NSP Maritime Link Incorporated

DECISION

2022 NSUARB 18

M10206

NOVA SCOTIA UTILITY AND REVIEW BOARD

IN THE MATTER OF the PUBLIC UTILITIES ACT and the MARITIME LINK ACT and

the MARITIME LINK COST RECOVERY PROCESS REGULATIONS

- and -

IN THE MATTER OF AN APPLICATION by NSP MARITIME LINK INCORPORATED for

final approval of the Maritime Link Project Costs and approval of the 2022 cost

assessment

BEFORE:

Peter W. Gurnham, Q.C., Chair

Roland A. Deveau, Q.C., Vice Chair

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

APPLICANT:

INTERVENORS:

NSP MARITIME LINK INCORPORATED

Colin J. Clarke, Q.C.

Ian Mondrow, Counsel

Mary Ellen Greenough, Counsel

CONSUMER ADVOCATE

William L. Mahody, Q.C.

Emily Mason, Counsel

SMALL BUSINESS ADVOCATE

E.A. Nelson Blackburn, Q.C.

Melissa MacAdam, Counsel

INDUSTRIAL GROUP

Nancy Rubin, Q.C.

ALTERNATIVE RESOURCE ENERGY AUTHORITY

David MacDougall, Counsel

PORT HAWKESBURY PAPER LP

James MacDuff, Counsel

NOVA SCOTIA POWER INCORPORATED

Eric MacRae, Counsel

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BOARD COUNSEL:

HEARING DATES:

S. Bruce Outhouse, Q.C.

December 6-8, 2021

FINAL SUBMISSIONS: January 14, 2022

DECISION DATE:

DECISION:

February 9, 2022

The Board approves NSPML’s application subject to the

amendments summarized in paragraph 4.

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TABLE OF CONTENTS

1.0

2.0

3.0

4.0

5.0

SUMMARY ........................................................................................................... 5

BACKGROUND.................................................................................................... 7

STATUTORY PROVISIONS................................................................................. 9

ISSUES .............................................................................................................. 10

ANALYSIS AND FINDINGS ............................................................................... 11

5.1

Were the Board’s 2017 conditions for this application met? .................... 11

Findings ................................................................................................... 14

What consequences flow from NSPML’s failure to meet those conditions?

................................................................................................................. 15

Findings ................................................................................................... 16

Was it prudent to sign the Acceleration Agreement?............................... 17

Findings ................................................................................................... 19

When should the equivalent economic value of NS Block under-deliveries

be determined?........................................................................................ 26

Findings ................................................................................................... 29

Integrity of Submarine Cable ................................................................... 29

Findings ................................................................................................... 33

Depreciation Policy and Depreciation Rates............................................ 33

Findings ................................................................................................... 35

NSPML’s Overall Project Execution......................................................... 35

5.7.1 Project Planning, Management, and Governance......................... 36

Findings ................................................................................................... 39

5.7.2 Financing Program........................................................................ 39

Findings ................................................................................................... 41

5.7.3 Management of the Submarine Cable Program............................ 41

Findings ................................................................................................... 44

5.7.4 Management of the Overland Transmission Program................... 45

Findings ................................................................................................... 50

5.7.5 Management of the Converter Station and Related Works Program

........................................................................................... 51

5.2

5.3

5.4

5.5

5.6

5.7

Findings ................................................................................................... 54

5.7.6 Management of Completion and Commissioning.......................... 55

Findings ................................................................................................... 56

Affiliate Transactions................................................................................ 56

Findings ................................................................................................... 57

Accounting or Tax Issues......................................................................... 57

Findings ................................................................................................... 60

5.8

5.9

5.10 Incentive Executive Compensation.......................................................... 61

5.10.1 Intervenor Comments.................................................................... 62

Findings ................................................................................................... 64

5.11 Sponsorships and Donations................................................................... 65

Findings ................................................................................................... 68

5.12 Final Project Capital Costs, including AFUDC ......................................... 70

Findings ................................................................................................... 75

5.13 Opening Rate Base ................................................................................. 76

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Findings ................................................................................................... 78

5.14 2022 Cost Assessment............................................................................ 78

Findings ................................................................................................... 82

5.15 Future Reporting Requirements............................................................... 87

Findings ................................................................................................... 88

5.16 Adjustment of Rate of Return................................................................... 89

Findings ................................................................................................... 92

5.17 Lingan 2 Retirement ................................................................................ 92

Findings ................................................................................................... 93

COMPLIANCE FILING ....................................................................................... 94

6.0

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1.0

SUMMARY

NSP Maritime Link Incorporated (NSPML) applied to the Nova Scotia Utility

[1]

and Review Board on August 9, 2021, for final approval of the Maritime Link Project Costs.

The application requests approval of:



Maritime Link Project Costs of $1.5712 billion and an Allowance for Funds

Used During Construction (AFUDC) of $208.8 million;

an opening rate base as at January 1, 2022 for NSPML of $1.7618 billion,

inclusive of unamortized deferred financing costs incurred as part of the

Federal Loan Guarantee financing program and net of recoveries to date

on account of depreciation and amortization;



a depreciation policy for NSPML and proposed depreciation rates; and

a 2022 assessment for recovery from NS Power of NSPML’s 2022 revenue

requirement, including depreciation and return on equity, in the total amount

of $169.4 million.

[2]

The 2022 cost assessment is the amount that will be paid by NS Power and

recovered from its customers in order to finance the Maritime Link. Pending final approval

of the application, NSPML requests that the 2021 monthly cost assessment continue on

an interim basis (i.e., on a level representing a total of $172.2 million per year). This

amount is currently reflected in NS Power’s rates.

[3]

NSPML states that the Maritime Link Project was completed on time and on

budget. The Maritime Link was placed in-service on January 15, 2018. However, as

described in earlier Decisions of the Board, the delivery of the NS Block of energy has

been delayed due to a variety of problems related to the construction and commissioning

of the Muskrat Falls Generating Station and the Labrador Island Link. However, on

August 6, 2021, NSPML signed an Acceleration Agreement with Nalcor, which effectively

commenced the delivery of the NS Block starting August 15, 2021.

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[4]

Having held a hearing and considered all of the evidence and submissions

in this matter, the Board approves NSPML’s application subject to the following

amendments:

 a holdback, as more particularly described in paragraph [31] of this Decision,

beginning April 1, 2022, in the amount of $2 million per month to ensure

NSPML/NS Power achieve and receive at least 90% of the basic NS Block and

Supplemental Energy;

 a reduction in operating and maintenance costs for 2022 of $500,000;

 a deduction from project capital costs of $700,000 to reflect a disallowed affiliate

transaction;

 an adjustment to project capital costs to reflect that NSPML may only recover

from ratepayers 50% of incentive compensation; and

 an adjustment to project capital costs to reflect that NSPML may only recover

80% of sponsorship and donations.

[5]

The planning and development of the Maritime Link Project was a significant

endeavor. There have been numerous examples across North America of substantial

cost overruns and construction delays of energy mega-projects. The completion of the

Maritime Link Project on time and on budget was a commendable achievement attributed

to NSPML's actions throughout all phases of the project. While there continue to be

delivery delays of the NS Block, NS ratepayers will benefit from NSPML's development

of the Maritime Link Project, including its continuing efforts with Nalcor as they both strive

to secure an important source of renewable energy for Nova Scotians and our neighbors

in Newfoundland and Labrador.

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2.0

BACKGROUND

NSPML applied to the Board on August 9, 2021, for final approval of the

[6]

Maritime Link Project (ML Project) Costs. The application is made pursuant to s. 8 of the

Maritime Link Cost Recovery Regulations (ML Regulations) and s. 64 of the Public

Utilities Act for approval of:

(a)

the Project’s final capital cost of $1.5712 billion (Project Costs) and AFUDC of

$208.8 million;

(b)

an opening rate base for NSPML, as at January 1, 2022, of $ 1.7618 billion, which:

(i)

includes unamortized deferred financing costs of $45.7 million; and

(ii)

takes into account amounts previously recovered for depreciation and

amortization totaling $63.9 million;

(c)

(d)

the proposed depreciation policy for NSPML; and

a 2022 assessment for recovery from Nova Scotia Power Inc. (NS Power) of

NSPML’s 2022 revenue requirement in the amount of $169.4 million.

[Exhibit N-1, p. 5]

[7]

With respect to the 2022 cost assessment, NSPML anticipated that this

proceeding may not be fully completed by the end of 2021 and, accordingly, it requested

an interim Order continuing 2021 monthly assessment payments from January 1, 2022,

representing an annual cost assessment of $172.2 million. This would represent a

temporary continuation of the 2021 cost assessment and is the amount already reflected

in Nova Scotia Power Incorporated’s (NS Power) rates to its ratepayers under the Board’s

2020-2022 Base Cost of Fuel (BCF) Decision, 2019 NSUARB 165. This request

contemplates that the Board will set NSPML’s monthly assessment payments for the

remainder of 2022 following the issuance of its final Decision and Order, taking these

interim monthly payments into account. The Board issued an Interim Order on December

15, 2021, approving the $172.2 million 2022 cost assessment, subject to continuation of

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the previously directed $10 million holdback and pending further Order of the Board

following its disposition of the final cost application.

[8]

The Board has repeated in its prior Decisions that it would not consider

NSPML’s application for approval of final costs of the ML Project until NS ratepayers are

receiving the NS Block that NSPML had originally promised:

[153] …The Board is not prepared to hold the Final Assessment hearing until it knows

that the NS Block is being delivered in accordance with the original bargain. This will

enable the Board to reserve whatever regulatory options may be available to it in the event

of further unfortunate news.

…

[155] However, the Board is not prepared to approve the final assessment until it is

confident the ratepayers will get what they bargained for – the NS Block, Supplemental

Energy and Nalcor Market-priced Energy.

[2017 ML Interim Assessment Decision, 2017 NSUARB 149]

[9]

The Maritime Link (ML) was placed in-service on January 15, 2018. As

described in earlier Decisions of the Board, and in evidence in this proceeding, the

delivery of the NS Block has been delayed due to a variety of problems related to the

construction and commissioning of the Muskrat Falls Generating Station (MFGS) and the

Labrador Island Link (LIL). NSPML asserted in its application that the NS Block started

on August 15, 2021, as a result of its execution of an Acceleration Agreement with Nalcor

on August 6, 2021. However, continuing problems with LIL pre-commissioning activities,

has resulted in continuing delivery delays of the NS Block, including Supplemental

Energy. NS Power and Nalcor are coordinating forecasts and schedules for the make-

up of undelivered energy.

[10]

Following the filing of Information Requests (IRs) and evidence by various

parties, the hearing was held from December 6 to 8, 2021, by way of a GoToMeeting

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webinar due to the continuation of the COVID-19 pandemic, with all counsel present in

the Board’s hearing room, but the witnesses appearing by videoconference.

3.0

STATUTORY PROVISIONS

[11]

The ML Project is defined under the Maritime Link Act, S.N.S. 2012, c. 9

(ML Act) as follows:

2

(c)

"Maritime Link Project" means the design, construction, operation and

maintenance of the Maritime Link, together with the related transactions involving the

delivery of energy, the provision of transmission services over the Maritime Link and the

enabling of transmission service through the Province, as set out in a term sheet between

Emera Incorporated and Nalcor Energy dated November 18, 2010; [Emphasis added]

[12]

The ML Act provides that the Board has the general supervision of the ML

Project and of an applicant in respect of the ML Project:

4

The Review Board has the general supervision of an applicant and the Maritime

Link Project, and may make all necessary examinations and inquiries and keep itself

informed as to the compliance by an applicant with the provisions of law and has the right

to obtain from an applicant all information necessary to enable the Review Board to fulfil

its duties.

[13]

The recovery of a rate, toll, charge or other compensation by an applicant

(in this case NSPML) from NS Power (and, ultimately, from its ratepayers) is governed by

ss. 4 and 8 of the ML Regulations:

Requirement for Review Board approval

4

(1)

(2)

(3)

To obtain a rate, toll, charge or other compensation for services as

defined under the Public Utilities Act, an applicant must first obtain an

approval of the Maritime Link Project under Section 5.

Once approved under Section 5, an applicant is entitled to recover Project

costs through a rate, toll, charge or other compensation from Nova Scotia

Power Incorporated in accordance with Section 8.

An applicant who makes an application under this Section is not required

to make a separate application under Section 35 or 35A of the Public

Utilities Act, but once the Review Board has approved an assessment

under Section 8, the applicant is subject to Sections 35 and 35A of the

Public Utilities Act with respect to any new expenditures.

. . .

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Assessment and costing approval

8

(1)

Before receiving energy under the Nalcor Transactions, an applicant

must set an assessment against Nova Scotia Power Incorporated for the

recovery of the all approved Project costs, and must apply to the Review

Board for an approval of the assessment under Section 64 of the Public

Utilities Act.

(2)

Nova Scotia Power Incorporated is entitled to recover through its rates any

assessment approved by the Review Board in respect of the Maritime Link

Project.

[14]

Section 3 of the ML Regulations provides that any applicant is deemed to

be a public utility:

Designation as public utility

3

An applicant is deemed to be a public utility within the meaning of the Public

Utilities Act and the Public Utilities Act applies to an applicant.

[15]

Section 5 of the ML Act sets out the application of the Public Utilities Act,

R.S.N.S. 1989, c. 380 (PUA):

5

(1)

Notwithstanding the regulations, Section 54 of Public Utilities Act does not

apply with respect to construction of the Maritime Link Project by an applicant in territory

already served by a public utility of like nature, as that territory exists at the time this Act

comes into force.

(2)

For greater certainty, where an applicant has been made subject to the

Public Utilities Act by regulation, for the purpose of that Act and in particular Section 64 of

that Act, the transmission of electricity by the applicant is a service to which Section 64 of

that Act applies.

(3)

Notwithstanding Section 117 of the Public Utilities Act, where there is a

conflict between this Act or the regulations and the Public Utilities Act or the regulations

made pursuant to that Act, this Act and the regulations prevail.

4.0

ISSUES

1.

2.

3.

4.

Were the Board’s 2017 conditions for this application met?

What consequences flow from NSPML’s failure to meet those conditions?

Was it prudent to sign the Acceleration Agreement?

When should the equivalent economic value of NS Block under-deliveries be

determined?

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5.

Integrity of Submarine Cable.

6.

Depreciation policy and depreciation rates.

NSPML’s overall project management.

Affiliate transactions.

7.

8.

9.

Accounting or tax issues.

10.

11.

12.

13.

14.

15.

16.

17.

Incentive Executive Compensation.

Sponsorships and Donations.

Final Project Capital Costs, including AFUDC.

Opening Rate Base.

2022 Cost Assessment.

Future reporting requirements.

Adjustment of Rate of Return.

Lingan 2 Retirement.

5.0

ANALYSIS AND FINDINGS

5.1

Were the Board’s 2017 conditions for this application met?

In the Board’s 2017 ML Interim Assessment Decision [2017 NSUARB 149],

[16]

the Board clearly laid out the conditions NSPML had to meet to have the final assessment.

The Board stated:

[153] NSPML indicated that it wants to have the Final Assessment hearing during 2018.

The Board is not prepared to hold the Final Assessment hearing until it knows that the NS

Block is being delivered in accordance with the original bargain. This will enable the Board

to reserve whatever regulatory options may be available to it in the event of further

unfortunate news.

…

[155] However, the Board is not prepared to approve the final assessment until it is

confident the ratepayers will get what they bargained for – the NS Block, Supplemental

Energy and Nalcor Market-priced Energy.

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[17]

The Board reiterated that position in the 2019 ML Interim Assessment

Decision [2019 NSUARB 156]:

[60]

NSPML has characterized the timing for the Board’s approval of the final

assessment as being linked to the point when the Board “has confidence in the timing of

commencement of the NS Block, Supplemental Energy and Nalcor Market-priced Energy”.

To be clear, the Board will not initiate the hearing process into the final assessment of costs

until the NS Block starts (including the Supplemental Energy) and there is the capacity to

transact Nalcor Market-priced Energy. That was what has been referenced in earlier

proceedings as the “original bargain”.

[61]

The Board repeats its direction from the 2017 Interim Assessment Decision as to

the timing of the final assessment hearing:

[153] …The Board is not prepared to hold the Final Assessment hearing

until it knows that the NS Block is being delivered in accordance with the

original bargain. This will enable the Board to reserve whatever regulatory

options may be available to it in the event of further unfortunate news.

…

[155] However, the Board is not prepared to approve the final

assessment until it is confident the ratepayers will get what they bargained

for – the NS Block, Supplemental Energy and Nalcor Market-priced

Energy.

[62]

Thus, no hearing process into the final assessment matter will be started until the

NS Block and related components are actually flowing over the Maritime Link.

[18]

In his post-hearing submission, the Consumer Advocate set out quite

succinctly the original bargain:

c. Meaning of – “what was bargained for”

NSPML’s 2013 Application (and the Board’s subsequent approval) was based on NS

ratepayers receiving the NS Block (Base and Supplemental). The attributes of the NS Block

were referenced in the 2013 ML Application (M05419) Ex M-2 p 33:

Figure 2-1 Energy Delivery Features

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Another critical representation at the 2013 ML Hearing related to the availability of Nalcor

market priced energy. Figure 4-4 from NSPML’s Application (Ex M-2 at p. 92):

Figure 4-4 Weighted Average Electricity Prices Per MWh

NSPML’s response to UARB IR-37 from the 2013 Application provided the assumptions

related to Figure 4-4 that IR response has been entered in this proceeding as Ex N-31.

During this hearing, NSPML confirmed that the anticipated amount of energy to be

delivered between mid-August 2021 and November 2021 was approximately 692,000

MWh, consisting of:

o

NS Block: 262,000 MWh

Supplemental Energy (winter only): 48,000 MWh

Nalcor Market-Priced Energy: 382,000 MWh

(Transcript, p. 51, line 19 – p. 54, line 1)

[Exhibit N-49, pp. 3-4]

[19]

As of the date of the hearing only approximately 19% of the NS Block and

Supplemental Energy had been delivered for the period commencing August 15 to the

end of November 2021.

[20]

In its submission, NSPML advised that since the hearing, NS Block energy

flows have improved. This advice was expanded upon in the reply submission but covers

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a time period measured in days – not cause for unbridled optimism. That evidence was

not subject to cross-examination or submitted under oath and is entitled to little weight.

The Board has noted in the past that NSPML and NS Power have over-promised and

under-delivered when they describe benefits from the Maritime Link. In the 2017 interim

assessment hearing, when NSPML was arguing that the Maritime Link was used and

useful even in the absence of NS Block, NSPML and NS Power stated that energy and

other benefits in excess of $120 million in 2018 and 2019 were expected. In fact, those

benefits were less than $5 million per year in each of those years.

[21]

One might ask why the Board set these conditions in the 2017 Decision and

repeated them in every interim assessment since. That turns on the phrase “this will

enable the Board to reserve whatever regulatory options may be available to it in the

event of further unfortunate news”.

[22]

its regulatory authority to deal with what that “unfortunate news” might turn out to be.

[23] Had the Board known at the time the hearing was set down that only 19%

The Board was preserving, for the benefit of ratepayers, the full measure of

of the energy would flow between August 15 and November 30, 2021, the Board would

not have agreed to have the hearing at this time.

Findings

[24]

The Board finds that the conditions set in 2017 and repeated in each

Decision since then for having the final assessment hearing have not been met. The

Board was placed in the position of convening this hearing in circumstances where the

hearing should not have taken place until the NS Block was being delivered in accordance

with the original bargain.

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[25]

That issue is quite separate from whether it was prudent to enter into the

Acceleration Agreement, which is canvassed below.

5.2

What consequences flow from NSPML’s failure to meet those

conditions?

[26]

All of the Intervenors suggest that the Board exercise some regulatory

mechanism to protect Nova Scotia ratepayers from further risk. The Municipal Utilities

(MUNIS) suggest a holdback similar to the holdback currently in place would be

necessary to be meaningful.

[27]

The Small Business Advocate also suggests continuation of a holdback with

the condition that it not be paid to NSPML until under-delivery is made in full and NS

Power is receiving, on a consistent basis, 90% or more of the promised energy delivery.

When those conditions are satisfied at some point, a pro-rated amount of the holdback

should be paid to NSPML, and the balance credited to ratepayers.

[28]

The Consumer Advocate argued that the Board’s response should be

“decisive” due to the fact that NSPML has ignored the direction of the Board. The

Consumer Advocate recommended a holdback significantly higher than the $10 million

holdback currently in place.

[29]

The Industrial Group stated that while there may be other regulatory tools,

at a minimum the existing deferral should continue into 2022 until the Board is satisfied

the original bargain has been reliably fulfilled. This means that the project is

commissioned and the non-operation of the LIL is no longer a forgivable event. The

Industrial Group says a form of holdback could be imposed tied to the benefits associated

with the original bargain to ensure redeliveries are similar in value.

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[30]

As noted in Undertaking U-1, the NS Power estimated cost related to the

non-delivery of the NS Block from January 1, 2018 to October 31, 2021, is $205.5 million

in replacement energy costs. However, as make-up power is delivered, that will work to

the benefit of ratepayers thereby reducing this $205.5 million cost.

Findings

[31]

The Board has determined it is appropriate to continue a form of holdback

to provide some continued protection to ratepayers. The holdback is as follows: Starting

April 1, 2022, and in each subsequent month of 2022, NS Power is to holdback $2 million

from the approved assessment. If in that month NSPML/NS Power achieve and receive

90% of the basic NS Block and Supplemental Energy, the holdback will be released to

NSPML in the following month. If 90% of the basic NS Block and Supplemental Energy

is not achieved, the holdback monies will be used to pay for the cost of any replacement

energy that may be required as a result of the failure to achieve the 90%, to a maximum

of $2 million per month. Any portion of the $2 million not utilized to pay for replacement

cost energy would be paid over to NSPML. This holdback mechanism will continue in

each and every month during 2022 and then will be reviewed by the Board in January of

2023.

[32]

The fact that today’s customers are paying for the Maritime Link but not

receiving anything close to the full benefit has caused intergenerational equity concerns.

This holdback, in some small way, may ameliorate those concerns to the extent an

imbalance continues. The Board believes this holdback would not jeopardize NSPML’s

ability to service the federal loan guaranteed debt; however, if circumstances arise where

that becomes a concern, NSPML should immediately apply to the Board for relief.

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[33]

The holdback in 2022 for January and February, pursuant to the Board’s

December 2021 Interim Order, may be released to NSPML.

5.3

[34]

Was it prudent to sign the Acceleration Agreement?

On August 6, 2021, NSPML signed an Acceleration Agreement with Nalcor,

which effectively commenced the delivery of the NS Block starting August 15, 2021.

Under the original commercial agreements, the NS Block would not have started until the

commissioning of the Muskrat Falls Generating Station and the LIL. In its Rebuttal

Evidence, NSPML outlined the effect of the Acceleration Agreement as follows:

On August 6, 2021, NSPML secured an agreement with Nalcor Energy (Nalcor) for delivery

of the NS Block prior to full commissioning of the LIL; the remaining condition precedent

under the Nalcor agreements for the commencement of delivery. In the result, delivery of

the NS Block commenced on August 15, 2021. Without the Acceleration Agreement, NS

customers would still be waiting for the receipt of any NS Block benefits. The effect of the

Acceleration Agreement has been to secure, and advance, the economic value of the NS

Block for the benefit of NS customers.

Pending full commissioning of the LIL there have been, and will continue to be, periods

when the LIL is derated or out of service. This was anticipated by the parties when the

Acceleration Agreement was signed and is addressed through the Agreement and ECA’s

make-up energy provisions which retain for NS customers the total benefit of the NS Block.

… In any event, the Acceleration Agreement, together with the ECA, ensures, and the

parties fully agree, that all NS Block energy not delivered to NS from and after August 15,

2021 has been, and will continue to be, tracked for delivery as soon as reasonably possible.

… NS Power will schedule such delivery in accord with system requirements and

capabilities, good utility practice, and maintenance of the economic value of those

deliveries to NS customers.

[Exhibit N-22, pp. 10-11]

[35]

The Intervenors expressed concerns about NSPML’s execution of the

Acceleration Agreement. They raised several points in support of their view that it was

not appropriate to enter into the Acceleration Agreement with Nalcor. One criticism is

that the delivery of the NS Block continues to be delayed despite the existence of the

Acceleration Agreement. To the extent this has changed the “original bargain” and there

continues to be a delay in the NS Block and the make-up of undelivered energy, those

issues were canvassed earlier in this Decision where the Board applied its regulatory

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tools to address the continuing delay. In this part of the Decision, the Board will

specifically address whether it was reasonable for NSPML to negotiate and enter into the

Acceleration Agreement.

[36]

The Industrial Group submitted:

Perhaps only time will tell whether the Acceleration Agreement – which traded off $18

million in disputed trenching costs, forgave non-delivery penalties due to the LIL prior to

commissioning and included O&M costs attributable to Muskrat Falls Plant and the LIL in

the Joint Operating Agreement calculation from August 15, 2021, notwithstanding only a

fraction of the promised energy is currently flowing – was a good deal. Clearly, it

fundamentally changed the ECA which was approved by the Board as part of the package

of agreements.

Regrettably, there is no contemporaneous economic analysis with sensitivities as to the

risk of further delays. NSMPL has outlined in its Rebuttal Evidence (Ex. N-22, pp.12-13)

the benefits it identified with the Acceleration Agreement. As discussed during the

confidential session, the assumed monetary benefit of avoiding replacement energy for the

period between August 15 – and the (then) forecasted LIL commercial operation date of

November 27, 2021 has not borne out. [Emphasis added]

[Exhibit N-50, p. 5]

[37]

Further, the MUNIS suggested there is a capacity deficiency for Muskrat

Falls energy under the Acceleration Agreement in the context of the Board’s recent BUTU

Decision (M09940) [2021 NSUARB 126]:

Notable to the Municipal Utilities is that NSPML has, at least to date, made no concession

that the capacity value of the NS Block has been diminished by the LIL Forgiveable Event

during the period of its applicability. … NSPI made clear in that proceeding its view on what

it felt was necessary to constitute capacity. Yet in this proceeding neither NSPI or NSPML

have conceded that the NS Block is not, while the Acceleration Agreement provisions are

in place, a viable capacity resource.

[Exhibit N-46, pp. 31-32]

[38]

In response to IRs from the Consumer Advocate to the Board Counsel’s

consultant, Bates White stated that it was “unaware of any evidence that would suggest

a date certain by which the entirety of the NS Block would be delivered” [Exhibit N-18, CA

IR-1]. Further, Bates White opined that the Acceleration Agreement changed the

definition of “forgivable event” as contained in the original commercial agreement:

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(b) Our opinion is that the revised definition of “Forgivable Event” is materially different

than the definition contained in the original agreement and approved by the Board

since it includes the LIL commissioning activities in the definition of Forgivable Event

and accelerates the commencement date of the NS Block to a date that precedes full

commissioning of the LIL, which is necessary for delivery of the full NS Block.

[Exhibit N-18, CA IR-3(b)]

[39]

However, in Bates White’s opinion, the Acceleration Agreement obligated

Nalcor to begin providing the firm, zero emissions NS Block energy to NS Power:

(a) Bates White’s understanding of the Acceleration Agreement is that it contractually

obligates Nalcor to commence delivery of the NS Block on a firm basis, consistent with

the terms of the Energy and Capacity Agreement.

i.

“Firm” is consistent with our response to CA IR-2(b). We note, however, that

because “Forgivable Event” has been revised by the Acceleration Agreement to

include LIL commissioning activities, there is a material expansion of the universe

of allowed excuses for underperformance. …

[Exhibit N-18, CA IR-5(a)]

[40]

Bates White defined “firm” as:

Firm service is the highest priority form of service, meaning it is the last form of service to

be curtailed, and is considered non-interruptible other than for force majeure events,

planned maintenance, and emergency events, and when otherwise interrupted, is typically

subject to penalties.

[Exhibit N-18, CA IR-2(b)]

Findings

[41]

In the Board’s view, the Intervenors have mischaracterized the impact of

the Acceleration Agreement. Most of their concerns relate to the delay in the delivery of

the NS Block. The delay, of course, was not caused by the execution of the Acceleration

Agreement. The NS Block has already been delayed since 2018. Indeed, NSPML

entered into negotiations with Nalcor to address the continuing delay in the delivery of the

NS Block. Earlier in this Decision, the Board applied its regulatory instruments to address

the impact of the continuing delay upon NS ratepayers. However, the Board considers

the prudence of the Acceleration Agreement to be a different question.

Document: 291318

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[42]

It is important to note that the premise underlying the Agreement is the

reality that the Muskrat Falls Generating Station and the LIL are now able to

accommodate the volume of energy comprising the NS Block, including Supplemental

Energy, as well as the commencement of Nalcor Market-priced Energy starting

September 1, 2022. In its reply argument, NSPML stated:

… Delivery of the NS Block (at its highest capacity being Supplemental Energy of under

200 MW) requires less than 25% of the as built capacity of the LIL. The LIL has been

running above that capacity since August, 2021 (though, as it has turned out, intermittently

in the initial months following execution of the Acceleration Agreement). The generation

capacity of MFGS is 824 MW, again well in excess of the capacity requirements of the NS

Block. The rationale for the Acceleration Agreement was that both facilities were already

operating above the required NS Block capacity, and neither required final commissioning

in order to commence NS Block delivery. Both parties agreed with these circumstances,

which is why they agreed to accelerate NS Block delivery. [Emphasis added]

[Exhibit N-53, p. 18]

[43]

While numerous deliveries of the NS Block after August 15, 2021, have

continued to be interrupted and delayed, the Acceleration Agreement contains provisions

that provide several benefits to NS ratepayers, mitigating the full impact of the delayed

NS Block delivery.

[44]

First, the start of the NS Block begins to immediately provide NS Power and

its customers with energy, mitigating the need for NS Power to secure replacement power

from other sources at an extra cost under the FAM. Given that the NS Block commenced

in advance of the 2021-2022 peak winter season, this might enable NS Power to avoid

relatively higher replacement energy costs this winter. In the absence of the Acceleration

Agreement, the NS Block would have been delayed until the commissioning of the LIL,

which was projected at the time to occur no earlier than late November 2021, and possibly

later. It is now clear that the commissioning date will be later. Moreover, the NS Block

provides valuable renewable energy which counts towards NS Power’s Renewable

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Electricity Standards requirements and addresses some of the Utility’s GHG

requirements, with potentially significant financial implications if not satisfied by the end

of the current compliance period on December 31, 2022. Granted, there have been

continuing delays in NS Block deliveries, but what has been delivered is provided on

account of what is currently embedded in customers’ power rates and, as explained

below, any under-deliveries must be re-scheduled by Nalcor.

[45]

Second, as noted above, some of the Intervenors argued that the terms of

the “original bargain” were relaxed in NSPML’s favour as the term “forgivable event” was

expanded to include interruptions during LIL pre-commissioning activities under the

original commercial agreements. However, in such an event, the Energy and Capacity

Agreement triggers a mechanism which allows Nalcor to provide this energy at a later

date, or so-called “makeup energy”. This provision serves as a benefit to ratepayers,

rather than a detriment. The Board finds this is a reasonable commercial provision which

recognizes that, under the original contractual agreements, the NS Block would not have

begun to flow over the Maritime Link until the LIL was commissioned. Thus, the

Acceleration Agreement allows the NS Block to flow during Nalcor’s continuing pre-

commissioning activities on the LIL. In the Board’s opinion, this appropriately relaxes the

original contractual term, allowing the deferral of non-deliveries caused by interruptions

during LIL pre-commissioning activities and requiring the provision of makeup energy.

The Board concurs with NSPML’s depiction of this component of the Agreement:

… The “forgivable events” clause of the Acceleration Agreement is a practical and workable

mechanism to address what the parties to the agreement acknowledged as an obvious

circumstance to be addressed if NS Block energy was to flow prior to full LIL contractual

commissioning. This amendment is, in the context of flowing the NS Block during

continuing commissioning activities, … This provision allowed for pre-LIL commissioning

delivery of the NS Block, and thus was beneficial for customers. It did not, as the IG

contends, “forgive non-delivery penalties”, since without the Acceleration Agreement there

would have been no non-deliveries to forgive. Without the reasonable expanded definition

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of “forgivable event” there would have been no Acceleration Agreement and thus no NS

Block during the period in question. [Emphasis added]

[Exhibit N-53, p. 12]

[46]

Further, Bates White confirmed that the Acceleration Agreement did not

change the nature of the energy dispatch requirements. The contractual dispatch of the

NS Block is still scheduled and managed under Schedule 5 of the Energy and Capacity

Agreement [see Exhibit N-18, RIR CA IR-2(c) and (d)]. Thus, the delivery of makeup

energy caused by interruptions related to the LIL commissioning activities are dealt with

in like fashion to makeup energy resulting from forgivable events as originally

contemplated. Similarly, the requirement to optimize the energy profile delivered to NS

Power is also set out in the Acceleration Agreement:

2.

Supplemental Energy - Prior to the Final Determination, as such term is defined in

Schedule 4 of the ECA, the Supplemental Energy shall be deemed to be 240 GWh

per year and during such period, the parties will work cooperatively to optimize the

profile of Nova Scotia Block Delivery Schedule including Supplemental Energy

consistent with the principles set forth in Section 2(d) of Schedule 5 of the ECA.

[Emphasis added]

[Exhibit N-2, p. 1]

[47]

Third, in support of the provision for makeup energy, the Acceleration

Agreement, through the operation of the Energy and Capacity Agreement, restricts

Nalcor’s ability to sell Muskrat Falls energy to any other party where that would impact

Nalcor’s obligation to deliver the makeup energy to NS Power:

…The ECA requires that Nalcor provide options for delivery of replacement energy

promptly upon quantification by NSPML of such energy, and requires suspension of all

non-firm sales from MFGS and precludes Nalcor from scheduling or entering into

arrangements for firm or non-firm export sales to the extent that any of which would affect

Nalcor’s obligation to deliver replacement energy. …

[Exhibit N-22, p. 17]

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[48]

This clearly provides an incentive for Nalcor to address any deficiencies in

the provision of the NS Block to NS Power, which under these contractual terms stand in

priority to third parties who may be interested in buying Muskrat Falls energy.

[49]

Fourth, the Acceleration Agreement secured the availability of Nalcor

Market-priced Energy by September 1, 2022. Section 4 of the Acceleration Agreement

provides:

4.

Energy Access Agreement - In accordance with Section 2.1(b) of the Energy

Access Agreement, dated April 13, 2015, Nalcor or its permitted assign shall

provide the first Nalcor forecast by March 1, 2022, and the first Contract Year shall

commence on September 1, 2022. [Emphasis added]

[Exhibit N-2, p. 2]

[50]

In the absence of the Acceleration Agreement, the start of the Nalcor

Market-priced Energy would likely have been delayed to September 2023, at the earliest.

Mr. Janega of NSPML testified:

Q.

(Murphy)…My question is, without the Acceleration Agreement in place, what

would have been the date for commencement of the ability to purchase market-priced

energy?

A.

(Janega) … But for the purpose of your question, Mr. Murphy, the Excess Energy

Agreement is that specific obligation that I know the UARB Panel, at the time, necessitated

as a part of the Maritime Link approval back in 2013, and it obligates Nova Scotia Power

and Nalcor to, through a commercial process, initiate a set of steps whereby Nalcor would

determine how much energy they have available to sell. Nova Scotia Power would engage

in a process that’s laid out where they would determine how much they want to procure on

a forward-looking basis, and Nalcor would then schedule that on a -- on whatever periodic

basis the two of them agree.

And that’s a formalized process where it's an annual trigger that they provide a forecast,

Nova Scotia Power provides a response, and Nalcor then, with NSPI, depending on the

commercial value of the energy for Nova Scotia customers, would agree to an annual

volume of energy that they would procure, and a profile.

... And if it wasn’t for the Acceleration Agreement, that would wait until LIL was fully

complete, and then essentially, within a year after that, the parties would be required to

start.

…

Q.

So without the Acceleration Agreement in place, it sounds like that formal process

could have been delayed a year, I suppose?

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A.

(Janega) It would likely have been the year after that we would have been talking

about, 2023 period.

[Transcript, December 7, 2021, pp. 409-412]

[51]

Thus, in addition to commencement of the NS Block (including

Supplemental Energy), the Acceleration Agreement benefits NS customers by advancing

the availability of Market-priced Energy by at least one year. Pursuant to the Energy

Access Agreement (EAA), which was negotiated to meet a condition imposed by the

Board in its 2013 ML Decision to ensure the ML Project was the lowest cost alternative

for NS ratepayers, Nalcor Market-priced Energy is contracted differently than other

Muskrat Falls excess energy.

[52]

It is instructive to recall the benefits of the EAA as outlined by Board Counsel

consultants, Morrison Park, in the Board’s Supplemental ML Decision, 2013 NSUARB

242:

[20]

Both Morrison Park and NSPI highlighted a number of benefits of the EAA which,

in their view, helped satisfy the Board’s concerns.

[21]

Indeed, Morrison Park indicated they do not believe it is a correct characterization

of the EAA to say it is an energy supply agreement. They said it is, in reality, a contract

that guarantees access by NSPI to the market, noting that NSPI may not in any particular

year actually issue an RFP or accept any bids for Nalcor Market-priced Energy, if that is

not the economic choice. However, the EAA provides NSPI with the benefit of precluding

Nalcor from contracting power to third parties on a long term basis as Nalcor must forecast

and bid into annual NSPI solicitations. That provision applies in each year of the term of

the EAA irrespective of the fact that Nalcor may have satisfied the average 1.2 TWh

contractual obligation. Morrison Park described that contractual commitment as a series

of 24 one-way options in favour of NSPI that it can exercise for 24 different consecutive

years in the future. Morrison Park noted that NSPI has not taken on any additional

commitments in the EAA.

…

[23]

Morrison Park noted that another beneficial provision of the EAA is that Nalcor

must disclose its expectations about power availability through the 24 month forecast. Mr.

Walker noted that when you are transacting with a counterparty, knowing their inventory

for a 24 month period is an important piece of information that normal market

counterparties do not have. This would give NSPI an advantage and could lead to better

energy prices for Nova Scotia ratepayers. …

[2013 NSUARB 242, paras. 20-23]

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[53]

The Board is satisfied that the availability of the Market-priced Energy by

September 1, 2022, provides earlier financial benefits to NS ratepayers by securing the

full profile of Muskrat Falls energy.

[54]

Finally, the Board is mindful that the Acceleration Agreement was the

subject of negotiation between NSPML and Nalcor, resulting in trade-offs and clarity for

both sides going forward. NSPML did concede a potential amount of $18 million in

trenching costs in favour of Nalcor. However, this was a matter of dispute between the

parties. Like any other negotiation, concluded agreements do provide certainty to the

parties. Viewed from Nalcor’s perspective, this was undoubtedly an important factor in

agreeing to commence the NS Block before the LIL commissioning, that being a risk or

obligation it had to assume. Given the potentially significant financial benefits of starting

the NS Block now, and avoiding the need for NS ratepayers to incur the burden of

additional replacement energy costs, the Board considers the trade-off of trenching costs

to be reasonable and appropriate in comparison. Further, given the relative timing of the

trenching work after the ML commissioning, the Board also considers the inclusion of

operating and maintenance (O&M) costs into the Joint Development Agreement to be

appropriate.

[55]

Moreover, despite the MUNIS’ assertions to the contrary, the Board is

satisfied that the start of the NS Block under the Acceleration Agreement does secure

firm capacity to NS Power, in that it is the subject of a contractual commitment (which

also requires the energy to be made up in the event of a forgivable event), which is

supported by dedicated generation capacity, and is accessed through a firm transmission

path. The NS Block energy produced at the MFGS and delivered through the LIL and

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Maritime Link is clearly distinguishable from the nature of the New Brunswick energy

imports canvassed in the BUTU proceeding.

[56]

Taking all the above into account, the Board concludes that it was

reasonable and appropriate for NSPML to negotiate and enter into the Acceleration

Agreement. The Agreement had the result of moving up the start of the NS Block,

Supplemental Energy and Nalcor Market-priced Energy, while also helping NS Power to

avoid the necessity of having to purchase costly replacement energy in the absence of

the NS Block.

5.4

When should the equivalent economic value of NS Block under-

deliveries be determined?

[57]

By definition, as set out in the commercial agreements between Emera and

Nalcor, the NS Block itself (excluding for the time being Supplemental Energy) is to be

delivered during NS Power’s peak hours (i.e., 8 am to midnight, seven days per week,

throughout the year). Further, the five-year Supplemental Energy is to be delivered in the

winter months (i.e., November to March), seven days per week, in off-peak hours. Since

NS Power’s system is winter peaking, energy delivered during those months, particularly

during the peak hours, has the greatest economic value to the Utility.

[58]

The requirement to receive the NS Block during peak hours, as well as the

Supplemental Energy during the winter months, is not coincidental. The economic value

of those allocations of energy were integral to the Board’s decision that the Maritime Link

Project was the lowest cost alternative for Nova Scotia customers, when NSPML’s

original application was considered in 2013.

[59]

Any delay in the delivery of the NS Block and the Supplemental Energy

which results in the re-delivery of such energy later than the winter peaking period (i.e.,

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after the month of March) leads to it being delivered at times when NS Power’s system

generally experiences lower loads, when energy from NS Power’s own generation

sources and imports can typically be obtained at lower costs than during the winter

months. Conceivably, the subsequent re-delivery of the NS Block and the Supplemental

Energy could also result in it being offered when the Utility is unable to use all or part of

the energy.

[60]

Thus, while NSPML has assured the Board and NS Power’s customers that

any undelivered energy will soon be re-delivered, the question remains how NS Power

will ensure the energy it receives from Nalcor will have similar economic value to its value

if it had been delivered when it should have been following August 15, 2021.

[61]

While not specifically addressed during the hearing, the Board infers that

similar considerations to the above also apply to the forecast delivery of Nalcor Market-

priced Energy.

[62]

The quandary created by the delayed delivery of the NS Block and

Supplemental Energy was highlighted by counsel for the Industrial Group in her

submissions:

There is also uncertainty as to the timing of redelivery by Nalcor of the under-delivered

energy and the complexity of ensuring it is of “similar value”. … [Emphasis added]

[Exhibit N-50, p. 5]

[63]

In questioning by the Board, Mr. Landrigan of NS Power, stated that NS

Power is working with Nalcor representatives about delivery schedules to ensure that the

energy will be re-delivered at a time that is economically beneficial to NS Power’s

ratepayers:

A.

So schedules for deliveries and what would -- the difference would be provided on

a daily basis except for weekends. So there would be a schedule for three days during

that period.

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So we have, on a handful of occasions, confirmed the exact numbers of the

undelivered energy so that we have alignment between us and Nalcor in terms of the

accumulated value, if it's to be redelivered on a one-to-one basis, and so there has been -

- I guess there's constant communication between the marketing groups in terms of what's

available to be delivered and then the accumulation of the undelivered amount.

[Transcript, December 7, 2021, pp. 464-465]

[64]

Mr. Landrigan also acknowledged that the review of any such energy

transactions would fall within the scope of a future FAM Audit:

Q.

(MacDougall) … what's the process you're anticipating for showing ratepayers,

confirming to ratepayers and this Board that for the undelivered energy, specifically created

by the Acceleration Agreement, that it is of similar value?

A.

(Landrigan) I have -- I shouldn't say it this way. I have no doubt it will be a part of

the FAM audit process, which is the -- which is the proper place for this to be -- in my mind,

for this to be reviewed.

[Transcript, December 7, 2021, pp. 520-521]

[65]

In questioning by counsel for the Industrial Group, Bates White stated that

the appropriate forum to review the financial aspects about the re-delivery of previously

undelivered energy is through the FAM Audit process:

Q.

(Rubin) Okay. You said, if it's done right it goes along way to demonstrate that the

Acceleration Agreement was a prudent decision. Are you suggesting that that needs to

await a valuation of those product services? Like, is that -- like, to make sure that it's an

equivalent value, or is this -- or are we looking at a FAM decision?

A.

(Musco) Well, I think the venue, you know, I think that's one of the questions, is

the proper venue for that determination. It's certainly, having conducted -- Bates White

having conducted the audit in the past, that's something we would look at, absolutely. We'd

be looking at the administration of that contract consistent with its terms, and we'd be

looking at the outcomes and the various calculations that support the decision-making

around that contract. So I think that would be a reasonable place for it to land and to be

reviewed.

[Transcript, December 8, 2021, pp. 731-732]

[66]

Mr. Musco of Bates White, in his role as FAM Auditor, also identified the

significance of assessing such transactions with an eye on whether the energy was re-

delivered at times, and in quantities, which maximize economic benefit for NS Power’s

ratepayers.

Document: 291318

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Findings

The consequences from any delay in receiving the NS Block prior to, and

[67]

following, the Acceleration Agreement, fall upon NSPML and have been dealt with earlier

in this Decision as directed by the Board.

[68]

However, the risks of prudently administering the re-deliveries of this energy

under the Acceleration Agreement and the Energy and Capacity Agreement is now upon

NS Power. The Board considers that the FAM Audit process is the appropriate forum to

review the economic value received by ratepayers from transactions involving the re-

delivery of the NS Block, Supplemental Energy, and Nalcor Market-priced Energy.

5.5

[69]

Integrity of Submarine Cable

The submarine cable program for the ML Project involved the design,

manufacture, transport, installation and protection of a submarine high voltage direct

current (HVDC) transmission system between Cape Ray, Newfoundland and Labrador,

and Point Aconi, Nova Scotia. Key elements of the program included:

 Approximately 340 kilometres of +/- 200 kV HVDC submarine cable (two

submarine cables in total);

 Approximately ten kilometres of land cable;

 Accessories, including terminations, joints and anchoring devices;

 Fiber optic strands in the cable for temperature sensing;

 Telecommunications housed with a separate cable jacket package; and

 Five kilometres of spare HVDC submarine cable and one kilometre of spare

land cable.

Document: 291318

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[70]

NSPML engaged Nexans Norway AS (Nexans) to design, manufacture,

install and protect the submarine cables. The cables were manufactured using mass

impregnated (MI) insulation system technology, which is used extensively in HVDC

projects. During the original design of the cable route, NSPML assessed the risk to the

cables of external contact by sea ice, ship anchors, and fishing gear. Additional planning

and preparation work in advance of cable installation included cable routing surveys,

stakeholder engagement and consideration of environmental requirements and mitigation

of effects on interested parties such as local lobster, crab and fish harvesters. The cable

route was later optimized within its established corridor to maximize natural protection

from external hazards.

[71]

To address nearshore wave, storm, ice and rock conditions, as well as the

greater incidence of marine traffic, NSPML used Horizontal Directional Drilling (HDD) to

construct micro-tunnels at the cable landfall transition on either side of the Cabot Strait.

Beyond the HDD exits, the cable was protected from external hazards, as necessary,

using a combination of trenching and rock cover.

[72]

In mid-2018, following cable installation, NSPML retained Xodus Group, an

international energy consultancy, to undertake a “Cable Integrity Risk Assessment”

(CIRA). This assessment was completed using as-built survey information provided by

Nexans to confirm that the subsea cables’ reliability and availability targets had been

satisfied. Xodus’ work included the creation of a comprehensive probabilistic risk model.

Xodus, in consultation with other recognized experts in cable protection and ice

mechanics, concluded that the cables are well protected in their “as built” condition

(lifetime availability of 97% or greater).

Document: 291318

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[73]

In 2018, NSPML learned that redfish stocks had rebounded much faster

than scientists had anticipated, and a new redfish fishery had emerged along the cable

route, including at depths below 400 metres. With this new information, NSPML assessed

the risk to the cables at these depths and determined it prudent to deploy additional burial

to ensure the integrity of the deep-water cable spans. Nexans completed this work and

associated survey activities by late September 2019. The 2019 survey data was provided

to Xodus to update the CIRA. Xodus subsequently confirmed that the reliability targets

for the cables continue to be met.

[74]

Laurence Trim of Cable Consulting International (CCI) was engaged by

Board Counsel in this matter to independently assess the integrity of the ML cables, both

submarine and land components, to ensure they meet contractual design requirements.

In his written evidence, Exhibit N-10, Mr. Trim stated the following:

 The thermal properties of the cable constructions from the Nexans factories had

not been verified. As such, he could not confirm that the submarine cable

systems are operating within their design limits;

 He calculated the energy availability of the ML to be less than the guaranteed

availability stated in the ML Reliability, Availability and Maintainability (RAM)

study prepared by ABB and Nexans; and

 Insufficient evidence had been presented by NSPML to support the design life

requirement for the ML cable systems.

[75]

It was clear in Mr. Trim’s evidence that he was not provided with all the

information he required to complete his review. Consequently, during the hearing on

December 8, 2021, the parties agreed to adjourn and reconvene on January 7, 2022. In

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the interim period, NSPML agreed to work with Mr. Trim and provide him with the missing

information needed to complete and update his cable integrity review. Upon NSPML

providing Mr. Trim with the additional information, he filed his amended written evidence

[Exhibit N-44] on December 23, 2021. After reviewing Mr. Trim’s amended evidence, the

parties advised the Board that cross-examination of Mr. Trim was not required. The

Board, therefore, cancelled the hearing scheduled for January 7, 2022.

[76]

Mr. Trim’s updated evidence concluded the following:

 The thermal properties of the cable constructions from the Nexans factories have

been verified. Therefore, the cable system as designed, and under the

assumption that all the engineering design parameters adopted are verified as

being valid for the “as installed” HVDC land and submarine cable systems,

should operate within the thermal and electrical stress limits of the cable design.

Further, given that the ambient sea bottom temperatures below 200m water

depth remains between 6 to 7^oC all year around, the cable in this region should

remain within the maximum design temperature parameter;

 The energy availability of the ML is in the range 91% to 98% rather than the

guaranteed ≥ 98% stated in the RAM study, with an optimistic probability of it

ranging from 95% to 97%. However, Mr. Trim noted that the ability of the ML to

transmit the NS Block and Supplemental Energy should be largely unaffected by

system availability. So long as the outage only affects one HVDC cable then the

link will still be capable of transmitting 250MW of power via the remaining healthy

cable operating in monopole configuration with a sea return; and

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 Test evidence has been presented to support the 50-year design life requirement

for the Maritime Link cable system.

[77]

Mr. Trim also presented three recommendations in his updated evidence:

 NSPML develop a document to describe the thermal characteristics of the ML

cables using as measured soil thermal resistivity data, appropriate sea bottom

temperatures (as determined from the 2011 survey and seasonal swing

information) and distributed temperature sensing (DTS) data;

 NSPML periodically review the cable failure rate and RAM study using the most

up to date data; and

 For planning purposes, NSPML consider adopting the CIGRE TB815 industry

failure rate of 0.0029 failures/100 circuit km/year, or 1 failure every 10 years.

In its final submission, NSPML agreed to implement these recommendations.

Findings

[78]

The Board finds that the “as installed” ML submarine cable system meets

its contractual design requirements. The Board directs NSPML to implement the

recommendations presented by Mr. Trim in his updated evidence. In its Compliance

Filing, NSPML is to provide a schedule for when it intends to implement these

recommendations.

5.6

[79]

Depreciation Policy and Depreciation Rates

In previous decisions, the Board directed NSPML to depreciate its rate base

over a period of 35 years to match the delivery term of the NS Block. The Board approved

recovery of depreciation to commence in 2020 to enable NSPML to meet Federal Loan

Guarantee (FLG) principal repayment obligations. For 2020 and 2021 NSPML has

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recovered $61.5 million on account of depreciation to meet the FLG requirements and

pay return on equity to NSPML shareholders. These interim payments have been

subtracted from capitalization project costs in setting the opening rate base. Gannett

Fleming conducted a depreciation study on NSPML’s assets.

[80]

In its post-hearing brief, NSPML summarized Gannett Fleming’s proposal:



to distribute the ML Project Costs between two broad asset categories- Electric

Plant in Service and General Plant – and thirteen sub-categories within these two

broad categories, all as set out in Gannett Fleming’s study and with each

subcategory being assigned its own depreciation rate;

to designate an annual depreciation amount based on the assumptions described

in Gannett Fleming’s report, including the overriding assumption that all assets

must be fully depreciated at the end of the 35-year duration of the NS Block when

the ML is to be transferred to Nalcor for $1;



going forward, to seek determination of depreciation expense on future

(sustaining) capital investments at the time of approval by the UARB of such

investments; and

all subject to periodic revision to depreciation amounts as may be proposed by

NSPML and determined appropriate by the UARB.

[Exhibit N-48, pp. 33-34]

[81]

[82]

Gannett Fleming proposed an annual depreciation expense of $56.8 million.

NSPML further noted that under its currently approved accounting policy

land costs would normally be excluded from depreciation and recovered when the land

was sold. However, under the Nalcor commercial agreements, NSPML must transfer

these assets to Nalcor once the NS Block has been fully delivered in 35 years. NSPML

seeks to recover these costs through including them in the allowance for depreciation.

[83]

Board Counsel consultants Grant Thornton and Bates White both reviewed

the depreciation evidence. Grant Thornton found the 35-year recovery period to be

appropriate and otherwise expressed no concerns with respect to the policy. Bates White

recommended approval of NSPML’s proposed 2022 depreciation expense.

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[84]

[85]

No other party commented on depreciation policy.

Findings

The Board approves the depreciation policy as summarized above and

more fully outlined in Section 3.3 of NSPML’s application and detailed in the Gannett

Fleming depreciation study. The Board also approves, in the unique circumstances of

this situation, including an allowance for depreciation of land costs in NSPML’s annual

depreciation.

5.7

[86]

NSPML’s Overall Project Execution

Over the course of the ML Project, NSPML was confronted with a number

of significant challenges. These included:

 Default of the project’s main overland transmission line contractor;

 Escalation of disputes with the replacement transmission line contractor;

 A tragic contractor safety incident in which a powerline technician lost his life;

 The failure of a transmission tower anchor and the resultant collapse of a tower;

 Quality control concerns during manufacturing of the subsea cable;

 Buckling of exterior insulated converter station wall panels and their subsequent

replacement during station construction;

 Several subsea trenching obstacles including a late emergence of a redfish fishery

necessitating additional cable burial activities once the project was in service;

 Extreme weather conditions and associated scheduling complexities; and

 Competition for skilled and qualified workforce.

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NSPML’s response to these challenges, and its overall approach to planning and

executing the ML Project, are described in Section 2.0 and Schedules 1 through 7 of its

Application and are discussed in the following sections.

5.7.1 Project Planning, Management, and Governance

[87]

Under the framework of the commercial agreements, Nalcor and NSPML

formed a joint development committee (JDC) with general oversight of the development

of the ML Project, including project design, contractual matters, budget and schedule.

The JDC approved all major contracts including those for converter stations, transmission

line construction and contractor replacements, and submarine cables. In addition,

NSPML’s Senior Project Manager reported directly to the JDC on a regular basis to keep

it fully apprised of the project status.

[88]

NSPML’s President and CEO was the Project Owner, and the second level

of approval after the Senior Project Manager under the project management structure.

The President and CEO was given the authority to approve contracts and change orders

up to $2 million in value. Beyond that value, NSPML required the approval of the Project

Decision Board (for decisions up to $25 million in value) or the Emera Newfoundland and

Labrador Holdings Inc. (ENLH) Board of Directors (for decisions of more than $25 million

in value). At the base of the project governance and oversight structure was the Project

Management Team (PMT). Led by a Senior Project Manager and an Assistant Project

Manager, the PMT was organized into ten teams, each with its own lead reporting to the

Senior Project Manager. The PMT included professionals with a combination of

engineering, construction, utility and project management training and experience.

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[89]

NSPML’s procurement program for all major project contracts involved

identifying top global and local contractors, an expression of interest and request for

proposal process, and a protocol for evaluation of contract bids against pre-defined

criteria through review by NSPML internal subject matter experts and support teams.

[90]

Working with external legal experts with international experience in the

HVDC cable and converter industry, NSPML’s legal and procurement teams developed

a contract standard that became the starting point for negotiations on all major scopes of

work. The terms and conditions of this standard were aimed at allocating risk in a manner

that optimized value and cost certainty and reflected FLG and ML-JDA contractual

requirements.

[91]

NSPML implemented a contract management strategy focused on closely

monitoring contractor performance to maintain the value contracted for and to defend

against unwarranted claims. NSPML deployed its specialized teams setup under the

PMT structure for each major work program, to identify and address project challenges

and emerging risks, and apply project management practices to minimize schedule

slippage and scope creep when matters did not go as planned. As part of this effort,

NSPML developed a project execution risk plan to identify and assess risks to design and

execution and implement mitigation measures when warranted.

[92]

With respect to NSPML’s management of the ML Project, John Reed of

Concentric, stated:

… The project management and oversight structures functioned exceptionally well,

responding appropriately to adverse conditions, and resulting in the completion of the ML

Project on-time and within the approved budget.

[Exhibit N-1, Schedule 7, Att. 1, p. 5]

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[93]

Similarly, Patricia Galloway of Pegasus-Global concluded:

… NSPML recognized the size and complexities of the Project and incorporated

appropriate dispute resolution and change order management clauses in its major

contracts to minimize the impacts that potential disputes could have on the Project,

including avoidance of potential litigation costs.

…

…the extensive Project planning that the NSPML Project Team performed pre-execution,

culminating in Decision Gates (DG) 2 and 3, created favorable circumstances for NSPML

to have a successful execution of the Project. The NSPML Project Team undertook a

number of risk management initiatives during early planning of the Project including

independent risk assessments, quarterly risk reviews, program and process reviews, best

practice research and continued assessments and reviews as the Project progressed.

These efforts put NSPML in a position to appropriately award and manage the major

contracts that comprise the bulk of the Project.

…

…NSPML fully evaluated and considered the factors typically considered in the selection

of contract approaches and delivery methodologies…

…

… NSPML’s Contract Strategy & Procurement Plan for the Project, Pegasus-Global found

that it met industry standard practices.

…

… NSPML’s contracting risk management strategy for the Project, Pegasus-Global found

that it met industry standard practices.

… NSPML’s contract management to be in alignment with industry standards, which

facilitated the successful execution of the Project, including providing a structure which

ensured the ability to add resources and expertise as necessary to address the challenges

which arose during execution in a way that consistently benefited the Project.

…

In resolving the commercial disputes on the three primary contracts, NSPML was able to

reach a resolution with each contractor that protected the Project and allowed for

successful completion on time and within budget, while also avoiding additional costs that

would have arisen from not being able to reach a resolution without arbitration and the

consequent risk of cross-contractor schedule impacts during claim disputes.

[Exhibit N-1, Schedule 7, Att. 3, pp. 5-6]

[94]

Bates White found no instances of red flags indicating NSPML

mismanagement or poor procurement practices on the ML Project. Bates White also

found that NSPML followed a clear change order process, and found no related red flags.

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Findings

Based on the evidence presented in this proceeding, the Board finds that

[95]

NSPML established an appropriate governance structure for the ML Project. The Board

also finds that NSPML effectively managed the project, incorporating appropriate

planning, procurement, resourcing, contract management, risk management, and dispute

resolution processes and strategies. The Board, therefore, finds that NSPML prudently

managed the design and construction of the ML Project.

5.7.2 Financing Program

[96]

The key feature of NSPML’s approach to financing the ML Project was the

FLG. Working with the Government of Canada and external financial experts, NSPML

implemented a structure for financing the project which resulted in full substitution of

Canada’s AAA credit rating for that of NSPML in support of $1.3 billion in ML bonds. In

effect, project bond investors provided funding for the project based on acceptance of a

credit rating for NSPML, as the borrower, equal to that of Canada.

[97]

The terms of the FLG required a segregation of project finance risk from

NSPML. To meet this requirement, the structure required the formation of the ML

Financing Trust (ML Trust), and a separate project company, NSPML. This structure was

a requirement of Canada, as guarantor, to “ring fence” the ML assets in order to support

the perfection of security in favour of Canada in support of its guarantee of the project

borrowing and to provide certainty, clarity, and comfort to the bond investors. In further

support of Canada’s interest in successful execution of the project, an Independent

Engineer (IE) was retained to provide oversight on behalf of Canada of construction of

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the project. The IE also approved associated construction funding draws from the ML

Trust funds.

[98]

Having secured FLG support for the project, NSPML received approval from

the Board to finance 70% of the capital cost of the ML Project with a forward bond

issuance under the FLG. The Board also approved financing of the remaining 30% of the

capital cost of the project with equity. On April 23, 2014, NSPML implemented an up-

front borrowing program and $1.3 billion of federally guaranteed bonds were issued with

a 3.5% coupon rate. The proceeds from these bonds were deposited in the ML Trust.

Those funds were then invested in structured deposit notes until required to meet

construction draws throughout the period of construction.

[99]

In keeping with the terms of the FLG, NSPML hedged interest rate risk for

the life of the project by securing all of the necessary FLG debt financing at the beginning

of the project. NSPML hedged the majority of the Government of Canada benchmark

rate risk at a simple average rate (i.e., hedging cost) of 3.02%. This short-term hedging

program ensured that NSPML met the FLG Term Sheet requirement that “a hedging

program shall be put in place for each Borrower at Financial Close” and provide protection

against an increase in the underlying benchmark rate between financial close and the

financing bond issuance. Between the dates the financial hedges were executed in early-

mid February and the April 23, 2014, issuance of the FLG bonds, the underlying

Government of Canada rates declined rather than increased. This resulted in a hedging

cost of approximately $36 million, the bulk of which resulted from the interest rate decline

from the rate at which the hedge was taken.

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[100]

As noted elsewhere in this Decision, Cliff Inskip of Polar Star Advisory

Services, concluded that NSPML's upfront bond financing strategy was not only a very

prudent financing strategy but also one that very likely provided a net benefit to electricity

customers in Nova Scotia. He also found that NSPML’s interest rate hedging strategy

was very defensible and prudent. Grant Thornton also concluded that NSPML’s chosen

approach to financing construction of the ML was an acceptable means to mitigate project

risk and was in accordance with the terms of the FLG.

Findings

[101]

The Board finds that NSPML’s combination of an up-front borrowing

program and hedging instrument was an acceptable financing strategy under the terms

of the FLG. The Board also finds that the chosen financing strategy was an appropriate

and prudent means to mitigate project risks, including:

 Availability of financing throughout construction;

 Interest rate volatility; and

 Unknown borrowing costs throughout the life of the project.

5.7.3 Management of the Submarine Cable Program

[102]

The physical components of the ML Project’s submarine cable program

have been previously described in this Decision. The following sections describe some

of the challenges that arose during implementation of the program and how NSPML

addressed these challenges.

[103]

NSPML conducted significant planning work to select a two-kilometre wide

corridor across the Cabot Strait in which to install the submarine cable system. This

involved cable routing surveys, stakeholder engagement and consideration of

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environmental requirements and mitigation of effects on interested parties such as local

lobster, crab and fish harvesters. Based on this initial work, NSPML, in consultation with

Nalcor and other stakeholders, also chose a cable protection strategy involving mainly

burial through trenching to 400m water depth, with supplemental rock installation in areas

where target burial was unachievable.

[104]

In 2011, NSPML and Nalcor formed a core evaluation team to jointly

manage the procurement process for the submarine cable systems. The team prepared

criteria and invited top global HVDC submarine cable suppliers to submit Expressions of

Interest (EOIs) for submarine cable design, supply, and installation. The EOIs received

were evaluated against key criteria focused on identifying safe, reliable, qualified,

technically competent, and financially sound candidates. Based on the results of the EOI

evaluation process, six global HVDC suppliers were approved as bidders and invited to

participate in the cable contract Request for Proposal (RFP).

[105]

NSPML’s procurement and legal teams worked with legal experts in HVDC

submarine cable projects to prepare contract terms and conditions to govern the work.

These were appended to the RFP and used as a baseline for contractual negotiations.

On August 6, 2013, NSPML’s Decision Board approved a recommendation to negotiate

with two cable proponents: ABB and Nexans. Following an extensive review and

negotiation process, NSPML decided that Nexans’ manufacturing and vessel supply best

met NSPML’s commercial and technical needs.

[106]

The cable contract was reviewed by NSPML and its counsel as well as

Nalcor, the IE, and legal counsel for Canada before being approved for execution. The

contract with Nexans was executed on January 30, 2014. The contract provided for a

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one-time price adjustment mechanism to fix foreign exchange and commodity prices,

which was exercised on February 7, 2014. After that date, Nexans assumed the risk of

all commodity and foreign exchange volatility.

[107]

To accommodate the length of cable required (two cables, each

approximately 170 km) for the preferred 2017 installation season, two separate Nexans

cable manufacturing sites were used, one in Halden, Norway and the other in Futtsu,

Japan. While the manufacturing process at Halden concluded in March 2017, a defect in

the lead sheath of the cable being manufactured in Futtsu was discovered in January

2016. In response, Nexans immediately ceased production at Futtsu and launched an

investigation into the source and extent of the problem. NSPML worked closely with

Nexans on the root cause investigation into this issue. The manufacturing issue was

eventually resolved, with no impact on the cost or schedule for the project.

[108]

NSPML continued to refine its cable protection strategy throughout the

cable manufacturing and construction phase of the Project. In August 2015, Nexans

performed a bathymetric and sub-bottom profiling survey in the nearshore Point Aconi

sand channel area. The survey data allowed Nexans to identify positive natural features

to enhance cable protection, as well as potential seabed obstacles. Nexans used the

results of its analysis to further optimize the existing cable route and avoid identified

obstacles and features of concern on the seabed.

[109]

Prior to the installation of the submarine cables, a horizontal directional

drilling (HDD) campaign was completed for the transition facilities where the marine

cables make landfall. The HDD conduits protect the cable from shoreline and nearshore

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hazards. NSPML undertook the HDD campaign the season prior to cable installation to

remove the potential risk that a back-to-back drill and installation campaign would create.

[110]

During cable installation in 2017, Nexans inadvertently caused one of the

cables to exceed its minimum bend radius. When investigation revealed that the cable

had suffered resulting damage, Nexans replaced the damaged section of the cable.

NSPML recovered all associated costs through its project insurance program.

[111]

In 2018, NSPML learned that redfish stocks had rebounded much faster

than scientists had anticipated, and a new redfish fishery had emerged along the cable

route, including at depths below 400 metres. Because the submarine cables were surface

laid over a 59-kilometre section below 400 metre water depth, they would not have been

physically protected from certain bottom trawling activities associated with the proposed

redfish fishery. To mitigate the risk of contact to the cables, NSPML retained Nexans to

trench the cables below 400m water depth. The cost of this additional work was

approximately $18 million.

Findings

[112]

The Board finds that NSPML’s procurement approach for the submarine

cable system was appropriate. Further, the Board finds that the one-time price

adjustment mechanism to fix foreign exchange and commodity prices allowed NSPML to

effectively mitigate the risk associated with the long lead time and large volumes of

commodities required to manufacture the cable.

[113]

With respect to the cable route selection process, the Board notes that route

optimization efforts led to increased project costs resulting from a requirement for a longer

length of cable than originally envisioned. However, as noted in NSPML’s response to

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Board IR-29 [Exhibit N-7], optimization of the route provided benefits. These included

obtaining more favorable positions for HDD exit points, re-routing around poor burial

areas to allow for cable trenching instead of rock dumping for cable protection, and

avoidance of pock marks that may have created unwanted free spans in the cables. The

Board finds that these benefits justified the additional costs of cable route optimization.

[114]

submarine cable program.

5.7.4 Management of the Overland Transmission Program

The overland transmission program of the ML Project consisted of five lines:

Overall, the Board finds that NSPML effectively and prudently managed the

[115]

 two direct current (DC) lines: one in Newfoundland running from Bottom Brook to

Cape Ray, and one in Nova Scotia running from Point Aconi to Woodbine;

 one alternating current (AC) line in Newfoundland connecting the Bottom Brook

and Granite Canal substations; and

 two grounding lines at each of the DC transmission facilities.

In total, the transmission program work involved clearing more than 1,800 hectares of

land, erecting more than 2,600 steel and wood transmission support structures, and

stringing 2,000 kilometres of conductor.

[116]

To help ensure the success of the overall ML Project, NSPML needed to

effectively manage the schedule for the transmission line program. Certain lines had to

be completed at specific times to align with a program of planned outages for testing.

Failure to meet any component of the transmission line construction schedule, and in turn

of the testing outage schedule, could have resulted in project delays and extra costs. To

help mitigate the risk of potential schedule slippage, NSPML:

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(a) engaged in advance procurement of long-lead steel towers, foundations, conductor,

and related materials;

(b) planned for and completed tree clearing and site preparation activities in advance of

construction to address the migratory bird construction exclusion period (which

generally occurs from May to July each year);

(c) contracted detailed design, engineering, and construction of each of the three

components of the transmission line program on a consolidated basis; and

(d) procured field camp accommodations to house and support up to 100 personnel

involved in the construction of the Newfoundland transmission works and the Granite

Canal switchyard in the Newfoundland interior, which mitigated the challenges of

regular travel to this remote location and enhanced the safety and efficiency of the

work.

[Exhibit N-1, p. 29]

[117]

In developing the transmission line scope of work, NSPML determined that

combining the scopes for constructing all five transmission lines in a single contract was

preferred. NSPML believed this would allow one contractor to assume and manage the

scheduling, integration, and associated risks of a geographically dispersed and multipart

construction program. NSPML issued an RFP for the transmission program to thirteen

companies and, in response, received seven proposals. NSPML’s proposal evaluations

focused on three proponents: Abengoa, Emera Utility Services (EUS), and Valard. The

price spread among them was significant, with Abengoa’s proposal being lower than the

next closest bid and within the expected pricing for the works. Further, since 2008,

Abengoa had been ranked as the largest international transmission and distribution

contractor in the world by leading trade publications.

[118]

Abengoa’s bid for the work met all the requirements in the bid evaluation

process, and Abengoa had secured a local contractor to support their construction

execution. As such, NSPML opted to award the transmission line program to Abengoa

in February 2015. However, NSPML had observed that Abengoa’s share price had been

subject to significant declines just prior to contract award. As such, NSPML determined

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it prudent to undertake additional due diligence and concluded that the financial risks

could be managed with Abengoa increasing its letter of credit prior to award, in addition

to other protections NSPML built into the Abengoa contract.

[119]

Abengoa was slow to begin its project execution and did not sufficiently

organize its workforce to carry out the work required on multiple work fronts. Following

Abengoa’s pre-insolvency filing in Spain on November 25, 2015, Abengoa began to

experience global cashflow difficulties, resulting in subcontractors complaining of late

payment. Eventually, Abengoa failed to meet contract performance expectations, despite

its assurances to the contrary, and its work quality and schedule began to slip. When it

became clear that Abengoa could not complete the work to NSPML’s satisfaction and to

the terms of its contract, NSPML triggered its contractual rights and:

(a) took assignment of Abengoa’s contract with PowerTel Utilities Contractors Limited

(PowerTel), Abengoa’s main subcontractor tasked with completing the AC and

grounding lines;

(b) called on Abengoa’s letter of credit, recovering $38 million to offset the cost of securing

a replacement contractor;

(c) worked closely with the sureties backing Abengoa’s performance bond (Sureties) to

re-award the DC line work to a replacement contractor, Emera Utility Services Inc.

(EUS)-Rokstad Joint Venture (ERJV); and

(d) settled with the Sureties to recover residual losses associated with the need to

reschedule and re-contract the transmission program.

[Exhibit N-1, p. 30]

[120]

Upon taking assignment of the PowerTel subcontract and issuing a contract

with ERJV to replace Abengoa, NSPML divided the transmission line work into two work

scopes, with PowerTel responsible for the AC and grounding lines and ERJV responsible

for the DC Transmission Lines. NSPML believed that this separation of the work,

combined with the resulting closer engagement in the work by NSPML’s PMT, would best

preserve the transmission line work schedule and ensure timely completion of this work

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scope to mesh with the other main work scopes on the overall ML Project. NSPML added

resources to its PMT so that it could appropriately monitor and manage the work of these

two contracts, maintain the project schedule, and help ensure cost effective overall project

completion.

[121]

In January 2017, PowerTel experienced a safety incident in which one of its

powerline technicians lost his life. As a result, NSPML immediately implemented a project

wide safety stand down that remained in place until all parties concerned, including

Newfoundland Occupational Health & Safety (NLOHS), the contractor, and NSPML, had

sufficient information to confirm that work could resume safely. While most contractors

returned to work in a matter of days, major components of the transmission line work

experienced a delay of several weeks until the applicable NLOHS stop work orders were

lifted. In addition, the DC line stringing work in Nova Scotia halted for several weeks until

the root cause of the incident in Newfoundland could be determined.

[122]

Once the stop work orders were lifted, it was clear that PowerTel’s ability to

achieve the completion date in the contract was at risk. Further, PowerTel had requested

an equitable adjustment to its contract price, non-resolution of which could have resulted

in additional schedule delays. As a result, NSPML and PowerTel entered into a

settlement agreement that secured a path to construction completion. Ultimately

PowerTel completed the balance of its work on the AC and grounding lines in time for

testing to take place on schedule. In addition, EUS completed the DC line work in NS by

May 2017, which, while five weeks behind schedule due to the work stoppage, was still

in time for all required testing to take place.

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[123]

The work on the DC line in NL also proved to be challenging. Rokstad

experienced schedule slippages, and contractual disputes arose between Rokstad and

NSPML. Rokstad and NSPML continued to advance work while each challenge

emerged. As the timeline to complete the work on schedule shortened, NSPML increased

its resources to monitor and assess claims and prepare for potential disputes. Rokstad

improved its performance in the spring of 2017 and was on track for substantial

completion of the Newfoundland DC line by July 31, 2017.

[124]

Then, in June 2017, a tower on the Newfoundland DC line collapsed and

NLOHS issued a stop work order. This effectively ceased NL DC transmission work for

almost three months, putting completion of the project in 2017 at risk. Further

complicating matters, by mid-October 2017, ERJV’s resources had almost been

exhausted as a result of its parent company, Carillion PLC, becoming financially

distressed. To address these challenges, NSPML:

(a) devoted substantial technical, commercial, and legal resources and, working with

NLOHS and ERJV, designed and executed a program to inspect all previously installed

tower anchors in Newfoundland and replace those found to be defective;

(b) worked with local NL contractors to implement an innovative means they proposed to

secure the towers while the anchoring systems were tested using techniques which

had to be developed and proven to satisfy NLOHS; and

(c) recognizing Rokstad’s financial difficulties (which had been exacerbated by the

financial deterioration of Rokstad’s parent company, Carillion PLC, in the United

Kingdom), negotiated an interim settlement utilizing payment milestones to incent

mechanical completion of the Newfoundland DC line by the end of November 2017, in

time for scheduled testing, and deferring outstanding commercial disputes for later

resolution.

[Exhibit N-1, p. 32]

In the end, and despite its best efforts, ERJV did not achieve Mechanical Completion in

NL until December 3, 2017, later than the agreed upon date but in time for the planned

testing.

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[125]

In February 2018, NSPML reach a final settlement agreement with ERJV.

As confirmed by Bates White, the final agreement eliminated all future claims against

NSPML by the endorsement of the court-appointed monitor overseeing the Carillion

Canada insolvency process and the approval of the Canadian government pursuant to

the requirements of the ML Credit Agreement. The settlement also avoided a potential

lengthy and costly arbitration process and ensured that all undisputed subcontractor and

supplier accounts were paid.

Findings

[126]

The cost of the transmission line program was approximately $129 million.

This exceeded the DG3 budget by roughly 40% and required the use of a significant

amount of the overall ML Project contingency amount. However, the Board finds that the

transmission line program did, in fact, face significant challenges that had not been

foreseen. Despite these substantial challenges, NSPML completed the transmission

work scope in time to avoid cross-contractor delays and initiate commissioning as soon

as end to end connectivity had been attained, helping to preserve the overall ML Project

schedule and budget.

[127]

With respect to the Abengoa contract, when Abengoa failed to meet

performance expectations, and when the quality and schedule of Abengoa’s work began

to slip, NSPML had the contractual tools to actively manage the work and to prepare for

a possible insolvency. The Board finds that these contractual protections allowed NSPML

to proactively manage and ultimately terminate and replace Abengoa with no incremental

cost to customers.

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[128]

Regarding the contract between NSPML and ERJV, the Board notes that

EUS (a member of ERJV) is an affiliate of Emera. As such, the NSPML procurement

team engaged in a self-provisioning analysis, as required by NSPML’s Affiliate Code of

Conduct, prior to deciding to award the work to ERJV. This analysis confirmed that the

ERJV bid provided the best value. As noted by NSPML in its application, replicating the

success it had achieved with PowerTel, NSPML negotiated a completion agreement with

ERJV that gave the best chance possible of completing the work without exposing the

project to additional risk. The Board agrees.

[129]

The Board also finds that the settlement agreements reached between

NSPML and PowerTel and NSPML and ERJV were appropriate and helped to avoid

potential future claims against NSPML.

[130]

Overall, the Board finds that through deployment of the necessary

resources and prudent efforts, NSPML was able to overcome the transmission line

program challenges, maintaining the overall ML Project budget and schedule, and

avoiding the risk of future claims. The Board, therefore, finds that NSPML effectively and

prudently managed the transmission line program.

5.7.5 Management of the Converter Station and Related Works

Program

[131]

NSPML’s converter station and related works program included the

following elements:

 two 500 MW +/- 200 kV DC Voltage Source Converter (VSC) stations and facilities

to connect incoming and outgoing conductors;

 HVAC substations at Granite Canal, Bottom Brook, and Woodbine to tie the

Maritime Link into the existing utility systems;

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 two transition compounds at Cape Ray and Point Aconi and installation of land

cable and associated terminations;

 grounding stations at Indian Head and Big Lorraine; and

 telecommunications systems to connect the converter station control systems to

the energy control centres of NL Hydro and NS Power.

The converter stations themselves comprised roughly 90% of the total work program.

[132]

In 2012, key technical and commercial members of NSPML’s project team

completed a review of the HVDC converter market globally to assess available

technologies and identify acceptable vendors from the limited competition in the

international HVDC market. NSPML’s contract team then developed an RFP for the

design, supply, and installation of the HVDC converter stations. Three top global HVDC

converter suppliers were then pre-qualified by NSPML and the related RFP was issued

in March 2013.

[133]

Following submission of proposals from RFP respondents, NSPML

concluded that ABB Inc. (ABB) offered the best overall value for the converter stations

work program. ABB’s proposal showed world-class experience with Voltage Source

Converter (VSC) technology, proposed a suitable work execution strategy, and provided

an acceptable overall cost. On two occasions during negotiations with ABB, prior to the

final scope of work being confirmed, NSPML removed certain scope elements from ABB’s

work plan, including warehouse construction and civil site rock exposure. This required

that NSPML increase its own resources to manage both reductions. The combined

scopes removed totaled approximately $48 million. NSPML and ABB executed the final

contract on June 26, 2014.

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[134]

In January 2015, ABB notified NSPML that an agreement with its intended

lead sub-contractor for the civil and installation component of the converter station scope

in both Nova Scotia and Newfoundland could not be obtained. As an alternative, ABB

proposed to take direct control over the construction management of this work. Before

approving this change, NSPML required that ABB demonstrate its readiness to self-

perform by outlining a comprehensive strategy for such self-performance. ABB

demonstrated its ability to perform the work to NSPML’s satisfaction. In August 2015,

ABB mobilized to the Bottom Brook and Woodbine converter sites and its schedule was

re-baselined to reflect this change.

[135]

ABB struggled with the timely completion of its protection and control

engineering design. NSPML recognized that any delay to this work could impact critical

outage work to be conducted by and with the utilities in Newfoundland and Nova Scotia

scheduled for the summer of 2017. Therefore, NSPML continually monitored ABB’s

progress in completing key interim milestones for this work. ABB completed all protection

and control design drawings in March 2017, in time for the realigned outage dates

required by the utilities in Newfoundland and Nova Scotia to allow for the commissioning

of the ML Project.

[136]

In October 2016, ABB encountered problems with the installation of

insulated exterior wall panels on the converter station buildings, which showed signs of

buckling shortly after erection. When it became clear that the panels would have to be

replaced, NSPML and ABB agreed to install temporary hoarding so that work could

continue on the building interiors through the winter weather. At the same time NSPML

worked with ABB to identify a suitable replacement panel supplier and validate the quality

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of the replacement panels, and ABB was able to obtain and complete installation of

exterior panels in April 2017. Under questioning during the hearing, Mr. Janega

confirmed that all extra contractor construction costs related to replacement of the panels

were paid directly by ABB with none absorbed by NSPML.

[137]

By mid-2017, ABB raised claims for recovery of substantial costs incurred

to accelerate the work and address quality issues and schedule delays. After evaluation

of the fairness of ABB’s claims and considering the need for continued performance and

commitment to schedule, NSPML proposed a settlement agreement designed to resolve

outstanding claims and change requests and solidify ABB’s resolve to meet the schedule.

A completion agreement was executed that set December 5, 2017, as the revised date

for substantial completion. For reasons not entirely within its control, ABB missed the

revised substantial completion date, and a second round of negotiation with ABB

followed. A final settlement agreement was subsequently executed between NSPML and

ABB.

Findings

[138]

The Board finds that NSPML’s efforts related to the panel buckling issue

allowed the project to avoid a substantial delay with no added contractor construction cost

incurred by NSPML. Further, the Board finds that the final settlement between NSPML

and ABB helped to avoid a potentially costly arbitration, secured cost and schedule

certainty, and required ABB to provide security covering the value of outstanding claims

with its subcontractors.

[139]

Overall, NSPML and ABB completed the converter station work program

without jeopardizing the project schedule and below the DG3 budget estimate. The Board

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finds that NSPML effectively and prudently managed the converter station and related

works program to an efficient conclusion.

5.7.6 Management of Completion and Commissioning

[140]

NSPML entered the ML Project completion phase in 2017. This phase

included the process of connecting systems, testing, commissioning and obtaining final

approvals. Prior to the commissioning phase, all electrical and mechanical terminations

were tested, and the integrity of the subsea cable and communication networks were

finalized. Integrated commissioning began in late 2017 and concluded with the first power

flow across the ML on December 8, 2017. This was followed by the final stage of

commissioning, which involved performance of multiple “heat runs” and concluded on

January 14, 2018. Throughout the completion phase, NSPML worked closely with NS

Power and NL Hydro to plan construction, energization and commissioning activities as

applicable to ensure that the utilities and operators had the information required to

perform their respective scopes of work and, when necessary, provide approvals.

[141]

On January 15, 2018, ABB declared its work substantially complete and

NSPML formally transferred control of the assets to NS Power and NL Hydro and released

the ML for service. After the ML was placed in service, NSPML reduced its project staffing

levels as needed. NSPML then completed the following activities:

 completion of remaining milestones under the primary contracts;

 obtained legal acceptance by the Government of Canada that “Commissioning”

requirements under the FLG had been met;

 obtained legal acceptance by Nalcor under the ML-JDA that requirements for

“Commercial Operation” had been met; and

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 finalized land rights and survey requirements, completed subsea cable locational

mapping and coordinates for marine navigational charts and other project

completion activities necessary to satisfy environmental and stakeholder

obligations and contractual completeness.

Findings

[142]

The Board finds that NSPML effectively and prudently managed and

completed the ML Project completion and commissioning phase.

[143]

NSPML continues its ML Project close out work related to a number of

outstanding insurance, warranty, expropriation and contract claims. Section 5.12 of this

Decision describes Board directives related to this close-out work.

5.8

[144]

Affiliate Transactions

Transactions with affiliates of NSPML are examined annually through Code

of Conduct report filings. As noted by NSPML in Exhibit N-1, NSPML incurred a total of

$3.5 million in office rent costs paid to affiliates from 2013 to the end of 2020 for rent at

NS Power’s Water Street Headquarters (Water Street) and Emera Place. The space at

Water Street was initially leased from NS Power and subsequently from Emera, and the

amount of space varied over time depending on requirements. As part of the original

approval process for the renovation of the then Water Street Power Plant, Emera leased

from NS Power a portion of the Water Street space at above market rates.

[145]

The Board, in an NS Power Affiliate Code of Conduct proceeding M09706,

determined appropriate market rates for NS Power to pay Emera for subleasing Water

Street space. This was as a result of a finding that NS Power was paying in excess of

market rates. In its direct evidence, NSPML confirmed that the amount it paid Emera is

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approximately $700,000 higher than these amounts determined by the Board in matter

M09706. The details with respect to amounts paid and adjustments made by the Board

are contained in two letters in the Affiliate Code of Conduct matter, a Board letter dated

September 28, 2020, and a response from NS Power dated October 9, 2020.

[146]

NSPML stated, both in its direct evidence and in response to Board IR-27,

that the space provided “needed flexibility” through the course of the Maritime Link

project.

[147]

In response to Board questions Mr. Rendall was asked, once the Board

determined an appropriate rate for Water Street space, what steps NSPML took to

renegotiate the lease arrangement or obtain a refund. It appears there was no attempt

to renegotiate the rate or negotiate a refund.

Findings

[148]

Consistent with the direction given to NS Power, the Board disallows the

$700,000 in above market rates paid by NSPML to affiliates. This amount is to be

deducted from the final project capital costs.

5.9

[149]

Accounting or Tax Issues

Grant Thornton’s evidence addressed several key items, including the

equity thickness which NSPML operated on throughout the construction period, NSPML’s

deferred income tax regulatory asset, and its depreciation policy.

[150]

The equity thickness which NSPML was permitted to operate on throughout

the construction period was prescribed in the Board’s original 2013 ML Decision:

To permit NSPML the flexibility it indicates is required, the Board finds it is appropriate to

permit NSPML the flexibility to earn up to 35% actual equity during Phase 3, the

construction phase. During Phase 4, the Board permits NSPML the flexibility to deviate

throughout the year as required. However, during Phase 4, the operating phase, the Board

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