Energy Regulators and Cost Overruns: The Nova Scotia Maritime Link Decision

It is no secret that building energy infrastructure in Canada is difficult. Recently, TransCanada threw in the towel on the Energy East project after years of delay and opposition. The final straw was the National Energy Board decision to consider the cost of carbon emissions in determining whether to allow the project to proceed. A brand new unexpected criteria was too much for TransCanada.

The TransCanada decision on October 5 came only a few days after the decision of the Federal Court of Appeal ordering the Federal government to reconsider aspects of its approval of the Trans Mountain pipeline. That project has also faced years of delay.

It turns out that regulatory challenges are not over once the construction permit is granted. On both sides of the country major energy projects now face serious delays and cost overruns.

On the Atlantic, the Nova Scotia Utility and Review Board is dealing with the problems at the Muskrat Falls Generating station and the implications for the Maritime Link transmission line. On the Pacific, the British Columbia Utilities Commission is grappling with the Site C dam being built by BC Hydro. This Case Comment deals with the Nova Scotia decision. The BC inquiry is still before the Commission.

On 11 September 2017, the Nova Scotia Utility and Review Board issued its latest Decision in Maritime Link1. This considered an application to approve an interim cost assessment starting January 1, 2018. The Nova Scotia Board first approved the Maritime Link project in 2013.2 Later in 2016 the Board approved certain costs to be recovered in 2018 and 2019 rates.3
However the latest Maritime Link application faces a new challenge. There are serious cost overruns and delays at the Muskrat Falls generating station in Newfoundland.4

The Nova Scotia customers were not responsible for the cost overruns5 but the delay in constructing the generating station means that the Maritime Link transmission line will not become operational for another two years. That raises the question of whether the Maritime Link assets will be “used and useful” on January 1, 2018, when the new costs come into rates.

The Parties

By way of background it is useful to describe the parties and the contracts between them. The Maritime Link project involves the delivery of power from the Muskrat Falls hydroelectricity project in Labrador to Nova Scotia through to New Brunswick and northeastern US markets. The Maritime Link is being constructed by NSP Maritime Link Inc. (NSPML), a subsidiary of Emera Inc. The Muskrat Falls project is being developed by NALCOR, a Newfoundland and Labrador Crown Corporation.

Muskrat Falls

Muskrat Falls has a generating capacity of 824 MW. It is the first phase of the Lower Churchill project in Labrador which ultimately will have a capacity of 3000 MW capable of providing 16.7 TWh of electricity a year.

The Muskrat Falls project also includes the Labrador – Island link which will transmit power from Labrador to mainland Newfoundland and the ML project from Newfoundland to Nova Scotia. When both links are in place Newfoundland will become part of an interconnected North American transmission system through the Nova Scotia- New Brunswick intertie and New Brunswick interconnections with the US.

The Maritime Link

The physical Maritime Link covers 360 km including 170 km across the Cabot Strait interconnecting with existing transmission lines at the Bottom Brook substation in Newfoundland and the Woodbine substation in Nova Scotia.

The Nova Scotia Board was required to approve the Maritime Link project if it was satisfied that the project would provide lowest-cost alternative for Nova Scotia ratepayers and was consistent with its obligations under the specified legislation. As indicated that approval was granted by the Nova Scotia Board in 2013.

The Contracts

Under the contractual arrangements NSP Maritime Link Inc. (NSPML) will pay 20 per cent of the cost of the Muskrat Falls project and in return will receive 20 per cent of the output of Muskrat Falls for 35 years. This commercial arrangement between NSPML and NALCOR has been described as the 20-20 principal.

In the first years of the operation of Maritime Link, NSPML will receive an additional block of electricity. This additional block and NSPML’s 20 per cent share of the output from Muskrat Falls are together defined as the NS block to be delivered to Nova Scotia Power for distribution to Nova Scotia Powers customers The NSPML costs of the Maritime Link project will be recovered from Nova Scotia consumers in the rates charged by Nova Scotia Power.

The Maritime Link facilities will have an expected service life of 50 years. NSPML would own the facilities during the first 35-year period at the end of which ownership will be transferred to NALCOR. To compensate for the 15-year differential for the first stage of the operation of the Maritime Link, NALCOR would supply NSPML with an additional 240 GW per year referred to as Supplemental Energy.

The Delays at Muskrat Falls

At the time of the 2013 application it was assumed that the NS block of energy including Supplementary Energy as well as the NALCOR market price energy would start flowing over the Maritime Link in the autumn of 2017. It was on the basis of this representation that the Board determined that the Maritime Link project would be the lowest long-term cost alternative for the ratepayers of Nova Scotia.

In the latest application NSPML seeks to start recovering all of its costs by way of an interim assessment as though the Maritime Link would be fully operational as planned.

The difficulty with that claim is the new delay in completion of the Muskrat Falls generation station until 2020. Originally the construction of the Muskrat Falls generation station was to be concurrent with the Maritime Link.

The real issue before the Board in the latest application is that given the delay at Muskrat Falls and the resulting delay in Maritime Link operations, the Maritime Link assets may not be “ used and useful “ as originally contemplated. Put differently, should there be a reduction in the interim assessment as a result of the delay in the delivery of the power and/or should the Board approve different costs relating to Maritime Link? Or should there be reduction in the interim costs initially approved and should the ratepayers of Nova Scotia receive a refund?

The Board set out the following issues in this proceeding:

  • Will the Maritime Link deliver energy to Nova Scotia ratepayers as originally contemplated? If the answer is no, is the Maritime Link used and useful?
  • Should there be a reduction in the interim assessment as a consequence of delayed delivery of the NS Block?
  • Should the Board approve the deferral of certain costs related to the Maritime Link Project?
  • What interim assessment should the Board set against NSPI respecting the amounts requested by NSPML for 2018 and 2019?
  • Should the Board approve the accounting policy amendments requested by NSPML?
  • When should the Final Assessment hearing be held, and what should the scope of that hearing be?

The Decision

The legal arguments turned on the used and useful principle and the prudence principle. Those claiming that there should be no reduction in the interim assessment argued that the investment was prudent at the time it was made and no reduction was called for. The consumer groups argued that the two-year delay meant that the Maritime Link was not used and useful.

The Board in its findings at page 23 of the Decision noted that in traditional rulemaking cost recovery is only available when it meets two conditions. First, the costs must be prudently incurred and second, the assets invested in must be used and useful.

None of the interveners argued that investment decision was imprudent. Nor was it imprudent to continue with the construction of Maritime Link in the face of the now announced delay in the completion of the Muskrat Falls generating station. The Board agreed the cost of halting construction of the Maritime Link would clearly exceed the benefits.

The “used and useful” question was however more complicated. The Applicant claimed that the investment was prudent and the assets were therefore used and useful. The Intervenors disagreed. The Board carefully reviewed the jurisprudence and concluded it had “considerable discretion” in deciding the issue stating:

[67] Kaiser and Heggie6, supra, at p 202, state that boards and other regulatory authorities have been given “considerable latitude” in determining whether assets are “used and useful” with respect to a utility’s ability to recover its costs for the construction of assets. As an example, they refer to the judgment of the Alberta Court of Appeal in Alberta Power Limited v. Alberta Public Utilities Board, 1990 ABCA 33 (CanLII), leave to appeal refused (1990), 110 A.R. 399 (note), 110 A.R. 400 (note) (S.C.C.). In Alberta Power, that Board considered whether certain transmission assets were “used and useful” and could be included in rate base, applying the rate base methodology set out in s.82 of the Public Utility Board Act, R.S.A. 1980, c. P-37, which provided: 82(1) In fixing just and reasonable rates, tolls or charges or schedules of them, to be imposed, observed and followed thereafter by an owner of a public utility, the Board shall determine a rate base for the property of the owner of a public utility used or required to be used to provide service to the public within Alberta and on determining a rate base it shall fix a fair return on the rate base.

[68] The Alberta Public Utilities Board denied the inclusion of certain assets into rate base because it found that the assets were not required, including a tie-line between Saskatchewan and Alberta. The Board concluded that the tie-line was being used to provide additional reserve capacity to Saskatchewan, applying the “used and useful” test:

[45] The phrase “used or required to be used” is well known in the field of utility regulation.

[46] Much of the argument before us was directed to a consideration of whether that expression is conjunctive or disjunctive. More significantly, it was directed to the proposition that if an asset is in fact “used”

[47] The case law, and common sense, dictate that there may be assets included in a rate base which are not in actual use such as standby equipment, and the phrase is often used disjunctively to recognize that situation. On the other hand, mere use is not sufficient to burden consumers with the cost. Clearly the consumer need not bear all the costs of an asset which is used if, for example, it reflects an imprudent expenditure. Assets unnecessarily used are not, simply by use, put into the rate base. Without putting too fine a point on interpretation we conclude that even if an object is used it must also be required. If it is not in actual use, it must nonetheless be required. The expression may be construed both disjunctively and conjunctively. We are supported in that view by American case law as well as by a consideration of the object of utility rate regulation.

[48] There are many decisions in the United States dealing with this terminology and a similar expression “used and useful”.

 [49] The phrase “used and useful” has come to import a measure of flexibility in determining when assets may be brought into the rate base. “Used and useful” may be viewed as both conjunctive and disjunctive: Used and Useful: Autopsy of a Ratemaking Policy, (1987), 8 Energy Law Journal 303.

[50] The object of these kinds of provisions is to recognize the need of utility operators to acguire property in advance of actual need while, at the same time, recognizing that ratepayers need only pay a return on that property from which they have a reasonable guarantee of receiving service: Central Maine Power Company v. The Public Utilities Commission et al. (1981) 433 Atl. R. (2nd) 331 (Supreme Court of Maine).

 [51] Once the interpretation is determined, whether a particular item is to be brought within the rate basis is essentially a question for the judgement of the board which does not involve a question of jurisdiction or law: B.C. Hydro and Power Authority v. The West Coast Transmission Co. Ltd, et al. (1981), 36 N.R. 33 at 56. [Bolding in original, underlined emphasis added] [Alberta Power, paras. 45-51]

[69] With respect to the specific issue of the tie-line between Alberta and Saskatchewan in that case, the Appeal Court found:

[53] This is a line which supplies the Saskatchewan Power Corporation with power generated in Alberta. It connects the Alberta Interconnected System (A.I.S.) with the Saskatchewan Power Corporation (S.P.C.) facilities. S.P.C. is to pay the carrying costs of this line until the end of 1994. The line may be used to generate revenue for the Alberta system as a whole, to provide an alternative inter-provincial connection to that with B.C. Hydro and to give flexibility.

[54] Alberta Power Limited claims that it comes within the concept in s. 82 because the tie provides benefits and is used or required to be used to obtain those benefits.

[55] The board did not err in deciding that the property was neither used or required to be used to provide service to the public within Alberta. There may be some benefit to the public within Alberta but that does not, on itself, justify the bringing of the asset into the rate base at this time.

[56] This is a classic example of the need for the regulatory agency to balance interests between utility investors and the consumers. No question of law therefore arises on this point.

[Alberta Power, paras. 53-56]

[70] Another decision noted by Kaiser and Heggie, supra, is British Columbia Hydro & Power Authority v. Westcoast Transmission Co. (1981), 36 N.R. 33 (Fed. C.A.); leave to appeal refused (1981), 37 N.R. 540n (S.C.C.). In that case, B.C. Hydro, a customer of Westcoast Transmission, opposed tolls before the National Energy Board (NEB), in part because it asserted certain assets that were included in rate base were not “used and useful”. Again, the authors note that the Court provided “considerable discretion” to the NEB. In confirming the NEB’s decision, the Court stated:

The question of what items should be included in a rate base is one for the judgment of the Board. In reaching that judgment, the Board is without doubt entitled to use as a guide, if it sees fit, the test of the present use or usefulness of the items sought to be included in providing utility service. But there is no rule of law that such a test must be used or followed or that it is the only principle that can be applied. Nor does it follow that the use of other principles in determining a rate base will result in tolls that are not just and reasonable. There is accordingly, in my opinion, no basis for regarding these objections as raising questions of law or jurisdiction on which the Court should or might properly intervene.

In the end the Board found that the assets were used and useful at least in part.

However, the Board noted that this was not the end of the matter. There was still the question of whether the rates were “just and reasonable”. Part of the interim costs were already in rates as a result of the 2016 decision.

In the end the Board made a number of adjustments, some of which were proposed by the Applicant. The Board in the final Decision ruled that:

The Board approves the interim assessment, subject to deferral and refunding to customers of depreciation and deferred financing amortization costs;

NSPI must holdback $10 million in both 2018 and 2019, subject to proof satisfactory to the Board that a minimum of $10 million per year in Maritime Link benefits are realized for NSPI ratepayers;

The Board is not prepared to approve final assessment until it is confident ratepayers will get NS Block, Supplemental Energy, and Nalcor Market-priced Energy.

Reductions in the Interim Assessment

The Nova Scotia Board in this case came to the conclusion that given the lack of any finding of imprudence it was not appropriate to arbitrarily reduce the interim assessment.

The Board did however deal with two concerns. The first was whether the delays deprived the Nova Scotia ratepayers of the benefit they had been promised. The Applicant took the position that the delays did not impose any burden on ratepayers. The Board rejected that submission and concluded at paragraph 121 that a conservative estimate suggests that there was at a minimum an annual benefit of $10 million for the ratepayers of NSPI. Accordingly the Board developed the holdback mechanism set out in paragraph 121:

[121] A conservative estimate of the benefit of the Maritime Link based on all of the evidence, without any accounting for the deferrals, is a minimum annual benefit of $10 million for the ratepayers of NSPI. The benefits to be achieved from the use of the Maritime Link are those outlined in paragraph 114 above. In order to incent the achievement of those conservatively estimated benefits and to, in a modest way, take account of the risks outlined in paragraph 336 of the 2013 Board ML Decision, NSPI is directed to hold back $10 million from the assessment in each of 2018 and 2019. At the end of each year, NSPML and NSPI are directed to provide proof satisfactory to the Board that a minimum of $10 million per year in benefits has been achieved. If the $10 million in benefits is achieved, the Board will direct NSPI to pay the $10 million to NSPML. If the $10 million in benefits is not achieved, then NSPI is to pay, on the direction of the Board, only that portion of the $10 million that is achieved and the balance will be refunded to ratepayers through the FAM. NSPI and NSPML have suggested the benefits could be significantly more than $10 million. Of course, NSPML and NSPI are obliged to realize any and all benefits over $10 million per year that are prudently achieved in the interests of ratepayers.

The other adjustment related to depreciation expense and involved concessions by the Applicant.

The original application had included depreciation expenses in the interim assessment amount of $51 million for each of 2018 and 2019. The Board had a concern about intergenerational equity as a result of the two-year delay given that there would be a delay in the benefits to certain classes of ratepayers.

In response NSPML agreed to defer $51 million depreciation expense from each of 2018 and 2019 and to defer approximately $1.5 million in deferred financing amortization expense in each of those two years.

Accordingly NSPML agreed to defer collection of Maritime Link depreciation expense to 2020 when the NS block was scheduled to start delivery. NSPML reduced its proposed Maritime Link interim assessment by $52.5 million for each of 2018 and 2019 resulting in a revised assessment amount of $109.5 million for 2018 and $111.5 million for 2019. NSPI proposed to return these deferred collections including interest to ratepayers. The proposed on bill credit would return 2018 and 2019 Maritime Link depreciation and deferred financing amortization amounts being collected from NSPI to ratepayers through the RSP.


This was a difficult case requiring a careful balancing of the interests between all parties. The holdback scheme developed by the Board was an interesting and novel approach that successfully addressed the concerns going forward without prejudging the result. This was after all a case where the delays were not the result of any actions by NSPML and Maritime Link.

The deferral of depreciation is explained by the fact that the 35-year term of NSPML ownership only commenced upon delivery of the Nova Scotia Block. The delay does not affect the term. Nova Scotians get the Nova Scotia Block for the contracted 35 years. The 35 years will just commence later.

It was also fortunate that the cost to the ratepayers was limited to the cost of the delay and did not involve bearing any part of the cost of the cost overruns experienced at Muskrat Falls. Those cost as indicated above were capped in the original contracts.

*Gordon E. Kaiser, Arbitrator and Settlement Counsel, Jams Resolution Center, Toronto and Washington DC. He is a former Vice Chair of the Ontario Energy Board; an Adjunct Professor at the Osgoode Hall Law School; the Co-Chair of the Canadian Energy Law Forum; and a Managing Editor of this publication (The Energy Regulation Quarterly).

  1. In the Matter of an Application by NSP Maritime Link Incorporated for Approval of an Interim Cost Assessment (11 September 2017), 2017 NSUARB 149.
  2. In the Matter of the Maritime Link Act and in the Matter of an Application by NSP Maritime Link Incorporated for Approval of the Maritime Link Project (22 July 2013), 2013 NSUARB 154.
  3. In the Matter of a Hearing into Nova Scotia Power Incorporated’s 2017-2019 Fuel Stability Plan and Base Cost of Fuel Reset under the Fuel Adjustment Mechanism (“FAM”) as Required under the Electricity Plan Implementation (2015) Act (19 July 2016), 2016 NSUARB 129. The amounts including depreciation were $162 million for 2018 and $164 million for 2019.
  4. The cost overruns experienced by NALCOR on the Lower Churchill as of June 2016 had increased from $7.4 billion to $11.4 billion. Supra note 1 at 12, para 31.
  5. The NALCOR cost overruns did not impacted Nova Scotia ratepayers because the agreement capped the NSPML exposure at $1.5554 billion, supra note 1 at 13, para 33.
  6. Gordon Kaiser & Bob Heggie, Energy Law and Policy (Toronto: Carswell, 2011) at 202.

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