Power

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claimed that this will result in the lessons learned business practice forming part of the

post-project reviews. Elements of the company’s proposal include:

 The post-project review will assess the project against a template of key

project elements and expected outcomes. The product of the review will be

a summary report with any recommendations for correction, improvement,

standardization or training as applicable.

 A post-project review template will be utilized to guide and record the

review. The template will identify key project elements for post-process

consideration. A copy of the proposed template was included as Appendix

D in the 2021 Stakeholder Engagement Report.

 Guidance and education on the post project review process will be

documented internally and included in the annual NS Power capital program

workshops for education and best practice awareness.

[85]

is deficient and presented recommendations for improvement.

[86] Other issues raised during the hearing concerning NS Power’s costs

minimization practices included:

 Sole-sourcing of capital projects; and

The CA contends that NS Power’s proposed post-project review template

 NS Power’s post-project review process.

[87]

Mr. Wilson expressed concern related to NS Power’s sole-sourcing

procurement practices. In particular, he noted that cost minimization is more difficult in

sole-source procurement due to a lack of competition and because it is more difficult to

form an independent estimate of cost. As such, he recommended that NS Power include

projects procured through a sole-sourcing process with budgets or costs over $1 million

and a sample of projects with costs below $1 million in the post-project review process.

Although NS Power questioned the value of such reviews, it agreed to add these items

to the post-project review criteria.

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[88]

With regards to post-project reviews, in the 2021 ACE Plan proceeding, NS

Power agreed to complete internal post-project reviews for capital projects over $5 million

in cost. The Board, however, found that a capital cost threshold of $5 million for NS Power

to conduct internal post-project reviews was too high, but needed to be countered by

concerns about regulatory efficiency and associated costs to complete more post-project

reviews at a lower threshold. Consequently, the Board directed NS Power to engage with

stakeholders to develop an appropriate threshold.

[89]

In its 2021 Stakeholder Engagement Report, NS Power outlined proposed

criteria and project capital cost thresholds which would trigger when post-project reviews

are to be completed. Through the 2022 ACE Plan proceeding, the company proposed

an additional trigger to address concerns of Mr. Wilson related to sole-sourced projects.

NS Power described these criteria and thresholds in its rebuttal evidence:

…NS Power will commit to conducting post project reviews as follows, which shall be

available upon the NSUARB’s request:



Post project reviews for all projects submitted for approval that are greater than $5

million (including actual spend greater than $5 million);

Post project reviews for all projects between $1 million - $5 million that meet the

following criteria (beyond already established ATO and FIN thresholds): (i) unique

or first-time undertaking (e.g. new technology), (ii) significant safety or

environmental event or risk management deployed, (iii) significant

schedule/budget under or over performance, (iv) project manager initiated for

sharing or recognition; and (v) projects that include sole sourcing of equipment,

materials or services of material monetary value within the context of the capital

project; and



5 post project reviews each year for projects less than $1 million, with a focus on

steam projects for the first year.

[Exhibit N-12, p. 26]

[90]

Mr. Wilson recommended that NS Power should make all, or a reasonably

sized sample, of its post-project reviews available as part of the 2023 ACE Plan filing. He

further recommended that the Board should then identify as issues in the 2023 ACE Plan

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proceeding (a) whether the post-project reviews are useful and effective and (b) what

information from those reviews (such as a summary) NS Power should submit on an

annual basis. NS Power objected to this recommendation, noting that post-project

reviews will be available at the Board’s request, and, as such, do not need to be filed with

future ACE Plans.

[91]

Finally, the 2021 Stakeholder Engagement Report addressed the Board’s

2021 ACE Plan directive to assess whether the Board's contingency directive should be

expanded to require data on all projects with budgets or spending over $250,000, and

whether the scope of the data request should be wider. The CA has recommended that

the contingency directive (Appendix E of the ACE Plan) be expanded to include the scope

of the contingency (e.g., Class 3) for each project, a breakout of the different levels of

contingency if a project has multiple contingency levels, data on all projects with budgets

or spending over $250,000, and relevant data (e.g., excluding “actual spend”) for in-

progress and proposed projects. In addition, Mr. Athas stated:

This filing raises the questions of whether NSPI’s cost estimation process merits further

review and lacks sufficient transparency to determine if the value ascribed to the project

has or will materialize for Nova Scotians. The cost estimation process is still creating more

examples where cost overruns extend well beyond the contingency set by NSPI in their

application.

[Exhibit N-9, p. 8]

[92]

Based on this assertion, Mr. Athas recommended expanding the annual

ACE filing to include a greater emphasis on cost minimization, with each specific project

submitted for approval including a detailed discussion of how various approaches to

reducing cost were evaluated and applied in an effort to better understand where there is

significant project scope risk.

[93]

NS Power does not agree with the CA’s recommendation. The company

believes that its current reporting effectively addresses ACE Plan reporting requirements

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ordered previously by the Board. NS Power also does not believe that Mr. Athas’

recommendation is either necessary or appropriate. The company noted that the extent

of such a discussion within the “why do the project this way” section of a capital application

description page will depend on the current stage of the project at filing. Further, NS

Power currently adds a technical justification explanation separate from the EAM to

identify alternatives to capital investments. Separate and apart from the EAM, the

company provides information within the Capital Description Page, which identifies

alternatives explored. In addition, when there is only one technically feasible project

alternative, NS Power provides information as to why other project alternatives were

discounted.

3.3.2.1

Findings

[94]

In Section 11.1.5 and Appendix F of its 2022 ACE Plan application, NS

Power provided examples of cost minimization efforts over the past year. The Board finds

these examples and related supporting information to be useful and informative. The

Board directs NS Power to continue to provide such information in subsequent ACE Plan

applications. This is to include specific examples of cost minimization practices used

during execution and construction of the prior year’s projects, fully describing specific cost

minimization efforts, complete with a description of the cost savings accrued by these

efforts. In particular, the Board directs that this information continue to be presented in

the format used in Section 11.1.5 and Appendix F of the 2022 ACE Plan application.

Further, as agreed by NS Power, the Board directs the company to report on any new

cost minimization techniques that it adopts.

[95]

During the 2021 ACE Plan hearing, NS Power revealed that it selected at

random the 35 projects used to produce the cost minimization data in Figure 69 of the

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2021 ACE Plan application. As such, the Board directed NS Power to engage with

stakeholders to develop criteria for the selection of projects to be included as specific

examples of NS Power's cost minimization efforts in future ACE Plan applications. NS

Power presented these proposed criteria in its 2021 Stakeholder Engagement Report.

The Board finds them to be reasonable and effectively balancing satisfactory reporting

that provides the Board and stakeholders with a sample size of cost minimization

achievements while not adding to regulatory inefficiencies or costly reporting. The Board,

therefore, directs NS Power to use these criteria (including those for projects less than $1

million) in future ACE Plan applications to select projects to be included as specific

examples of the company’s cost minimization efforts. The Board also directs NS Power

to monitor the process for effectiveness and solicit feedback internally and through

stakeholder engagement through future ACE Plan processes and consider updates as a

continuing improvement activity.

[96]

As noted above, the Board questioned NS Power during the hearing about

its claimed cost savings related to “procurement negotiations” for five projects in Appendix

F. Specifically, these questions dealt with the issue of claimed project cost savings

associated with using the company's RFP process where the selected lowest cost

vendor's cost was less than the original budget amount. The Board understands and

agrees with NS Power’s response that seeking competitive bids is a means of obtaining

value and minimizing costs for customers. However, as noted in its 2021 ACE Plan

decision, the Board considers this a general example of obtaining best value, and one

that the Board would expect NS Power to use for the bulk of its capital projects. As such,

the Board does not consider the noted costs savings on these projects to be specific

examples of a proactive cost minimization practice by the company. Instead, the Board

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considers these cost savings may primarily result from astute or aggressive bidding

practices on the part of the low bidder and/or NS Power over-estimating the project cost.

[97]

Similarly, there are three projects in Appendix F (HYD - WRC LEM Balance

of Plant, HYD - Weymouth Falls Unit 1 Generator Refurbishment, and TRE Heavy Fuel

Oil Tank Refurbishment) where NS Power explained, in response to NSUARB IR-77(b),

that the claimed cost savings are a result of NS Power selecting the lowest bidder for the

project. The claimed savings are the difference in price between the lowest bidder and

the next lowest bidder. Again, the Board does not consider the noted costs savings on

these projects to be specific examples of a proactive cost minimization practice by the

company. Instead, the Board considers these cost savings may primarily relate to

individual bidder’s approaches to pricing projects and/or astute or aggressive bidding

practices on the part of the low bidder.

[98]

NS Power’s noted cost savings in Appendix F for the eight capital projects

referenced in the preceding two paragraphs amounts to a total of approximately $8.2

million. If these savings are deducted from the total Appendix F project cost savings of

$13.4 million, the Appendix F savings would be $5.2 million. This would represent only

4% of the approved project costs in Appendix F. The Board trusts that in future ACE Plan

applications NS Power will not weight its Appendix F reporting so heavily to these types

of minimization and savings examples. As such, the Board partially supports Mr. Wilson’s

recommendation, and encourages NS Power to provide cost minimization information in

future ACE Plan applications that is more useful for identifying lessons learned. Ideally,

NS Power’s new criteria to include projects as specific examples of the company’s cost

minimization efforts will help to address this issue.

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[99]

The Board looks forward to implementation of the company’s new PDM in

the second quarter of 2022. As per the documentation included in the 2021 Stakeholder

Engagement Report, the Board expects the PDM will include development and execution

of a planned and documented forward-looking cost minimization review process to be

applied to projects indicated for cost minimization review. The Board also expects that

the process will utilize a simple running cost minimization tracker of key project elements

with status for cost avoidance and cost reduction opportunities.

[100]

Moving forward, the Board would like to see a capital project cost estimating

process incorporated into the PDM. The intent of this process would be to help NS Power

improve its capital cost estimating/budgeting practices, with the goal of reducing the

company’s overall spending variance. If this process has not yet been incorporated into

the PDM, the Board directs NS Power to engage with stakeholders to solicit input.

[101]

In its rebuttal evidence, NS Power proposed criteria and project capital cost

thresholds (including those for sole-sourced projects) which would trigger when post-

project reviews are to be completed. The Board finds these to be reasonable and directs

that they be adopted by NS Power in advance of submission of the 2023 ACE Plan

application. Mr. Wilson recommended that NS Power should make all, or a reasonably

sized sample, of its post-project reviews available as part of the 2023 ACE Plan filing. NS

Power does not agree that, as a matter of practice, internal post-project reviews should

be filed with future ACE Plans. The Board agrees with NS Power, particularly given that

the company must continue to file both ATOs and FINs with the Board in accordance with

the CEJC, fully justifying either under- or overspending beyond CEJC thresholds. In

addition, the company has stated that post-project reviews will be available at the Board’s

request. As such, if the Board requires a sample of post-project reviews for future ACE

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Plan applications, it can simply request, and would expect, to be provided with the

information. Through future ACE Plan proceedings, the Board and stakeholders will have

the option to review the triggers for post-project reviews.

[102]

The Board finds NS Power’s proposal for a framework and reporting

protocols for a capital cost "lessons learned" business practice to be appropriate. The

Board, therefore, directs the company to implement that practice in advance of

submission of the 2023 ACE Plan application. The CA expressed concerns related to NS

Power’s proposed post-project review template in the “lessons learned” business

practice. However, the Board has reviewed the template and finds it reasonable, as well

as addressing most of the CA’s concerns. Nonetheless, as the “lessons learned”

business practice evolves, there may be opportunities and reasons for the template to be

updated. The Board, therefore, encourages NS Power to review the template regularly

to determine whether it can be improved. The Board and stakeholders will also have the

option to review usefulness and effectiveness of the “lessons learned” business practice

in future ACE Plan proceedings.

[103]

The Board has reviewed the evidence related to the Board’s 2021 ACE Plan

directive to assess whether the Board's contingency directive should be expanded to

require data on all projects with budgets or spending over $250,000, and whether the

scope of the data request should be wider. Both the CA and the SBA (through Mr. Athas)

have argued that ACE Plan cost minimization reporting should be expanded. NS Power

believes that its current approach to cost minimization reporting strikes a proper balance

of providing the Board and stakeholders with helpful information to assess contingency

and capital budgeting/spending, while not being overly burdensome. The company thus

submitted that no further Board direction is required with respect to cost minimization

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reporting, whether within future ACE Plans or otherwise, beyond what NS Power has

already committed to in the current ACE Plan proceeding. NS Power argued that the

contingency directive should remain as directed by the Board.

[104]

The Board agrees with NS Power. At this point, the Board believes it has

the required cost minimization reporting, both currently and as directed in this decision,

that it needs to effectively evaluate the company’s capital cost performance and cost

minimization efforts and practices. Nevertheless, the Board still has concerns associated

with the effectiveness of NS Power’s capital cost minimization and budgeting practices.

The Board expects to see improvement in these areas, and these issues will continue to

be monitored in future ACE Plan proceedings. Should these concerns continue, the

Board may, at some point, direct NS Power to engage a third-party expert to review cost

minimization and capital cost budgeting practices.

3.4

Reliability Investments

[105]

In past ACE Plan applications, NS Power has stated that reliability is a

primary focus of its investments. The 2022 application is no different. NS Power also

emphasizes the need to balance affordability for customers with improvement in system

reliability.

[106]

In this application, the reliability focus is on T&D projects and a response to

weather events, which are becoming increasingly more severe. The transmission capital

investment is focused on sustaining system reliability. Customer reliability is the focus of

distribution capital investment. The 2022 ACE Plan is targeting investments for T&D

vegetation management and defective, deteriorated, or failed distribution equipment.

[107]

NS Power said it employs a Customer Reliability Strategy (CRS) to identify

and implement improvements in system reliability to benefit its customers. The

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company’s goal is to prioritize reliability investments to “mitigate the highest risks on the

system for the greatest number of customers.” The company said it uses lessons learned

from problem feeder investments to improve CRS projects.

[108]

In response to NSUARB IR-48, NS Power discussed its CRS, describing

the strategy as “the collection of asset strategies, processes and investment

recommendations…for T&D assets.” However, there is no separate documented

program for the elements of the CRS. The CA further explored this:

Q.

…Ms. MacDonald, as I reviewed the various IR responses, I understand

that Nova Scotia Power's Customer Reliability Strategy is not documented. Is that correct?

A.

(L. MacDonald) So what I would say on that is that it -- insofar as it is the

collection of programmes, it's the collection of how we're organized in terms of our asset

management approach, and then the various projects or collections of projects that you

see, those things working together is the Customer Reliability Strategy.

Q.

Okay. And so if one were looking to see Nova Scotia Power's strategy for

customer reliability that has been committed to writing, what would we look at?

A.

(L. MacDonald) We would look across recent ACE Plans, performance

standards, the problem circuit reporting as well as the various storm templates, so there's

really a collection of reliability driven reporting and programming that we think is very

comprehensive and transparent and has absolutely developed and evolved over the last

number of years.

Q.

And at other major electrical utilities, Ms. MacDonald, that have a

Customer Reliability Strategy, are you familiar with whether or not at those utilities it's

common to have a documented reliability strategy?

A.

(L. MacDonald) Yes, I think different utilities do this in different ways. In

some ways, you could -- you could think of it in terms of presentations, of PowerPoint

presentations or Word documents which summarize the collection of activities that I’m

talking about here.

When we say that it's not documented as its own standalone, it's because we have

these other parallel collection of approaches working together, and that's the approach

we've taken. But I am familiar with how other utilities can certainly put together one

document or one presentation to summarize these types of efforts.

Q.

And is the company giving consideration to centralizing this and having a

documented reliability strategy?

A.

(L. MacDonald) In terms of centralizing, in fact, what we've done over the

last few years is reorganized to an enterprise asset management function, which is where

we've integrated the generation as well as transmission and distribution grid reliability

approach into an overall function and department of engineers and analysts and others

working together constantly to make sure that we are coordinated and are seeing those

cross-functional learnings that apply to various reliability strategies all in one function. And

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in that way, perhaps you could think of it as the reliability strategy is embodied in how that

is organized and some of the -- we've alluded to reliability teams in many of our IR

responses in this ACE proceeding, and that is how we do the work. It's constant and it's

every day as opposed to a document or a presentation.

Q.

And I don't mean to sound as though I'm challenging about the work

getting done, and we'll come to some of the reliability results in a moment, but just from an

idea of having a centralized, documented strategy that then can be looked at in order to

understand, okay, certain capital projects being justified on this basis, here's the strategy

under which that particular capital project fits, is the company giving some thought to

getting a documented reliability strategy put in place?

A.

(L. MacDonald) As -- as I'm explaining, Mr. Mahody, I think we are, or we

have. How that results in one document, I think remains to be determined whether that is

a valuable exercise in and of itself, but the criteria, the asset management mechanisms,

the various reports and metrics against which we report on all of this, those are absolutely

documented and provided and then elaborated on as needed through the various

processes that we're part of.

Q.

Ms. MacDonald, perhaps by way of an undertaking, would you be willing

to list the various documents that do make up the overall reliability strategies so we have

in one place where this list of documentation would be?

A.

(L. MacDonald) Yes, we can undertake to do that.

[Transcript, pp. 49-54]

[109]

Undertaking U-1 lists the documents NS Power considers support the CRS:

A listing of documents and data that support this strategy are outlined below and are

organized in the three main components of the Asset Management Mechanism. Risk

Profiles, Mitigating Measures and Maintenance Strategies.

Risk Profiles:

•

Feeder Risk Profiles

Transmission Line Risk Profiles

Major Substation Asset Risk Profiles

Mitigating Measures:

•

Annual Capital Expenditure Plans

Performance Standards Annual Report

Performance Standards Summary and Revision Reports

Storm Reports

NS Power Problem Circuit Study

Climate Adaptation Planning Documents

Third Party Risk Reviews from Insurers

Reliability Team Working Documents

Maintenance Strategies:

•

Feeder Inspection Data

Transmission Inspection Data

Preventative Maintenance Programs

Real Time Monitoring Data

Feeder Load Monitoring Data

Feeder Protection Coordination Studies

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•

Third Party Engineering Assessments

Substation Field Inspection Data

Root Cause Analysis Reports

Distribution Planning Studies

[Exhibit N-19, U-1, pp. 4-5]

[110]

NS Power’s application included reliability statistics for its own operations,

as well as those for Atlantic Canada utilities. The company stated that, generally, its

annual outage frequency and duration is below the other Atlantic utilities, and where it is

higher, it is due to a substantial number of storms.

[111]

In its 2020 Performance Standards decision (M10055), the Board identified

the worst 5% problem circuits and set out its expectations of NS Power regarding the

circuits:

A comprehensive and effective approach to align the reliability performance of those

circuits with the service level provided to customers in other regions of the province needs

to be developed. It is unclear whether NS Power has undertaken any reliability analysis to

determine if performance would be improved with additional or reconfigured infrastructure

(circuits or substation) that could minimize circuit exposure. It is also unclear whether

integrating innovative technological advances associated with microgrids, battery storage,

or other distributed energy resources was studied to determine the effectiveness of such

measures in improving service restoration or minimizing outage durations. The Board

directs NS Power to undertake a comprehensive analysis which results in clearly identified

measures, as well as the associated timing and costs, to bring these problem and chronic

circuits into alignment with the reliability performance in the rest of the province. This study

and the action plan are to be reviewed during an upcoming ACE Plan proceeding.

[Emphasis added]

[Decision letter, June 23, 2021, p.13]

[112]

The NS Power Problem Circuit Reliability Study was filed with the Board on

December 10, 2021 in response to the Board’s directive. The Board made the Study an

exhibit in this proceeding. The Study described four problem circuits in Cape Breton. The

four circuits “have been and continue to be, targets of reliability investments to improve

performance.” NS Power considered other options for improving the performance of each

circuit, and developing some specific projects, taking into account reliability gains, costs,

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feasibility, and the time required to implement the work. The proposed investment for 26

projects totals $10.8 million. The Study noted four key areas as investment targets:

 Targeted priority device replacement;

 Storm hardening and reliability upgrades of devices;

 Enhanced vegetation management; and

 Smart Grid and Intelligent Devices deployment.

[113]

Mr. Athas expressed concern about the overall level of funding stemming

from the plan for the four problem circuits and what he considers to be disproportionate

spending on outage causes as well as a general lack of specifics. He noted that most of

the spending is on vegetation management and bringing lines to roadside, leaving little

for the issues noted in the Study. Mr. Athas also expressed his concerns, generally, about

a lack of specifics in the justification of T&D projects based on the impact on reliability:

Reliability impact is frequently used as justification for T&D capital projects and at times

excessively so. Absent a specific numerical impact upon which to evaluate the cost-benefit

of what is being proposed the term becomes little more than a buzz word.

[Exhibit N-9, p. 33]

[114]

NS Power stated in its rebuttal evidence that the investment in the four

problem circuits on vegetation management and outage causes is warranted due to the

geographic conditions as well as the meteorological systems in the areas. The company

considers its approach to mitigating the issues with the circuits in the circumstances is

balanced.

[115]

Mr. Athas set out several questions about vegetation management

spending, suggesting that the circuits in question had fallen behind, and remedial

attention was long overdue. NS Power rejected Mr. Athas’ position, saying that there was

no evidence that NS Power had fallen behind in its vegetation management. The

company said it regularly reviews indicators to take the best steps to undertake the

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necessary activities. NS Power did not accept Mr. Athas’ suggestion that there is a need

for an investigation. Further the company disputed the accuracy of the suggestion that it

waits for a feeder to be in the “bottom 5%” before investing in it, noting that there are other

feeders on which it is making investments in addition to the problem circuits.

[116]

A further concern of Mr. Athas is the impact of underspending on several

projects which he claims could negatively impact reliability. In its rebuttal evidence, NS

Power responded to these concerns, noting that the projects identified by Mr. Athas have

progressed. Further, with one exception, the projects all had variances of less than 10%

from their approved budgets. NS Power noted that, in its quarterly reports filed with the

Board, variance explanations are available to address Mr. Athas’ concerns.

[117]

In its application, NS Power discussed its Reliability Investment Strategy for

aging T&D assets. The company stated that aging infrastructure is not replaced solely

based on age, but other factors may impact its useful life: condition; risk; reliability impact,

and others. In response to NSUARB IR-8, NS Power said its proposed capital

investments for these assets will address current challenges as well as help to avoid

future outages. In the longer term, the investments will support reliability “by both

correcting existing/emerging reliability issues and avoiding issues that have not caused

reliability impacts yet.”

[118]

The CA also explored the amount of spending on vegetation management

with the NS Power panel during the hearing:

Q.

(Mahody) Still on the topic of reliability, I would like to talk about trees. And

if we could turn up page 168 of the Exhibit N-1, Mr. Goodine?

Q.

And down as the very bottom, line of that portion of the evidence, it

indicates that 27 percent of all identified event-day outage hours year to date in 2021 have

been caused by trees.

So is that fair to say that somewhere between 25 to 30 percent of customer-

experienced outages, the company in 2021 said that those were caused by trees?

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A.

(L. MacDonald) Yes, in addition to what I think we explain as well in the

ACE Plan and elsewhere in respect to how weather-coded outages are often also tree

caused, but coded to the weather event in question, so it's at least that, and likely more,

depending on how the weather codes fall into trees.

Q.

And that range of tree-caused outages, Ms. MacDonald, has been a

relatively consistent level over the last 10 or more years?

A.

(L. MacDonald) Subject to check, I think so, and again, depending on how

the weather relates to it. And if you want to point me to something, we can, ---

Q.

A.

Q.

Sure.

--- myself and my colleagues, talk more about that.

Certainly.

Mr. Goodine, Exhibit N-5, Responses to Board IRs, could we turn up Response to

Board IR-50(b), and just down at the bottom of that page, if we could see that graph? Okay.

Q.

So Ms. MacDonald, I was understanding that this graph, if you take out

the 2010 and 2014, or if you normalize those as significant events that occurred that’s

referenced in your evidence, that line, at approximately 25 percent is what I understood to

be a relatively consistent impact of trees on the system.

A.

(L. MacDonald) Yes. Looking at it that way, you can definitely say that.

Q.

Okay. As you know, Ms. MacDonald, a significant amount of investment

has been made in vegetation management, in tree trimming, over at least the last 10 or 15

years, to the tune of millions and millions of dollars annually. Why is it that the impact that

we see of trees causing outages doesn’t seem to have changed, even though we've

invested the tens of millions of dollars that we have in that initiative?

A.

(L. MacDonald) So broadly speaking, I would say that maintaining the level

-- perhaps it's a downward trend as well, if we look at it -- but is working in the context of

increasing occurrences and severity of those weather days that I spoke about in terms of

both the day itself that weather could be affecting the system as well as the stress in the

days after.

And so all of that taken together, we know that the frequency and the severity of

those events, the wind, for example, that causes -- typically causes the tree issues, have

been increasing, so in some ways, to be holding or slightly decreasing in terms of the

effects of that, as part of what we call maintaining and improving system performance in

the context of the increasing severity and frequency of the weather.

Q.

And going forward, Ms. MacDonald, I understand the company plans to

spend approximately $8 million in vegetation management tree trimming in the coming

years. Is that a sufficient amount, in the company's view, given the impact the trees are

having on our reliability?

A.

(L. MacDonald) Well, we're constantly reviewing that, and if it becomes

apparent that we need to increase in a material way the size of one of those programmes,

we would bring that forward. But that is exactly the work that we're reviewing constantly,

in terms of the balance of our programme among vegetation management investment as

well as the other equipment related system-wide transmission distribution and feeder level

improvement.

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So it's all part of that balancing act based on what we see in the trends.

[Transcript, pp. 55-59]

[119]

In her opening statement and closing submission, the SBA said that

significant questions remained about what is targeted to address reliability and how

success is assessed. The SBA emphasized the need for clarity, saying it is necessary to

be able to determine what has been achieved by the investment.

[120]

During the hearing, Ms. MacAdam asked the NS Power panel how the

company will know if it has addressed the problem and achieved reliability. Matthew

Drover, Senior Director of T&D and Delivery Operations, said that NS Power tracks the

performance of all its feeders regularly, and if they are improving, the company knows it

has made a difference.

[121]

The Board also explored performance measures with the NS Power panel:

Q.

(Murphy) So these two tables, my understanding is they present expected

reductions in CKAIDI and CKAIFI performance measures as a result of completing

proposed projects in the Feeder Action Plan that was submitted -- I think it was Exhibit N-

2, as part of this proceeding.

And I think these may be questions for Mr. Drover, but I'm wondering if you could

explain how the targets for the estimated reduction in CKAIDI and CKAIFI were

determined?

A.

Q.

A.

(Dandurand) Mr. Murphy, maybe I'll start ---

Sure.

(Dandurand) --- with -- in response to your question, and then Mr. Drover

and I can respond accordingly.

Q.

Maybe I'll -- before you start, my next question was going to also be how

were those estimated range reductions estimated as well, so let's combine in the one

question.

A.

(Dandurand) Okay. For sure.

Yeah. So the estimated reduction in CKAIDI and CKAIFI, as you’ve noted in the

table, are what the company would expect as a reduction in those two metrics as a result

of the investments that are included in the plan.

I guess the caveat to that, though, would be listed at the bottom of the table as

well, just an important note that that anticipated avoided CKAIDI, CKAIFI from a particular

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project within the plan would vary, depending on the unique conditions that the feeder is

exposed to in any given year.

So they are a range of, I'll say, possible outcomes, as the sub-note suggests to the

table, with respect to reduction in those reliability metrics; again, based on the investments

within the study.

Q.

But is that specifically based on, I guess, Nova Scotia Power experience

in doing previous type of work and what you saw in terms of reductions in those measures?

A.

(Dandurand) So I guess partly.

My understanding would be that certainly, with the elements that feed into what

the causes of outages are and having a firm understanding as to what the causes of

outages are or impacts to reliability, and again, I'll say, coupled with the company's

experience using that information to provide an expected range in reduction to CKAIDI and

CKAIFI.

Q.

Thank you. In that same IR Response to the -- it was IR Response 81(b)

---

Q. --- there's reference there, it says:

Loss of supply related outages on feeder 53 [or sorry] 58C-403 contributed

approximately 15 percent of customer hours of interruption and approximately 22 percent

of the number of customer interruptions on average from 2018 to 2021.

Those numbers, I guess, to me, anyway, appear rather significant and I'm

wondering what steps Nova Scotia Power's undertaking to reduce those particular

transmission interruptions.

A. (Drover) I can speak to that one, Mr. Murphy.

So when it comes to loss of supply, those are typically either transmission or

substation interruptions to a poll substation, and they can have the same causes as the

other types of feeder outages we have, whether it's vegetation that falls on the transmission

line or a type of asset that has weakened for whatever reason.

So it's part of our asset management programme, same that we do with our feeder

inspections, we do the same thing with transmission inspections, and the projects that we

put forth within the ACE Plan would reflect those -- those programmes.

[Transcript, pp. 285-289]

[122]

While the SBA sought some means of quantifying the success of reliability

investments, the Board observes that there was no suggestion about how this might be

achieved. The Board notes NS Power’s statements in its rebuttal evidence about the use

of predictive analysis to inform its spending priorities, targeting improvements in CKAIDI

and CKAIFI in the study. The company said improvements in feeders are hard to predict

exactly, due in large part to external factors like storms. NS Power went on to say that

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its success can also be reviewed in the annual Performance Standards Review by the

Board.

3.4.1.1

Findings

[123]

The Board finds that presently there is no need to direct an investigation

into reliability investments made by NS Power as part of this proceeding. No party

objected to the approval of any of the projects identified to improve reliability in the 2022

ACE Plan application. The Board considers that the appropriate venue in which to explore

whether improved performance has been achieved is in its annual Performance

Standards Review. The Board understands that the results of T&D capital spending will

not necessarily be seen immediately, however, and expects NS Power to be diligent in

continuing regular monitoring of the circuits/feeders in the interim.

3.5

Economic Analysis Model

[124]

The Board identified the EAM in the Final Issues List developed for this

proceeding, with three areas for examination: Replacement Energy Cost (REC);

Accounting Treatment of Decommissioning Costs; and Monte Carlo/Decision Analysis.

The Board discusses these areas below, recognizing that they are all elements for

consideration in the EAM.

[125]

The SBA suggested that NS Power could expand the use of the EAM to

scrutinize projects where the company has identified only one option as technically

feasible. Mr. Athas said NS Power should expand on this conclusion as well as clarifying

its review of alternatives. NS Power’s response was that the company already does this

and will continue to do so. The Board does not consider further direction is required.

[126]

In its 2021 ACE Plan decision, the Board referred several questions to the

stakeholder engagement process, including:

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 Whether the Board should direct NS Power to update the EAM to align with

new practices and more recent data that affect the replacement cost of

energy and the design of sensitivities;

 Whether NS Power should be directed to provide a full explanation of the

current accounting treatment for all decommissioning-related costs.

[127]

In its 2021 Stakeholder Engagement Report, NS Power indicated that

complete agreement with stakeholders was not reached on these two issues. The Board

accepted the report in a letter dated November 2, 2021, and said it expected the

unresolved issues would be addressed in either the next ACE Plan proceeding or other

applications before the Board.

3.5.1 Replacement Energy Cost

[128]

NS Power reported agreement to update the REC calculations in the EAM

to align with the IRP Reference Plan 2.0C. The sensitivity for the REC would remain at

10%; however, NS Power noted that this would be updated to show it represents a

P67/P33 range in alignment with IRP fuel sensitivities. In its closing submissions, NS

Power said it would update the 10% sensitivity once it has completed its IRP evergreen

work, suggesting it makes no sense to update it on a frequent or annual basis.

[129]

Sensitivities for capital investment were updated to 30%, although the CA

considered that rather than apply a Class 3 sensitivity of 30% to all projects, the sensitivity

should be aligned with the class of each project. NS Power’s position is that most projects

submitted for Board approval are based on Class 3 estimates and therefore the 30%

sensitivity is most appropriate. The company claimed that making changes to the EAM

to accommodate the CA’s position would be administratively burdensome. Finally, NS

Power said it would continue to show the economic impact on a project of a one-, two-

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and three-year delay in its EAM, with analysis of longer periods for projects where there

is uncertainty around timelines.

[130]

In his evidence, Mr. Wilson said that the changes made from the

stakeholder engagement regarding REC are appropriate but suggested that the energy

cost sensitivity should reflect the same range as the sensitivity for capital investment. He

also suggested that, due to recent legislative changes, there should be a change to a

different IRP scenario.

3.5.1.1

Findings

[131]

The Board is satisfied that NS Power has appropriately updated its EAM

regarding REC for current use and expects that there will be a further update once the

evergreen process of the IRP is complete.

3.5.2 Accounting Treatment of Decommissioning Costs

[132]

In its October 1, 2021 Stakeholder Engagement Report, NS Power said it

had provided stakeholders with a complete explanation of its current accounting treatment

for decommissioning-related costs and considered the Board’s directive to have been

properly addressed. However, the company noted concerns of the CA about how

decommissioning liabilities are treated in the EAM. NS Power’s position is that the

decommissioning liability is the same in reinvestment and decommissioning options in

the EAM at the beginning of the analysis, and the future revenue requirement only

changes if the future cash flows between the options are different. The company said the

changes are captured in the EAM through the changes in depreciation expense, financing

costs and tax impacts.

[133]

The CA pursued the issue of decommissioning costs in the context of the

Tusket Main Dam Refurbishment ATO proceeding (M10197) currently before the Board.

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In response to CA IR-19, NS Power said it does not have formal policies and practices

about the comprehensiveness and accuracy of decommissioning costs developed for use

in the EAM. The company said it typically evaluates the projects at a Class 5 level, and

then further refines its analysis. The company went on to say that hydro projects can be

deferred indefinitely if there is sustaining capital to ensure it reaches the next

refurbishment or life extension modernization investment. While such a deferral may not

be the most economic alternative, NS Power said it looks at what is the best value for its

customers.

[134]

Mr. Wilson suggested that the Board should direct NS Power to provide a

sensitivity analysis including the cost of decommissioning in the economic analysis of the

Mersey redevelopment project, which is not yet before the Board. During the hearing,

this issue was explored by the CA with the NS Power panel:

Q.

… In his eighth recommendation, Mr. Wilson indicates that Nova Scotia

Power should include a sensitivity analysis in the Mersey EAM that, at a minimum, includes

the full cost of decommissioning the facility at the end of the analysis period. It is Nova

Scotia Power’s intent to supply that type of information as part of the Mersey filing?

A.

(Dandurand) Yes, Mr. Mahody, to the extent it’s appropriate, a

decommissioning scenario would be included as part of the filing.

[Transcript, p. 83]

[135]

Justin Heisler, Controller, also confirmed this in response to Board

questions, with additional comment from Mr. MacDonald:

Q.

(Murphy) Again aligned with Mersey, I wanted to follow up on a question

that Mr. Mahody asked earlier today. …

But Mr. Mahody referenced a recommendation from Mr. Wilson that Nova Scotia

Power include a sensitivity analysis in the Mersey EAM, which includes the full costs of

decommissioning the facility at the end of the analysis period.

And I think Mr. Mahody asked the panel to confirm that that would be done, but

maybe I misheard, but the answer I heard was that Nova Scotia Power agreed to consider

decommissioning as an alternative to Mersey Project. Is that what I heard?

A.

(Heisler) Mr. Murphy, that was me, Justin Heisler. So we will look at a

decommissioning.

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Q.

As an alternative. But the question was per Mr. Wilson’s

recommendations, when you look at the Mersey Redevelopment option, will you include

decommissioning in that particular option at the end?

It’s along the lines of the questions that Mr. Melanson was asking earlier. Will you

look at decommissioning at the end of the project and include that in the costs for the

refurbishment project or the redevelopment project?

A.

(Heisler) Yes, we will.

Q.

And you’ll conduct the sensitivity analysis that Mr. Wilson had

recommended?

A.

Q.

A.

(Heisler) Correct.

Okay, thank you.

(J. MacDonald) Mr. Murphy, just to add to that. So certainly when you look

at the price tag that’s on Mersey, we’re all, you know, like, a bit taken aback by sticker

shock. But we’re endeavouring to look at the lowest cost option for customers whether,

you know, it’s replacing the assets and sustaining the energy, whether it’s de-energizing,

which would include keeping the dams in place; and then the third option is to take the

dams out which is kind of the decommissioning option for Phase 1.

So those are the considerations. And also part of those considerations are part of

the consultation process that we have currently. And then certainly different views on all

three of those, but certainly that would be part of the filing of the latter part of this year. But

those are kind of the three options that we’re looking at.

[Transcript, pp. 267-270]

[136]

The question of whether NS Power’s approach described in response to CA

IR-19 of using a 40-year model in the EAM when looking at refurbishment or

decommissioning introduces a bias in favour of refurbishment was pursued with Mr.

Heisler:

Q.

(Melanson) And my experience with decommissioning versus

refurbishment is primarily in the area of hydro, and most of the hydro assets, the useful life

has been considerably longer than 40 years and could go on to perpetuity depending on

how often you refurbish it. Doesn't that introduce a bias in favour of refurbishment in every

application?

A.

(Heisler) Mr. Melanson, I mean, I think as we would have noted in our

response to you; I believe it was CA IR-19. We do generally take the view that based on

there’ sufficient sustaining capital, we can extend the life of specifically hydro facilities in

perpetuity. But to your point, that isn’t always necessarily the most economic option. And

so our approach would be to -- would be to look at all options, including decommissioning.

And then we do expect that in certain cases at a certain point continuing to refurbish or

extend the life of those assets may not be the most economic. So we would look at all

appropriate options to ensure that the conclusion we’re drawing is in the best interests of

customers.

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Q.

My question was not so much whether you're going to be looking at the

two options or not. My question is not -- is there not a problem, is there not an internal

problem with the mechanism of the economic analysis model so that every time you do it

separately over the course of time, the outcome is never going to be in favour of

decommissioning.

A.

(Heisler) I mean, certainly given the time value (indiscernible) on the basis

of the – comparing options on a net present value revenue requirement basis, there is –

there is a benefit in deferring the decommissioning costs, but at the same time, there are

sustaining capital requirements throughout the course of the – throughout the course –

through the life of the asset to extend that life, so I don’t know what the – certainly the time

value of money isn’t a factor, but I think our general view would be that the approach we’re

taking is appropriate from a net present value revenue requirement.

[Transcript pp. 211-213]

3.5.2.1

Findings

[137]

NS Power confirmed, in its reply submission, its commitment to provide the

sensitivity analysis around decommissioning in its Mersey application as suggested by

Mr. Wilson. The Board agrees that doing so will provide a more appropriate EAM, but

considering the potential inherent bias, expects that application to be closely scrutinized

by stakeholders as well as the Board.

3.5.3 Monte Carlo/Decision Analysis

[138]

In its decision in M10013 regarding the Annapolis Tidal Generator

Retirement, the Board discussed NS Power’s Decision Analysis model and the Monte

Carlo Economic Analysis model as discussed in the evidence of Matthew Schoenhardt of

MS Consulting, a consultant to the Board’s consultant, Grant Thornton. The Board

quoted a description of the Monte Carlo analysis from his report:

[67]

MS Consulting stated that the primary purpose of Monte Carlo Economic Analysis

(MCEA) is:

... The primary purpose of using MCEA is to compare project alternatives and understand

under which scenarios does the ordinal ranking of each alternative change. Once the

variables are identified that change the ordinal ranking, investigation of the most significant

variables should have priority funding in the next stage so that their ranges can be further

refined and/or reduced (i.e., de-risked by progressive project development). Investigating

these key variables allows for reduced project development costs.

One method of understanding critical conditions are “tornado diagrams”. A tornado diagram

runs the economic analysis moving each variable through its maximum and minimum

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range to determine the impact value on the outcome. This allows a user to see which

variables are the most important to the desired outcome.

[M10013, Exhibit N-9, Appendix A, p. 6]

[139]

In the Annapolis matter, Mr. Schoenhardt considered the NS Power

Decision Analysis to be lacking. In this matter, there was little discussion of the issue.

The Board notes that the Non-Binding Contingency Guidelines of NS Power, as filed in

response to CA IR-15, refer to when a Monte Carlo analysis or similar simulation is used

for range estimation. In response to NSUARB IR-21, NS Power explained that the

company does not use such simulations as a standard for risk-rating and optimization;

rather, NS Power uses the simulations for the evaluation of specific complex capital

projects to compare alternatives.

[140]

Mr. Wilson did not suggest the Board should favour the use or the non-use

of a Monte Carlo decision analysis in his evidence. In his opinion, the EAM is suitable,

but the Monte Carlo analysis could be useful as an “intermediate level of sophistication

and complexity that is particularly useful for complex hydro projects or new technologies.”

3.5.3.1

Findings

[141]

The Board considers Mr. Wilson’s view to be aligned with that of NS Power

regarding the use of a Monte Carlo analysis. This appears reasonable to the Board;

however, the Board will expect NS Power to be diligent in determining when such an

analytical approach is called for, and to undertake a rigorous analysis in those instances.

3.6

Revenue Requirement

[142]

In the Board’s 2011 and 2012 ACE Plan decisions, the Board directed NS

Power to provide an estimate of the effect which the ACE Plan spending might have on

the revenue requirement over the next five years. NS Power included this information in

its application, as it has done since those directives were issued. The Board’s purpose

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for the directives was to gain insight into the affordability of proposed ACE Plan spending.

The Board subsequently directed NS Power in the 2017 ACE Plan decision to provide the

same information based on assumptions from stakeholders.

[143]

NS Power provided the calculations for revenue requirement based on its

own, and on stakeholder, assumptions. In the application, NS Power claimed that the

table based on its assumptions (Figure 59) “shows that NS Power’s capital expenditures

have a cumulative decreasing effect on NS Power’s revenue requirement for customers

over the next five years, taking into account the contribution to fixed costs provided by

new customer additions.” After explaining the method of its calculation, NS Power stated:

This method does not address the revenue requirement effect should capital projects not

be completed. Costs resulting from not completing certain projects include items such as

increased operating costs, increased fuel costs, increased repair costs, and other risks or

implications. Avoided cost benefits are not included in this revenue requirement calculation.

[Exhibit N-1, p. 119]

[144]

In addition to cost recovery from customer growth, NS Power went on to

explain that Administrative Overhead (AO) and AFUDC credits and income tax impact

contributed to the cumulative decrease in revenue requirement.

[145]

The Board notes that NS Power does not believe that the stakeholder

assumptions accurately impact its capital program because the impact of fixed cost

recovery and AO and AFUDC credits are removed. In response to NSUARB IR-44, NS

Power acknowledged that AO is a main driver of the decrease.

[146]

NS Power also acknowledged in response to SBA IR-28 that the customer

growth used in determining the revenue requirement includes projected growth, and if

that growth is lower than projected, the revenue requirement increases. This led Mr.

Athas to conclude that, without support for the projected customer growth, that growth

should not be included to justify minimizing the revenue requirement. He described it as

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“misleading” and suggested the use of AO, most of which is in the early years, is not

appropriate. He said that NS Power should use a low case customer growth projection.

Mr. Athas concluded that the Board should make approval of the 2022 ACE Plan spending

“contingent upon its projected customer growth metric for each year being achieved.”

[147]

NS Power rejected the SBA’s suggestion for using a low case customer

growth scenario and said that the company had already provided such a scenario in

response to SBA IR-28 which resulted in no change, and had also demonstrated this in

Figure 59 by excluding all customer growth in the section entitled ‘Excluding Fixed Cost

Recovery.” In its closing submission, NS Power confirmed that the revenue requirement

is merely an estimate, and said it was neither necessary nor appropriate to adopt Mr.

Athas’ suggestion to make the 2022 ACE Plan spending contingent on the growth being

achieved.

3.6.1.1

Findings

[148]

While several years ago the Board directed the impact of proposed capital

spending on revenue requirement be included in the ACE Plan applications, the Board

now questions whether the information proves useful. As NS Power has acknowledged,

it is an estimate only. In the Board’s view, given the uncertainties surrounding estimates

in the calculation, and the lack of consensus on the inputs, the information does not

appear to be useful. The Board will not require this information to be included in the 2023

ACE Plan but reserves the right to seek information on the revenue requirement in a

future proceeding. The Board observes that the GRA proceeding later this year may shed

more light on this subject. Further, the Board agrees with NS Power that it should not

accept Mr. Athas’ suggestion to make approval of the 2022 ACE Plan contingent on the

achievement of projected customer growth.

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3.7

Contingency and Contingency Guidelines

[149]

Directive 7 of the Board’s 2020 ACE Plan Order directed NS Power to

develop non-binding contingency guidelines “…describing how it determines when a

capital cost estimate contingency amount is merited and at what level… .” The company

issued the Non-Binding Contingency Guidelines (Contingency Guidelines) on November

20, 2020 and revised them on August 31, 2021.

[150]

In this proceeding, Mr. Wilson made the following recommendation in his

report:

Include the following documents with every capital work order and application.

•

Project maturity classification checklist

Statement of the basis for the contingency guidelines including, as applicable:

a. Predetermined guidelines – reference to or statement of documented basis for

use of a standard “single contingency” or other referenced practice;

b. Subject matter expert judgement – documented reasons for the determination,

including a supporting risk register; and

c. Other, more technical methods - Supporting analysis as described in the

Contingency Guidelines. (Page 29)

[Exhibit N-10, p.5]

[151]

Mr. Dandurand confirmed during the hearing that NS Power would provide

the requested information for all projects with a capital cost over $1 million requiring Board

approval as part of the 2023 ACE Plan filing. This was further confirmed by the company

at pages 15-16 of its closing submission. The Board, therefore, directs NS Power to

follow through on its commitment and provide the information set out in Mr. Wilson’s

recommendation.

[152]

Mr. Wilson’s report also raised an issue with the use of expected accuracy

ranges in establishing a contingency amount. His concern was that the Contingency

Guidelines “…conflate the expected accuracy range of the budget estimate with the

contingency determination.”

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[153]

The portion of the Contingency Guidelines quoted by Mr. Wilson which gave

rise to his concern is reproduced for ease of reference:

NS Power recognizes that AACE makes no correlation between the contingency and the

upper limits of the estimate accuracy, however, the level of a project maturity and hence

the estimate class is directly related to the level of Uncertainty inherent in the project budget

estimate; as a result, there are varying levels of contingency that can be applied and

although NS Power starts with using the AACE recommended upper limits of the estimate

accuracy range to establish the range for the probable contingency, as project progression

develops, NS Power will take into account evidence such as budgetary quotes, RFP

responses, further detailed design, construction assessments and other insight as

necessary to narrow the proposed AACE accuracy where possible for a given class of

estimate.

[Exhibit N-4, RIR-15, Attachment 1, p.10]

[154]

In Mr. Wilson’s opinion there is an internal contradiction in the referenced

passage, where the AACE makes no correlation between the contingency and the upper

limits of the estimate accuracy, while NS Power uses the AACE “upper limits of the

estimate accuracy range to establish the range of the probable contingency… .” Mr.

Wilson provided the Nictaux Canal Crest Rebuild project as an example where the AACE

Class 3 estimate was apparently used to justify a 15% contingency, described as “…the

lower end of the 10-30 percent range of this estimate class…”

[155]

This analysis led Mr. Wilson to make the following recommendation:

Further clarify the Contingency Guidelines to avoid relying on the expected accuracy

range to set a contingency, considering an approach I suggest for application of the

predetermined guidelines method when used to determine a contingency.

[Exhibit N-10, p.5]

[156]

The predetermined guidelines method envisaged by Mr. Wilson would be

based on past performance modified up or down with the use of expert judgment. While

Mr. Wilson discussed, by way of example, aligning the expert judgment with a project’s

risk register, during questioning at the hearing he indicated a risk register would not

necessarily be required for every project. For example, standard projects which are done

over and over again might not require this type of assessment. Mr. Wilson did not want

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to become involved in micro-management but suggested a risk register would be useful

for civil hydro-electric projects.

[157]

NS Power was less receptive to this recommendation. The company

confirmed the predetermined guidelines method is one already found in the Contingency

Guidelines. NS Power agreed with Mr. Wilson that predetermined guidelines used with

expert judgment is an appropriate approach. That said, the company maintained that a

contingency range adds useful information in addition to methods such as predetermined

guidelines. NS Power suggested that if the contingency amounts for projects were

estimated at greater than 30%, they might not be ready for submittal. The company

further submitted “a contingency range also provides clear direction and bounds to project

managers.” Furthermore, the company said that because of the varying nature of projects

within an asset class, the predetermined guideline plus expert judgment approach may

not always be the preferred one.

[158]

The Board begins its analysis by noting that the issues being addressed

relate to non-binding contingency guidelines. These were developed in response to

concerns from stakeholders and the Board that, in numerous instances, it was difficult to

determine, and therefore assess, what specific factors went into the contingency figure

found in a capital work order. That said, as the guidelines are non-binding, the Board

must be careful not to make them too prescriptive or, as discussed by Mr. Wilson, become

involved in micro-management.

[159]

In every case, NS Power has the burden of showing that the chosen

contingency amount is reasonable. If the Contingency Guidelines are helpful in focusing

project managers on the need to have reasonable contingency figures reflected in the

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preparation and execution of capital work orders, and showing the reasonableness of

these figures to the Board, they are useful to both the company and the Board.

[160]

In this context, the Board has some difficulty in following how the range of

the expected accuracy of, for example, a Class 3 estimate under the AACE guidelines

informs the chosen contingency amount. NS Power and Mr. Wilson appear to agree that

the AACE guidelines related to the accuracy of estimates make no direct correlation

between this and the determination of contingency amounts.

[161]

The purpose of the AACE guidelines related to class estimates is to

establish a range of accuracy based on the amount of work that has been done to arrive

at these estimates. The purpose of these AACE guidelines is not to establish the potential

bounds of any contingency related to each known risk, sometimes referenced as “known,

unknowns.” Mr. Wilson said potentially unknown project risks, sometimes described as

“unknown, unknowns,” would be best addressed in a project management reserve type

of account.

[162]

The use of the expected AACE class estimate accuracy range to support a

contingency figure, such as appears to have been done in the Nictaux Falls Crest Rebuild,

does not appear to the Board to add much to the exercise. Using the AACE class

estimates to set upper bounds also potentially increases the project contingency to

unreasonable levels, as explained by Mr. Wilson in his testimony when discussing Figure

2 in his report, which is taken directly from the Contingency Guidelines.

3.7.1.1

Findings

[163]

The Board will not order the Contingency Guidelines to be altered at this

stage, given their non-binding nature. Mr. Wilson’s recommended approach appears to

have merit as it relates to transparency and simplicity. That said, the Contingency

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Guidelines have just been adopted by the company. The Board will, therefore, not, at this

stage, direct NS Power to limit its approach to the one suggested by Mr. Wilson.

[164]

Despite the foregoing, the Board is not satisfied NS Power’s evidence and

submissions on this point sufficiently address the possibility of conflating accuracy ranges

for estimates with the determination of a contingency amount. The Board would benefit

from a better understanding of how NS Power can address the concerns about

transparency, simplicity and potential inflation of contingency amounts when using the

estimated accuracy ranges arising from the AACE guidelines as a form of guidance in

arriving at a contingency amount. The Board directs NS Power to provide greater clarity

in this regard in the 2023 ACE Plan.

3.8

Eastern Clean Energy Initiative and Impact of Recent Provincial and

Federal legislation on Proposed Spending

[165]

The ECEI projects consist of C0044392 (Coal Conversion), C0044771

(Wind), C0044391 (Transmission) and C0045132 (Energy Storage). The goal of the

ECEI is to assist NS Power in the transition to 80% renewable electricity by 2030. These

projects are listed as items for subsequent submittal in the 2022 ACE Plan. They are,

therefore, not currently before the Board for approval.

[166]

The Coal Conversion project is for the conversion of up to two coal

generating units (Point Tupper and Trenton 6) to gas-fired units. Understanding that

scoping and project refinement have not reached a level required for submittal, the current

total capital cost estimate for this project is $32,341,325, with $9,390,264 forecast to be

spent in 2022.

[167]

The Wind project consists of 350 MW of wind energy from a provincial RFP,

along with new generation facilities for onshore wind of up to 160 MW in partnership with

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one or more Mi’Kmaq communities. The current total capital cost estimate for this project

is $83,280,972, with a budgeted forecast spend of $29,563,744 in 2022.

[168]

The Transmission project involves a portion of the proposed Atlantic Loop,

the purpose of which is to provide a transmission loop for accessing hydro-electric power

from Quebec and Newfoundland and Labrador. This portion of the project would expand

and upgrade the New Brunswick intertie and transmission capacity from that province.

The current capital cost estimate for this project is $351,898,909, with a budgeted forecast

spend of $20,378,370 in 2022.

[169]

The Energy Storage project envisages the purchase of four 50 MW 4-hour

grid scale batteries for installation on the transmission system, to assist in integrating new

renewable energy, provide energy arbitrage and resiliency services, along with firm

capacity and fuel savings. The current capital cost estimate for this project is

$171,207,920, with a budgeted forecast spend of $60,413,412 in 2022.

[170]

The total current capital cost estimate for the four ECEI projects is,

therefore, approximately $638,729,126, of which approximately $119,745,790 is

scheduled to be spent in 2022. The Board further understands that there are sensitive

ongoing negotiations with respect to potential government funding for portions of these

capital costs. Notwithstanding this, and the fact the company is not seeking approval of

the ECEI projects as part of this application, the level of spending attracted considerable

interest from the parties and the Board.

[171]

NS Power currently intends to file each capital work order for approval as a

separate project. The company says the four ECEI projects are consistent with the

scenarios developed in the recent 2020 IRP Action Plan. NS Power also says each

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project can stand on its own merits, separate and apart from the others, as part of an

overall approach designed to meet legislated climate change mitigation objectives.

[172]

The relationship between the ECEI projects and the 2020 IRP Action Plan

will be discussed in more detail below. Aside from issues related to consistency with the

2020 IRP, and any request by the parties to update the 2020 IRP, another issue raised

as part of the ACE Plan proceeding was whether the projects should be considered

separately by the Board. The Board further raised the issue of whether the ECEI could

proceed without government funding assistance. As well, the Board raised the risk

associated with natural gas conversions as a transitional energy source in the event

natural gas falls out of favour when total methane emissions from source to burning are

considered.

3.8.1.1

Findings

[173]

At this stage it is premature to provide any specific directions on many of

the issues canvassed during the hearing, as the ECEI projects are not before the Board.

Each project is tied to the goal of ending coal-fired generation in the province, significantly

reducing reliance on carbon-based energy, and substantially increasing renewable

energy production. NS Power has determined that each project can be justified on its

own. The Board should not pre-judge this assertion at this stage.

[174]

In the past, the Board has commented on the conceptual and analytical

difficulties which can arise, especially in the context of individual EAMs, when reviewing

large projects involving a single generating system, which are presented in phases. The

Board will simply comment that reviewing large projects with a common goal in isolation

has similar potential pitfalls if information gaps arise. This is particularly the case in the

context of the level of investment contemplated by the ECEI and its long-term systems

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and planning impacts. To avoid delays, with the knowledge of stakeholder concerns

expressed in this proceeding, engagement takes on added importance.

[175]

The Board is mindful that there are clear distinctions, for example, between

the transmission upgrades with New Brunswick, and eventually Quebec, and converting

coal plants to gas-fired ones. There would appear to potentially be direct links between

substantial increases in intermittent wind generation and grid scale battery storage. In

any event, all the projects relate to the decarbonization and renewable energy goal. The

need for certain attributes in notionally separate projects, such as, for example, firm

capacity attained through hydroelectric purchases or gasification of coal plants, could

theoretically be dependent on what firm capacity is achieved by each project. The onus

will be on NS Power to justify its approach and the Board expects a rigorous analysis.

[176]

NS Power has committed to providing project alternatives for each of the

four ECEI submittals. The number of viable alternatives will depend on the scope and

project refinements leading to the ultimate applications. This is the methodology

envisaged by the CEJC and the Board expects all reasonable and viable alternatives to

be included. Depending on how these alternatives are presented, it may or may not

alleviate Mr. Wilson’s concern about EAMs for ECEI projects that are considered in

isolation from the other ECEI projects. That is for another day.

3.9

Alignment with the 2020 IRP

[177]

The 2020 IRP proceeding involved a comprehensive exercise with

significant stakeholder input. The goal was to develop a robust and risk-weighted long-

term strategy to guide NS Power in meeting government decarbonization goals in a safe

and reliable manner at the least cost to its customers. Through the engagement process,

the company produced a number of scenarios in order to explore future policy options

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and resource strategies, which were tested against various potential future conditions and

circumstances.

[178]

In its rebuttal evidence, NS Power described one of the outputs of the 2020

IRP process as follows:

Another key objective of NS Power’s 2020 IRP was to construct an Action Plan and

Roadmap outlining the key tasks to be undertaken in the next five years to implement the

strategy, and to identify signposts to monitor and decision gates to be addressed in order

to enable carefully considered changes in strategy as the external policy, technology, and

market landscape evolves. This Action Plan and Roadmap are directly informed by the

modeling performed by NS Power as part of the 2020 IRP analysis, which reflected a range

of potential external influences, as well as by other known potential future uncertainties.

[Exhibit N-12, p. 13]

[179]

Both Mr. Wilson and Mr. Athas were concerned about the alignment of the

four proposed ECEI projects for subsequent submittal with the 2020 IRP. Both made

recommendations on how NS Power should present the four capital work orders to the

Board for approval.

[180]

Mr. Wilson made the following recommendation:

Demonstrate that the levels of investment in proposed Eastern Clean Energy Initiative

projects are supported by an optimal resource plan based on a scenario similar to 2020

IRP Scenario 3.1C, and that NS Power has engaged directly with stakeholders in

developing this demonstration prior to filing its subsequent submittals.

[Exhibit N-10, p. 5]

[181]

Mr. Athas said that a full perspective on an update to the 2020 IRP should

be provided before approval of the four ECEI projects is considered by the Board. He

stated:

It will be crucial to conduct a thorough evaluation of the ECEI CIs once NSPI submits them

for approval. The Board should be careful in its review and delay any approval of these

matters until the updated IRP modeling is complete and NSPI has more certainty regarding

its long-term resource strategy.

NSPI has stated that each ECEI investment stands on its own and intends to submit for

approval as separate capital filings. However, due to the integrated nature of the

investments, it is important that the Board have an updated, complete picture of NSPI’s

long-term planning strategy prior to considering any of these large investment decisions.

[Exhibit N-9, pp. 19-20]

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[182]

In its rebuttal evidence and submissions, NS Power says the purpose of an

IRP is not to prescribe specific investments. The company, therefore, disagrees with any

suggestion that the four projects either displace components of the 2020 IRP or are

investments which formed part of the IRP. That said, NS Power views the four ECEI

projects as aligned with the 2020 IRP strategy. It provided a detailed description of its

position on this alignment in its rebuttal evidence.

[183]

The company further points out that it filed its first annual 2020 IRP Action

Plan update on January 21, 2022. It says stakeholder engagement will take place with

respect to this report and other evergreen related aspects of the IRP. NS Power does

not agree that the submittal of the ECEI projects should await a complete update of the

2020 IRP. The company says no specific direction should be provided at this time. It

argues the Board’s process when the capital work orders are submitted is the proper

venue to address issues related to alignment with the 2020 IRP.

[184]

NS Power goes on to say how it sees the Board approval process will

address IRP alignment concerns and burden of proof the company expects it will have to

meet:

Having said that, the Company reiterates that it is committed to continuing to engage

interested parties around the process to keep its IRP strategy evergreen. As of the filing of

this Closing Submission, NS Power and stakeholders have begun to engage with respect

to updated scenarios that reflect recent decarbonization policies.

NS Power further notes that the IRP is not intended as the venue to test specific projects

for approval. Upon submission to the Board, the ECEI projects will (i) be thoroughly vetted

and fully justified; (ii) will confirm consistency with IRP Findings, IRP Roadmap Items, and

IRP Action Plan Items; and (iii) be supported by the appropriate analysis.

[Exhibit N-22, p. 11]

[185]

NS Power is concerned about the relatively short time the company has to

meet the 2030 targets related to coal generation and renewables. It is one of the reasons

why it opposes delaying project submittals pending updated 2020 IRP modeling. In

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response to a Board question about potential delay if an updated IRP modelling exercise

is not done in advance of the submittals, Ms. MacDonald provided the following view:

The way that the model will be updated to consider the projects is the same type

of work that would happen to update the relevant generic plan. And we are at the stage

where we’ve spent a couple of years with the directional plans and have paths that look, if

not exactly like ECEI, similar.

And the next step is the project definition to then evaluate using both the starting

point of the IRP and the updated analysis that goes with the project, but in the IRP

Evergreen, so to speak, set of inputs and modelling runs.

So in that way, I think we're talking about the same thing, but to pause for X-months

to have one happen before the other, we don’t think it's necessary.

[Transcript, pp. 242-243]

[186]

Mr. Athas appeared to be relatively satisfied, at least in principle, with the

evidence NS Power provided about his concerns in its rebuttal evidence and in responses

to questioning during the hearing. In his opening remarks, Mr. Wilson indicated the type

of updated modeling he was recommending, while involving a significant amount of work,

was not equivalent to the extensive 18-month 2020 IRP process, as NS Power had

suggested in its rebuttal evidence. He is still of the opinion this updated modeling should

occur before the four ECEI projects are submitted for approval.

3.9.1.1

Findings

[187]

The Board agrees with the general proposition that the purpose of an IRP

is not to prescribe specific investments. When, however, there are short time horizons

for completing a massive change in the way the electricity system will produce and deliver

energy, it is clear the 2020 IRP forms an integral part of any capital works planning. An

Action Plan Update and Roadmap were developed from the exercise with a relatively

short initial five-year horizon.

[188]

The Board would, therefore, expect there would be alignment between the

scenarios reviewed in the 2020 IRP, or any updated modeling related thereto, and the

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2020 IRP Action Plan Update and Roadmap, and any related updating. NS Power

acknowledges this in its rebuttal evidence and submissions. The issue is how and when

this updated modelling should occur. Because of the scope of the projects, and the

urgency of addressing the fast-approaching 2030 deadlines, NS Power says this can be

done in parallel with the preparation and submittal of the four ECEI projects.

[189]

The Board agrees in principle that a parallel approach could achieve the

desired result. It will, therefore, not direct an alternative approach. That said, the devil is

in the details. The Board has cautioned NS Power about its concerns that time could

potentially be wasted if all the modelling is not done before submitting the applications. It

will be up to NS Power, as the proponent, to marshal its resources and plan its approach

to avoid this scenario.

[190]

The Board expects NS Power to include, in its approval requests for the

ECEI projects, all relevant information that should allow for an efficient and timely review

of these applications.

3.10 Total Cost of Ownership for IT Projects and Electric Vehicles

[191]

Total cost of ownership (TCO) is the cost to acquire an asset plus the cost

to operate it over its useful life. It accounts for all the costs, both the upfront acquisition

costs and those to be incurred to operate the asset. In addition to providing a

comprehensive understanding of the cost of a capital investment, a TCO is considered a

useful tool for comparing capital investment options to determine the best value for

money.

[192]

In its 2021 ACE Plan decision, the Board directed the stakeholder

engagement to address whether NS Power should provide the Board with a TCO estimate

for the PAM IT project (CI 49094), and whether NS Power should be directed to routinely

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provide such information for IT projects with capital budgets over $1 million. The 2021

Stakeholder Engagement Report indicated that although consensus was not reached with

all stakeholders regarding whether a TCO for the PAM IT project was necessary, NS

Power agreed to provide a TCO for IT projects over $1 million if an alternative is available,

and not cost prohibitive. If an alternative is not available or not available for a reasonable

price, then it will provide additional explanatory information.

[193]

In his evidence, Mr. Wilson noted that expensive IT projects are increasingly

accounting for larger portions of NS Power’s investments. Mr. Wilson considers that,

given the short useful life of these investments, a TCO analysis should be brief and

primarily use information from the project budget with assumptions regarding pricing after

the contract term.

[194]

Mr. Wilson recognized that there may be unanticipated costs from items that

are out of the scope of a project when it is submitted to the Board for approval. Therefore,

he considers that it is reasonable for NS Power to provide a TCO analysis at a Class 1 or

2 level of maturity.

[195]

Mr. Wilson took issue with NS Power’s limitation to providing additional

evidence to the Board upon request for IT projects over a $1 million dollars when an

alternative is not available. He found three problems with this approach:

1. Other parties or the Board may have a different opinion on whether a proposed project

is the only technically or economically feasible alternative;

2. The opportunity to obtain a TCO “on request,” presumably in response to the only

information request opportunity, denies parties the opportunity to question NS Power

regarding the assumptions and methods it used to develop the TCO; and,

3. Even if there is no alternative to the proposed project, parties and the Board should

understand the full implications of project approval. For example, the assumptions

included in the TCO may indicate constraints that parties may wish to question in light

of other planned investments by NS Power. Such review ensures that NS Power can

demonstrate a full understanding of the requirements to maintain and further develop

its IT investments.

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[Exhibit N-10, p.41]

[196]

project with a budget over $1 million unless an EAM is prepared.

[197] NS Power stated that it will provide a TCO when there are technically

Mr. Wilson recommended that NS Power submit a 10-year TCO for each IT

feasible alternatives and an EAM is not provided; however, if the project is valued over

$1 million and an EAM is not provided to the Board, then NS Power will give explanatory

information as to why there are no other alternatives.

[198]

In the hearing, NS Power was asked by the Board whether a TCO is applied

only to IT projects, or if it is referred to, or used in the CEJC, and if the TCO is different

from other methods of analysis for capital projects:

Q.

(Clarke) So how do you -- is the total cost of ownership different from

something that else that’s looked at when capital projects are put forward? Does it relate

only to IT or only to electric vehicles? Obviously it’s those two have been mentioned.

A.

(Willett) So we’ve typically been talking about total cost ownership in

relation to IT projects but as you mentioned, electric vehicles, so it is a relatively newer

term that’s been introduced in these proceedings and discussions on ACE approval.

Q.

And does it get at the same information that you provide in other capital

projects, in terms of looking at the cost of a piece of equipment or something else?

A.

(Willett) So I would say in -- when we’re comparing alternatives within a

project in an EAM, it would be comparing all the capital and sustain operating costs. So a

similar process would be undertaken in an economic analysis model.

Q.

Okay. So since it’s not referred to in the CEJC, do you feel that there

should be any amendment to the CEJC to reflect that consideration, or is it adequately

covered in the requirements that are set out there already?

A.

(Willett) So I think that there could be some clarification on the TCO in that

document to help with ensuring that there’s clarity on what’s being discussed when

discussing TCO versus an EAM.

Q.

And particularly, I guess as it relates to IT projects because that seems to

be where it’s most commonly used up to this point. Is that right, Mr. Cummings?

A.

(Cummings) That’s certainly where it’s been discussed to date, Madam

Chair.

[Transcript, pp. 338-339]

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[199]

The CA stated in his closing submission that the clarification to the CEJC

would be a useful addition.

[200]

In Undertaking U-12, NS Power submitted a TCO analysis for two vehicles

it compared in 2019. NS Power elaborated:

While the TCO for the RAV4 HEV AWD is less than the Ford Escape ICE AWD, the cost

of retrofitting the vehicles with custom equipment post purchase of the vehicles is not

included in the TCO analysis. In addition, TCO analysis was not being completed as

broadly in 2019 as it is today. Given the increase in the price of gasoline in 2022 and

greater spread in the TCO between the two vehicles, NS Power’s current planning for

replacement of Ford Escape ICE AWD vehicles in a planned manner includes sourcing

vehicles such as the Toyota RAV4 HEV (AWD) whenever it is beneficial for customers to

do so.

[Exhibit N-19, U-12]

[201]

Board Counsel requested that NS Power confirm that all vehicles being

compared have the same useful life. Board Counsel asked:

Q.

Is it possible, Mr. Drover, that eight years is what’s being used for the

analysis on all these vehicles?

A.

(Drover) Subject to check. We have used eight years for our internal

combustion vehicles in the past. Most of those were treated equal. As we’re doing the

analysis of the other vehicles, there are lots of unknowns that may factor into that as well.

Q.

So, all right, would you confirm whether eight years is being used for all of

the HEVs and the Ford ICE?

[Transcript, pp. 174-175]

[202]

TCO of vehicles which is assumed for all types of vehicles.

[203] In its closing submission, NS Power stated that it considers it unnecessary

In Undertaking U-14, NS Power confirmed that eight years is used in the

to provide a TCO for every IT project over $1 million. The company explains that when

there is only one feasible option for an IT project, it will be justified in accordance with the

CEJC and will include explanatory information as to why there is only one alternative.

With respect to the CA’s request for a 10-year timeframe for IT project TCOs, in its closing

submission NS Power claims that:

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… An examination of future costs associated with software/IT licensing requirements, for

example, may not always be known with certainty beyond the short term, and so such an

analysis over a 10-year period (as is being requested by Mr. Wilson) will not add meaningful

value for customers.

[Exhibit N-22, p. 25]

3.10.1.1 Findings

[204]

The Board finds the CA’s request that NS Power use a 10-year timeframe

for an IT project TCO is inflexible. NS Power is directed to use a TCO timeframe to match

that of the expected useful life of the IT software and/or hardware. This approach is

currently applied to other investments as demonstrated by NS Power’s use of an eight-

year TCO for vehicle purchases. The Board finds it appropriate for NS Power to have

flexibility to select an appropriate timeframe for a TCO analysis that is in keeping with the

useful life of an investment rather than a prescribed timeline.

[205]

The Board considers that NS Power’s offer to provide a TCO for IT projects

over $1 million only when there is a technically feasible alternative, and an EAM is not

provided, is inadequate. The Board finds that a TCO provides a fulsome understanding

of a project’s costs over the course of its useful life, rather than just a tool for comparing

options. Therefore, the Board directs NS Power to use a TCO for IT projects over $1

million when an EAM is not provided, whether or not an alternative is available.

[206]

The Board finds that the CEJC requires revision to include the TCO model

in Section 6.3 Economic Analysis. NS Power is directed to revise the CEJC in consultation

with Board staff and stakeholders. This consultation should be completed in time for a

revised CEJC to be submitted to the Board with the 2023 ACE Plan application.

3.11 Impact of COVID-19 on Capital Spending and Lessons Learned

[207]

Because of the number of projects deferred or cancelled in 2020 due to the

COVID-19 pandemic, in its 2021 ACE Plan decision, the Board directed NS Power to

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provide more detailed information in its quarterly reports to the Board on any projects

deferred or cancelled due to the pandemic. NS Power has continued to provide that

information.

[208]

In its application, NS Power reported that it has adapted its processes to

ensure that there is no material impact from COVID-19 on the reliability of the electricity

system generally, and to ensure safety. The Board observes that in various documents

in support of specific projects, suppliers or contractors referred to COVID-19 and its

implications for safety and supply chain delays, which has impacted costs. The Board

has already noted this in its discussion on the VJ1 projects in the 2022 ACE Plan earlier

in this decision.

[209]

The Board notes from various IR responses that there have been delays in

work vehicle replacements (NSUARB IR-38), delivery of blades (NSUARB IR-63), and in

the protocol of equipment spares due to supply chain disruptions (SBA IR-14) attributed

to COVID-19. However, NS Power confirmed in Undertaking U-24 that while the

pandemic has been a factor for consideration, no projects were deferred or cancelled in

2021 due to COVID-19, unlike 2020.

[210]

The Board explored the implications of the pandemic with the NS Power

witnesses:

Q.

(Chair): …Has there been a significant change in the impact of the COVID-

19 over the past three years, starting in 2020? As I said, last year's plan talked about a lot

of projects being deferred as a result of that. And then we had 2021 just passed, and now

we're, I guess, at least up to today, still with the -- living with various restrictions.

So I'm wondering if there's been any change over that period of time?

A.

(Dandurand) As you've noted, Madam Chair, we've also been adjusting to

the restrictions related to the COVID-19 pandemic over time, and certainly, there's still

impacts from the pandemic in the execution of our capital projects.

But the company, again, has adapted to those quite well, and has implemented,

you know, the required practices and procedures in order to execute our capital

programmes, as I believe we've been demonstrating over the last number of years. And

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one of the things I would say that is relatively new that we have an eye to would be related

to the supply chain, and so seeing supply chain impacts, or I should say, keeping an eye

on supply chain impacts and the potential that that may have on the execution of our

projects going forward.

…

…I would say that as per our prior comments and discussions through the 2021

ACE Plan, certainly, would have had to react to the impacts of the COVID-19 pandemic,

but going into this year's ACE Plan and over the course of the last year, we’ve continued

to adapt to the pandemic and incorporated the necessary elements within our execution

plans in order to be able to execute as best we can in the face of what the pandemic brings.

Q.

Mr. Dandurand, were there any projects deferred in 2021 specifically due

(Dandurand) I'll just need to caucus on that for a moment, Madam Chair,

to COVID-19?

A.

…

So for specific examples in that timeframe that you've mentioned, I would need to

go and look at the cancelled and deferred list from the prior year's ACE Plan, from the 2021

ACE Plan, to see if there are specific projects that were cancelled or deferred exclusively

for the reasons related to the COVID-19 pandemic.

But I would say that in general, there were some projects that were impacted in

that timeframe, so for last year. And by that, I mean the COVID-19 pandemic would have

had an impact on the execution of some of those projects, in terms of timing, in some

cases, as the company adapted to working under those restrictions related to the

pandemic.

…

Q.

And continuing along that COVID vein, in the application at page 10, the

company said it's continuing to adapt, and specifically, in quotes, "Changes continue to be

implemented," and again in quotes, "Processes enhanced" regarding that.

So I'm wondering if you could describe the changes and process enhancements

in somewhat greater detail?

…

A.

(Dandurand) Yes, Madam Chair, I see it there now, and I would say that

most of the changes that have been implemented would relate to the operational elements

of our business, so both on the power production side of our business and on the T&D side

of our business.

And as I'm sure you can appreciate, the nature of the work that our operational

employees do, certainly there's a heightened level of risk for those employees, in the face

of what the pandemic has brought, due to the nature of their work.

…

Q.

Just to take it a little bit further, the application itself was filed in November

of 2021. The situation then was different than it is now, hopefully, so is there any change

that you're aware of in the current state, in the near future expectations?

A.

(J. MacDonald) Madam Chair, this is Mr. MacDonald. I can speak to that.

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So I would say one word for us that’s changed with respect to the early days of the

pandemic is just adaptability. We’ve built numerous procedures and processes, but we've

also learned that we have to move and adapt very quickly, because from one day to the

next, things can change, you know?

And just even over the last few months, we've had a number of employees have

come down with Covid. We’ve had one plant in particular have over 30 employees infected

through our peak season. So we’ve had to adapt buildings’ contingency plans, so in the

event that, you know, we got into a situation where we couldn’t run a unit, we would move

people from the other areas over. So we built contingency plans in the event that we had

serious pandemic concerns at one site or another.

But, you know, I think daily pandemic calls in the morning, coordination calls,

making sure everybody knows what’s happening in every plant across the province,

sharing resources, and building out strong procedures and processes, those are just a few

elements of the change and improvements that we’ve made from onset of the pandemic.

Q.

Mr. MacDonald, are those the kinds of improvements that you might see

continuing even when there is no issue with Covid?

A.

(J. MacDonald) Absolutely.

[Transcript pp. 343 to 350]

3.11.1.1 Findings

[211]

The Board is satisfied that NS Power is working to ensure that COVID-19

does not negatively impact operation of the electricity system. The pandemic has been

a challenge in all areas of business and, indeed all aspects of life, in the province.

Challenges will continue, especially in relation to the supply chain, and there will

undoubtedly be cost implications. While that requires NS Power to continue to be diligent

in its procurement practices, as well as project management, the Board is encouraged by

Mr. MacDonald’s assurance that the company has learned lessons and improved

practices that will continue in the future to the benefit of ratepayers. The Board expects

nothing less.

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4.0

SUMMARY

The Board approves the 2022 ACE Plan and lists the approved projects in

[212]

Schedule “A”. The Board has provided comments on reliability investments, the EAM,

ECEI projects, alignment with the IRP, and impact of COVID-19 in this decision.

[213]

The Board directs NS Power to:

1.

Provide a table in future ACE Plan applications similar to the table provided

in NSUARB IR-10(e), modified in accordance with the direction in

Paragraph 66 of this decision.

2.

3.

Continue to track the information referred to and as modified in Paragraph

67 and 68 of this decision.

Continue to provide examples of cost minimization efforts over the previous

year in future ACE Plan applications as directed in Paragraphs 94, 95 and

98 of this decision.

4.

Implement the Project Delivery Model (PDM) and engage with stakeholders

regarding a capital cost estimating process in the PDM as discussed in

Paragraphs 99 and 100.

5.

6.

7.

Adopt the proposed criteria and capital cost thresholds to trigger post-

project reviews as set out in Paragraph 101 of this decision.

Remove information as previously required on the impact of proposed

capital spending on revenue requirement in the 2023 ACE Plan.

Provide greater clarity in its use of the estimated accuracy range from AACE

guidelines as guidance to arrive at a contingency amount in the 2023 ACE

Plan.

8.

Implement the framework and reporting protocols referred to in Paragraph

102 in advance of the 2023 ACE Plan application.

9.

Provide the information outlined in Paragraph 150 for all projects with a

capital cost over $1 million in the 2023 ACE Plan.

10.

Regarding Total Cost of Ownership to:

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a. Use a TCO timeframe to match the expected useful life of IT software

and hardware;

b. Use a TCO analysis for all IT projects over $1 million when an EAM

is not provided, whether or not an alternative is available; and

c. Revise the CEJC in consultation with stakeholders and Board staff

regarding TCO in time for a revised CEJC to be submitted to the

Board with the 2023 ACE Plan application.

[214]

An Order will issue accordingly.

DATED at Halifax, Nova Scotia, this 9th day of June, 2022.

______________________________

Roberta J. Clarke

______________________________

Steven M. Murphy

______________________________

Richard J. Melanson

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SCHEDULE “A”

2022 ACE Plan Approved Projects

CI Number

Title

2022 Budget Project Total

Generation

C0038747

LIN1 L-0 Blade Replacement

$1,289,669

$5,532,037

$3,276,746

$1,629,446

$1,126,746

$930,499

$6,066,800

$5,942,640

$3,729,597

$1,629,926

$1,362,281

$1,145,245

$1,016,225

C0029693 CT - VJ1 Generator Replacement

C0041906 PHB – 2022 Turbine Refurbishment

C0030529 TUC3 Generator Refurbishment

C0036368 HYD - Lower Great Brook Switchgear Replacement

C0024484 HYD - Fourth Lake Switchgear Replacement

C0029691 CT - VJ1 Control System Upgrade

Transmission

$751,417

C0041893 2022/2023 Transmission Right-of-Way Widening 69kV

$2,536,790

$2,299,568

$5,312,315

$3,805,434

2022/2023 Substation Polychlorinated Biphenyl (PCB)

C0041837

Equipment Removal

C0041793 L7002 Replacements and Upgrades Phase 2

C0041805 L7005 Replacements and Upgrades Phase 2

C0041989 2022/2023 Sacrificial Anode Installation Program

C0041794 L5031 Replacements and Upgrades Phase 2

C0041789 L5550 Replacements and Upgrades Phase 2

C0041796 L6020 Replacements and Upgrades Phase 2

C0041810 L5022 Replacements and Upgrades

$564,090

$1,399,971

$646,705

$3,640,960

$3,182,518

$3,015,107

$644,038

$702,915

$1,225,755

$920,607

$765,590

$511,414

$696,045

$525,751

$563,202

$454,663

$2,905,019

$2,698,515

$2,518,243

$2,172,200

$1,988,246

$1,612,638

$1,395,537

$1,300,037

$1,270,698

$1,242,178

C0041791 L6551 Replacements and Upgrades

C0043571 2022/2023 Transmission Switch & Breaker Replacement

C0041790 L8001 Replacements and Upgrades Phase 2

C0043010 2022/2023 Wood Pole Retreatment Program

C0041800 L5537 Replacements and Upgrades

C0041804 2022 Line Retirement Program

Distribution

C0041892 New Distribution Rights-of-Way Phase 7

C0043130 2022 Padmount Replacement Program

TOTAL APPROVED AMOUNT

$2,940,175

$1,386,611

$33,320,452

$9,854,291

$1,807,359

$70,614,010

Document: 295729