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  
Document: 291318  
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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
o
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.  
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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 MUNISassertions 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.  
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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.  
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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).  
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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 installedHVDC 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 7oC 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 installedML 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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