Norfolk and Altalink: Ontario and Alberta Regulators Refine Mergers and Acquisitions Standards

The past year saw noteworthy developments around the regulation of mergers and acquisitions in the electricity sector in both Ontario and Alberta.   The energy regulators of those provinces each considered the approval of significant acquisitions of utilities within their respective jurisdictions. In July 2014, the Ontario Energy Board (OEB) concluded a 15-month hearing into a bid by the publicly owned Hydro One to acquire Norfolk Power, a local electricity distribution company (LDC).2 In November 2014, the Alberta Utilities Commission (AUC) ruled on an application for approval of the sale of AltaLink’s transmission assets and business to a foreign private investor.3 Both transactions involved complex commercial agreements, the terms of which were unique to the parties involved. Despite the differences, however, there was one common element with which both regulators had to grapple – purchase incentives. In both deals, the purchasers offered a premium on the purchase price. Hydro One also offered a 1% reduction from 2012 rates and a five-year rate freeze as an additional incentive for existing Norfolk Power customers. Other utilities intervening in each of the proceedings argued that the purchase price premium ran afoul of the criteria governing the approval of mergers and acquisitions. Would the regulators permit the purchasers to offer these types of bids?

Hydro One and Norfolk Power: Consolidation in Ontario’s Electricity Distribution Sector

Hydro One’s bid for Norfolk Power is another step in the long path toward consolidation in Ontario’s electricity distribution sector. As part of the restructuring of Ontario’s power sector around the year 2000, legislation required municipalities to “corporatize” their distribution assets and, in this process, many merged to become bigger or simply sold to Hydro One. During that process, Ontario’s electricity distribution sector contracted from over 300 distributors in the 1990’s to around 90. Since then, a continuing trend of mergers and sales has further reduced the number to a little over 70 today. In December 2012 the provincially appointed Distribution Sector Review Panel issued a report calling for further consolidation of the sector including, as a last resort, forced amalgamations, into eight to twelve larger regional distributors. The backlash among municipalities and numerous LDCs was immediate and the Minister of Energy quickly assured the industry that there would be no forced amalgamations or sales.

Despite the disavowal of the Distribution Sector report, consolidation and efficiencies were on the front burner again moving into 2013. That year Hydro One signed an agreement to purchase Norfolk Power (announced April 2, 2013) and subsequently made an application to the OEB for approval of that deal.

In assessing whether or not to approve an acquisition of a public utility, the OEB applies a “no harm” test.   The no harm test arises from an earlier OEB decision, the Combined Proceedings,4 and requires that the OEB consider whether a proposed acquisition would be consistent with the OEB’s legislated objectives as set out in the Ontario Energy Board Act, 1998, S.O. 1998, c. 15 (the “OEB Act”).5 At the time the Combined Proceeding was decided, the OEB Act only provided for the first two of what are currently five objectives:6

  1. To protect the interests of consumers with respect to prices and the adequacy, reliability and quality of electricity service.
  2. To promote economic efficiency and cost effectiveness in the generation, transmission, distribution, sale and demand management of electricity and to facilitate the maintenance of a financially viable electricity industry.
  3. To promote electricity conservation and demand management in a manner consistent with the policies of the Government of Ontario, including having regard to the consumer’s economic circumstances.
  4. To facilitate the implementation of a smart grid in Ontario.
  5. To promote the use and generation of electricity from renewable energy sources in a manner consistent with the policies of the Government of Ontario, including the timely expansion or reinforcement of transmission systems and distribution systems to accommodate the connection of renewable energy generation facilities.7

In the Norfolk decision, the Board determined that only the first two objectives were relevant to the issues raised. 8 The OEB went on to consider, however, the application under the present-day no harm test of the three objectives added to the OEB Act after the Combined Proceedings decision. The Board concluded that because it is required by law to be guided by all five of the objectives, the no harm test should not be limited to the first two objectives, but must be applied having regard to all five. 9

Under the terms of the deal with Norfolk Power, Hydro One proposed to pay a premium of $39.1 million above the $53.9 million net book value.10 As well, Hydro One offered a 1% reduction from 2012 rates and a five-year rate freeze for Norfolk customers.11 Intervenors made a number of arguments that completion of the transaction with these incentives would not satisfy the no harm test. Key issues for the intervenors were the potential for large rate increases at the end of the five-year period and concerns that the premium paid on the purchase price would result in higher rates not only for Norfolk (eventually) but for all Hydro One customers.12

The OEB rejected these arguments and found that, in applying the no harm test it was not relevant to consider whether the purchase price has been set at an appropriate level since future rates would be determined without reference to the purchase price paid. It was the OEB’s policy that the premium would not find its way into future rates.13 The OEB also dismissed the argument that the purchase price was set at a level that would create a financial burden on Hydro One on the basis of the proportion of the purchase price to Hydro One’s asset base ($39.1 million to $20.8 billion).14

With the Norfolk decision, the OEB confirmed that incentives such as rate reductions and freezes and price premiums are fair game as the province contemplates further consolidation in the electricity distribution sector. According to the OEB, its policy and oversight will prevent any feared rate increases on account of the purchase price premium.

Foreign Investment in Alberta’s Electricity Transmission Sector: Buffett’s Bid for AltaLink

In 2002, Quebec-based SNC-Lavalin acquired Alberta’s largest electricity transmission company which continued as AltaLink.15 In 2013, following a series of corruption scandals, SNC-Lavalin announced a new strategic direction whereby it would focus on its core engineering and construction business and divest itself of non-core holdings, including AltaLink.16 In May 2014, SNC-Lavalin concluded a deal with Warren Buffett’s US-based Berkshire Hathaway for the purchase of AltaLink.17 This deal, involving a foreign investor, triggered a review by the Competition Bureau of Canada and Industry Canada, both of which approved the transaction.18 The final hurdle for the parties to clear was approval by the AUC.

Like the OEB, the AUC applies a “no harm” test in evaluating an application to approve the acquisition of a utility. The no harm test and other factors considered by the AUC evolved from a number past decisions19 and include:

  1. Whether there will be any impact to the rates and charges passed on to customers.
  2. Whether any operational benefit or risk arises related to the acquiring party’s utility experience.
  3. Whether the financial profile of the utility will be impacted for the purposes of attracting capital.
  4. In the case of AltaLink, whether the utility will remain sufficiently legally, financially and operationally separate from the acquiring party.
  5. Whether the AUC will maintain sufficient regulatory oversight of the utility.
  6. Whether the management and operational expertise will remain in place post-transaction.
  7. Whether the transaction will result in any cost impacts for customers relating to such things as tax and pension funds.
  8. That the acquiring party wishes to be in the utility business in Alberta whereas the divesting party does not.
  9. That customers are, to the maximum extent possible, to be protected against any negative ramifications arising from the transactions.
  10. That customers are not entitled to a level of post-transaction regulatory certainty they would not have realized if the transaction had not been approved.
  11. That customers are at least no worse off after the transaction is completed after consideration of the potential positive and negative impacts of the proposed share transactions.20

The no harm test is applied in two stages. First the AUC assesses whether the transaction results in harm to customers. If the AUC determines that it will, the AUC proceeds to the second stage and considers whether any identified harms can be mitigated through approval conditions.21

A number of utilities intervened in the application arguing, among other issues, that the purchase premium offered by Berkshire Hathaway of $3.2 billion on an approximate book value of about $800 million raised a potential negative impact on customer rates and service that remained unresolved. Even if the purchaser was prohibited from including the premium in rate base they argued, the purchaser may seek recovery in an indirect manner that would have an impact on the future costs included in the utility revenue requirement and rates. Otherwise, they asked, how would the purchaser recoup its substantial investment? 22

One intervening utility argued that the AUC ought to impose the following condition on any approval to address this concern:

None of the Applicants, nor any related entity nor successor of them, shall seek to recover from customers the premium over net book value paid for the shares of NewCo pursuant to the Share Purchase Agreement.23

The AUC dismissed these concerns stating that the proposed transaction did not fail the no harm test simply because a premium over book value had been offered.24 Reliability and service quality matters would remain subject to AUC oversight, as would the prudency of AltaLink’s costs and the justness and reasonableness of the rates approved in AltaLink’s tariff.25 Further, the AUC refused to impose the recommended condition that none of the applicants should seek to recover the purchase price premium on the bases that the AUC’s ongoing regulatory oversight made such a condition unnecessary.26 In November 2014, the AUC issued its decision approving the transaction and the final hurdle was cleared for the parties to conclude their deal.

Ontario and Alberta Regulators Clear the Way for Purchase Premiums

The deals to acquire Norfolk Power and AltaLink differed in many respects. Hydro One is a publicly owned company pursuing a consolidation strategy in Ontario’s LDC sector while Berkshire Hathaway is a private, foreign-owned company acquiring the largest transmission business in Alberta. Both of the proposed transactions, however, included incentives of purchase price premiums, and in the case of Norfolk Power, a 1% rate reduction and five-year rate freeze. In both cases, the issue of purchase price premiums were raised by intervening utilities as a possible breach of the no harm test used by the OEB and AUC to evaluate utility mergers and acquisitions. In both cases, the OEB and AUC determined that their on-going oversight was sufficient to ensure that customers would not suffer the feared harms of rate increases or negative impacts to service reliability. In particular, the regulators noted that rates would be determined based on book value without reference to premiums paid.

While it is certainly true that Norfolk Power and AltaLink continue to be subject to regulation by the OEB and AUC respectively, the reality is that these utilities will be under constant pressure by their shareholders, whether public or private, to obtain a return on the purchase price premium. The regulators will have to be vigilant in their oversight to prevent any indirect attempts at recovery once the splash made by these acquisitions fades and the newly acquired utilities move forward with their business.

* Ron Clark is a partner and member of Aird & Berlis LLP’s Corporate/Commercial Group and Energy Team. He previously served as a diplomat with the Canadian Department of Foreign Affairs and International Trade.
** Zoë Thoms is an associate and a member of Aird & Berlis LLP’s Litigation Group and Energy Team. Prior to joining A&B, she practised at another major Canadian law firm.

  1. An earlier version of this article previously appeared on the Aird & Berlis LLP website
  2. Hydro One Inc. and Norfolk Power Distribution Inc., EB-2013-0196/EB-2013-0187/EB-2013-0198, online: OEB <> [Norfolk].
  3. Altalink Investment Management Ltd. and SNC Lavalin Transmission Ltd. et al.(28 November 2014), (Application for Approval)AUC Decision 2014-326 [AltaLink].
  4. Combined Proceedings (5 August 2005), EB-2005-0018/0234\0254\0257, online: OEB <> [Combined Proceedings].
  5. Ibid at 6-7; Norfolk, supra note 1at 10-13;
  6. Combined Proceedings, supra note 4 at 12-13.
  7. Ontario Energy Board Act, 1998, SO 1998, c 15, s 1.
  8. Norfolk, supra note 1 at 13.
  9. Ibid at 12-13.
  10. Ibid at 14.
  11. Ibid at 12.
  12. Ibid at 14-15.
  13. Ibid at 15.
  14. Ibid at 16.
  15. TransAlta and AltaLink (28 March 2002)., AUC Decision 2002-038.
  16. SNC-Lavalin, News Release, “SNC-Lavalin Announces its Strategic Plan” (2 May 2013), SNC- online: <>.
  17. SNC-Lavalin, News Release, “SNC-Lavalin enters into agreement to sell its equity stake in Altalink for $3.2 billion –transaction unlocks significant value in support of company’s strategic plan”(1 May 2014), online:SNC-Lavalin:<>.
  18. AltaLink, supra note 3 at para 4.
  19. These factors arise from seven separate prior decisions of the AUC which are set out in further detail at paragraphs 108-109 and the footnotes n81 – n86 in AltaLink.
  20. AltaLink, supra note 3 at paras 108-109.
  21. Ibid at para 110.
  22. Ibid at paras 219, 227.
  23. Ibid at para 222.
  24. Ibid at para 231.
  25. Ibid at para 133
  26. Ibid at para 231.

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